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EX-21 - EXHIBIT 21 - APCO OIL & GAS INTERNATIONAL INCex21.htm
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EX-31.1 - EXHIBIT 31.1 - APCO OIL & GAS INTERNATIONAL INCex31_1.htm
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EX-99.2 - EXHIBIT 99.2 - APCO OIL & GAS INTERNATIONAL INCex99_2.htm
EX-99.1 - EXHIBIT 99.1 - APCO OIL & GAS INTERNATIONAL INCex99_1.htm
EX-31.2 - EXHIBIT 31.2 - APCO OIL & GAS INTERNATIONAL INCex31_2.htm



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
For the fiscal year ended December 31, 2010
   
 
OR
   
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from to
 
Commission file number 0-8933
 
APCO OIL AND GAS INTERNATIONAL INC.
(Exact Name of Registrant as Specified in its Charter)
 
Cayman Islands
 98-0199453
(State or Other Jurisdiction of Incorporation or Organization)
(IRS Employer Identification No.)
   
One Williams Center, Mail Drop 35
 
Tulsa, Oklahoma
74172
(Address of Principal Executive Offices)
(Zip Code)
 
Registrant’s Telephone Number, Including Area Code: (918) 573-2164
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Each Class
Name of Each Exchange on Which Registered
Ordinary Shares $.01 Par Value
The NASDAQ Stock Market
        The NASDAQ Capital Market)
Securities registered pursuant to Section 12(g) of the Act:
 
None
 
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yeso Nox
 
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 o No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer o   Accelerated Filer x   Non-Accelerated Filer o   Smaller reporting company o
                                                                               (Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x
 
The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates on June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, was $214,873,124. This value was computed by reference to the closing price of the registrant’s shares on such date. Since the registrant’s shares trade sporadically in The NASDAQ Capital Market, the bid and asked prices and the aggregate market value of shares held by non-affiliates based thereon may not necessarily be representative of the actual market value. Please read Item 5 for more information.
 
As of March 3, 2011 there were 29,441,240 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


APCO OIL AND GAS INTERNATIONAL INC.
FORM 10-K
 
 
 
 
PART I
 
   
Page No.
Items 1 and 2.
1
     
Item 1A.
17
 
 
     
Item 1B.
30
     
Item 3.
30
     
     
     
 
                      PART II
 
     
Item 5.
31
     
Item 6.
33
     
Item 7.
34
     
Item 7A.
48
     
Item 8.
51
     
Item 9.
78
     
Item 9A.
78
     
Item 9B.
78
     
 
PART III
 
     
Item 10.
79
     
Item 11.
83
     
Item 12.
85
     
Item 13.
87
     
Item 14.
89
     
 
PART IV
 
     
Item 15.
90




DEFINITIONS
 
 
We use the following oil and gas measurements and abbreviations in this report:
 
- “Bbl” means barrel, or 42 gallons of liquid volume, “MBbls” means thousand barrels, and “MMBls” means million barrels.
 
- “MBbls/day” means thousand barrels per day.
 
- “Mcf” means thousand cubic feet, “MMcf” means million cubic feet, and “Bcf” means billion cubic feet.
 
- “Mcf/d” means thousand cubic feet per day.
 
- “BOE” means barrel of oil equivalent, a unit of measure used to express all of the Company’s products in one unit of measure based on choleric equivalency of the three products; one barrel of oil is equal to one barrel of oil equivalent, six mcf of gas are equal to one barrel of oil equivalent, and one ton of LPG is equivalent to 11.735 barrels of oil equivalent.
 
- “MBOE” means thousand barrels of oil equivalent, and “MMBOE” means million barrels of oil equivalent.
 
- “LPG” means liquefied petroleum gas. More specifically in this report, the Company produces propane and butane at its LPG plant; LPG may also be referred to as plant products.
 
- “Metric ton” means a unit of mass equal to 1,000 kilograms (2,205 pounds); as used in this report, a metric ton is equal to 11.735 barrels of oil equivalent.
 
- “2D” means two dimensional seismic imaging of the sub surface.
 
- “3D” means three dimensional seismic imaging of the sub surface.
 
- “WTI” 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 I and 2.   BUSINESS AND PROPERTIES
 
(a) General Development of Business
 
Apco Oil and Gas International Inc. (formerly Apco Argentina Inc.) is a Cayman Islands company organized on April 6, 1979 as a successor to Apco Argentina Inc., a Delaware corporation organized on July 1, 1970. References in this report to “we,” “us,” “our,” “Apco,” or the “Company” refer to Apco Oil and Gas International Inc. and its consolidated subsidiaries and, unless the context indicates otherwise, its proportionately consolidated interests in various joint ventures.
 
Apco is an international oil and gas exploration and production company with a focus on South America. Exploration and production will be referred to as “E&P” in this document. Apco began E&P activities in Argentina in the late 1960s and it entered Colombia in 2009.  As of December 31, 2010, Apco had interests in eight oil and gas producing concessions and two exploration permits in Argentina, and three exploration and production contracts in Colombia. Our producing operations are located in the Neuquén, Austral, and Northwest basins in Argentina.  We also have exploration activities currently ongoing in both Argentina and Colombia.
 
The Williams Companies, Inc. (“Williams”) indirectly owns 68.96 percent of our outstanding ordinary shares.  Please read “Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.”  Our executive officers are employees of Williams and some of our directors are employees of Williams.  In addition, pursuant to an administrative services agreement, Williams provides certain other services to us, such as risk management, internal audit services, and, for our headquarters office in Tulsa, Oklahoma, office supplies, office space and computer support.  Please read “Certain Relationships and Related Party Transactions, and Director Independence — Transactions with Related Persons — Administrative Services Agreement.”
 
On February 16, 2011,  Williams announced that its Board of Directors approved pursuing a plan to separate Williams into two standalone, publicly traded corporations. The plan calls for the separation of its exploration and production business via an initial public offering in 2011 of up to 20 percent of a corporation holding that business ("New E&P") and, in 2012, a spin-off to Williams’ shareholders of its remaining interest in New E&P.  Williams stated its intention to include its interest in Apco in New E&P.  Williams retains the discretion to determine whether and when to execute the spinoff.
 
(b) Financial Information About Segments
 
We treat all operations as one operating segment.
 
(c) Narrative Description of Business
 
Our business model is to create strategic partnerships to share risk and gain operational efficiencies in the exploration, development and production of oil and natural gas. We have historically acquired non-operating interests in the producing properties in which we participate.
 
Although we place great reliance on our operating partners because we generally have non-operating interests, Apco actively participates in the management of our sub-surface resources and reservoirs.  Our branch office in Buenos Aires includes technical, administration and accounting staff which obtains operational and financial data from our joint venture operators that is used to monitor operations. Our technical staff continuously analyzes and evaluates subsurface data and reservoir performance, provides technical assistance to our joint venture operators, makes recommendations regarding field development and reservoir management, and calculates our estimates of reserves.  When deemed strategically appropriate, we have occasionally chosen to operate properties that are exploratory in nature and are prepared to operate producing properties given the right opportunity.



In Argentina, we are active in four of the five principal producing basins in the country. Our core assets are located in the Neuquén basin in the provinces of Río Negro and Neuquén in southwestern Argentina, where Apco has been active for more than 40 years.  In 2009, we expanded our E&P activities into Colombia where we have interests in three exploration blocks.
 
In general, we conduct our E&P operations in our concessions through participation in various joint venture partnerships.  We also have a significant equity interest in combination with our direct working interest in our core properties.  The following table details the areas and basins where we have E&P operations and our respective direct working and equity interests in those areas:


       
Interest
Area
Basin
Province
Country
Working
Equity (1)
Combined
Entre Lomas
Neuquén
Neuquén / Río Negro
Argentina
23.00%
29.85%
52.85%
Bajada del Palo
Neuquén
Neuquén
Argentina
23.00%
29.85%
52.85%
Charco del Palenque
Neuquén
Río Negro
Argentina
23.00%
29.85%
52.85%
Agua Amarga
Neuquén
Río Negro
Argentina
23.00%
29.85%
52.85%
Coirón Amargo
Neuquén
Neuquén
Argentina
45.00%
 -
 
Acambuco
Northwest
Salta
Argentina
1.50%
 -
 
Río Cullen
Austral
Tierra del Fuego
Argentina
25.78%
 -
 
Las Violetas
Austral
Tierra del Fuego
Argentina
25.78%
 -
 
Angostura
Austral
Tierra del Fuego
Argentina
25.78%
 -
 
Sur Río Deseado Este (2)
San Jorge
Santa Cruz
Argentina
16.94%
 -
 
Llanos 32
Llanos
Casanare
Colombia
20.00%
 -
 
Turpial
Middle Magdalena
Boyaca / Antioquia
Colombia
50.00%
 -
 
Llanos 40
Llanos
Casanare
Colombia
50.00%
 -
 

(1)  
In addition to our direct working interests in the Entre Lomas, Bajada del Palo, Agua Amarga and Charco del Palenque blocks, Apco and its subsidiaries own 40.803 percent of the shares of Petrolera Entre Lomas S.A. (“Petrolera”) which holds a 73.15 percent direct working interest in the areas, resulting in a 29.85 percent equity interest for Apco. Consequently, Apco’s combined direct working interest and equity interest in the four areas totals 52.85 percent.  We refer to these properties in a group as our “Neuquén basin properties.”
(2)  
In the Sur Río Deseado Este concession our 16.94 percent working interest is in an exploitation area with limited oil production and we have an 88 percent working interest in an exploratory area in the northern sector of the concession.

 
 
Oil and Gas Producing Activities
 
All of our production and reserves are located in Argentina as of December 31, 2010. Our core properties in the Neuquén basin predominantly produce crude oil and associated natural gas.  Our other properties in the Northwest and Austral basins predominantly produce natural gas and condensate.  On a barrel of oil equivalent basis, 59 percent of our combined consolidated and equity proved reserves are oil and condensate and 41 percent are natural gas as of December 31, 2010.
 
Our current portfolio of reserves provides us with strong capital investment opportunities for several years into the future. Our goal is to drill existing proved undeveloped reserves, which comprise 38 percent of our total proved reserves, and also drill in unproven areas as a result of exploration and/or field extension drilling to add to our proved reserves and replace as much of the current year’s production as possible. In recent years, we have complemented our development projects in Argentina by increasing exploration activities and this year by adding a third exploration block in Colombia.


Oil and Natural Gas Reserves
 
 
Summary of Proved Oil and Natural Gas Reserves as of December 31, 2010
Based on Average 2010 Prices and Costs
 
 
Oil (Mbbls) (1)
Natural Gas (Bcf) (2)
Total Proved (Mboe) (3)
 
Interests
Interests
Interests
 
Consolidated
Equity
Combined
Consolidated
Equity
Combined
Consolidated
Equity
Combined
                   
Proved Developed
7,747
8,878
16,625
39.8
27.9
67.7
14,380
13,528
27,908
Proved Undeveloped
4,961
5,551
10,512
24.8
20.3
45.1
9,095
8,934
18,029
Total Proved (4)
12,708
14,429
27,137
64.6
48.2
112.8
23,475
22,462
45,937

(1)
Volumes presented in the above table have not been reduced by the provincial production tax that is paid separately and is accounted for as an expense by Apco. For natural gas, the provincial production tax is paid on volumes sold to customers, but not on natural gas consumed in operations.  Our effective tax rate is approximately 12 percent.
(2)
A portion of our natural gas reserves are consumed in field operations.  The volume of natural gas reserves for 2010 estimated to be consumed in field operations included as proved natural gas reserves within our consolidated interests are14.8 Bcf and 16.6 Bcf for our equity interests, or an oil-equivalent combined amount of 5,237 Mboe.
(3)
Natural gas is converted to oil-equivalent at six Bcf to one million barrels.
(4)
All of our reserves are in Argentina as of December 31, 2010.
 

Preparation of Reserves Estimates
 
Our engineering staff in our office in Buenos Aires provides reserves modeling and production forecasts for our concessions. The finance and accounting department provides supporting information such as pricing, costs, tax rates and other information pertinent to developing our discounted cash flows. The entire reserves process is coordinated by management in our head office. Our reserves analysis also includes working closely with joint venture operators to coordinate future investment plans; contracting with a third-party consultant to complete the independent review; ensuring internal controls are appropriate and making any changes required; performing internal overview of data for reasonableness and accuracy; and the final preparation of the year-end reserves report.
 
Preparing Apco’s year-end reserves is a formal process. It begins soon after finalizing year-end reserves with a review of the existing process to identify where improvements can be made. Usually in early summer of each year, the internal controls, as they relate to the year-end reserves, are reviewed and updated. Typically in late summer, our reserves engineering and geological technical staff, management, and the third-party engineering consultants meet to begin coordinating the year-end process and review. Throughout the third quarter, the reserves staff, third-party engineering consultants, and joint venture operators exchange data and interpretations to finish year-end reserves estimations. During the fourth quarter, forecasts, interpretations, maps and preliminary estimates of reserves are reviewed with upper management for their comment.
 
Approximately 96 percent of our total year-end 2010 proved reserves estimates on a barrel of equivalent basis were audited by Ralph E. Davis Associates, Inc. (“Davis”).  When compared on a well-by-well basis, some of our estimates were greater and some were less than the estimates of Davis. Any differences were discussed and resolved.  In the opinion of Davis, the estimates of our proved reserves are in the aggregate reasonable by basin and total and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Davis is satisfied with our methods and procedures in preparing the December 31, 2010 reserves estimates and saw nothing of an unusual nature that would cause Davis to take exception with the estimates, in the aggregate, as prepared by us. Reserves estimates related to our properties in the Northwest basin of Argentina represent approximately four percent of our total proved reserves and were audited by RPS Energy. These reports are included as exhibits to this Form 10-K.
 
The engineer primarily responsible for overseeing preparation of the reserves estimates and the third party reserves audit is our Manager of Engineering.  The Manager’s qualifications include over 20 years of reserves evaluation experience, a Ph.D in Petroleum Engineering from the University of New Mexico at Socorro, New Mexico and a B.S. in Petroleum Engineering from the University of Buenos Aires, Argentina.
 
 
Proved Undeveloped Reserves
 
Apco’s proved undeveloped reserves for its combined interests as of December 31, 2010 are 18.0 Mmboe, an increase from 15.9 Mmboe as of December 31, 2009.  The largest component of the increase is successful development and exploration drilling.  All locations comprising our remaining proved undeveloped reserves are forecast to be drilled by 2016; 21 percent of these locations are expected to be drilled in 2011.  For many years, Apco has enjoyed a track record of success converting proved undeveloped reserves to proved producing reserves as we have drilled and put on production undeveloped locations, including both step-out and in-fill wells, with a greater than 90 percent success rate. Historically, all of our drilling investments have been financed by internally generated cash flows and cash reserves. During 2010, 3 Mmboe, or 19 percent of our net proved undeveloped reserves as of December 31, 2009, were converted to proved developed reserves.
 
 
Oil and Natural Gas Properties, Wells, Operations, and Acreage
 
The following table sets forth our productive oil and gas wells and our developed acreage assignable to such wells as of December 31, 2010. We use the terms “gross” to refer to all wells or acreage in which we have a working interest and “net” to refer to our ownership represented by that working interest.  Because of our significant equity interest in our core areas, we also include our share of our equity investee’s net interests.

 
 
Productive Wells
           
                           
 
Oil
 
Gas
 
Developed Acreage
                           
 
Gross
Net
Equity
 
Gross
Net
Equity
 
Gross
 
Net
Equity
Combined
                           
Neuquén basin
517
119
154
 
41
9
12
 
50,074
 
11,517
14,947
26,464
Austral basin
76
20
              -
 
30
8
              -
 
11,641
 
3,001
                  -
3,001
Northwest basin
3
            -
              -
 
6
              -
              -
 
10,759
 
161
                    -
161
Total Argentina
596
139
154
 
77
17
12
 
72,474
 
14,679
14,947
29,626


At December 31, 2010, we held the following undeveloped acreage in Argentina and Colombia:
 

 
Undeveloped Acreage
         
 
Gross Acres
Net
Equity
Combined
         
Neuquén basin
437,555
122,638
100,760
223,398
Austral basin
455,448
117,415
                     -
117,415
Northwest basin
282,862
4,243
                     -
4,243
San Jorge basin
75,582
57,743
                     -
57,743
Total Argentina
1,251,447
302,039
100,760
402,799
Colombia
374,363
153,862
                     -
153,862
Total Company
1,625,810
455,901
100,760
556,661
 
Our Neuquén basin properties have various concession terms that currently end between 2016 and 2034.  Approximately 38% of our undeveloped acreage in our Neuquén basin properties is subject to exploration permits that expire in 2011, although the permits can be extended various times in exchange for relinquishing certain amounts of the acreage and making additional investment commitments.  We expect to extend the terms of our permits. Our properties in the Austral, San Jorge and Northwest basins currently have concession terms which end on dates ranging from 2016 to 2036.  Apco and its operating partners will attempt to secure the ten-year extensions from the respective provinces for all of our Argentine concessions for which such extensions have not yet been negotiated. Our acreage in Colombia is held under exploration and production contracts that expire in 2012 and 2014, unless commercial quantities of hydrocarbons are found, in which case a 24-year exploitation period would be granted.
 
 
Neuquén Basin Properties
 
Since 1968, Apco has participated in a joint venture partnership with two Argentine companies, Petrolera and Petrobras Argentina S.A. (“Petrobras Argentina”), formerly Petrobras Energía S.A. and Pecom Energía S.A. The purpose of the joint venture is the exploration and development of the Entre Lomas oil and gas concession in the provinces of Río Negro and Neuquén in southwest Argentina. In 2007, the partners created two new joint ventures consisting of the same partners with the same interests in order to expand operations into two areas adjacent to Entre Lomas, the Agua Amarga exploration permit in the province of Río Negro, and the Bajada del Palo concession in the province of Neuquén. In 2009, a portion of the Agua Amarga permit was converted to a 25-year exploitation concession called Charco del Palenque.
 
Although these blocks are separate areas governed by their own concession and exploration permit agreements, the areas are operated and managed by Petrolera as an extension of Entre Lomas to achieve efficiencies through economies of scale. Infrastructure in the Entre Lomas concession has sufficient existing capacity to accommodate production volumes from all the areas during the early stages of exploration and development of Bajada del Palo, Agua Amarga and Charco del Palenque. Pipelines can be extended over relatively short distances to connect storage facilities in the new areas to treating, pumping and transportation facilities already in place in the Entre Lomas concession.
 
The partners' interests in the above mentioned joint ventures as of December 31, 2010 are as follows:
 
Petrolera (Operator)
73.15%
Apco
23.00%
Petrobras Argentina
3.85%
 
100.00%



In addition to its direct participation interest, Apco owns an effective 29.85 percent equity interest in the areas through its stock ownership in Petrolera, which holds a 73.15 percent direct interest in each of the properties. Our 23 percent direct participation interest combined with our 29.85 percent equity interest gives Apco an effective 52.85 percent interest in all of the properties operated by Petrolera.
 
Petrolera Entre Lomas S.A.
 
Petrolera is an Argentine company with administrative offices in Buenos Aires and Neuquén and a field office with technical staff located on the Entre Lomas concession.  Petrolera has been a partner in the Entre Lomas joint venture since its inception. As of December 31, 2010, Petrolera had 107 employees.  The shareholders of Petrolera and their ownership percentages are as follows:

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


Investment decisions and strategy for development of the properties are agreed upon by the joint venture partners and implemented by Petrolera. Petrolera has a board of 11 directors, five of whom are nominees of Apco 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.
 
Apco’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.
 
Entre Lomas Concession
 
The Entre Lomas concession is located about 950 miles southwest of the city of Buenos Aires on the eastern slopes of the Andes Mountains. It straddles the provinces of Río Negro and Neuquén approximately 60 miles north of the city of Neuquén. The concession covers a surface area of approximately 183,000 acres and produces oil and gas from seven fields, the largest of which is Charco Bayo/Piedras Blancas (“CB/PB”). The concession is equipped with centralized facilities that serve all productive fields.  These facilities include processing, treating, compression, injection, storage, power generation and an automatic custody transfer unit through which all oil production is transported to market.
 
The most productive formation in the concession is the Tordillo, but we also produce oil and gas from the Quintuco and the Punta Rosada formations (also known as the Petrolifera). The joint venture extracts propane and butane from gas production in its gas processing plant located in the concession. Secondary recovery projects whereby water is injected into the producing reservoirs to restore pressure and increase the ultimate volume of hydrocarbons to be recovered are used extensively in the Entre Lomas concession.
 
The Entre Lomas concession has a primary term of 25 years that expires in the year 2016 with an option to extend for an additional ten-year period based on terms to be agreed with the government.  In 2009, the concession contract for the portion of the Entre Lomas concession located in the Neuquén province was extended to January 2026.  This extension agreement does not apply to the portion of the Entre Lomas concession located in Río Negro. The formal process to negotiate the extension with the provincial government of Río Negro began in 2010, and we expect to finish those negotiations in 2011.



Bajada del Palo Concession
 
The Bajada del Palo concession has a total surface area of approximately 111,000 acres.  It is located in the province of Neuquén immediately to the southwest of the Entre Lomas concession and to the northwest of the Agua Amarga area.  The primary target formations in Bajada del Palo are the same as those that have been developed and produced in Entre Lomas.  In 2009, the Bajada del Palo concession term was extended to September 2025.
 
 
Agua Amarga and Charco del Palenque
 
The Agua Amarga exploration area was awarded to Petrolera by the province of Río Negro in 2007. The property has a total surface area of approximately 95,000 acres and is located immediately to the southeast of the Entre Lomas concession. The terms of the exploration permit include a work commitment for the acquisition of three dimensional (“3D”) seismic information and exploration drilling.  The first exploration period was scheduled to end in May 2010 and was extended for one year until May 2011.  The completion of our work commitments and additional activities executed in the area has enabled us to request an additional one-year extension.  If granted, the first exploration period would end on May 2012.  At the end of the term of the exploration permit, the balance of the acreage that has not been converted to an exploitation concession will be subject to relinquishment, or we can elect to enter another exploration period in exchange for additional work commitments.
 
In 2009, a portion of the Agua Amarga area covering approximately 18,000 acres was converted to an exploitation concession called Charco del Palenque with a 25-year term and a five-year optional extension period.
 
In 2010, we drilled a discovery well on the Jarilla Quemada prospect located on the far eastern portion of the Agua Amarga permit.  This well will require a long-term test to evaluate its natural gas potential from the Tordillo formation.  We will also plan to evaluate its potential from the deeper Molles formation.  The well has been put on production as an oil producer from the Quintuco formation.
 
Neuquén Exploration
 
Apco and its partners make extensive use of 3D seismic information to develop and explore in our Neuquén basin properties.  In addition to aiding in the development of existing producing areas, the seismic surveys have two exploratory objectives. The primary exploratory objective is finding lower risk exploration opportunities that target formations known to be productive from structural closures and/or fault traps that exist away from the principal producing structures. The second objective is to evaluate high-risk, deep exploration potential.
 
Since 2005, on the basis of interpretation of 3D seismic, 17 lower risk wells have been drilled in our three blocks on structural closures or fault traps away from principal producing structures. All wells drilled were oil discoveries and have been completed and put on production. The structures on which these wells have been drilled are limited in size compared with the principal producing fields in Entre Lomas and do not present development opportunities of more than a few wells. The geologic model utilized for identifying fault traps in the southeast region of the Entre Lomas concession has proven to be an excellent predictor of trapped hydrocarbons. The acquisitions of both the Agua Amarga exploration permit and the Bajada del Palo concession were in part based on the interpretation that the trend of faults that have been identified in the southeast region of the Entre Lomas concession continues into both the Agua Amarga and Bajada del Palo areas, and has since resulted in proved reserve additions due to successful exploration and subsequent development drilling.
 


We are drilling development wells on the structures where discoveries were made in the blocks. We will continue drilling these new structures in the foreseeable future and investigating other undrilled structures in this region of our Neuquén basin properties by applying the geologic model that has yielded these successes.
 
In addition to the above described activities, the joint venture partners are in the process of studying and evaluating exploration potential of sedimentary layers deeper than those currently on production in our blocks, including potential for shale production and unconventional natural gas.
 
Shale and Tight Sands in the Neuquén Basin
 
In recent years, oil and gas companies operating in the Neuquén basin have been evaluating the possibility of unconventional sources for hydrocarbon production.  The sub surface formations of interest comprise both shale and what is commonly referred to as “tight sands.”  Apco’s interests in the Neuquén basin include exploitation concessions and exploration permits that are contiguous and comprise up to 245,000 net acres including our interest in Coirón Amargo.  The formations of interest are present in all of the properties in which we participate.  We are conducting technical studies to determine if any unconventional potential exists in our properties.
 
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 needed to comply with ISO 14001: 2004 environmental standards, and OHSAS 18001: 2007 to achieve occupational safety and health standards.  This system encompasses all of the properties that it operates.  Independent party audits are conducted annually to assure that Petrolera’s certifications remain in full force.  Other complementary activities related to environment, safety and health are performed in addition to the standards required by the local governing authorities to improve the system.
 
 
Northwest Basin Properties
 
Acambuco Concession
 
Apco holds a 1.5 percent non-operated interest in the Acambuco concession located in the province of Salta in northwest Argentina on the border with Bolivia. The concession covers an area of 294,000 acres, and is one of the largest gas producing concessions in Argentina. There are two producing fields in this concession, the San Pedrito and Macueta fields, that produce primarily from the Huamampampa formation, which is a deep fractured quartzite with substantial natural gas reserves in this basin and in southern Bolivia. In Acambuco the Huamampampa is found at depths in excess of 14,000 feet. The concession term expires in 2036.
 
Acambuco is situated in an area where drilling is difficult and costly because of the depths of the primary objectives and extreme formation pressures encountered during drilling that significantly increase the risk of mechanical problems during drilling. Wells drilled to the Huamampampa formation in the Acambuco concession have generally required one year to drill with total costs for drilling and completion ranging from $50 to $70 million.
 
The operator of the Acambuco joint venture is Pan American Energy Investments L.L.C. (“PAE”) which holds a 52 percent interest.  The remaining interests are held by three other partners, including a subsidiary of Williams, Northwest Argentina Corporation, which holds a 1.5 percent interest.
 
 
Austral Basin Properties
 
Apco holds a 25.78 percent non-operated interest in a joint venture engaged in E&P activities in three concessions located on the island of Tierra del Fuego. The operator of the concessions is ROCH S.A., a privately owned Argentine oil and gas company.
 
We refer to the Río Cullen, Las Violetas and Angostura concessions as our “TDF concessions.”  These properties are located in the Austral basin which extends both onshore and offshore from the provinces of Santa Cruz to Tierra del Fuego. The principal producing formation is the Springhill sandstone. Several large offshore producing gas condensate fields with significant reserves are productive in the basin, two of which are in close proximity to our concessions.
 
The concessions cover a total surface area of approximately 467,000 gross acres, or 120,000 acres net to Apco. Each of the concessions extends three kilometers offshore with their eastern boundaries paralleling the coastline. The most developed of the three concessions is the Las Violetas concession which is the largest onshore concession on the Argentine side of the island of Tierra del Fuego.  The concessions have terms of 25 years that expire in 2016 with an option to extend the concessions for an additional ten-year period based on terms to be agreed with the government.  In February 2011, the province of Tierra del Fuego commenced concession extension negotiations with producers on the island.
 
Operations in the TDF concessions are exempt from Argentine federal income taxes pursuant to Argentine law. This exemption is in effect until the year 2023.
 
 
San Jorge Basin Properties
 
In the San Jorge basin, our areas are more prospective and exploratory in nature.  In the Sur Río Deseado Este concession in the province of Santa Cruz we have a 16.94 percent working interest in an exploitation area with limited oil production and an 88 percent working interest in an exploratory area in the northern sector of the concession. We sold our interest in the Cañadón Ramirez concession at the end of 2010.
 
 
Colombia - Overview
 
In 2008, a subsidiary of Apco, Apco Properties Ltd., opened a branch in Colombia, Apco Properties Sucursal de Colombia.  We retained a legal representative in Colombia, and began searching for investment opportunities in the country.  During 2009, Apco entered farm-in agreements to obtain significant interests in two exploration and production contracts in the Llanos and Middle Magdalena basins.  In 2010, Apco added a third block through a public bidding process.  Apco now has interests in approximately 374,000 gross acres.
 
Llanos Basin
 
In July 2009, Apco entered into a farm-in agreement to earn a 20 percent interest in the Llanos 32 exploration and production contract (“Llanos 32”).  The Llanos 32 block covers approximately 100,000 acres in the Llanos basin of western Colombia.  Apco agreed to fund approximately $5.8 million - or 27 percent - of exploration activities during a three-year period ending in early 2012 to earn its 20 percent working interest.  The farm-in was approved by the Colombia National Hydrocarbons Agency (the “ANH”) in early 2010.
 
The work commitments associated with Llanos 32 include the acquisition of at least 200 square kilometers of 3D seismic and the drilling of at least two exploration wells.  In 2010 Apco and its partners acquired 260 square kilometers of 3D seismic information.  We expect to commence drilling activities during 2011.
 
In 2010, Apco and Ramshorn International Limited (“Ramshorn”), a subsidiary of Nabors Drilling, were awarded the Llanos 40 block in the 2010 licensing round.  We will hold a 50 percent working interest in the block and Ramshorn will also hold 50 percent and will be the operator.  The block will be governed by an exploration and production contract executed with the ANH.  One of the requirements of the contract is to issue a letter of credit to guarantee the contract’s work commitments.  We anticipate issuing a $5.5 million letter of credit net to Apco in the first quarter of 2011 and collateralizing it with cash.
 
The Llanos 40 block covers approximately 163,000 acres and is approximately 175 kilometers to the northeast of the Llanos 32 block.  Our three-year first phase exploration work commitments will include seismic reprocessing, acquisition of 300 square kilometers, or approximately 74,000 acres, of 3D seismic and drilling of four exploration wells.  We anticipate spending between $15 and $20 million net to Apco for these work commitments over a three-year period.  We expect exploration activities and expenditures to begin in 2011.
 
Middle Magdalena Basin
 
In December 2009, Apco entered into a farm-in agreement with Petrolifera Petroleum (Colombia) Limited to earn a 50 percent working interest in the Turpial Exploration and Production Contract “Turpial."  Petrolifera is the operator.  In January of 2011, Petrolifera announced an agreement to sell its company to Gran Tierra Energy, an established Colombian exploration and production company.  The sale is expected to close in March of 2011.
 
Turpial covers approximately 111,000 acres of underexplored area between the Velazquez and Cocorna oil fields in the Middle Magdalena basin.  Under the farm-in agreement Apco paid $2.6 million and agreed to carry second-phase expenditures up to $1.9 million in order to earn its working interest.
 
The operator acquired Turpial in 2008 agreeing to a six year exploration term.  During the completion of its first-phase obligations, 120 square kilometers of 3D seismic and 37 kilometers of 2D seismic were acquired. The operator elected to enter the second phase and agreed to acquire an additional 114 kilometers of 2D seismic which was completed in 2010.  During 2010, the partners agreed to enter a third phase and committed to drill an exploration well in 2011.  Each additional phase will be at the election of the parties and will require the drilling of one exploration well.  Should the parties declare commerciality, the contract allows for a 24 year exploitation period.
 
 


Oil and Natural Gas Production, Prices and Costs
 
The table below summarizes total sales volumes, prices and production costs per unit for our consolidated interests and sales volumes and prices for our equity interests for the periods presented:
 
   
For the Years Ended December 31,
   
2010
 
2009
 
2008
 
Sales Volumes (1, 2, 3):
                 
Consolidated interests
                 
Crude oil and condensate (bbls)
 
1,338,195
   
1,330,020
   
1,218,896
 
Natural gas (mcf)
 
6,306,883
   
5,849,497
   
4,850,144
 
LPG (tons)
 
9,893
   
10,097
   
8,734
 
Barrels of oil equivalent (boe)
 
2,505,438
55%
 
2,423,425
55%
 
2,129,747
54%
Equity interests
                 
Crude oil and condensate (bbls)
 
1,549,396
   
1,533,828
   
1,417,203
 
Natural gas (mcf)
 
2,325,353
   
1,900,786
   
1,882,529
 
LPG (tons)
 
10,048
   
10,420
   
9,581
 
Barrels of oil equivalent (boe)
 
2,054,864
45%
 
1,972,900
45%
 
1,843,388
46%
Total volumes
                 
Crude oil and condensate (bbls)
 
2,887,591
   
2,863,848
   
2,636,099
 
Natural gas (mcf)
 
8,632,236
   
7,750,283
   
6,732,673
 
LPG (tons)
 
19,941
   
20,517
   
18,315
 
Barrels of oil equivalent (boe)
 
4,560,302
100%
 
4,396,325
100%
 
3,973,134
100%
                   
Total volumes by basin
                 
Neuquén
 
3,641,439
80%
 
3,493,189
80%
 
3,263,878
82%
Austral
 
685,763
15%
 
635,193
14%
 
409,865
10%
Others
 
233,100
5%
 
267,943
6%
 
299,391
8%
Barrels of oil equivalent (boe)
 
4,560,302
100%
 
4,396,325
100%
 
3,973,134
100%
                   
                   
Average Sales Prices:
                 
Consolidated interests
                 
Oil (per bbl)
 
$52.22
   
$43.46
   
$46.09
 
Natural gas (per mcf)
 
1.90
   
1.70
   
1.46
 
LPG (per ton)
 
346.61
   
264.33
   
490.27
 
Equity interests
                 
Oil (per bbl)
 
$52.54
   
$44.04
   
$46.70
 
Natural gas (per mcf)
 
1.75
   
1.52
   
1.35
 
LPG (per ton)
 
358.83
   
273.02
   
468.94
 
                   
Average Production Costs (4) per Boe:
                 
Production and lifting cost
 
$7.71
   
$6.19
   
$7.43
 
Provincial production tax
 
4.04
   
3.52
   
3.73
 
DD&A
 
6.71
   
6.35
   
6.22
 
                   
 
(1)  
Volumes presented in the above table represent those sold to customers and have not been reduced by provincial production tax that is paid separately and is accounted for as an expense by Apco. Our effective tax rate is approximately 12 percent.
(2)  
Natural gas production represents only volumes available for sale.
(3)  
Natural gas is converted to oil-equivalent at six mcf to one barrel, and one ton of LPG is equivalent to 11.735 barrels.
(4)  
Average production and lifting costs, provincial production taxes, and depreciation costs are calculated using total costs divided by consolidated interest sales volumes expressed in barrels of oil equivalent.


Drilling and Other Exploratory and Development Activities
 
The following tables summarize our drilling activity by number and type of well for the periods indicated. We use the terms “gross” to refer to all wells in which we have a working interest and “net consolidated” to refer to our ownership represented by that working interest.  Because of our significant equity interest in our core areas, we also include our share of our equity investee’s net interests.
 
 
   
2010
   
2009
   
2008
 
   
Gross
   
Net
Consolidated
   
Net
Equity
   
Gross
   
Net Consolidated
   
Net
Equity
   
Gross
   
Net
Consolidated
   
Net
Equity
 
                                                       
Development:
                                                     
  Productive
    39.0       9.2       9.3       26.0       6.0       7.8       55.0       13.0       12.8  
  Non-Productive
    3.0       0.7       0.3       0.0       0.0       0.0       6.0       1.5       0.0  
Total
    42.0       9.9       9.6       26.0       6.0       7.8       61.0       14.5       12.8  
                                                                         
Exploratory:
                                                                       
  Productive
    3.0       0.7       0.3       6.0       1.4       1.8       7.0       1.6       1.8  
  Non-Productive
    0.0       0.0       0.0       0.0       0.0       0.0       4.0       1.1       0.0  
Total
    3.0       0.7       0.3       6.0       1.4       1.8       11.0       2.7       1.8  
                                                                         
Total:
                                                                       
  Productive
    42.0       9.9       9.6       32.0       7.4       9.6       62.0       14.6       14.6  
  Non-Productive
    3.0       0.7       0.3       0.0       0.0       0.0       10.0       2.6       0.0  
Total
    45.0       10.6       9.9       32.0       7.4       9.6       72.0       17.2       14.6  
 
Present Activities
 
At December 31, 2010, we had five gross development wells and one exploration well (1.4 net consolidated 1.8 net equity) in various stages of drilling or completion. 
 
Delivery Commitments
 
We hold obligations to deliver certain amounts of natural gas. Our properties contain sufficient reserves to fulfill these obligations without risk of non-performance during periods of normal infrastructure and market operations.  These transactions do not represent a material exposure.
 
 
 


Government Regulations
 
The Company’s operations in Argentina are subject to various laws, taxes and regulations governing the oil and gas industry. Taxes generally include income taxes, value added taxes, export taxes, and other production taxes such as provincial production taxes and turnover taxes. Labor laws and provincial environmental regulations are also in place.
 
Our right to conduct E&P activities in Argentina is derived from participation in concessions and exploration permits granted by the Argentine federal government and provincial governments that control sub-surface minerals.  In general, provincial governments have had full jurisdiction over concession contracts since early 2007, when the Argentine federal government transferred to the provincial governments full ownership and administration rights over all hydrocarbon deposits located within the respective territories of the provinces, including all exploration permits and exploitation concessions originally granted by the federal government.
 
A concession granted by the government gives the concession holders, or the joint venture partners, ownership of hydrocarbons at the moment they are produced through the wellhead. Under this arrangement, the concession holders have the right to freely sell produced hydrocarbons, and have authority over operations including exploration and development plans. Concessions generally have a term of 25 years which can be extended for 10 years based on terms to be agreed with the government. Throughout the term of their concessions, the partners are subject to provincial production taxes, turnover taxes, and federal income taxes. These tax rates are fixed by law and are currently 12 to 18.5 percent, two percent, and 35 percent, respectively. Subsequent to the transfer of ownership and administrative rights over hydrocarbon deposits to the provinces, provincial governments have sometimes required higher provincial production tax rates or a net profit interest in blocks awarded by the provinces or in concessions that have been granted the 10-year extension.
 
In Colombia, our right to conduct E&P activities is derived from participation in exploration and production contracts entered into directly with the Colombian National Hydrocarbons Agency (the “ANH”) with no mandatory participation by Ecopetrol, the state oil company.  The ANH was formed in 2003 in response to declining reserves which was leading Colombia toward becoming a net oil importer.
 
Exploration and production contracts in Colombia typically run for an initial exploration period of up to six years.  The first phase of work usually requires acquisition of new seismic data.  After the first phase, contracts can be retained for up to five additional years, usually by drilling one well per year.  An exploration and production contract can be relinquished after any completed phase at the option of the investor.
 
Once a field is declared commercial, the exploitation period is 24 years, which may be extended another 10 years under certain circumstances.  The investor retains the rights to all reserves and production from newly discovered fields, subject to a sliding scale of royalty, which is initially eight percent for production up to 5,000 barrels of oil per day “bopd” per field up to a maximum of 25 percent for production exceeding 600,000 bopd per field.  In addition, a windfall profit tax applies once a field has cumulatively produced more than five million barrels of oil.  The windfall profits tax is 30 percent of the price per barrel received in excess of certain threshold prices which are periodically set by the ANH and are established by the quality of the oil produced.
 
 


MARKETING
 
Oil Markets
 
Crude oil produced in the Entre Lomas region of the Neuquén basin is referred to as Medanito crude oil, a high quality oil generally in strong demand among Argentine refiners for subsequent distribution in the domestic market. During 2010, all of the oil produced in our Neuquén basin properties was sold to Argentine refiners. Production from our Neuquén basin properties is transported to Puerto Rosales, a major industrial port in southern Buenos Aires Province through the Oleoductos del Valle S.A. (“Oldelval”) pipeline system.
 
In previous years, we exported our oil and condensate production from the TDF concessions to Chile. After the Argentine government levied an export tax on hydrocarbon exports from the island of Tierra del Fuego in early 2007, we began to sell our oil production to domestic refiners in Argentina.
 
The Argentine domestic refining market is limited, and basically consists of five active refiners. As a result, our oil sales have historically depended on a relatively limited group of customers. The largest of these five companies refines mostly its own crude oil production, while the smallest of the five operates only in the northwest basin of Argentina near our Acambuco concession. Decisions to sell to any of the remaining three refiners are based on advantages presented by the commercial terms negotiated with each customer.
 
A description of our major customers over the last three years is in Note 5 of Notes to Consolidated Financial Statements.  As can be seen in Note 5, Petrobras Argentina has been a major customer of us over the past several years.  However, although our oil sales have historically depended on a relatively limited group of customers, we do not believe that the loss of Petrobras Argentina as a customer would have a material adverse effect on the Company.  As previously discussed, crude oil produced in the Entre Lomas region of the Neuquén basin, referred to as Medanito crude oil, is a high quality oil generally in strong demand among Argentine refiners.  Our crude oil production can be marketed to other refiners or exported, but we have sold a significant amount of our production to Petrobras Argentina over the past several years as we have been able to negotiate competitive prices with that particular customer.
 
For a full discussion about our oil sales prices, please read the information under the caption “Overview of 2010 – Oil and Natural Gas Marketing” in the Management’s Discussion and Analysis (MD&A) section of this report.  Additional discussion about the reduced net backs is included in Item 1A. “Risk Factors – Risks Associated with Operations in Argentina,” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk.”
 
Natural Gas Markets
 
Natural gas markets in Argentina are heavily regulated by the Argentine government. In general, the government sets the volumes producers are required to sell to residential customers at low government-regulated prices. Incremental volumes are sold to industrial and other customers, and pricing varies with seasonal factors and industry category. Apco sells its natural gas to Argentine customers pursuant to short-term contracts and in the spot market.
 
The Neuquén basin is served by a substantial gas pipeline network that delivers gas to the Buenos Aires metropolitan and surrounding areas, and the industrial regions of Bahia Blanca and Rosario. Natural gas produced in our Neuquén basin properties is readily marketed due to accessibility to this infrastructure and our properties are well situated in the basin with two major pipelines in close proximity. Natural gas produced in this basin that is not under contract can readily be sold in the spot market.
 


Natural gas and condensate produced in Acambuco is being sold primarily to domestic distribution companies and industrial customers in the northern part of Argentina under contracts negotiated by the operator of the concession.
 
Natural gas production from the TDF concessions has been primarily sold under contract to 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. In 2008, our joint venture’s production facilities were connected directly to the San Martín pipeline, giving us a physical outlet for transportation of gas from the island of Tierra del Fuego to continental Argentina, where higher prices are being realized.
 
Natural gas is a needed commodity in Argentina. The country’s energy consumption is highly reliant on natural gas as a source of fuel. With a highly sophisticated natural gas infrastructure in place to deliver natural gas to both industrial and residential markets, the country ranks near the top in the world in terms of percentage of natural gas as a source of energy.  Heavy government regulation over gas prices since 2002 have kept natural gas prices artificially low and as a result, exploration efforts in Argentina targeting natural gas slowed dramatically during this period. Consequently, natural gas reserves in the country have fallen significantly and exploration discoveries and development of existing fields have not added sufficient reserves to replace production.
 
Argentina currently suffers from a shortage of natural gas and has to import natural gas from neighboring Bolivia and import high-priced LNG while Argentine producers are supplying domestic consumers with domestic production at prices significantly below those paid for imported natural gas. Subsidizing these high priced imports is a significant drain on the government’s finances. Hence, natural gas production in Argentina can readily be marketed either by contract or on the spot market because it is a highly a sought after commodity both for residential use and to drive industry and the country’s economy.  For further discussion of natural gas prices and the Argentine government’s regulation of the supply of natural gas in the domestic market in Argentina, please see the information under the caption “Overview of 2010 – Oil and Natural Gas Marketing” in the MD&A section of this report.
 
EMPLOYEES
 
At March 2, 2011, the Company had ­­22 full-time employees.
 
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
 
The Company is a Cayman Islands company with executive offices located in Tulsa, Oklahoma, a branch office located in Buenos Aires, Argentina and a branch office in Bogota, Colombia.  All of the Company’s production and reserves are currently generated in Argentina.
 
The Company presently has no operating revenues in either the Cayman Islands or the United States.  Because all of the Company’s operating revenues are generated in Argentina, all of its products are sold either domestically in Argentina, or exported from Argentina to neighboring countries.  Refer to Note 5 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 the exception of cash and cash equivalents deposited in banks in the Cayman Islands and the Bahamas, a bank account in Tulsa, Oklahoma and furniture and equipment in its executive offices, all of the Company’s productive assets are located in Argentina and Colombia.
 
Risks associated with foreign operations are discussed elsewhere in this Item 1, Item 1A “Risk Factors” and in Item 7A “Quantitative and Qualitative Disclosures about Market Risk.”


WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
 
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and other documents electronically with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934, as amended (“Exchange Act”).  You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  You may also obtain such reports from the SEC’s Internet website at http://www.sec.gov.
 
Our Internet website is http://www.apcooilandgas.com. We make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Code of Ethics and Board committee charters are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to the Corporate Secretary, Apco Oil and Gas International Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172.



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 forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
 
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,”could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,”might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
 
·  
Amounts and nature of future capital expenditures;
 
·  
Volumes of future oil, gas and LPG production;
 
·  
Expansion and growth of our business and operations;
 
·  
Financial condition and liquidity;
 
·  
Business strategy;
 
·  
Estimates of proved oil and gas reserves;
 
·  
Reserve potential;
 
·  
Development drilling potential;
 
·  
Cash flow from operations or results of operations;
 
·  
Seasonality of natural gas demand; and
 
·  
Oil and natural gas prices and demand for those products.
 
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
 
 
·  
Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;
 
 
·  
Inflation, interest rates, fluctuation in foreign currency exchange rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
 
·  
The strength and financial resources of our competitors;
 
·  
Development of alternative energy sources;
 
·  
The impact of operational and development hazards;
 
·  
Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities and litigation;
 
·  
Political conditions in Argentina, Colombia and other parts of the world;
 
·  
The failure to renew participation in hydrocarbon concessions granted by the Argentine government on reasonable terms;
 
·  
Risks related to strategy and financing, including restrictions stemming from our proposed loan agreement and the availability and cost of credit;
 
·  
Risks associated with future weather conditions, volcanic activity and earthquakes;
 
·  
Acts of terrorism; and
 
·  
Additional risks described in our filings with the SEC.
 
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
 
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
 
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements.  These factors are described in the following section.



RISK FACTORS
 
You should carefully consider the following risk factors in addition to the other information in this report.  Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.
 
Risks Inherent to the Company’s Industry and Business
 
Significant capital expenditures are required to replace our reserves.
 
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and cash on hand. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access bank debt, issue debt or equity securities or access other methods of financing on an economic basis to meet our capital expenditure budget.  As a result, our capital expenditure plans may have to be adjusted.
 
 
Failure to replace reserves may negatively affect our business.
 
The growth of our business depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.  Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both.  We may not be able to find, develop or acquire additional reserves on an economical basis.  If oil or natural gas prices increase, our costs for additional reserves would also increase, conversely if oil or natural gas prices decrease, it could make it more difficult to fund the replacement of our reserves.
 
 
Exploration and development drilling may not result in commercially productive reserves.
 
Our past success rate for drilling projects should not be considered a predictor of future commercial success.  We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in those wells.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
 
·  
Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, skilled labor, capital or transportation;
 
·  
Unexpected drilling conditions or problems;
 
·  
Regulations and regulatory approvals;
 
·  
Changes or anticipated changes in energy prices; and
 
·  
Compliance with environmental and other governmental requirements.
 


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

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions, but should not be considered as a guarantee of results for future drilling projects.
 
The process relies on interpretations of available geological, geophysical, engineering and production data.  There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this report represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.
 
Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and natural gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.
 
If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. These revisions, as well as revisions in the assumption of future cash flows of these reserves, may also be sufficient to trigger impairment losses on certain properties which would result in a non-cash charge to earnings. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves.
 
Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.
 
Our operations are subject to all the risks and hazards typically associated with the development and exploration for, and the production and transportation of oil and natural gas.  These operating risks include, but are not limited to:
 
·  
Earthquakes, volcanic activity, floods, fires, extreme weather conditions, and other natural disasters;
 
·  
Aging infrastructure and mechanical problems;
 
·  
Damages to pipelines and pipeline blockages;
 
·  
Fires, blowouts, cratering, and explosions;
 
·  
Uncontrolled releases of oil, natural gas, or well fluids;
 
·  
Formations with abnormal pressures;
 
·  
Operator error;
 
·  
Damage inadvertently caused by third-party activity, such as operation of construction equipment;
 
·  
Pollution and other environmental risks;
 
·  
Risks related to truck loading and unloading; and


·  
Terrorist attacks or threatened attacks on our facilities or those of other energy companies.
 
 
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In spite of our precautions, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
 
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
 
We are not fully insured against all risks inherent to our business, including environmental accidents. The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows.  We also may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.  In addition, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims.  As a result, we could be exposed to greater losses than anticipated.
 
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities and could exceed current expectations.
 
Our operations are subject to environmental regulation pursuant to a variety of laws and regulations.  Such laws and regulations impose, among other things, restrictions, liabilities, and obligations in connection with the generation, handling, use, storage, extraction, transportation, treatment, and disposal of hazardous substances and wastes in connection with spills, releases, and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment, and reclamation of our facilities.
 
Compliance with environmental legislation could require significant expenditures including for clean up costs and damages arising out of contaminated properties.  In addition, the possible failure to comply with environmental legislation and regulations might result in the imposition of fines and penalties. Subject to any rights to indemnification, we are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against environmental liabilities that could expose us to material losses, which may not be covered by insurance.  In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.  Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no assurance can be given that the costs of complying with environmental laws in the future will not have such an effect. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.
 
Legislative and regulatory responses related to greenhouse gases (“GHG”) and climate change creates the potential for financial risk. Governing bodies have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more laws and regulations to reduce or mitigate GHG emissions.


 
While it is not clear whether or when any climate change laws or regulations will be passed, any of these actions could result in increased costs to (i) operate and maintain our facilities and (ii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and cash flows. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.
 
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations.  If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change.  If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our operations.
 
Drilling for oil and gas is an inherently risky business.
 
Drilling for oil and gas is inherently risky because we make assessments of where hydrocarbon reservoirs exist at considerable depths in the subsurface based on interpretation of geophysical, geological and engineering information and data without the benefit of physical contact with the accumulations of trapped oil and gas we believe can be produced. Finding and producing oil and gas requires the existence of a combination of geologic conditions in the subsurface that include the following: hydrocarbons must have been generated in a sedimentary basin, they must have migrated from the source into the subsurface area of interest, tectonic conditions in the area of interest must have created a trap required for the storage and accumulation of migrating hydrocarbons, and the sedimentary layer in which the hydrocarbons could be stored must have sufficient porosity and permeability to allow the flow of oil and gas into the drilled well bore.
 
Our oil sales have historically depended on a relatively limited group of customers.  The lack of competition for buyers could result in unfavorable sales terms which, in turn, could adversely affect our financial results.
 
The Argentine domestic refining market is limited.  There are five active refiners that constitute 99 percent of the total market.  As a result, our oil sales have historically depended on a relatively limited group of customers.  The largest of these five companies refines mostly its own crude oil production, while the smallest of the five operates only in the northwest basin of Argentina.  The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect our financial results.
 
Competition in the markets in which we operate may adversely affect our results of operations.
 
We have numerous competitors in our businesses, and additional competitors may enter our markets. Other companies with which we compete may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their assets than we can. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make investments or acquisitions. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our businesses and results of operations.
 
 
 
We are not the operator of all our hydrocarbon interests.  Our reliance on others to operate these interests could adversely affect our business and operating results.
 
We generally have non-operating interests in our properties and therefore we rely on other companies to operate our properties in Argentina and Colombia.  As the non-operating partner, we have limited ability to control operations or the associated costs of such operations.  The success of those operations is therefore dependent on a number of factors outside our control, including the competence and financial resources of the operators.
 
Changes in, and volatility of, supply, demand, and prices for crude oil, natural gas and other hydrocarbons have a significant impact on our ability to generate earnings, fund capital requirements, and pay shareholder dividends.
 
Our revenues, operating results, future rate of growth and the value of our business depends primarily upon the prices we receive for crude oil, natural gas or other hydrocarbons.  Price volatility can impact both the amount we receive for our products and the volume of products we sell.  Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.
 
The markets for crude oil, natural gas, and other hydrocarbon commodities are likely to continue to be volatile.  Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty, and other factors that are beyond our control, including:
 
·  
Argentine and Colombian governmental actions;
 
·  
Supplies of and demand for electricity, natural gas, petroleum, and related commodities;
 
·  
Exploration discoveries throughout the world;
 
·  
The level of development investment in the oil and gas industry;
 
·  
Turmoil in the Middle East and other producing regions;
 
·  
Terrorist attacks on production or transportation assets;
 
·  
Weather conditions;
 
·  
Strikes, work stoppages, or protests;
 
·  
The price and availability of other types of fuels;
 
·  
The availability of pipeline capacity;
 
·  
Supply disruptions and transportation disruptions;
 
·  
Governmental regulations and taxes;
 
·  
The overall economic environment;
 
·  
The credit of participants in the markets where hydrocarbon products are bought and sold; and
 
·  
The adoption of regulations or legislation relating to climate change.


Future disruptions in the global credit markets may make equity and debt markets less accessible, create a shortage in the availability of credit, and lead to credit market volatility which could limit our ability to grow.
 
In 2008, public equity markets experienced significant declines and global credit markets experienced a shortage in overall liquidity, resulting in a disruption in the availability of credit. Future disruptions in the global financial marketplace, including the bankruptcy or restructuring of financial institutions, may make equity and debt markets inaccessible, and the availability and cost of credit could increase in the future. Although we have historically funded capital programs and past property acquisitions with our internally generated cash flow, these developments could impair our ability to make acquisitions, finance growth projects, or proceed with capital expenditures as planned.
 
Oil and gas investments are inherently risky and there is no guarantee that the fiscal conditions that existed at the time of investment will not be changed by the host country.
 
Oil and gas investments are attractive when stable fiscal conditions exist over the productive life of an investment.  There is no guarantee that the fiscal conditions that existed at the time of investment will not be changed by the host country, thereby lowering the future economic return that was anticipated when the decision to invest was made.
 
The vast amount of international oil and gas reserves are controlled by national oil companies and access to oil and gas reserves and resource potential is limited.
 
Access to oil and gas reserves and resource potential is becoming more limited over time. Known producing oil and gas reserves under production in developed countries are declining thereby increasing the concentration of oil and gas reserves and resource potential in undeveloped countries that reserve the right to explore and develop such reserves for their national oil companies. This restricts investment opportunities for international oil and gas companies and makes it more difficult to find international oil and gas investment opportunities with economic terms that are attractive.
 
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
 
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures and companies’ relationships with their independent registered public accounting firms. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have.  In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity.  Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations and financial condition.
 
Risks Associated with Operations in Argentina and Colombia
 
Our right to explore for, drill for, and produce hydrocarbons is generally derived from participation in concessions and/or exploration and production contracts granted by the governments where we do business, which have a finite term, the expiration or termination of which could materially affect our results.
 
Our right to explore for, drill for, and produce hydrocarbons is generally derived from participation in concessions or exploration and production contracts granted by the governments where we do business. These agreements have finite terms, the expiration or termination of which could materially affect our results.  In Argentina, the terms of the portion of the Entre Lomas concession located in Río Negro province and our three TDF concessions expire in 2016. The term of a concession can be extended for 10 years based on the consent of and terms to be agreed with the government.  However, the government may withhold its consent, or could extend the term of the concession on terms less favorable than those we have today. Refer to the section “Concession Contracts in Argentina” in MD&A for additional discussion about concession extensions.

 
 
Argentina has a history of economic instability.  Because our operations are predominately located in Argentina, our operations and financial results have been, and could be in the future, adversely affected by economic, market, currency, and political instability in Argentina as well as measures taken by its government in response to such instability.
 
Please read “Quantitative and Qualitative Disclosures about Market Risk – Argentine Economic and Political Environment” for a description of Argentina’s economic crisis of 2002 and the government’s reaction to that crisis.  Some of those actions had an adverse effect on our results.
 
Argentina’s economic and political situation continues to evolve, and the Argentine government may enact future regulations or policies that may materially impact, among other items, (i) the realized prices we receive for the commodities we produce and sell as a result of new taxes; (ii) the timing of repatriations of cash to the Cayman Islands; (iii) our asset valuations; and (iv) peso-denominated monetary assets and liabilities.
 
Strikes, work stoppages, and protests could increase our operating costs, hinder operations, reduce cash flow, and delay growth projects.
 
Strikes, work stoppages, and protests could arise from the delicate political and economic situation in Argentina and these actions could increase our operating costs, hinder operations, reduce cash flow, and delay growth projects.
 
Oil sales price realizations for oil produced and sold in Argentina are significantly influenced by Argentine governmental actions. Consequently, sharp increases in oil prices benefit oil producers outside of Argentina more than us.
 
Historically, the price per barrel for Argentine crude oil was based on the spot market price of West Texas Intermediate crude oil (“WTI”) less a discount for differences in gravity and quality. In the wake of the Argentine economic crises of 2002, and as the price of crude oil increased to record levels over the past several years, politically driven mechanisms were implemented to determine the sale price of oil produced and sold in Argentina. To alleviate the impact of higher crude oil prices on their economy, the Argentine government created an oil export tax and enacted strict price controls on gasoline prices to force producers and refiners to negotiate oil sales prices significantly below international market levels.  For further discussion about oil prices, please read the section “Overview of 2010 – Oil and Natural Gas Marketing” in MD&A.
 
The Argentine government enforces strict price controls over the sale of natural gas.
 
The government of Argentina enforces strict price controls over the sale of natural gas in the country. These price controls are more strict when gas is destined for residential consumption or to power generators known to primarily serve residential customers. Price controls are less strict for sales to industrial customers and in certain cases can be freely negotiable with industrial customers. As a result, natural gas prices for gas sold in Argentina have, since 2002, been significantly below natural gas price levels in neighboring countries, or below natural gas prices paid by the Argentine government to import natural gas from neighboring countries or for imported LNG. Regulations in Argentina enable the government, under certain conditions, to nominate a producer’s natural gas for residential sales during peak demand seasons requiring a producer to sell gas at prices below $1.00 per mcf. Apco and Petrolera, our equity investee, are required to sell natural gas under these conditions.



Insurgency activity in Colombia could disrupt or delay our operations.
 
A 40-year armed conflict between the Colombian government and armed anti-government insurgent groups and illegal paramilitary groups is ongoing in Colombia.  Insurgents continue to attack civilians and violent guerilla activity continues in many parts of the country.
 
We have acquired interests in the Middle Magdalena and Llanos basins in Colombia. While neither of the basins is located near the Colombian borders with Ecuador and Venezuela which have been more prone to recent guerilla activity, the ability of the Colombian government to maintain security in the areas where we have operations may not be successful and guerilla related violence could affect our operations in the future, resulting in losses or interruptions of our activities.
 
Risks Related to the Control Exercised by Williams that Affect Our Business and Corporate Governance.
 
Williams effectively controls the outcome of actions requiring the approval of our shareholders and there is a risk that Williams’ interests will not be consistent with the interests of our other shareholders.
 
Williams beneficially owns approximately 68.96 percent of our outstanding ordinary shares.  In addition, our executive officers are employees of Williams and three of our seven directors are employees of Williams.   Therefore, Williams (a) has the ability to exert substantial influence and actual control over our management policies and affairs, such as our business strategy, purchase or sale of assets, financing, business combinations, and other company transactions, (b) controls the outcome of any matter submitted to our shareholders, including amendments to our memorandum of association and articles of association, and (c) has the ability to elect or remove all of our directors.  There is a risk that the interests of Williams and its other affiliates will not be consistent with the interests of our other shareholders.  In general, our shareholders do not have an obligation to consider the interests of other shareholders when voting their shares.
 
Additionally, Williams and its other affiliates could make it more difficult for us to raise capital by selling shares or for us to use our shares in connection with acquisitions or other business arrangements. Williams could also adversely affect the market price of our shares by selling its shares.  This concentrated ownership also might delay or prevent a change in control and may impede or prevent transactions in which shareholders might otherwise receive a premium for their shares.
 
Our proposed credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit and affect our ability to operate our business.
 
Our proposed credit facility contains certain covenants that would restrict or limit our ability and our subsidiaries’ ability to grant liens to support indebtedness,  merge or sell substantially all of our assets,  or make any material change in the nature of our business. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.
 
Williams’ public indentures contain covenants that restrict Williams’ and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.



Our failure to comply with the covenants in our proposed credit facility could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under our facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. If an event of default occurs, and the lenders under our proposed credit agreement accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. For more information regarding our proposed credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
 
Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends and distributions paid to it by its subsidiaries. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as loans or contributions to capital. Due to our relationship with Williams, our ability to obtain credit could  be affected by Williams’ credit standing or financial condition.
 
Because we are a “controlled company” as defined by the rules of The Nasdaq Stock Market, we are not required to comply with certain corporate governance requirements that would otherwise be applicable  if we were not a controlled company.
 
We are a “controlled company” as defined by the rules of The Nasdaq Stock Market because Williams indirectly owns approximately 69 percent of our ordinary shares. Therefore, we are not subject to the requirements of The Nasdaq Stock Market that would otherwise require us to have (a) a majority of independent directors on the Board of Directors, (b) the compensation of executive officers determined by a majority of independent directors or a compensation committee composed solely of independent directors, and (c) a majority of the independent directors or a nominating committee composed solely of independent directors elect or recommend director nominees for selection by the Board of Directors.
 
Our Board of Directors does not have a compensation committee or any other committees performing similar functions.  Compensation decisions for our executive officers are made by Williams and compensation decisions affecting our directors who are not employees of Williams are made by our Board of Directors.  Please read “Executive Compensation” and “Certain Relationships and Related Transactions, and Director Independence — Transactions with Related Persons — Administrative Services Agreement.”
 
Williams and its affiliates may have conflicts of interest with us and they may favor their own interests to the detriment of our other shareholders.  In addition, our executive officers and some of our directors are also officers and/or directors of Williams and/or its other affiliates, and these persons also owe fiduciary duties to those entities.
 
Williams and its affiliates may have conflicts of interest with us and they may favor their own interests to the detriment of our other shareholders.  In general, our shareholders, including Williams, do not have an obligation to consider the interest of other shareholders when voting their shares.
 
Williams could engage in businesses that directly or indirectly compete with us without any obligation to offer us those opportunities.  In addition, although our officers and directors have an obligation to act in our best interest, our executive officers and some of our directors are also officers and/or directors of Williams and/or its other affiliates, and these persons also owe fiduciary duties to those entities.  For example, our Chief Executive Officer and the Chairman of our Board of Directors is also an executive officer of Williams.  We also have business relationships with Williams, including an administrative services agreement pursuant to which Williams provides us with certain administrative and management services.   Please read “Certain Relationships and Related Party Transactions, and Director Independence — Transactions with Related Persons and — Review, Approval or Ratification of Transactions with Related Persons.”



Our executive officers and certain other persons who provide services to us at our headquarters office are employees of Williams, and we rely on Williams to provide us with certain administrative services.  The loss of any of these persons or administrative services could have a materially adverse effect on our business and results of operations.
 
Our executive officers and certain other persons who provide services to us pursuant to an administrative services agreement are employees of Williams.  Any service provided under the agreement may be terminated by either us or Williams upon 60 days prior written notice.  The loss of any of our key executive officers or other management personnel could have a material adverse effect on our business unless and until we find a qualified replacement.  A limited number of persons exist with the requisite experience and skills to serve in our senior management positions and competition for the services of such persons is intense.  We may not be able to locate or employ qualified executives or other key employees at a cost competitive with the amounts paid to Williams for the services of these persons.
 
Williams also provides certain other services to us, such as risk management, internal audit services, and at our headquarters office in Tulsa, Oklahoma, provides office supplies, office space, and computer support pursuant to the administrative services agreement.  Please read “Certain Relationships and Related Party Transactions, and Director Independence — Transactions with Related Persons — Administrative Services Agreement.”  If Williams did not provide these services, we would be required to provide these services ourselves or to obtain substitute arrangements with third parties.  Our cost to replace such services may be significantly higher than the cost we currently pay.  In addition, the failure to replace these services in a timely and effective fashion could have a material adverse effect on our business, including our ability to comply with our financial reporting requirements and other rules that apply to public companies.
 
Risks Related to Williams’ Separation Plan
 
If Williams completes its previously announced plan to spin-off its exploration and production businesses, which includes its share ownership in us, we will then be controlled by a newly formed entity without the history or resources of Williams.
 
Williams has announced a plan to separate its exploration and production assets (including its approximately 69% share ownership in us) into a separate entity.  This newly formed entity is then expected to conduct an initial public offering of a portion of its common stock, to be followed according to Williams’ plan by a tax-free spin-off of Williams’ remaining ownership interest in the separate entity to Williams’ stockholders.  Williams has stated that it expects the spin-off to occur in 2012, though it has the discretion to determine whether and when to execute the spin-off.  At the conclusion of these proposed transactions, we will no longer be controlled by Williams or utilize the operating experience and other resources of Williams, which could negatively impact our ability to operate and the costs of our operations, all of which could negatively impact our results of operations.  In addition, we anticipate that following the spin-off, Williams will no longer provide us with the services it currently provides to us under an administrative services agreement, such as management, risk management, internal audit services, and domestic office space and computer support.  Our cost to replace such support may be significantly higher than the cost we currently pay to Williams.
 
 
Risks Related to Regulations that Affect Our Business
 
The cost and outcome of legal and administrative claims and proceedings against us and our subsidiaries could adversely affect our results and operations.
 
We are a 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.”  We anticipate 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 us.  In addition, the cost and outcome of any future legal or administrative claims could adversely affect us.


Our operations require us to comply with certain United States and international regulations, violations of which could have a material adverse effect on our consolidated results of operations and consolidated financial condition.
 
Our operations require us to comply with certain United States and international regulations, including the Foreign Corrupt Practices Act (FCPA). Our activities include the risk that unauthorized payments or offers of payments may be made by one of our employees, agents, or joint venture partners that could be in violation of the FCPA, even though these parties are not always subject to our control.  We have internal control policies and procedures and have implemented training and compliance programs with respect to the FCPA.  However, we cannot assure that our policies, procedures and programs will always protect us from reckless or criminal acts.  Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.  We are also subject to the risks that our employees, joint venture partners, and agents may fail to comply with other applicable laws.
 
Changes in the laws and regulations of the countries where we do business, including tax, environmental and employment laws, and regulations, could have a material effect on financial condition and results of operations.
 
We are subject to numerous laws and regulations in Argentina and Colombia, which, among others, include those related to taxation, environmental regulations, and employment.  We are also subject to certain laws of the United States.  Regulation of certain aspects of our business that are currently unregulated in the future and changes in the laws or regulations could materially affect our financial condition and results of operations.
 
Possible changes in tax laws could affect us and our shareholders.
 
Tax laws and regulations are highly complex and subject to interpretation, and the tax laws, treaties and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various countries at the time that the filings were made. If these laws, treaties or regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws, treaties and regulations, it could have a material adverse effect on us.  In addition, the manner in which our shareholders are taxed on distributions in connection with our shares could be affected by changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the jurisdictions in which our shareholders reside. Any of the foregoing changes could affect the trading price of our shares.
 
 
Risks Related to Employees
 
Institutional knowledge residing with current employees might not be adequately preserved.
 
Certain of our employees who have many years of service have extensive institutional knowledge.  As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience.  In addition, we may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate.  If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.



Risks Related to Weather, other Natural Phenomena, and Business Disruption
 
Our assets and operations can be adversely affected by weather and other natural phenomena.
 
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, volcanoes, and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance has not been available at all.  A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.
 
In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change.  To the extent weather conditions are affected by climate change or demand is impacted by laws or regulations associated with climate change, energy use could increase or decrease depending on the duration and magnitude of the changes, leading to either increased investment or decreased revenues.
 
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
 
Our assets and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport or distribute oil, natural gas or other commodities. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.
 
Risks Related to Dividends and Distributions
 
Our articles of association provide that the Company may pay dividends or make distributions out of our profits, the share premium account, or as otherwise permitted by law.
 
In the event we have no profits for a given period and have accumulated deficits, we can make dividend or other distributions to our shareholders from the share premium account, which is similar to the paid in capital account under U.S. GAAP, as long as the distributions do not render us insolvent.  If we elect to pay dividends at times when we do not otherwise have current profits or accumulated earnings and profits, such dividends could have a material adverse effect on our financial condition.
 
ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 3.   LEGAL PROCEEDINGS
 
The 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.
 



PART II
 
 
ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Market information, Number of Shareholders and Dividends
 
Our ordinary shares are traded sporadically on The NASDAQ Capital Market under the symbol “APAGF.”  At the close of business on March 1, 2011, there were 29,441,240 of the Company’s ordinary shares, $0.01 par value, outstanding, held by approximately 2,335 holders, including ordinary shares held of record and in street name.
 
Our articles of association allow us to pay dividends or distributions out of our profits, our share premium account, or as otherwise permitted by law.
 
The high and low trade closing sales price ranges and dividends declared by quarter for each of the past two years are as follows:
 
 
2010
2009
Quarter
High
Low
Dividend
High
Low
Dividend
1st
$27.06
$18.88
$.0200
$27.28
$6.39
$.0200
2nd
$30.00
$21.95
$.0200
$20.40
$9.91
$.0200
3rd
$34.61
$21.86
$.0200
$27.25
$16.47
$.0200
4th
$58.79
$35.86
$.0200
$26.00
$20.05
$.0200
 
 
The quarterly dividends declared for the ordinary shares were $.02 per share during each of the four quarters of 2010, or $.08 for the year. The current quarterly dividend remains at $.02 cents per share.  Future dividends are necessarily dependent upon numerous factors, including, among others, earnings, levels of capital spending, funds required for acquisitions, changes in governmental regulations and changes in crude oil and natural gas prices.  The Company reserves the right to change the level of dividend payments or to discontinue or suspend such payments at the discretion of the Board of Directors.
 
The Company has been advised that: we may pay dividends to shareholders only out of its realized or unrealized profits, share premium account or otherwise as permitted by the laws of the Cayman Islands; there are no current applicable Cayman Islands laws, decrees or regulations relating to restrictions on the import or export of capital or exchange controls affecting remittances of dividends, interest and other payments to non-resident holders of the our ordinary shares; there are no limitations either under the laws of the Cayman Islands or under our memorandum or articles of association restricting the right of foreigners to hold or vote our 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 our 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 our cumulative total shareholder return on our ordinary shares with the cumulative total return of The NASDAQ US and Foreign Securities Index and the NASDAQ US and Foreign Oil & Gas Extraction Index (SIC 1300-1399) for a five-year period commencing December 31, 2005. We will provide shareholders a list of the component companies included in the NASDAQ US and Foreign Oil & Gas Extraction Index upon request.
 
 



ITEM 6.      SELECTED FINANCIAL DATA
 
The following financial data at December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, should be read in conjunction with Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. The following financial data at December 31, 2007 and 2006, and for the years ended December 31, 2007 and 2006, has been prepared from our previous filings on Form 10-K.
 
(Amounts in thousands except per share amounts)
                     
                       
As of and for the years ended December 31,
 
2010
 
2009
 
2008
 
2007
 
2006
 
                       
Results of Operations
                     
                       
Revenues
  $ 87,815   $ 72,716   $ 69,116   $ 62,506   $ 57,952  
Equity income from Argentine investment
  16,158   14,143   16,375   17,403   22,391  
Net income
  25,834   23,527   23,825   31,385   40,108  
Amounts attributable to Apco:
                     
   Net income
  25,800   23,497   23,793   31,349   40,062  
   Income per ordinary share (a)
  0.88   0.80   0.81   1.06   1.36  
   Dividends declared per ordinary share (a)
  0.08   0.08   0.35   0.35   0.325  
                       
Financial Position
                     
                       
Total assets
  248,189   224,191   202,794   190,126   164,244  
Total liabilities
  18,731   18,354   17,999   18,768   14,090  
Total equity
  229,458   205,837   184,795   171,358   150,154  
                       
Market Capitalization (b)
  1,692,871   650,651   784,020   810,223   645,867  
                       
Cash Flow
                     
Cash provided by operating activities
  37,573   28,262   29,236   34,482   41,233  
Capital expenditures (c)
  33,829   20,516   32,202   26,747   17,513  
Cash (used) provided by all other investing activities, net
  -   (4,779 ) 1,097   (1,097 ) 6,127  
Cash dividends paid
  2,379   4,352   10,317   10,325   8,855  
                       
 
(a) All share and per share amounts have been adjusted to reflect the four-for-one share split effected in the fourth quarter of 2007.
 
(b) Market capitalization is calculated by multiplying the year-end total shares outstanding by the year-end closing share price.
 
(c) Includes acquisitions.
 
Refer to the table “Oil and Natural Gas Production, Prices and Costs” in Part I, Item I for variations in prices that influence our revenues and net income.


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
General
 
We are an international oil and gas exploration and production company focused on South America, with operations in Argentina and Colombia. As of December 31, 2010, we had interests in eight oil and gas producing concessions and two exploration permits in Argentina, and three exploration and production contracts in Colombia.
 
We have experienced gradual improvements in the economic environment for Argentina’s hydrocarbons industry since the second half of 2009 and throughout 2010.  Product prices have continued to trend modestly upward during this period.  With improved product prices, recently added investments and business development opportunities, our business plan for 2010 was structured around growing our presence in the Neuquén basin, completing the initial phases of our exploration projects in Colombia and continued development in our core properties.
 
Our capital expenditures totaled $33.8 million in 2010, and we spent an additional $6.1 million for the acquisition of seismic information in both Argentina and Colombia.  Highlights for 2010 include the following:
 
·  
Increased total consolidated and equity sales volumes on a barrel of oil equivalent basis by four percent;
 
·  
Successful development and exploration drilling campaigns in our core Neuquén basin properties;
 
·  
Exploration discovery in the Agua Amarga exploration permit;
 
·  
Exploration discoveries in the Coirón Amargo exploration permit; and
 
·  
Awarded an exploration block in Colombia.
 
For 2010, net income attributable to Apco Oil and Gas International Inc. was $25.8 million compared with $23.5 million for 2009.  Higher average sales prices and greater equity income from Argentine investment in 2010 led to the increase in net income compared with 2009.  These favorable variances were partially offset by greater costs and operating expenses and higher income tax expense.
 
Outlook for 2011
 
We expect oil prices in Argentina to increase moderately in 2011 compared with 2010 year end prices of around $55 per barrel. After completing significant seismic exploration activities in 2010, we plan to initiate exploration drilling activities in Colombia, resulting in increased capital expenditures compared with 2010. We have the following expectations and objectives for 2011:
 
·  
Obtain the ten-year concession extensions for our properties in Río Negro and Tierra del Fuego;
 
·  
Continued development and exploration drilling in our core properties in our Neuquén basin properties;
 
·  
Complete farm-in drilling commitments in Coirón Amargo;
 
·  
Initiate exploration activities in Sur Río Deseado Este;
 
·  
Commence exploration drilling in Colombia and acquire 3D seismic data over Block 40; and
 
·  
Continue a disciplined approach toward seeking investment opportunities in South America.



Our 2011 oil and gas capital expenditure budget is $34 million net to our consolidated interests.  After taking into consideration the portion of capital expenditures attributable to our equity interest in Petrolera, our combined consolidated and equity capital budget for 2011 is $59 million.  In addition, we plan on spending approximately $8 million for the acquisition of seismic information.  For further discussion about funding our capital budget, please read the section “Liquidity and Capital Resources” in MD&A.  
 
 
Potential Change in Control – Williams’ Separation Plan
 
On February 16, 2011,  Williams announced that its Board of Directors approved pursuing a plan to separate Williams into two standalone, publicly traded corporations. The plan calls for the separation of its exploration and production business via an initial public offering in 2011 of up to 20 percent of a corporation holding that business ("New E&P") and, in 2012, a spin-off to Williams’ shareholders of its remaining interest in New E&P.  Williams stated its intention to include its interest in Apco in New E&P.  Williams retains the discretion to determine whether and when to execute the spinoff.
 
Following the spinoff, Apco would be majority owned by New E&P company, a large-scale, independent primarily North American diversified exploration and production company which would not be controlled by Williams. This proposed ownership change of Williams could, among other things, affect our leadership and financing opportunities.
 
Williams indicated that the completion and timing of the separation plan is dependent on a number of factors including, but not limited to, the macroeconomic environment, credit markets, equity markets, energy prices, the receipt of a tax opinion from counsel and/or Internal Revenue Service rulings, final approvals from Williams’ Board of Directors, and other matters. There can be no assurance as to the timing or that the transaction terms announced by Williams will result in any changes to Williams’ current structure.
 
 
Overview of 2010
 
Business Development
 
In 2010, Apco participated in a public bidding process known as “ANH Miniround 2010” for the assignment of certain exploration properties by the government of Colombia. Apco and Ramshorn International Limited (“Ramshorn”), a subsidiary of Nabors Drilling, were awarded the Llanos 40 block in the 2010 bidding round.  We will hold a 50 percent working interest in the block and Ramshorn will also hold 50 percent and will be the operator.  The block will be governed by an exploration and production contract executed with the ANH.  One of the requirements of the contract is to issue a letter of credit to guarantee the contract’s work commitments.  We anticipate issuing a $5.5 million letter of credit net to Apco in the first quarter of 2011 and collateralizing it with cash.
 
The Llanos 40 block covers approximately 163,000 acres and is approximately 175 kilometers to the northeast of the Llanos 32 block.  Our three-year first phase exploration work commitments will include seismic reprocessing, acquisition of 300 square kilometers, or approximately 74,000 acres, of 3D seismic and the drilling of four exploration wells.  We anticipate spending between $15 and $20 million net to Apco for these work commitments over a three-year period and funding these activities from cash reserves and internally generated cash.  We expect exploration activities and expenditures to begin in 2011.



Neuquén Basin Properties
 
Apco and its partners used two rigs throughout 2010 to drill 32 gross development wells and one exploration well in the areas. All wells but one were successful.  Total gross capital expenditures was $97.3 million for the year, or $22.4 million net to our 23 percent direct working interest and $28.9 million attributable to our equity interest in Petrolera.  We have a 23 percent direct working interest and an effective 29.85 percent equity interest in the wells mentioned above.
 
Additional activities included production facility investments for gas compression and oil pipelines in the Charco del Palenque and Bajada del Palo concessions, and the acquisition of approximately 300 square kilometers of 3D seismic information in the western portion of the Bajada del Palo concession for a cost of approximately $1.0 million net to Apco.
 
In our Agua Amarga exploration permit, we drilled the Jarilla Quemada x-1 exploration well which resulted in a natural gas and condensate discovery.  The well was located in the eastern part of the block.  In December 2010, we began drilling another exploration well on the Meseta Filosa prospect in the central part of the area.
 
Coirón Amargo
 
In February 2010, we entered into a farm-in agreement that allows us to acquire, through a “drill to earn” structure, up to a 45 percent net interest in the Coirón Amargo exploration permit in the Neuquén basin. The Coirón Amargo block covers approximately 100,000 acres and is adjacent to our core properties in the basin.
 
Under the agreement, Apco earned a 22.5 percent non-operated interest for funding the drilling of two exploration wells during 2010.  The first two wells were drilled in the third quarter and discovered oil and associated natural gas from the Tordillo formation.  Apco subsequently elected to proceed to a second phase and drill two additional wells to increase our interest to 45 percent.  We spent approximately $6 million during the first phase of this agreement in 2010, and we anticipate spending an additional $6 million for the drilling of two wells in 2011.
 
Austral & Northwest Basin Properties
 
We re-commenced development drilling in our Tierra del Fuego and Acambuco concessions in early 2010. During the year, we drilled ten development gas wells in Tierra del Fuego, of which two were determined to be non-productive and two are currently awaiting completion.  In Acambuco, the Macueta 1006 development well was drilled during 2010 and will be tested in 2011.
 
Concession Contracts in Argentina
 
In the second half of 2010, the provinces of Río Negro and Tierra del Fuego approved basic frameworks for the negotiation of the 10-year concession extensions provided by Argentina’s hydrocarbon law.  Similar to the negotiations concluded with the province of Neuquén in 2009, the requirements include the negotiation of a cash bonus payment, an increase to provincial production taxes, and a future expenditure program.
 
The concession terms for the portion of the Entre Lomas concession located in Río Negro and for our Tierra del Fuego concessions currently end in 2016.  The operators of the concessions are leading negotiations with the provinces on behalf of the joint venture partners. We expect to conclude these negotiations in 2011.  Approximately one half of the Entre Lomas concession, including our largest producing field, is located in the province of Río Negro.  In general, the depletion life of many of our proved wells extends beyond 2016 and through the end of the concession extension period, and consequently, obtaining the 10-year extension should lead to reserve upgrades that will result in a material increase in the volume of proved reserves.


Colombia
 
In the Llanos 32 block in the Llanos basin of western Colombia, Apco and its partners completed the acquisition of 268 square kilometers, or 66,196 acres, of 3D seismic information.  We spent approximately $1.9 million net to Apco during 2010 for this program.  Drilling prospects are being identified by the partners and we expect to drill two exploration wells on this block during 2011.  Recent exploration drilling results achieved by other companies drilling to the same sub-surface formations that we will be targeting in the Llanos basin have been encouraging.
 
In the Turpial block, Apco and its partner completed a program to extend seismic coverage in the northern area of the block with 144 kilometers of 2D seismic information. We spent approximately $3.1 million net to Apco during 2010 for this program.  We anticipate initiating exploration drilling on the block during 2011.
 
 
Oil and Natural Gas Marketing
 
Oil Prices
 
Oil prices have a significant impact on our ability to generate earnings, fund capital projects, and pay shareholder dividends. Oil prices are affected by changes in market demands, global economic activity, political events, weather, inventory storage levels, refinery infrastructure capacity, OPEC production quotas, and other factors.  Additionally, oil sales price realizations for oil produced and sold in Argentina are significantly influenced by Argentine governmental actions as described in the following paragraphs. As a result, we cannot accurately predict future prices, and therefore it is difficult for us to determine what effect increases or decreases in product prices may have on our capital programs, production volumes, or future revenues.
 
Historically, the price per barrel for Argentine crude oil was based on the spot market price of West Texas Intermediate crude oil (“WTI”) less a discount for differences in gravity and quality. In the wake of the Argentine economic crises of 2002, and as the price of crude oil increased to record levels over the past several years, politically driven mechanisms were implemented to determine the sale price of oil produced and sold in Argentina. To alleviate the impact of higher crude oil prices on Argentina’s economy, the Argentine government created an oil export tax and enacted strict price controls over gasoline prices to force producers and refiners to negotiate oil sales prices significantly below international market levels.
 
In response to those governmental actions, Argentine producers and refiners had to negotiate domestic oil sale prices that take into consideration both net backs for oil exported from Argentina and the cost of feedstock to refiners in light of gasoline price controls.  Consequently, Apco has not benefited from increases in world oil prices over the past several years as have producers outside of Argentina.
 
The extreme volatility of world oil prices during recent years has not been reflected in our results of operations due to the price controls and marketing environment in Argentina.  Our oil sales price per barrel for our consolidated interests averaged $52.22 for 2010 compared with $43.46 for 2009 and $46.09 in 2008.
 
As a result of the level of oil sale prices in Argentina when compared with oil sales prices in other countries, oil exploration investments and consequent oil discoveries in Argentina have not been sufficient to replace domestic production. As a result, oil reserves in the country have fallen in recent years. We cannot predict how world oil prices will evolve in 2011 and beyond or what additional actions the Argentine government will take in response to either future fluctuations in world oil prices or the drop in the level of the country’s oil reserves.



Natural Gas Prices
 
We sell our natural gas to Argentine customers pursuant to contracts and spot market sales. As a consequence of the growth in Argentina’s economy over the past several years, and stimulated by low natural gas prices resulting from a price freeze implemented by the Argentine government in 2002, demand for natural gas in Argentina has grown significantly. However, the unfavorable price environment for producers has acted to discourage natural gas exploration activities. Without significant new discoveries of natural gas reserves in Argentina, the supply of natural gas has failed to keep up with increased demand. The result is a natural gas and power supply shortage in the country. Since 2004, the Argentine government has taken several steps to prevent shortages in the domestic market. Natural gas exports to Chile were suspended and the country began importing natural gas from Bolivia at significantly greater prices than sales prices for natural gas produced in Argentina.  In addition, Argentina was forced to import high priced LNG. As described in the following paragraphs, Resolution 599/2007 is designed to supply natural gas in the domestic market and provide a framework for natural gas prices in Argentina.
 
In 2007, the Argentine Secretary of Energy issued Resolution 599/2007 to regulate the supply of natural gas in the domestic market for the period 2007 to 2011 through a natural gas supply agreement referred to as the “Acuerdo 2007-2011.”
 
The resolution is intended to provide for equitable sharing of all sectors of the internal natural gas market among producers and establishes a mechanism for doing so based on average natural gas volumes produced from 2002 to 2004. The resolution determines which sectors of the market will have priority during periods of peak demand. During peak periods, the residential market will have first priority.  With respect to the lower-priced residential market, each producer’s share of the residential market will be distributed based on an allocation of its volumes produced during the period 2002 to 2004, while natural gas production in excess of those volumes can be sold to electric power generators at regulated prices, and industrial customers at freely negotiated prices.
 
Producers that increased natural gas production since 2004 have an advantage compared to those producers whose production decreased over the period because natural gas prices to residential customers remain suppressed at approximately 60 cents per Mcf. The resolution allows producers to choose to participate in the Acuerdo 2007-2011 natural gas supply agreement or not. However, if a producer chooses not to participate, then during periods of peak demand, or when there is a shortage of natural gas in the country, the government can nominate non-participating producers to be the first to supply excess residential volume demand above the base-line demand as projected in the Acuerdo 2007-2011, regardless of the non-participating producer’s contractual commitments.
 
In general, resolution 599/2007 has had a slightly positive impact on natural gas sales prices in Acambuco and Tierra del Fuego, but, during peak demand periods, it has lowered natural gas sales prices in Entre Lomas and Bajada del Palo.  Nevertheless, because natural gas revenues from Entre Lomas and Bajada del Palo represent approximately three percent of our total operating revenues on an annual basis, the overall impact of the resolution has not been material to our cash flows or results of operations.  Our average natural gas sale price per Mcf, averaged $1.90 in 2010, $1.70 in 2009, and $1.46 during 2008.
 
The level of gas reserves in Argentina has fallen in recent years in a country that relies on natural gas for more than 50 percent of its energy consumption. Given the government’s tendency to intervene over pricing of a commodity in such high demand, we cannot predict how Argentine natural gas prices will evolve in 2011 and beyond or whether the current Argentine government will continue to maintain tight controls over prices or decide to loosen price controls in response to falling production and reserves.
 



Seasonality
 
Of the products we sell, only natural gas is subject to seasonal demand.  Demand for natural gas in Argentina is reduced during the warmer months of October through April, with generally lower natural gas prices during this off-peak period. During 2010, natural gas sales represented 14 percent of our total operating revenues compared with 14 percent in 2009 and 10 percent in 2008.  Consequently, the fluctuation in natural gas sales between summer and winter is not significant for the Company.
 
 
New Accounting Standards and Emerging Issues
 
There were no new accounting standards issued in 2010 that we anticipate having a material effect on our consolidated financial statements.
 
 
Critical Accounting Policies and Estimates
 
The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions. We believe that these particular estimates and assumptions are critical due to their subjective nature and inherent uncertainties, the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations. We have discussed the following accounting estimates and assumptions as well as related disclosures with our Audit Committee.
 
Proved reserve estimates. Estimates of 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 reserve engineers and geologists that prepare the estimate.
 
The Company’s proved reserve information is based on estimates prepared by its reserve engineers. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing, and production after the date of an estimate may justify material revisions to the estimate. The Company’s proved reserves are limited to the concession life. Certain of our existing concession terms can be extended for 10 years with the consent of and based on terms to be agreed with the Argentine government. The extension of our concessions could materially affect the Company’s estimate of proved reserves.
 
The present value of future net cash flows should not be assumed to be the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2010 and 2009 estimated discounted future net cash flows from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price received for the period January through December with the most current cost information. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.
 
Our estimates of proved reserves materially impact depreciation, depletion and amortization expense. If the estimates of proved reserves decline, the rate at which we record depreciation expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment.
 
Impairment of oil and gas properties. We review our proved and unproved properties for impairment on a concession by concession basis and recognize an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues (“fair value”). In estimating future net revenues, we assume costs will escalate annually and apply an oil and gas price forecast that we believe to be reasonable. Due to the volatility of oil and gas prices and governmental regulations in Argentina, it is possible that the our assumptions regarding oil and gas prices may change in the future.  However, at prices equivalent to those at year-end 2010,  we do not expect to recognize any impairments in the near term.  We could, depending upon the results of exploration, determine that some or all of our interests in unproved areas need to be impaired as we drill and evaluate certain of these areas in future periods.  For example, we have $2.6 million of unproved properties related to our operations in Colombia;  if our exploration drilling planned for 2011 is unsuccessful, we may have to recognize an impairment loss related to this asset.
 
 





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

   
For the Years Ended December 31,
 
                                           
         
$ Change
   
% Change
         
$ Change
   
% Change
       
   
2010
   
from 2009*
   
from 2009*
   
2009
   
from 2008*
   
from 2008*
   
2008
 
   
(Amounts in Thousands)
 
                                           
Operating revenues
  $ 87,815       15,099       21 %   $ 72,716       3,600       5 %   $ 69,116  
Total costs and operating expenses
    68,881       (13,121 )     -24 %     55,760       347       1 %     56,107  
 Operating income
    18,934       1,978       12 %     16,956       3,947       30 %     13,009  
Investment income
    16,594       2,030       14 %     14,564       (2,922 )     -17 %     17,486  
Income taxes
    9,694       (1,701 )     -21 %     7,993       (1,323 )     -20 %     6,670  
Net Income
    25,834                       23,527                       23,825  
  Less: Net income attributable to
                                                       
noncontrolling interests
    34       (4 )     -13 %     30       2       6 %     32  
Net income attributable to Apco
  $ 25,800       2,303       10 %   $ 23,497       (296 )     -1 %   $ 23,793  
 
       *    + = Favorable change; — = Unfavorable change.
 
 
Net Income
 
2010 vs. 2009  Our Net income attributable to Apco for 2010 was $25.8 million, an increase of $2.3 million compared with 2009.  Net income attributable to Apco increased compared with 2009 primarily due to the favorable effects of higher sales prices and greater equity income from Argentine investment.  These favorable variances were partially offset by greater exploration expense for the acquisition of seismic information, higher production and lifting costs, increased provincial production taxes and higher income tax expense.
 
 
2009 vs. 2008  Our Net income attributable to Apco for 2009 was $23.5 million, a decrease of $296 thousand or one percent compared with 2008.  Net income attributable to Apco decreased compared with 2008 as the favorable effects of increased sales volumes and lower exploration expenses were more than offset by a combination of lower average oil and LPG sales prices, greater depletion, depreciation and amortization expense, higher selling and administrative expense, lower equity income from Argentine investment, and greater income tax expense.
 
 
Total Operating Revenues
 
Operating revenues for 2010 increased by $15.1 million, or 21 percent compared with 2009.  The following tables and discussion explain the components and variances in Operating revenues.


Changes in oil, natural gas and LPG sales volumes, prices and revenues from 2008 to 2010 for our consolidated interests accounted for as operating revenues are shown in the following tables.
 

   
Year Ended December 31,
 
                               
   
2010
   
% Change
   
2009
   
% Change
   
2008
 
                               
Sales Volumes
                             
Consolidated interests
                             
Oil (bbls)
    1,338,195       1 %     1,330,020       9 %     1,218,896  
Natural Gas (mcf)
    6,306,883       8 %     5,849,497       21 %     4,850,144  
LPG (tons)
    9,893       -2 %     10,097       16 %     8,734  
Oil, Natural Gas and LPG (boe)
    2,505,438       3 %     2,423,425       14 %     2,129,747  
Average Sales Prices
                                       
Consolidated interests
                                       
Oil (per bbl)
  $ 52.22       20 %   $ 43.46       -6 %   $ 46.09  
Natural Gas (per mcf)
    1.90       12 %     1.70       17 %     1.46  
LPG (per ton)
    346.61       31 %     264.33       -46 %     490.27  
                                         
Revenues ($ in thousands)
                                       
Oil revenues
  $ 69,882       21 %   $ 57,809       3 %   $ 56,182  
Natural Gas revenues
    12,000       21 %     9,949       41 %     7,073  
LPG revenues
    3,429       28 %     2,669       -38 %     4,282  
    $ 85,311       21 %   $ 70,427       4 %   $ 67,536  
                                         
 
The volume and price changes in the table above caused the following changes to our oil, natural gas and LPG revenues from 2008 to 2010.
 

   
Oil
   
Gas
   
LPG
   
Total
 
   
(Amounts in Thousands)
 
                         
2008 Sales
  $ 56,182     $ 7,073     $ 4,282     $ 67,537  
Changes due to volumes
    4,830       1,700       360       6,890  
Changes due to prices
    (3,203 )     1,176       (1,973 )     (4,000 )
2009 Sales
    57,809       9,949       2,669       70,427  
Changes due to volumes
    427       870       (71 )     1,226  
Changes due to prices
    11,646       1,181       831       13,658  
2010 Sales
  $ 69,882     $ 12,000     $ 3,429     $ 85,311  
                                 

Oil Revenues
 
2010 vs. 2009  During 2010, Oil revenues increased by $12.1 million, or 21 percent compared with 2009, due to higher average oil sales prices with some contribution from increased sales volumes.  For further explanation of oil sales prices in Argentina, please read the section “Oil and Natural Gas Marketing – Oil Prices,” previously discussed in MD&A.


2009 vs. 2008  During 2009, Oil revenues increased by $1.6 million, or three percent compared with 2008.  A nine percent increase in total consolidated oil sales volumes resulted in a positive variance of $4.8 million.  Successful drilling in our Neuquén basin properties and increased condensate production in our Austral basin properties were the primary drivers of higher sales volumes. However, the benefit of greater sales volumes was offset by a six percent decrease in average oil sales prices which resulted in a $3.2 million decrease in revenues.
 
Natural Gas Revenues
 
2010 vs. 2009  Natural gas revenues increased by $2.1 million, or 21 percent compared with 2009.  The construction of production facilities and well-connections in our Bajada del Palo and Charco del Palenque concessions drove a seven percent increase in consolidated natural gas sales volumes for the year, resulting in an $870 thousand benefit to revenues.  Average natural gas prices continued to moderately increase resulting in a $1.2 million increase in revenues for the year. For further explanation of natural gas sales prices in Argentina, please read the section “Oil and Natural Gas Marketing – Natural Gas Prices,” previously discussed in MD&A.
 
2009 vs. 2008  During 2009, Natural gas revenues increased by $2.9 million, or 41 percent compared with 2008.  Production facility enhancements and well-connections in our Tierra del Fuego operations drove a 21 percent increase in consolidated natural gas sales volumes for the year, resulting in a $1.7 million benefit to revenues.  Additionally, a 17 percent increase in average natural gas sales prices resulted in a $1.2 million increase in revenues for the year. Higher average natural gas sales prices are primarily attributable to a gas sales contract allowing for a portion of our Tierra del Fuego production volumes to be delivered to higher priced industrial markets. In addition, the Argentine government allowed natural gas sales prices in low priced residential markets to increase from approximately $0.36 per mcf to $0.50 per mcf beginning in the third quarter 2009.
 
LPG Revenues
 
2010 vs. 2009  LPG revenues increased by $760 thousand in 2010 as improved market conditions in Argentina allowed for higher average LPG sales prices during the year.
 
2009 vs. 2008  LPG revenues decreased by $1.6 million in 2009, or 38 percent compared with 2008, as the benefit of higher volumes was more than offset by lower prices.  In 2009, decreased international commodity prices and market conditions in Argentina resulted in a 46 percent decrease in average LPG sales prices, which decreased revenues by $2.0 million.
 
Other Operating Revenues
 
2010 vs. 2009 Other operating revenues increased by $215 thousand during 2010 compared with 2009.  The majority of our other operating revenues relates to value-added tax collections related to hydrocarbon sales revenues from our operations in Tierra del Fuego.  For oil, natural gas, and LPG that is produced on the island of Tierra del Fuego and sold domestically to continental Argentina, sellers are allowed to retain the value-added tax collected from buyers as part of the island’s tax exemption rules.  This mechanism effectively increases our realized prices by 21 percent for sales made to the continent. As a result, fluctuations in our other operating revenues are driven by sales revenues from our operations in Tierra del Fuego.
 
2009 vs. 2008 Other operating revenues increased by $710 thousand during 2009 compared with 2008 due to greater amounts of value-added tax collections resulting from increased sales revenues from our operations in Tierra del Fuego.
 


Total Costs and Operating Expenses
 
 
2010 vs. 2009 Total costs and operating expenses increased by $13.1 million, or 24 percent, primarily due to the following factors:
 
·  
Production and lifting costs increased by $4.3 million, or 29 percent due to greater operation and maintenance expenses related to our Neuquén and Austral basin properties.  These increases were driven by the growth in our operations and the impact of inflation in Argentina;
 
·  
Exploration expense increased by $5.1 million due to significant exploration activity in 2010 including expenses related to the acquisition and processing of seismic information in Colombia for $4.9 million and $1.0 million in our Neuquén basin properties.  Exploration activity in 2009 was minimal;
 
·  
Provincial production taxes increased $1.6 million related to greater operating revenues from higher sales prices.
 
 
2009 vs. 2008 Total costs and operating expenses decreased by $347 thousand due to certain offsetting variances.  Specifically, lower exploration expense offset increases in certain operating costs as follows:
 
·  
Exploration expense decreased by $4.6 million due to the absence of dry-hole expense for unsuccessful exploratory wells and lower exploration activity including acquiring less amounts of 3D seismic information;
 
·  
Depreciation, depletion and amortization (DD&A) increased by $2.2 million, or 16 percent primarily due to increased volumes. See below for a more detailed discussion of DD&A expense; and
 
·  
Selling and administrative expense increased by $1.5 million due to higher business development activity reflecting management’s strategy to search for and evaluate growth opportunities and increased salaries and wages.
 
 
Depreciation, Depletion and Amortization Expenses (“DD&A”)
 
Our DD&A expense is based on the units-of-production method, which in basic terms multiplies the percentage of estimated proved developed reserves produced each period times the net carrying value of our proved oil and gas properties. Our proved developed reserves are limited to an area’s concession life even though a concession’s term can be extended for 10 years based on terms to be agreed with and the consent of the government. In the third quarter of 2009, the terms for a portion of our concessions were extended until 2025 and 2026.  The extensions have had a favorable effect on our average DD&A rates beginning in the third quarter of 2009 compared with prior periods as more proved producing reserves are included in our DD&A calculation.
 
We are working to obtain the ten-year concession extensions for our properties in Río Negro and Tierra del Fuego which currently have concession terms ending in 2016.  If any extensions are obtained, we expect to experience an additional favorable effect on future DD&A rates as wells whose productive lives extend beyond 2016 will result in the addition of proved producing reserves.



The changes in our total volumes, DD&A average rates per unit and DD&A expense of oil and gas properties between 2008 and 2010 are shown in the following table:
 
 
   
Year Ended December 31,
 
         
Change
   
% Change
         
Change
   
% Change
       
   
2010
   
from 2009
   
from 2009
   
2009
   
from 2008
   
from 2008
   
2008
 
                                           
Consolidated Sales Volumes (boe)
    2,505,438       82,013       3 %     2,423,425       293,679       14 %     2,129,747  
DD&A Rate per boe
  $ 6.71     $ 0.36       6 %   $ 6.35     $ 0.13       2 %   $ 6.22  
DD&A Expense (In thousands)
  $ 16,824     $ 1,446       9 %   $ 15,378     $ 2,138       16 %   $ 13,240  
 

The following table details the increases in DD&A of oil and gas properties between 2008 and 2010 due to the changes in volumes and average DD&A rates presented in the table above:

   
(Thousands)
 
       
2008 DD&A
  $ 13,240  
Changes due to volumes
    1,864  
Changes due to rates
    274  
2009 DD&A
    15,378  
Changes due to volumes
    551  
Changes due to rates
    895  
2010 DD&A
  $ 16,824  

2010 vs. 2009 DD&A increased by $1.5 million in 2010 compared with 2009 primarily due to greater volumes and increased DD&A rates.  Our DD&A rate increased in 2010 because we add less proved reserves per well drilled for calculating depreciation with each year that passes without obtaining the remaining ten-year extensions for our concessions because our proved reserves are limited to the current concession life.
 
2009 vs. 2008 DD&A increased by $2.2 million in 2009 compared with 2008.  As seen in the table above, the majority of the increase in DD&A expense was due to greater volumes, which is contrary to our historical trend.  Although our DD&A rate increased for the year, in 2009 our year-over-year DD&A rate increased at a decelerating rate, or was only two percent greater than it was in 2008, which is a significantly lower rate compared with previous years including the 32 percent increase we experienced in 2008.  Various factors contributed to this deceleration of increased DD&A rates we have experienced, including the previously mentioned concession extensions, the increased proportion of sales volumes on a barrel of oil equivalent basis due to greater natural gas sales volumes from our Tierra del Fuego concessions which lowers our weighted average DD&A rate, and increased proved reserves from successful drilling in our Neuquén basin properties.
 
Investment Income
 
2010 vs. 2009  In 2010, our Total investment income increased by $2.0 million, or 14 percent, due to greater Equity income from Argentine investment. The increase in our equity income is due to an increase in the net income of our equity investee, Petrolera.  The comparative increase in Petrolera’s net income is a result of greater revenues driven by higher oil, natural gas and LPG average sales prices.



2009 vs. 2008  In 2009, our Total investment income decreased by $2.9 million, or 17 percent, primarily due to a $2.2 million decrease in equity income from Argentine investment. The decrease in our equity income is due to a decrease in the net income of our equity investee, Petrolera.  The comparative decrease in Petrolera’s net income is a result of lower oil and LPG sales prices and increased depreciation expense. These two factors more than offset the benefits of greater oil sales volumes attributable to successful exploration and development drilling in our joint operations in the Neuquén basin.  Additionally, interest and other income decreased by $690 thousand compared to 2008 due to lower yields on our financial investments and lower balances of cash equivalents.
 
Income Taxes
 
2010 vs. 2009  Income taxes increased by $1.7 million compared with 2009 in direct relation to our increase in pre-tax income in Argentina.  The effective income tax rate on the total provision for 2010 is greater than the effective income tax rate in the prior year primarily due to the greater amounts of exploration activity in Colombia which provide no benefit to income tax expense during the period.  See Note 8 in the Notes to Consolidated Financial Statements for further discussion of income taxes.
 
2009 vs. 2008  Income taxes increased by $1.3 million compared to 2008.  Although our Income before income taxes is only three percent higher in 2009 compared with 2008, the effective tax rate for the period increased due to higher non-deductible costs including greater foreign exchange losses and higher general and administrative expenses in our home office, lower interest and other income which is not subject to income tax, lower equity earnings from Argentine investments which is recorded on an after-tax basis, and exploration expenses incurred in Colombia which are not deductible until we generate revenues in that country.
 
 
LIQUIDITY AND CAPITAL RESOURCES
 
Outlook
 
As previously discussed, the price of WTI crude oil and oil price realizations in Argentina have been on a steady upward trend during 2009 and 2010, reaching an average price of $55 per barrel in December 2010.  For 2011, operating results and cash flows from operations are expected to be greater than 2010 levels if oil prices continue their upward trend. Our oil price realizations continue to be negotiated on a short-term basis, and as such, we cannot accurately predict how they will evolve beyond 2011.
 
Higher oil prices also benefit Petrolera’s cash flows from operations and its ability to pay dividends.  Higher product prices resulted in Petrolera paying more dividends in 2010 than in 2009.  Petrolera’s ability to pay dividends is dependent upon numerous factors, including its cash flows provided by operating activities, levels of capital spending, changes in crude oil and natural gas prices, and debt and interest payments.  Due to expected increases in capital spending for development and exploration activities in our Neuquén basin properties and Petrolera’s scheduled principal and interest payments, we expect Petrolera to pay less dividends during the next several years compared with dividends paid over the past three years.
 
We will continue to monitor our capital programs and the quarterly shareholder dividend as necessary to provide Apco with the financial resources and liquidity needed to continue development drilling in its core properties over the long-term, fund new investment opportunities, meet future working capital needs and fund any further cash bonus payments that may be negotiated to obtain concession extensions, if any, while maintaining sufficient liquidity to reasonably protect against unforeseen circumstances requiring the use of funds.
 


We estimate capital expenditures net to our direct working interests will total approximately $34 million in 2011. Due to our remaining funding commitment to pay for 100 percent of two additional wells in Coirón Amargo, increased exploration and development activities in our core areas for the year and in anticipation of obtaining the ten-year concession extensions for our properties in Río Negro and Tierra del Fuego, in 2011 we negotiated a loan agreement with a financial institution for a $10 million bank line of credit.  We expect the agreement to be effective by the end of the first quarter of 2011.  If executed, borrowings under this facility will be unsecured and will bear interest at Libor plus four percent per annum plus a commitment fee for the unused portion of the loan amount. The funds can be borrowed during a one-year period from the effective date of the loan agreement, and principal amounts will be repaid in four equal installments over four years from each borrowing date after a two and a half year grace period.  We expect to fund our 2011 capital expenditures with cash on hand, cash flows from operations and borrowings under our proposed line of credit.
 
Liquidity
 
Although we have interests in several oil and gas properties in Argentina, our direct participation in those Neuquén basin properties in which we are partners with Petrolera and dividends from our equity interest in Petrolera are the largest contributors to our net cash provided by operating activities.
 
We have historically funded capital programs and past property acquisitions with internally generated cash flow. We have not relied on debt or equity as sources of capital due to the turmoil that periodically affects Argentina’s economy which made financing difficult to obtain at reasonable terms.  However, as has been the case with financing for Petrolera, we observed an improvement in financing terms for companies doing business in Argentina.  Consequently, we negotiated the previously described $10 million line of credit in the first quarter of 2011.
 
With a cash and cash equivalents balance at December 31, 2010, of $35.2 million, or 14 percent of total assets, our proposed bank line of credit, and the ability to adjust capital spending as necessary, we believe we have sufficient liquidity and capital resources to effectively manage our business in 2011.
 
Although Apco has not typically relied on debt or equity as sources of capital, successful exploration efforts in Argentina or Colombia could lead to development capital needs that are currently beyond Apco’s ability to fund from operations.  Consequently, if necessary, we may have to consider additional bank financing or some form of equity financing in the future.
 
Our liquidity is affected by restricted cash balances that are pledged as collateral for letters of credit for exploration activities in Colombia.  A total of $4 million is considered restricted and included in restricted cash as of December 31, 2010.  In January 2011, the first exploration phase letter of credit of $4 million expired and a second letter of credit valid for 18 months was issued and collateralized by $2.9 million of cash.  We expect to issue another $5.5 million letter of credit for another exploration block in the first quarter of 2011.  The restricted cash is invested in a short-term money market account with a financial institution.



Cash Flow Analysis
 
The following table summarizes the change in cash and cash equivalents for the periods shown.
 
Sources (Uses) of Cash

                   
   
Years Ended December 31,
 
   
2010
   
2009
   
2008
 
   
(Thousands)
 
Net cash provided (used) by:
                 
Operating activities
  $ 39,038     $ 28,262     $ 29,236  
Investing activities
    (33,829 )     (25,295 )     (31,105 )
Financing activities
    (2,379 )     (4,352 )     (10,317 )
Increase / (decrease) in cash and cash equivalents
  $ 2,830     $ (1,385 )   $ (12,186 )
                         
 
Operating Activities
 
Our net cash provided by operating activities in 2010 increased by $10.8 million compared with 2009 due to higher operating income and greater dividends from our equity investment in Petrolera.
 
Our net cash provided by operating activities in 2009 decreased by $974 thousand compared with 2008 primarily due to changes in operating assets and liabilities.
 
Included in our net cash provided by operating activities are dividends received from our equity investment in Petrolera of $14.1 million in 2010, $5.3 million in 2009 and $7.0 million in 2008.
 
Investing Activities
 
During 2010, we spent $33.8 million for capital expenditures, including $31.8 million for development and exploration drilling, and $2.0 million for related production and surface facilities.
 
During 2009, we spent $20.5 million for capital expenditures, including $17.9  million primarily related to development and exploration drilling, and $2.6 million as acquisition cost related to our entrance into Colombia. Additionally, $4 million was invested as collateral for a letter of credit for investments in Colombia.
 
During 2008, capital expenditures totaled $32.2 million.
 
Financing Activities
 
Apco paid $2.4 million of dividends to its shareholders in 2010, $4.4 million in 2009, and $10.3 million in 2008.
 
Capital & Exploration Expenditures Budget for 2011
 
Our 2011 capital plan provides for $34 million for development and exploration drilling expenditures net to our direct working interests.  In addition, we plan on spending approximately $8 million for the acquisition of seismic information.  After taking into consideration the portion of capital expenditures attributable to our equity interest in Petrolera, our combined consolidated and equity capital expenditure budget for 2011 is $59 million.  Any cash bonus payments that may be negotiated to obtain concession extensions would result in additional capital expenditures.  We expect the Company and Petrolera to have sufficient capital resources to fund our investment programs in 2011.  We review our capital spending programs throughout the year in light of any changing economic or price conditions and, if necessary, will adjust our planned investments accordingly.
 
 
 
Contractual Obligations
 
The table below summarizes Apco’s contractual obligations. We expect to fund these contractual obligations with cash and cash generated from operating activities.
 

   
Obligations per Period
 
                         
   
2011
   
2012
   
Thereafter
   
Total
 
   
(Amounts in Thousands)
 
                         
International oil and gas activities
  $ 17,800     $ 6,500     $ 6,500     $ 30,800  
Other long-term liabilities
    -       -       2,709       2,709  
Total
  $ 17,800     $ 6,500     $ 9,209     $ 33,509  
 
 
International oil and gas activities includes estimates for remaining drilling or seismic investments pursuant to exploration permit work obligations.  In addition to the table above, and as described elsewhere in this report, during 2009 the terms of portions of our concessions located in the province of Neuquén were extended for an additional 10 years.  As a result of the extensions, we also agreed to make expenditures for oil and gas activities net to our direct working interest of approximately $12 million during the three year period ending December 31, 2011, $13 million during the three year period ending December 31, 2014, and $29 million between 2015 and 2026. We expect to fund these expenditures with cash provided by operating activities.
 
Please read Note 10 in the Notes to Consolidated Financial Statements for further discussion about other long-term liabilities which include pension obligations and asset retirement obligations.
 
 
Off-Balance Sheet Arrangements
 
We do not currently use any off-balance sheet arrangements to enhance liquidity and capital resources.

 
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 has historically not used derivatives to hedge price volatility. As previously mentioned in MD&A, oil sales price realizations for oil produced and sold in Argentina are significantly influenced by Argentine governmental actions.  In the current regulatory environment, the combination of hydrocarbon export taxes and strict government controls over Argentine gasoline prices directly impacts net backs for the sale of crude oil in the domestic Argentine market.  As a result, our price is impacted more by government controls than changes in world oil prices and our netbacks have not been responsive to fluctuations in world oil prices.  Therefore, we cannot accurately predict our future sales prices, and it is difficult for us to determine what effect increases or decreases in world oil prices may have on our results of operations.  Our oil sales price per barrel for our consolidated interests averaged $52.22 during 2010 and $43.46 in 2009.  During 2008, when the per barrel price of WTI peaked at $145 in July and fell to nearly $30 in December 2008, our average price was $46.09.
 
 

 
Foreign Currency and Operations Risk
 
Our results of operations are exposed to currency fluctuation and any devaluation of the Argentine peso against the U.S. dollar and other hard currencies may adversely affect our business and results of operations. The value of the Argentine peso has fluctuated significantly in the past and may do so in the future. We are unable to predict whether, and to what extent, the value of the Argentine peso may further depreciate or appreciate against the U.S. dollar and how any such fluctuations would affect our business.  At December 31, 2010 the peso to U.S. dollar exchange rate was 3.98:1.
 
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 U.S. 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. The government subsequently defaulted on a significant portion of its debt in early 2002.
 
In January 2002, the national Congress passed Emergency Law 25,561, which, among other things, overturned the convertibility plan. The government subsequently adopted a floating exchange rate. The Emergency Law directly impacted the Company by establishing a tax on the value of hydrocarbon exports effective April 1, 2002. In addition the government implemented strict controls over the price of natural gas including the freezing prices for residential consumption.
 
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. Argentina’s economy has since shown signs of stabilization with economic conditions improving considerably growing at an average annual rate of eight percent until 2008. As a commodity exporter, the country 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, took advantage of this environment by increasing certain taxes, such as the oil export tax in order to increase its total tax revenues and improve its fiscal balance.
 
Over the last several years, the government has implemented various price control mechanisms in order to control inflation across many sectors of the economy. In order to shield the Argentine consumer from inflation, the government has implemented price controls over oil, diesel, gasoline and natural gas and imposed greater export taxes that result in lower energy prices in the country. These price controls together with higher taxes impacted the balance of supply and demand for hydrocarbons leading to energy shortages which exist today in Argentina and have created less favorable conditions for energy companies doing business in the country. Given the recent world economic crisis and economic contraction, demand for Argentine exports fell off significantly and Argentina’s economy began to contract. The reduction in economic activity in the country has reduced the previously described energy shortages in Argentina.
 
In late 2008, a sharp drop in world commodity prices, including oil and agricultural products, has strained Argentina’s economy. Sharply reduced exports resulted in reduced government export revenues and negatively impacted the country’s fiscal balance. Argentina continues to suffer from inflation but did experience economic growth in 2010.


 
Cristina Kirchner, wife of former president Nestor Kirchner, was elected president in December 2007. She has essentially pursued the same policies as her predecessor. Mrs. Kirchner’s party lost the mid-term congressional elections in 2009, losing control of both houses of Congress.  In October 2010, the former president of Argentina, Nestor Kirchner, passed away.  Former president Kirchner had remained very involved in the political environment alongside his wife and current president since she was elected.  Presidential elections are scheduled for November 2011.
 
We cannot predict how the government will react to the present economic and political situation or what government policies will be implemented by this administration or any future administration or what government actions will impact the country’s energy sector and the Company in particular.




ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
 



 
 
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
 
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2010, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment we concluded that, as of December 31, 2010, our internal control over financial reporting was effective.
 
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.


 
To the Board of Directors and Shareholders of
Apco Oil and Gas International Inc.
 
We have audited Apco Oil and Gas International Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apco Oil and Gas International Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Apco Oil and Gas International Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apco Oil and Gas International Inc. as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2010 of Apco Oil and Gas International Inc. and our report dated March 9, 2011 expressed an unqualified opinion thereon.
 
/s/ ERNST & YOUNG LLP