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:
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Amounts and nature of future capital expenditures;
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Volumes of future oil, gas and LPG production;
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Expansion and growth of our business and operations;
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Financial condition and liquidity;
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Business strategy;
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Estimates of proved oil and gas reserves;
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Reserve potential;
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Development drilling potential;
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Cash flow from operations or results of operations;
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Seasonality of natural gas demand; and
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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:
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Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;
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Inflation, interest rates, fluctuation in foreign currency exchange rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
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The strength and financial resources of our competitors;
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Development of alternative energy sources;
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The impact of operational and development hazards;
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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;
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Political conditions in Argentina, Colombia and other parts of the world;
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The failure to renew participation in hydrocarbon concessions granted by the Argentine government on reasonable terms;
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Risks related to strategy and financing, including restrictions stemming from our proposed loan agreement and the availability and cost of credit;
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Risks associated with future weather conditions, volcanic activity and earthquakes;
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Acts of terrorism; and
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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:
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Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, skilled labor, capital or transportation;
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Unexpected drilling conditions or problems;
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Regulations and regulatory approvals;
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Changes or anticipated changes in energy prices; and
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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:
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Earthquakes, volcanic activity, floods, fires, extreme weather conditions, and other natural disasters;
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Aging infrastructure and mechanical problems;
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Damages to pipelines and pipeline blockages;
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Fires, blowouts, cratering, and explosions;
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Uncontrolled releases of oil, natural gas, or well fluids;
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Formations with abnormal pressures;
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Operator error;
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Damage inadvertently caused by third-party activity, such as operation of construction equipment;
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Pollution and other environmental risks;
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Risks related to truck loading and unloading; and
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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:
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Argentine and Colombian governmental actions;
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Supplies of and demand for electricity, natural gas, petroleum, and related commodities;
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Exploration discoveries throughout the world;
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The level of development investment in the oil and gas industry;
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Turmoil in the Middle East and other producing regions;
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Terrorist attacks on production or transportation assets;
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Weather conditions;
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Strikes, work stoppages, or protests;
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The price and availability of other types of fuels;
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The availability of pipeline capacity;
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Supply disruptions and transportation disruptions;
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Governmental regulations and taxes;
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The overall economic environment;
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The credit of participants in the markets where hydrocarbon products are bought and sold; and
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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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
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.
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:
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.
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.
(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.
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.
* + = 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.
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 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:
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:
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
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.
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.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s operations are exposed to market risks as a result of changes in commodity prices and foreign currency exchange rates.
Commodity Price Risk
The Company 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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Management’s Annual Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2010 and 2009
Consolidated Statements of Income for each year in the three-year period ended December 31, 2010
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2010
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2010
Notes to Consolidated Financial Statements
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Shareholders of
Apco Oil and Gas International Inc.
We have audited Apco Oil and Gas International Inc.’s internal control over financial reporting as of December 31, 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
Tulsa, Oklahoma
March 9, 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Apco Oil and Gas International Inc.
We have audited the accompanying consolidated balance sheets of Apco Oil and Gas International Inc. as of December 31, 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. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Apco Austral S.A., a majority owned subsidiary, which statements reflect total assets of $29.6 million and $26.3 million as of December 31, 2010 and 2009, respectively, and total revenues of $14.2 million and $11.2 million, for the years then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements of the Company, insofar as it relates to the amounts included for Apco Austral S.A., is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and, for 2010 and 2009, the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apco Oil and Gas International Inc. at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, in 2009 Apco Oil and Gas International Inc. has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apco Oil and Gas International Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Tulsa, Oklahoma
March 9, 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Apco Austral S.A.
We have audited the accompanying consolidated balance sheet of Apco Austral S.A. (the “Company”) as of December 31, 2010 and 2009, and the related statement of income, shareholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Apco Austral S.A. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Buenos Aires City, Argentina
March 1, 2011
/s/ Deloitte & Co. S.R.L
Guillermo D. Cohen
Partner
APCO OIL AND GAS INTERNATIONAL INC.
CONSOLIDATED BALANCE SHEETS
APCO OIL AND GAS INTERNATIONAL INC.
CONSOLIDATED STATEMENTS OF INCOME
APCO OIL AND GAS INTERNATIONAL INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
APCO OIL AND GAS INTERNATIONAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
APCO OIL AND GAS INTERNATIONAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Apco Oil and Gas International Inc. (formerly Apco Argentina Inc.) is an international oil and gas exploration and production company with a focus on South America. Exploration and production will be referred to as “E&P” in this document.
Apco began E&P activities in Argentina in the late 1960s, and as of December 31, 2010, had interests in eight oil and gas producing concessions and two exploration permits in Argentina, and three exploration and production contracts in Colombia. Our producing operations are located in the Neuquén, Austral, and Northwest basins in Argentina. The Company also has exploration activities currently ongoing in both Argentina and Colombia. As of December 31, 2010, all of the Company’s operating revenues and equity income, and all but $2.6 million of its long-lived assets for which we have carrying values on our balance sheet, were in Argentina.
A wholly owned subsidiary of The Williams Companies, Inc. (“Williams”) currently owns 68.96 percent of the outstanding ordinary shares of the Company.
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of Apco Oil and Gas International Inc. (a Cayman Islands company) and its subsidiaries, Apco Properties Ltd. (a Cayman Islands company), Apco Austral S.A. (an Argentine corporation), and Apco Argentina S.A. (an Argentine corporation), which as a group are at times referred to in the first person as “we,” “us,” or “our.” We also sometimes refer to Apco as the “Company.”
The Company proportionately consolidates its direct interest of the accounts of its joint ventures into its consolidated financial statements.
Our core operations are our 23 percent working interests in the Entre Lomas, Bajada del Palo and Charco del Palenque concessions and the Agua Amarga exploration permit in the Neuquén basin, and a 40.803 percent equity interest in Petrolera Entre Lomas S.A. (Petrolera, a privately owned Argentine corporation), which is accounted for using the equity method (see Note 2). Petrolera is the operator and owns a 73.15 percent working interest in the same properties. Consequently, Apco’s combined direct consolidated and indirect equity interests in the properties underlying the joint ventures total 52.85 percent. The Charco del Palenque concession is the portion of the Agua Amarga exploration permit which was converted to a 25-year exploitation concession in the fourth quarter of 2009. We sometimes refer to these areas in a group as our “Neuquén basin properties.”
Summary of Significant Accounting Policies
Use of Estimates
Oil and gas operations are high risk in nature. A successful operation requires that a company deal with uncertainties about the subsurface that even a combination of experience, scientific information and careful evaluation cannot always overcome. Because the Company’s assets are located primarily in Argentina, management has historically been required to deal with the impact of inflation, currency devaluation and currency controls. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Our significant estimates and assumptions include: (i) impairment assessments of investments and long-lived assets; (ii) environmental remediation obligations; (iii) realization of deferred income tax assets (iv) oil and natural gas reserves; and (v) asset retirement obligations.
Segments
All of the Company’s producing operations which presently generate revenues are located in Argentina and its only business in Argentina is oil and gas exploration and production. As a result, management views all of the Company’s business and operations to be one segment.
Revenue Recognition
The Company recognizes revenues from sales of oil, gas, and plant products at the time the product is delivered to the purchaser and title has been transferred. We do not require collateral from our purchasers. Any product produced that has not been delivered is reported as inventory and is valued at the lower of cost or market. When cost is calculated, it includes total per unit operating cost and depreciation. Transportation and storage costs are recorded as expenses when incurred. The Company has had no contract imbalances relating to either oil or gas production.
Cash and Cash Equivalents
The Company considers all investments with a maturity of three months or less when acquired to be cash equivalents.
Inventory Valuation
Includes hydrocarbons and spare-parts materials, which are accounted for at production and acquisition cost, respectively.
APCO OIL AND GAS INTERNATIONAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property and Equipment
The Company uses the successful-efforts method of accounting for oil and gas exploration and production operations, whereby costs of acquiring non-producing acreage and costs of drilling successful exploration wells and development costs are capitalized. Costs of unsuccessful exploratory drilling are expensed as incurred. Oil and gas properties are depreciated over their concession life using the units of production method based on proved and proved developed reserves. Non oil and gas property is recorded at cost and is depreciated on a straight-line basis, using estimated useful lives of 3 to 15 years. The Company reviews its proved and unproved properties for impairment on a property by property basis and recognizes an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues (“fair value”). In estimating future net revenues, the Company utilizes what we believe are market participation assumptions, including an oil and natural gas price forecast that it believes to be reasonable given the pricing environment in Argentina. Due to the volatility of oil and gas prices, it is possible that the Company’s assumptions regarding oil and gas prices may change in the future.
Unproved properties may include concession acquisition costs and costs of acquired unproved reserves. Concession acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining concession contract term and recent drilling results. Costs of acquired unproved properties are assessed annually, or as conditions warrant, for impairment using estimated future discounted cash flows on a field basis and considering our future drilling plans. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.
The Company records an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in other operating expense.
Given the uncertainty inherent in the process of estimating future oil and gas reserves and future oil and gas production streams, the estimate of the number of future wells to be plugged and abandoned could change as new information is obtained. Furthermore, given past uncertainties associated with future levels of inflation in Argentina and devaluation of the peso, any future estimate of the cost to plug and abandon a well is subject to a wide range of outcomes as the estimate is updated as time passes. Finally, adjustments in the total asset retirement obligation included in the Company’s Consolidated Balance Sheets will take into consideration future estimates of inflation and present value factors based on the Company’s credit standing. Given past economic turmoil in Argentina, future inflation rates and interest rates, upon which present value factors are based, as recent history demonstrates, may be subject to large variations over short periods of time. A change in the total asset retirement obligation from year to year can result from changes in the estimate of number of wells that will need to be abandoned, changes in the estimate of the cost to abandon a well and accretion of the obligation.
Net Income per Ordinary Share
Net income per ordinary share is based on the weighted average number of ordinary shares outstanding. Basic and diluted net income per ordinary share are the same, as the Company has not issued any potentially dilutive securities such as stock options.
Foreign Exchange
The general policy followed in the translation of the Company’s financial statements of foreign operations into United States dollars is in accordance with ASC 830-30, “Translation of Financial Statements,” using the United States dollar as the functional currency. Accordingly, translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar, are included in results of operations as incurred.
Environmental Obligations
The governments of Argentina and Colombia, at both the federal and provincial levels, promulgate and propose new rules and issue updated guidance to existing rules. We therefore accrue environmental remediation costs for oil and natural gas production activities as they are identified in conjunction with the operators of our concession interests. At December 31, 2010, we have accrued liabilities of $524 thousand for these costs.
Income Taxes
Deferred income taxes are computed using the liability method and are provided to reflect the future tax consequences of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements.
Fair Value
The carrying amount reported in the balance sheet for cash equivalents, accounts receivable, accounts payable and accrued liabilities is equivalent to fair value.
Equity Investment Impairment Policy
We evaluate our equity investment for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment.
Judgments and assumptions are inherent in our management’s estimate of discounted future cash flows and an asset’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.
(2)
Investment in Argentine Oil and Gas Company
As described in Note 1, the Company uses the equity method to account for its investment in Petrolera, a non-public Argentine corporation. Petrolera’s only business is its operatorship and 73.15 percent interest in the Entre Lomas, Bajada del Palo and Charco del Palenque concessions and the Agua Amarga exploration permit.
Under the equity method of accounting, the Company's share of net income (loss) from Petrolera is reflected as an increase (decrease) in its investment accounts and is also recorded as equity income (loss) from Argentine investment. Dividends from Petrolera are recorded as reductions of the Company’s investment. At December 31, 2010, cumulative undistributed earnings in Petrolera were $152.1 million.
The Company’s carrying amount of its investment in Petrolera is greater than its proportionate share of Petrolera’s net equity by $518 thousand. The reasons for this basis difference are: (i) goodwill recognized on its acquisition of additional Petrolera shares in 2002 and 2003; (ii) certain costs expensed by Petrolera but capitalized by the Company; (iii) recognition of a provision for doubtful account associated with a receivable held by Petrolera; and (iv) a difference from periods prior to 1991 when the Company accounted for its interest in Petrolera under the cost recovery method, which will be recognized upon full recovery of the Company’s investment.
Petrolera’s financial position at December 31, 2010 and 2009 is as follows. Amounts are stated in thousands:
Petrolera’s results of operations for the years ended December 31, 2010, 2009 and 2008 are as follows. Amounts are stated in thousands:
(3)
Restricted Cash
Restricted cash of $4 million as of December 31, 2010, is related to a farm-in agreement for an exploration block in Colombia. As part of the contractual requirements related to the block, Apco issued a $4 million letter of credit in July of 2009. The letter of credit expires on January 12, 2011, and is collateralized by cash. The restricted cash is invested in a short-term money market account with a financial institution. As of December 31, 2009, the restricted cash was classified as other non-current assets.
(4)
Exploratory Well Costs Pending the Determination of Proved Reserves
For the years ended December 31, 2010, 2009, and 2008, the changes in capitalized exploratory drilling costs pending the determination of proved reserves are detailed in the table below. The balance as of each year end consisted of wells that were in progress for less than one year.
(5)
Major Customers
Sales to customers with greater than ten percent of total operating revenues consists of the following:
Management believes that the credit risk imposed by this concentration is offset by the creditworthiness of these two customers and upon expiration, the oil sales contracts with these customers will be extended or replaced.
(6)
Related Party Transactions
The Company incurred expenses in 2010, 2009, and 2008, from Williams and affiliates for management services, overhead allocation, rent, general and administrative expenses (including the costs of compensating employees of Williams who allocate a portion of their time to managing the affairs of the Company), internal audit services, and purchases of materials and supplies. These charges were incurred by the Company pursuant to an administrative services agreement between the Company and Williams.
The Company sold hydrocarbons to Petrobras Argentina, the majority shareholder of Petrolera, in 2010, 2009, and 2008.
The Company and Northwest Argentina Corporation (“NWA”), a wholly owned subsidiary of Williams, each own a 1.5 percent interest in the Acambuco concession. NWA has no employees and its sole asset is its interest in Acambuco. The Company’s branch office in Argentina provides administrative assistance to NWA. Specifically, the Company pays cash calls and collects revenues pertaining to NWA’s interest.
As of December 31, 2010 and 2009, the balances of related party transactions were as follows:
For the years ended December 31, 2010, 2009 and 2008, revenues and expenses derived from related party transactions were as follows:
(7)
Accrued Liabilities
At December 31, 2010 and 2009 accrued liabilities consisted of the following:
(8)
Income Taxes
The Company incorporated in the Cayman Islands in 1979. Since then, the Company’s income, to the extent that it is derived from sources outside the U.S., is not subject to U.S. income taxes. Also, the Company has been granted an undertaking from the Cayman Islands government, expiring in 2019, to the effect that the Company will be exempt from tax liabilities resulting from tax laws enacted by the Cayman Islands government subsequent to 1979. The Cayman Islands currently has no applicable income tax or corporation tax. All of the Company’s income during 2010, 2009, and 2008 was generated outside the United States.
The effective income tax rate reflected in the Consolidated Statements of Income differs from Argentina’s statutory rate of 35 percent. This is because the Company currently incurs income taxes only in Argentina where all of its oil and gas income generating activities are presently located. Additionally, equity income from Argentine investment is recorded by the Company on an after tax basis. The Company also generates income and incurs expenses outside of Argentina that are not subject to income taxes in Argentina or in any other jurisdiction. Therefore these amounts do not affect the amount of income taxes paid by the Company. Such items include interest income resulting from the Company’s cash and cash equivalents deposited in its Cayman Island and Bahamas bank accounts, general and administrative expenses incurred by the Company in its headquarters office in Tulsa, Oklahoma, and foreign exchange gains and losses resulting from changes in the value of the peso which do not affect taxable income in Argentina. The Company also incurred expenses related to exploration activity in Colombia that provide no benefit to income tax expense until these activities generate sufficient taxable income in Colombia.
The Company recorded expenses for Argentine taxes as presented in the following table. Amounts are stated in thousands. The Company is not subject to taxes in any other jurisdiction.
Reconciliations from the provision for income taxes from continuing operations at the Argentine statutory rate to the realized provision for income taxes as follows:
Income taxes payable at December 31, 2010 and 2009 were $3.2 million and $3.7 million, respectively. The deferred Argentine income tax benefit relates primarily to certain costs capitalized for Argentine tax purposes and the tax effect of accrued benefit plan obligations included in Accumulated Other Comprehensive Loss that are expensed for financial reporting purposes.
The deferred tax asset at December 31 for each of the years presented consists of the following. Amounts are stated in thousands:
The valuation allowance at December 31, 2010 serves to reduce the recognized tax benefit associated with a foreign carryover to an amount that will, more likely than not, be realized. We do not expect to be able to utilize the $2 million of foreign deferred tax assets until such time as we generate sufficient taxable income in Colombia to absorb the carryover losses.
As of December 31, 2010 and December 31, 2009, the Company had no unrecognized tax benefits or reserve for uncertain tax positions.
It is the Company’s policy to recognize tax related interest and penalties as a component of income tax expense. The statute of limitations for income tax audits in Argentina is six years and the tax years 2003 through 2010 remain open to examination.
(9)
Defined Contribution Retirement Plan
In April 2004, the Company formed a defined contribution retirement benefit plan for its Argentine employees. Assuming the current level of staffing, future annual contributions are expected to range between $50 thousand to $150 thousand and will be charged to expense as earned. In March 2011, the Company made a contribution of $100 thousand. This amount was accrued as administrative expense in 2010. The total amount expensed in 2009 was $96 thousand. Plan contributions are based on employees’ current levels of compensation and years of service. Employees vest at a rate of 20 percent per year with full vesting after five years.
(10)
Long-Term Liabilities
At December 31, 2010 and 2009, long-term liabilities consisted of the following. Amounts are stated in thousands:
Retirement plan obligations represent the Company’s proportionate share of the obligation arising from the pension plan that covers all employees of Petrolera, the operator of the Entre Lomas concession. The Company’s proportionate share of the projected benefit obligation at December 31, 2010 and 2009, was $2.3 million and $2.4 million, respectively, while the fair value of plan assets (which are invested in money market mutual funds and treasury federal funds) was $1.6 million and $1.4 million, respectively. The Company expects its contributions in 2011 to be less than $200 thousand.
(11)
Contingencies and Commitments
Certain conditions may exist as of the date of financial statements which may result in a loss to the Company but which will only be resolved when one or more future events occur or fail to occur. Contingent liabilities are assessed by the Company’s management based on the opinion of the Company's legal counsel and available evidence. Such contingencies could include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company’s business, as well as third party claims arising from disputes concerning the interpretation of legislation. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount can be estimated, a liability is accrued. If the assessment indicates that a potential loss contingency is not probable, but is reasonably possible, or is probable but it cannot be estimated, then the nature of the contingent liability, together with an estimate of the possibility of occurrence, is disclosed in a note to the financial statements. Loss contingencies considered remote are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed. However, in some instances in which disclosure is not otherwise required, the Company may disclose contingent liabilities of an unusual nature which, in the judgment of management, may be of interest to the users of the financial statements. As facts concerning contingencies become known to the Company, the Company reassesses its position both with respect to accrued liabilities and other potential exposures.
In November of 2004, the Company received a formal notice from the Banco Central de la Republica Argentina (the Central Bank of Argentina or the “BCRA”), of certain proceedings based upon alleged violation of foreign currency regulations. Specifically, the BCRA claimed that between December of 2001 and November of 2002 the Company failed to bring into the country 100 percent of the foreign currency proceeds from its Argentine oil exports. In 1989, the government established guidelines that required most oil companies to bring into Argentina 30 percent of foreign currency proceeds from exports instead of 100 percent of such proceeds as was generally required of exporters in other industries. In 1991, all foreign exchange controls were lifted by the government. In response to Argentina’s economic crisis of 2001 and 2002, the government reintroduced foreign exchange controls in 2002 and as a result during 2002 the Company repatriated 30 percent of its proceeds from oil exports following the 1989 guidelines. An opinion from Argentina’s Attorney General, however, declared that the benefits granted to the oil and gas industry in 1989 were no longer effective and, therefore, 100 percent of such funds had to be repatriated. This opinion supported the position taken by the Argentine government during 2002. The government then revised its position in 2003 and expressly clarified that oil companies are required to only repatriate 30 percent of such proceeds. The government’s departure from its 2002 position was effective January 1, 2003, leaving some uncertainty in the law with regard to 2002.
The BCRA audited the Company in 2004 and took the position that 100 percent of its foreign currency proceeds from its 2002 exports were required to be returned to the country rather than only 30 percent, as had been returned to the country by the Company in 2002. The difference for the Company totals $6.2 million. In December 2004, the Company filed a formal response disagreeing with the position taken by the BCRA. In addition, without admitting any wrongdoing, the Company brought into the country $6.2 million and exchanged this amount for Argentine pesos using the applicable exchange rates required by the regulation.
To date, this process has not advanced beyond what is described in the previous paragraphs. The Company anticipates that this matter will remain open for some time. Under the pertinent foreign exchange regulations, the BCRA may impose significant fines on the Company; however, historically few fines have been made effective in those cases where the foreign currency proceeds were brought into the country and traded in the exchange market at the adequate exchange rate and the exporters had reasonable grounds to support their behavior. As a result, it is premature to reach a conclusion as to the probability of an ultimate outcome or the amount of any loss to the Company that might result from this proceeding. There have been no new developments with regard to this matter since the Company filed its formal response in December 2004.
Commitments
Commitments for international oil and gas activities including drilling and seismic investments for concession extensions are approximately $30.8 million at December 31, 2010. Additionally, 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.
(12)
Subsequent Events
In January 2011, a letter of credit of $4 million for exploration activities in Colombia expired and a second letter of credit which will expire in January of 2013 was issued and collateralized by $2.9 million of cash.
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.
(13)
Quarterly Financial Data (Unaudited)
Net income for the fourth quarter of 2010 includes a $524 thousand unfavorable pre-tax adjustment to operating expenses and a $442 thousand adjustment to our equity income from our Argentine investment due to the recognition of environmental remediation costs in our Neuquén basin properties.
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Oil and Natural Gas Reserves
Proved Oil, Condensate and Plant Products
The following table summarizes changes in quantities and balances of net proved oil, condensate and plant product reserves for each of the years presented. All of our reserves are located in Argentina. Ninety-nine percent of net proved oil reserves as of December 31, 2010, were audited by our independent reserve engineer, Ralph E. Davis Associates, Inc. (“Davis”), and one percent was audited by RPS Energy.
·
Volumes presented in the above table have not been reduced by the approximately 12 percent provincial production tax that is paid separately and is accounted for as an expense by Apco.
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Natural Gas
The following table summarizes changes in quantities and balances of net proved natural gas reserves for each of the years presented. All of our reserves are located in Argentina. As of December 31, 2010, 91 percent of the net proved natural gas reserves was audited by Davis and nine percent was audited by RPS Energy.
·
A portion of our natural gas reserves are consumed in field operations. The volume of natural gas reserves for 2008, 2009, and 2010 estimated to be consumed in field operations included as proved natural gas reserves within consolidated interest is 14.8 bcf, 13.8 bcf, and 14.8 bcf, respectively, and within the equity interest is 15.6 bcf, 13.7 bcf, and 16.6 bcf.
·
Volumes presented in the above table have not been reduced by the approximately 12 percent provincial production tax that is paid separately and is accounted for as an expense by Apco. The tax is paid on volumes sold to customers, but not on natural gas consumed in operations.
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
The increase in our total proved reserves for 2010 is attributable to successful development drilling that resulted in upgrading reserves previously classified as probable and possible to proved and successful exploration discoveries. Revisions in 2010 of natural gas reserves relating to our consolidated interest are primarily a result of lower than expected production performance in our Northwest basin properties. There were no estimates of total proved net oil or gas reserves filed with any other United States Federal authority or agency during any of the years presented. The new rules and expanded definitions of oil and gas reserves supported by reliable technologies and practices have not had a material impact on our current estimate of reserves.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves. During 2009 we adopted prescribed accounting revisions associated with oil and gas authoritative guidance. Those revisions include using the 12-month average price computed as an un-weighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. These revisions are reflected in our 2010 and 2009 amounts. For the years-ended December 31, 2010 and 2009, the average oil prices used in the estimates were $52.11 and $43.62 per barrel. For the year ended December 31, 2008, the year-end oil price used in the estimate was $46.94 per barrel.
For the years-ended December 31, 2010 and 2009, the average natural gas prices used in the estimates were $1.63 and $1.93 per mcf. Future natural gas revenues included in the standardized measure consist of estimated natural gas production volumes, net of natural gas volumes consumed in operations as described in the footnote in the natural gas reserves table above. For the year ended December 31, 2008, the year-end natural gas price used in the estimate was $1.86 per mcf. Prior to the year-ended December 31, 2009, values for natural gas consumed in field operations were included both as revenues in future cash inflows and as gas consumption expense in future production and development costs. For the year 2008, the amounts attributable to natural gas consumption that were included as both revenues and natural gas consumption expense in Consolidated Interests are $27 million and $24 million in Equity Interests.
Future income tax expenses have been computed considering applicable taxable cash flows and the appropriate statutory tax rate. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. Conversion of U.S. dollars is made utilizing the rate of exchange at December 31 for each of the years presented. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Standardized Measure of Discounted Future Net Cash Flows
The following tables summarize the standardized measure of discounted future net cash flows from proved oil and natural gas reserves that could be produced from our concessions in Argentina for each of the years presented:
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Changes in Standardized Measure
The following analysis summarizes the factors that caused the changes in the amount of standardized measure attributable to the estimate of our Argentine proved oil and gas reserves for each of the years presented.
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Capitalized Costs Related to Oil and Gas Producing Activities
Total capitalized costs related to oil and gas producing activities for our consolidated interests are as follows:
Total capitalized costs related to oil and gas producing activities net to our equity interests included in the balance sheet of our equity investee, Petrolera, are as follows:
APCO OIL AND GAS INTERNATIONAL INC.
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Costs Incurred in Acquisitions, Exploration, and Development
The following table details costs incurred for acquisitions, exploration, and development during 2008, 2009 and 2010. Costs incurred include capitalized and expensed items.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
See “Management’s Annual Report on Internal Control over Financial Reporting” set forth in Item 8, “Financial Statements and Supplementary Data.”
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Changes in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. Other Information
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Directors and Executive Officers
Our articles of association provide for a Board of Directors of not less than three and not more than nine persons. The articles of association also provide that at each annual general meeting of shareholders one-third of the directors, or if their number is not three or a multiple of three, then the number nearest one-third, must retire from office. The directors to retire in every year are those who have been longest in office since their last election and retiring directors are eligible to be re-elected as directors. Between persons who become directors on the same day those to retire are determined by lot unless they otherwise agree among themselves as to who will retire. Directors appointed by the Board of Directors to fill a vacancy or as an addition to the existing directors hold office until the next following annual meeting of shareholders and are not taken into account in determining the directors who are to retire by rotation as described above. Mr. Piero Ruffinengo was last elected as a director at the annual general meeting of shareholders held in 2007. Messrs. Keith E. Bailey and Messrs. Ralph A. Hill were last elected as directors at the annual general meeting of shareholders held in 2008. Messrs. Robert J. LaFortune and John H. Williams were last elected at the annual general meeting of shareholders held in 2009. Messrs Bryan K. Guderian and Rodney J. Sailor were last elected as directors at the annual general meeting of shareholders held in 2010. The number of directors is currently seven and if this number remains the same by the next annual general meeting of shareholders, the term of Mr. Ruffinengo and the term of one of Messrs. Bailey or Hill will expire at such meeting. Our executive officers are elected by the Board of Directors and hold office until relieved of such office by action of the Board of Directors.
The following table sets forth certain information with respect to our executive officers and members of the Board of Directors.
Business Experience and Qualifications
Below is information about our directors and executive officers, including experience in the following areas that are important qualifications for directors in the context of our business and structure:
·
Industry Experience in the oil and natural gas exploration and production business.
·
Financial Experience with which to evaluate our financial statements and capital investments.
·
Corporate Governance Experience to support our goals of accountability for management and the Board of Directors and protection of shareholders interests.
·
Legal Experience is valuable to the Board of Director’s oversight of our legal and regulatory compliance.
·
Operating Experience which is relevant to the understanding of our operating plan and strategy.
·
International Business Experience because all of our operations are in South America.
Mr. Hill has served as a director of the Company, Chairman of the Board of Directors, and Chief Executive Officer since 2002. Since 2003 he has served as a Senior Vice President of The Williams Companies, Inc. (“Williams”) (an integrated natural gas company focused on exploration and production, midstream gathering and processing, and interstate natural gas transportation primarily in the Rocky Mountains, Gulf Coast, Pacific Northwest, Eastern Seaboard, and Marcellus Shale in Pennsylvania) and acts as the President of Williams exploration and production unit. He joined Williams in 1981 and has held various positions in Williams’ exploration and production, gas marketing, and petroleum services businesses. Mr. Hill has served as a director of Petrolera Entre Lomas S.A. (“Petrolera”) since 2003.
Mr. Hill’s qualifications include industry, financial, operating, and international business experience.
Mr. Bailey has served as a director of the Company since 2002. He has served as a director and Chairman of the Board of Cloud Peak Energy Inc. (a U.S. coal producer) since September 2009. Since 2005, Mr. Bailey has served as a director of the general partner of Mark West Energy Partners, L.P. (“MarkWest”) (a U.S. midstream energy company), and serves on its Corporate Governance Committee and is Chairman of its Compensation Committee. Mr. Bailey formerly served on MarkWest’s Finance Committee and as the Chairman of its Audit Committee. He has served as a director of AEGIS Insurance Services Inc. (a mutual insurance company) since 2001 and serves on its Investment Committee. Since 2007, Mr. Bailey has served as a director of Integrys Energy Group, Inc. (“Integrys”) (which provides services and products in the regulated and unregulated U.S. energy markets) and serves on its Audit Committee and as the Chairman of its Finance Committee. He served as a director and was a member of the Audit and Oil and Gas Committees of People’s Energy from 2005 to 2007, when People’s Energy merged with Integrys. Mr. Bailey served as Chairman of the Board and Chief Executive Officer of Williams from 1994 to 2002, as President from 1992 to 2001, and as Executive Vice President and Chief Financial Officer from 1986 to 1992. Mr. Bailey previously served as a director of the Company from 1987 to 1998 and as our Chairman of the Board from 1992 to 1996. He served as a director of Petrolera from 1988 to 1999.
Mr. Bailey’s qualifications include industry, financial, corporate governance, and operating experience.
Mr. Guderian has served as a director of the Company since 2002. He has also served as Vice President of Williams’ exploration and production unit since 1998, where he is a member of the management team that pursued a growth strategy to transform the company into a top independent natural gas producer in the U.S. Mr. Guderian has served as a director of Petrolera since 2003. He is a member of numerous professional organizations, including the Independent Petroleum Association of America, the Natural Gas Supply Association, the American Association of Professional Landmen, and the Oklahoma Independent Petroleum Association.
Mr. Guderian’s qualifications include industry, financial, corporate governance, operating, and international business experience.
Mr. LaFortune has served as a director of the Company since 1998. He is self-employed and manages, evaluates, and analyzes personal investments. Mr. LaFortune is also a director of the Bank of Oklahoma Financial Corporation (a regional financial services company based in Tulsa, Oklahoma) and serves on the Credit Committee and formerly served on its Audit Committee. He served as a director of Williams from 1978 to 1999, including six years as Chairman of its Audit Committee. He was the Mayor of the City of Tulsa from 1970-1978 and the Commissioner of Streets and Public Property for the city from 1964 to 1970. Mr. La Fortune was a co-owner of an independent U.S. oil and gas exploration and production company from 1956 to 1963. He is also a member of the National Executive Board of the Boy Scouts of America, a member of the Executive Committee of the Philbrook museum, a member of the Board of Trustees of the Tulsa Performing Arts Center, and Vice-Chairman of the Board and Chairman of the Audit Committee and Compliance Committee of St. John Health System.
Mr. La Fortune’s qualifications include industry, financial, and corporate governance experience.
Mr. Sailor has served as a director of the Company since 2006. He has served as Vice President and Treasurer of Williams since 2005 and is responsible for overseeing Williams’ enterprise risk management function. Mr. Sailor served as Assistant Treasurer of Williams from 2001 to 2005 and was responsible for capital structuring and capital markets transactions, and management of Williams’ liquidity position. Mr. Sailor served as Vice President of Strategic International Development and Latin America for the former telecommunications business unit of Williams from 1999 to 2001. He held various positions at Williams involving international finance, corporate finance, strategic planning and development, and accounting from 1985 to 1999. Mr. Sailor served as a director of Williams Partners GP LLC, the general partner of Williams Partners L.P. (“WPZ”) (a publicly traded master limited partnership formed by Williams that is focused on natural gas transportation, gathering, treating and processing, storage, natural gas liquids fractionation, and oil transportation), from October 2007 to February 2010. He served as a director of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P. (“WMZ”) (a limited partnership formed by Williams that owned and operated natural gas transportation and storage assets), from January 2008 until WMZ merged with WPZ in August 2010.
Mr. Sailor’s qualifications include financial, industry, and international business experience.
Mr. Williams has served as a director of the Company since 1992. He is engaged in personal investments and has been for more than five years. Mr. Williams has over 60 years of experience in the energy industry. In 1949, he co-founded Williams and served as a director and its President and Chief Executive Officer from 1949 to 1978 and as Chairman of the Board from 1971 to 1978. Mr. Williams worked on pipeline construction projects in the U.S. and internationally for the family business that preceded Williams from 1946 to 1949. He has served as a director of Unit Corporation (a diversified energy company engaged in the exploration for and production of oil and natural gas, the acquisition of producing oil and natural gas properties, the contract drilling of onshore oil and natural gas wells, and the gathering and processing of natural gas) since 1988. Mr. Williams is an honorary director of Willbros Group, Inc. and Williams. He formerly served as a director of Petrolera.
Mr. Williams’ qualifications include industry, financial, corporate governance, operating, and international business experience.
Mr. Ruffinengo has served as a director of the Company since 2002. He has been engaged in the private practice of law in Salt Lake City, Utah since 1984. He served the Company as a consultant from 1984 through 1999. Mr. Ruffinengo served in a variety of positions for Northwest Energy Company (“Northwest Energy”) and its subsidiary, Northwest Pipeline Corporation (“Northwest Pipeline”), from 1975 to 1983, when Northwest Energy was acquired by Williams. Those positions included General Counsel of Northwest Pipeline and the Company, Vice President of Mergers and Acquisitions, and Vice President of International Operations. Over his career, Mr. Ruffinengo has practiced law in the areas of corporate governance and compliance, commercial transactions, oil and gas law, intellectual property, finance, and domestic and international litigation. Mr. Ruffinengo served as a director of Petrolera at various times in the past and most recently from 2002 to 2003.
Mr. Ruffinengo’s qualifications include industry, financial, corporate governance, legal, and international business experience.
Mr. Fullmer has served as our Chief Financial Officer since 2003 and as our Chief Accounting Officer and Controller since 2005. He currently serves as the director of finance and accounting business partner for the Exploration and Production unit of Williams. Mr. Fullmer served as the director of accounting/controller for the Exploration and Production unit of Williams from 1996 to 2007.
Mr. Bueno has served as our President and Chief Operating Officer since 2002. He served as a director of the Company from 1998 until becoming President in 2002 and he served as General Manager from 1999 to 2003. Mr. Bueno has been employed by Williams since 1984 and has held various positions with the Company since 1985. He has served as a director of Petrolera since 1991.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s officers and directors and persons who own more than ten percent of a registered class of the Company’s equity securities, to file with the SEC and The Nasdaq Stock Market reports of ownership of Company securities and changes in reported ownership. Officers, directors and greater than ten percent shareholders are required by SEC rules to furnish the Company with copies of all Section 16(a) reports they file. Based solely on a review of the reports furnished to the Company, or written representations from reporting persons that all reportable transactions were reported, the Company believes that during the fiscal year ended December 31, 2010 the Company’s officers, directors and greater than ten percent owners timely filed all reports they were required to file under Section 16(a).
Code of Ethics
The Company adopted a Code of Ethics that applies to the Company’s directors, officers and employees. The Code of Ethics is consistent with the criteria for codes of ethics and conduct established by the rules of the U.S. Securities and Exchange Commission and the listing standards of The Nasdaq Stock Market. The Code of Ethics is also available on our Internet website at http://www.apcooilandgas.com under the “Investor Relations” tab. We will also provide, free of charge, a copy of any of our Code of Ethics upon written request to the Corporate Secretary, Apco Oil and Gas International Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172. We intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our directors and executive officers, principal accounting officer, or controller on our Internet website at http://www.apcooilandgas.com under the “Investor Relations” tab, promptly following the date of any such amendment or waiver.
Corporate Governance
Audit Committee
The Company’s Board of Directors has a separately-designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee include Messrs. Bailey, LaFortune, Ruffinengo, and Williams. The Board of Directors has determined that each of these persons meets the independence and other qualification requirements of the rules of The Nasdaq Stock Market. In addition, the Board of Directors has determined that Mr. Bailey qualifies as an “audit committee financial expert” as defined by the rules of the SEC. Biographical information for Mr. Bailey is set forth above under the caption “Business Experience and Qualifications.” For more information about the Audit Committee, please read “Certain Relationships and Related Transactions, and Director Independence - Corporate Governance” and “Principal Accountant Fees and Services.”
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
The Company is managed by the employees of Williams and all of our executive officers are employees of Williams. The Company’s executive officers are compensated directly by Williams rather than by the Company. All decisions as to the compensation of the Company’s executive officers are made by Williams. Therefore, the Company does not have any policies or programs relating to compensation of its executive officers and does not make any decisions relating to such compensation. A full discussion of the policies and programs of Williams will be set forth in the proxy statement for Williams’ 2011 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors - SEC Filings.” Williams charges the Company, pursuant to an administrative services agreement, an annual flat fee for the services of certain Williams’ employees, other than Mr. Bueno, who dedicate a significant amount of time to the affairs of the Company. Williams also charges the Company, pursuant to the terms of the same agreement, a fee for Mr. Bueno’s services based on both his actual total compensation and an estimated percentage of his time that is dedicated to performing services for the Company. Please read “Certain Relationships and Related Transactions, and Director Independence - Transactions with Related Persons - Administrative Services Agreement and - Review, Approval or Ratification of Transactions with Related Persons” for more information regarding this arrangement.
Executive Compensation
In 2010, the Company incurred an allocated charge of $180,059 for Mr. Bueno's salary and $128,989 for his cash incentive bonus. In 2009, the Company incurred an allocated charge of $173,504 for Mr. Bueno's salary and $108,478 for his cash incentive bonus. In 2008, the Company incurred an allocated charge of $160,793 for Mr. Bueno's salary and $95,963 for his cash incentive bonus. Each year the Company also incurs a charge for Mr. Bueno’s benefits, including without limitation his pension and welfare benefits, which charge is equal to approximately 33 percent of the allocated charge incurred by the Company for Mr. Bueno’s salary in that year. This benefits charge was $60,020 in 2010, $57,835 in 2009 and $53,598 in 2008.
Further information regarding the compensation of our principal executive officer, Ralph A. Hill, who also serves as a Senior Vice President of Williams, will be set forth in the proxy statement for Williams' 2011 annual meeting of stockholders which will be available upon its filing on the SEC's website at http://www.sec.gov and on Williams' website at http://www.williams.com under the heading "Investors-SEC Filings." Further information regarding the portion of Mr. Hill's compensation and that of Landy L. Fullmer, who serves as the Company’s Chief Financial Officer, allocable to us may be found in this filing under the heading "Certain Relationships and Related Transactions, and Director Independence - Transactions with Related Persons - Administrative Services Agreement."
Compensation Committee Interlocks and Insider Participation
The Board of Directors of the Company does not maintain a compensation committee. The executive officers of the Company during 2010 were employees of Williams and compensation decisions with respect to those individuals were determined by Williams.
Compensation Policies and Practices as They Relate to Risk Management
All of our employees are located in Argentina. We do not believe that our compensation policies and practices create risks reasonably likely to have a material adverse effect on us. Our executive officers and certain other persons who provide services to us pursuant to an administrative services agreement are employees of Williams. For more information about this arrangement, please read “Certain Relationships and Related Party Transactions, and Director Independence - Transactions with Related Persons - Administrative Services Agreement.” For an analysis of any risks arising from Williams’ compensation policies and practices, please read the proxy statement for Williams’ 2011 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors - SEC Filings.”
Compensation of Directors
Directors who are employees of Williams receive no compensation for service on the Company’s Board of Directors. Directors who are not employees of Williams or an affiliate of the Company or Williams (“Non-Management Directors”) receive a quarterly fee of $12,500 cash for Board service. In addition, the Chairman of the Audit Committee receives a quarterly fee of $2,500 cash and the Chairman of the Nominating Committee receives a quarterly fee of $1,250 in cash. Each Non-Management Director receives a fee of $1,000 for each Board and committee meeting attended by such director, provided that such fee is limited to $1,000 per day regardless of the number of meetings attended on a given day. Fees are paid quarterly in arrears. Directors are also reimbursed for reasonable expenses (including costs of travel, food and lodging) incurred in attending meetings of the Board, committee, and shareholder meetings. Directors are also reimbursed for reasonable expenses associated with other business activities, including participation in director education programs.
For their service, Non-Management Directors received the following compensation in 2010:
(1)
This column includes quarterly and meeting attendance fees earned for each person in 2010.
Compensation Committee Report
The Board of Directors does not have a compensation committee. The Board has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.
The Board of Directors:
Keith E. Bailey, Bryan K. Guderian, Ralph A. Hill,
Robert J. LaFortune, Piero Ruffinengo,
Rod J. Sailor, John H. Williams
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth the number of ordinary shares and the percentage represented by such number of each person who is known to us to own beneficially five percent or more of our ordinary shares. We obtained certain information in the table from filings made with the SEC.
(1)
A Schedule 13D/A filed on February 18, 2011 indicates that Williams Global Energy (Cayman) Limited (“Williams Global Energy”) is the record holder of 20,301,592 of our ordinary shares. The Schedule 13D/A further indicates that Williams Global Energy is an indirect, wholly owned subsidiary of The Williams Companies, Inc. The address of Williams is One Williams Center, Tulsa, Oklahoma 74172. The address of Williams Global Energy is Ugland House, South Church Street, George Town, Cayman Islands, KY1-1104.
(2)
A Schedule 13G filed with the SEC on January 10, 2011 indicates that NSB Advisors LLC (“NSB”), is an Investment Advisor registered under Section 203 of the Investment Advisors Act of 1940 and has sole dispositive power for 6,129,653 of our ordinary shares. The address of NSB is 200 Westage Business Center Drive, Suite 228, Fishkill, NY 12524.
The following table sets forth, as of March 1, 2011, the number of our ordinary shares beneficially owned by each of our directors, each of our executive officers, and by all directors and executive officers as a group. The persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them, subject to community property laws where applicable.
Percentage of shares beneficially owned is based on 29,441,240 ordinary shares outstanding.
___________________
* Less than one percent.
The following table sets forth, as of March 1, 2011, the number of shares of common stock of The Williams Companies, Inc., beneficially owned by each of our directors, each of our named executive officers, and by all directors and executive officers as a group. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them, subject to community property laws where applicable.
Percentage of common stock beneficially owned is based on 587,641,048 shares outstanding on March 1, 2011.
____________________
* Less than one percent.
(1)
Includes shares held under the terms of incentive and investment plans as follows: Mr. Bueno, 9,788 restricted stock units; Mr. Fullmer, 313 shares in The Williams Companies Investment Plus Plan and 3,405 restricted stock units; Mr. Guderian, 41,870 restricted stock units; Mr. Hill, 632 shares in The Williams Companies Investment Plus Plan and 229,274 restricted stock units; Mr. Sailor, 244 shares in The Williams Companies Investment Plus Plan and 37,527 restricted stock units. Restricted stock units, formerly referred to as deferred stock, includes both time-based and performance-based units and do not have voting or investment power. Shares held in The Williams Companies Investment Plus Plan have voting and investment power.
(2)
Includes 991,210 shares held in trust by Mr. Williams and 16,246 shares held in trust by his spouse; 224 shares held in trust by Mr. Bailey and 1,740 shares held in trust by his spouse; and 55,346 shares held in trust by Mr. LaFortune.
(3)
The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of March 1, 2011. Shares subject to options cannot be voted.
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. A wholly owned subsidiary of Williams currently owns approximately 69 percent of our outstanding ordinary shares. 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. For more information, please read “Management’s Discussion and Analysis of Financial Results and Results of Operations - Potential Change in Control - Williams’ Separation Plan.”
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Transactions with Related Persons
Administrative Services Agreement
Williams owns 69 percent of the Company’s ordinary shares. The Company incurred charges of $1.3 million in fiscal year 2010 from Williams and its affiliates for management services, rent, overhead allocation, general and administrative expenses (including the costs of compensating employees of Williams who allocate a portion of their time to managing the affairs of the Company), insurance, internal audit services, and purchases of materials and supplies. The Company is also dependent upon Williams to cover certain other costs such as reproduction, office supplies, computer support, etc for which it reimburses Williams. These charges were incurred by the Company pursuant to an administrative services agreement between the Company and Williams.
The Company is managed by employees of Williams and all of its executive officers, including Mr. Hill, our Chairman of the Board and Chief Executive Officer, and Mr. Fullmer, our Chief Financial Officer and Chief Accounting Officer, are employees of Williams who are compensated directly by Williams rather than by the Company. Pursuant to the administrative services agreement, Williams charges the Company an executive support charge, which charge is incurred by the Company primarily for the time spent by employees of Williams, other than Mr. Bueno, in managing the affairs of the Company. In 2010, 2009, and 2008 the Company paid an annual aggregate charge of $150,000 for the services of these persons. In addition, Williams also charges the Company, pursuant to the terms of the same agreement, a fee for Mr. Bueno’s services based on both his actual total compensation and an estimated percentage of his time that is dedicated to performing services for the Company. Please read “Executive Compensation - Executive Compensation” for further information regarding the amounts paid by the Company for Mr. Bueno’s services.
Northwest Argentina Corporation
The Company and Northwest Argentina Corporation ("NWA"), a wholly owned subsidiary of Williams, each own a 1.5 percent interest in the Acambuco concession. NWA has no employees and its sole asset is its interest in Acambuco. The Company's branch office in Argentina provides administrative assistance to NWA. Specifically, the Company pays cash calls and collects revenues pertaining to NWA's interest. For the period from January 1, 2010 through March 1, 2011, the Company did not incur any indebtedness to NWA. For the same period, $156 thousand was the largest aggregate amount that NWA owed to the Company, representing the accumulated balance of cash calls paid on NWA's behalf in excess of revenues collected on its behalf. This amount was repaid during 2010.
Review, Approval or Ratification of Transactions with Related Persons
The charter of the Audit Committee of the Company’s Board of Directors provides that the committee will review, on an ongoing basis and approve all related party transactions required to be disclosed pursuant to Item 404(a) of the SEC’s Regulation S-K (“Related Party Transactions”). The Audit Committee’s charter further provides that (i) the committee consider whether a Related Party Transaction is bona fide in the best interest of the Company and (ii) the members of the committee reviewing and taking action on a Related Party Transaction observe any relevant and applicable provisions of the Company’s articles of association and exercise the powers vested in them for the purpose in which they were conferred and not for a collateral purpose. The Audit Committee reviewed and approved each of the related transactions discussed above, including the administrative services agreement and amendments to that agreement, the annual charges to the Company pursuant to the administrative services agreement, and the arrangement with NWA.
Corporate Governance
The Company is a “controlled company” as defined by the rules of The Nasdaq Stock Market because a subsidiary of Williams owns approximately 69 percent of the Company’s ordinary shares. Therefore, the Company is not subject to the requirements of The Nasdaq Stock Market that would otherwise require the Company to have (1) a majority of independent directors on the Board, (2) the compensation of executive officers determined by a majority of independent directors or a compensation committee composed solely of independent directors, and (3) a majority of independent directors or a nominating committee composed solely of independent directors elect or recommend director nominees for selection by the Board. Notwithstanding the foregoing, the Board of Directors has established a Nominating Committee. The Board of Directors also has a standing audit committee. The Board of Directors does not have a Compensation Committee or any other committees performing similar functions. Compensation decisions for the Company’s executive officers are made by Williams. The Board of Directors has determined that it is more appropriate for compensation decisions affecting the Company’s directors who are not employees of Williams to be made by the Board.
The following indicates committee membership as of March 1, 2011.
● = Chairperson
ü = Committee Member
The Board of Directors annually reviews the independence of directors and makes a determination that each director expected to be independent qualifies as an “independent director” as defined by the rules of the Nasdaq Stock Market, including a determination that the director does not have a relationship, which, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities as director. The Board has determined that each of Messrs. Bailey, LaFortune, Ruffinengo, and Williams is an “independent director” under the current rules of The Nasdaq Stock Market. The Board of directors also considered that (i) Mr. Bailey serves as a director of Aegis Insurance Services Inc. (“Aegis”), which participates in the insurance coverage programs of Williams and certain of its affiliates, including the Company; and (ii) Mr. LaFortune serves as a director of Bank of Oklahoma Financial Corporation, which provides banking services to the Company. The Board noted that because Messrs. Bailey and LaFortune do not serve as executive officers and are not significant stockholders of these companies, these relationships would not interfere with the exercise of independent judgment in carrying out responsibilities as a director. In addition, the Board of Directors has determined that each of these persons meets the heightened independence requirements of the Nasdaq Stock Market for audit committee members. Although the Board does not require that members of the Nominating Committee be independent, the Board has determined that its current members are independent as defined by the rules of the Nasdaq Stock Market. Messrs. Guderian, Hill, and Sailor, as employees of Williams, are not independent directors under these standards.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees for professional services provided by Ernst & Young LLP (“E&Y”), the Company’s principal independent registered public accounting firm, for each of the last two fiscal years in each of the following categories are:
Fees for audit services in 2010 and 2009 include fees associated with the annual audit, the audit of the Company’s assessment of internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, and services performed in connection with other filings with the SEC. Audit-related fees in 2010 and 2009 generally include fees for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements. More specifically, these services consisted principally of consultation concerning financial accounting and reporting standards.
The Audit Committee of our Board of Directors is responsible for appointing (subject to shareholder approval), setting compensation for, and overseeing the work of E&Y. The Audit Committee has established a policy regarding pre-approval of all audit and non-audit services provided by E&Y. On an ongoing basis, our management presents specific projects and categories of service to the Audit Committee to request advance approval. The Audit Committee reviews those requests and advises management if the Audit Committee approves the engagement of E&Y. On a quarterly basis, management reports to the Audit Committee regarding the actual spending for such projects and services compared to approved amounts. The Audit Committee may also delegate the ability to pre-approve permissible services, excluding services related to the Company’s internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported on at a subsequent Audit Committee meeting. In 2010 and 2009, 100 percent of E&Y’s fees were pre-approved by the Audit Committee.
The Audit Committee’s pre-approval policy with respect to audit and non-audit services is available on our website at http://www.apcooilandgas.com under the “Investor Relations” tab.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Financial Statements filed in this report are set forth in the Index to Consolidated Financial Statements under Item 8.
(a)
2 and (c)
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto.
Separate financial statements and supplementary data of Petrolera, a 50-percent-or-less owned person are filed as Schedule S-1.
(a)
3 and (b)
The following documents are included as exhibits to this report:
Exhibit
Number
Description +
3.1
-
Memorandum of Association of Apco Oil and Gas International Inc. (fomerly known as Apco Argentina Inc.) as amended (including Certificate of Incorporation on Change of Name issued by the Registry of Companies, Cayman Islands, dated July 13, 2009), (filed on August 7, 2009 as Exhibit 3.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
3.2
-
Articles of Association of Apco Oil and Gas International Inc. (formerly known as Apco Argentina Inc.) as amended, (filed on August 7, 2007 as Exhibit 3.2 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0- 8933)) and incorporated herein by reference.
4.1
-
Specimen Share Certificate of Apco Oil and Gas International Inc. (filed on August 7, 2009 as Exhibit 4.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
10.1
-
Joint Venture Agreement dated April 1, 1968, among Apco Oil Corporation, Perez Companc and Petrolera (filed on September 26, 1978 with Apco Oil and Gas International Inc.’s Form S-1 (Registration No. 2-62187)) and incorporated herein by reference.
10.2
-
Joint Venture Agreement dated February 29, 1972, among Apco Oil and Gas International Inc., Perez Companc and Petrolera (filed on September 26, 1978 with Apco Oil and Gas International Inc.’s Form S-1 (Registration No. 2-62187)) and incorporated herein by reference.
10.3
-
Joint Venture Agreement dated March 23, 1977, among Apco Oil and Gas International Inc., Perez Companc and Petrolera(filed on September 26, 1978 with Apco Oil and Gas International Inc.’s Form S-1 (Registration No. 2-62187)) and incorporated herein by reference.
10.4
-
Memorandum of Agreement dated August 16, 1979, among the Apco Oil and Gas International Inc., Perez Companc and Petrolera (filed on March 28, 1980 with Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.5
-
Agreement dated December 7, 1983, between Petrolera and YPF regarding the delivery of propane and butane from the Entre Lomas area (filed on April 12, 2983 with Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.6
-
Agreement between the Joint Committee created by the Ministry of Public Works and Services and the Ministry of Energy, YPF and Petrolera Perez Companc S.A. dated December 26, 1990, constituting the conversion to concession and deregulation of the original Entre Lomas contract number 12,507 (filed on April 13, 1992 with Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.7
-
Share purchase agreement by and among Ms. Maria Carmen Sundblad de Perez Companc, Sudacia S.A. and Apco Oil and Gas International Inc. dated October 23, 2002, relating to the purchase by Apco Oil and Gas International Inc. of 27,700 shares of Petrolera (filed on March 28, 2008 as Exhibit 10 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0- 8933)) and incorporated herein by reference.
10.8
-
Share purchase agreement by and between the shareholders of Fimaipu S.A. and Apco Oil and Gas International Inc. dated December 5, 2002, relating to the purchase by Apco Oil and Gas International Inc. of all of the shares of Fimaipu S.A. (filed on March 28, 2003 as Exhibit 10 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
#10.9
-
Administrative Services Agreement by and between The Williams Companies, Inc. and Apco Oil and Gas International Inc. (filed on August 12, 2004 as Exhibit 10.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
10.10
-
English translation of stock purchase agreement by and between the Tower Fund L.P., Apco Oil and Gas International Inc., Netherfield Corporation, Sucursal Tierra del Fuego, Antartida e Islas del Atlantico Sur and ROCH S.A. dated February 25, 2005 relating to the purchase by Apco Oil and Gas International Inc. of 79,752 shares of Rio Cullen-Las Violetas S.A. dated February 25, 2005 (filed on March 14, 2005 as Exhibit 10 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
#10.11
-
Summary of Non-Management Director Compensation Action (filed on August 7, 2009 as Exhibit 10.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
#10.12
-
Amendment No. 1 to Administrative Services Agreement between the Williams Companies, Inc. and Apco Oil and Gas International Inc. dated March 7, 2008 (filed on March 11, 2008 as Exhibit 10.17 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.13
-
English translation of Contrato de Union Transitoria de Empresas agreement by and between the Argentine branch of Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Energia S.A. relating to the Bajada del Palo concession, dated January 26, 2009 (filed on March 16, 2009 as Exhibit 10.13 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.14
-
English translation of agreement between the province of Neuquén Argentina, Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Argentina S.A., effective July 23, 2009, relating to the extension of the terms of the Bajada del Palo and Entre Lomas hydrocarbon concessions located in the Neuquén province for an additional 10 years (filed on August 7, 2009 as Exhibit 10.2 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
* 21
-
Subsidiaries of the registrant
*23.1
-
Consent of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.
*23.2
-
Consent of Independent Petroleum Engineers, RPS Energy.
*24
-
Power of attorney.
*31.1
-
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
*31.2
-
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
**32
-
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*99.1
-
Report of Independent Petroleum Engineers and Geologists, Ralph E. Davis Associates, Inc.
*99.2
-
Report of Independent Petroleum Engineers and Geologists, RPS Energy.
+
In July 2009, the registrant’s name was changed from Apco Argentina Inc. to Apco Oil and Gas International Inc.
*
Filed herewith.
**
Furnished herewith.
#
Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
APCO OIL AND GAS INTERNATIONAL INC.
(Registrant)
By: /s/ Landy L. Fullmer
Landy L. Fullmer
Chief Financial Officer, Chief Accounting Officer, and Controller
Date: March 9, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Ralph A. Hill
Ralph A. Hill
Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
March 9, 2011
/s/ Landy L. Fullmer
Landy L. Fullmer
Chief Financial Officer,
Chief Accounting Officer, and Controller
(Principal Financial Officer and Principal Accounting Officer)
March 9, 2011
/s/ *Keith E. Bailey
Director
March 9, 2011
Keith E. Bailey
/s/ *Rodney J. Sailor
Director
March 9, 2011
Rodney J. Sailor
/s/ *Robert J. LaFortune
Director
March 9, 2011
Robert J. LaFortune
/s/ *Bryan K. Guderian
Director
March 9, 2011
Bryan K. Guderian
/s/ *Piero Ruffinengo
Director
March 9, 2011
Piero Ruffinengo
/s/ *John H. Williams
Director
March 9, 2011
John H. Williams
*By: /s/ Thomas Bueno
March 9, 2011
Thomas Bueno
Attorney-in-Fact
INDEX TO EXHIBITS
Exhibit
Number
Description +
3.1
-
Memorandum of Association of Apco Oil and Gas International Inc. (fomerly known as Apco Argentina Inc.) as amended (including Certificate of Incorporation on Change of Name issued by the Registry of Companies, Cayman Islands, dated July 13, 2009), (filed on August 7, 2009 as Exhibit 3.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
3.2
-
Articles of Association of Apco Oil and Gas International Inc. (formerly known as Apco Argentina Inc.) as amended, (filed on August 7, 2007 as Exhibit 3.2 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0- 8933)) and incorporated herein by reference.
4.1
-
Specimen Share Certificate of Apco Oil and Gas International Inc. (filed on August 7, 2009 as Exhibit 4.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
10.1
-
Joint Venture Agreement dated April 1, 1968, among Apco Oil Corporation, Perez Companc and Petrolera (filed on September 26, 1978 with Apco Oil and Gas International Inc.’s Form S-1 (Registration No. 2-62187)) and incorporated herein by reference.
10.2
-
Joint Venture Agreement dated February 29, 1972, among Apco Oil and Gas International Inc., Perez Companc and Petrolera (filed on September 26, 1978 with Apco Oil and Gas International Inc.’s Form S-1 (Registration No. 2-62187)) and incorporated herein by reference.
10.3
-
Joint Venture Agreement dated March 23, 1977, among Apco Oil and Gas International Inc., Perez Companc and Petrolera(filed on September 26, 1978 with Apco Oil and Gas International Inc.’s Form S-1 (Registration No. 2-62187)) and incorporated herein by reference.
10.4
-
Memorandum of Agreement dated August 16, 1979, among the Apco Oil and Gas International Inc., Perez Companc and Petrolera (filed on March 28, 1980 with Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.5
-
Agreement dated December 7, 1983, between Petrolera and YPF regarding the delivery of propane and butane from the Entre Lomas area (filed on April 12, 2983 with Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.6
-
Agreement between the Joint Committee created by the Ministry of Public Works and Services and the Ministry of Energy, YPF and Petrolera Perez Companc S.A. dated December 26, 1990, constituting the conversion to concession and deregulation of the original Entre Lomas contract number 12,507 (filed on April 13, 1992 with Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.7
-
Share purchase agreement by and among Ms. Maria Carmen Sundblad de Perez Companc, Sudacia S.A. and Apco Oil and Gas International Inc. dated October 23, 2002, relating to the purchase by Apco Oil and Gas International Inc. of 27,700 shares of Petrolera (filed on March 28, 2008 as Exhibit 10 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0- 8933)) and incorporated herein by reference.
10.8
-
Share purchase agreement by and between the shareholders of Fimaipu S.A. and Apco Oil and Gas International Inc. dated December 5, 2002, relating to the purchase by Apco Oil and Gas International Inc. of all of the shares of Fimaipu S.A. (filed on March 28, 2003 as Exhibit 10 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
#10.9
-
Administrative Services Agreement by and between The Williams Companies, Inc. and Apco Oil and Gas International Inc. (filed on August 12, 2004 as Exhibit 10.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
10.10
-
English translation of stock purchase agreement by and between the Tower Fund L.P., Apco Oil and Gas International Inc., Netherfield Corporation, Sucursal Tierra del Fuego, Antartida e Islas del Atlantico Sur and ROCH S.A. dated February 25, 2005 relating to the purchase by Apco Oil and Gas International Inc. of 79,752 shares of Rio Cullen-Las Violetas S.A. dated February 25, 2005 (filed on March 14, 2005 as Exhibit 10 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
#10.11
-
Summary of Non-Management Director Compensation Action (filed on August 7, 2009 as Exhibit 10.1 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
#10.12
-
Amendment No. 1 to Administrative Services Agreement between the Williams Companies, Inc. and Apco Oil and Gas International Inc. dated March 7, 2008 (filed on March 11, 2008 as Exhibit 10.17 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.13
-
English translation of Contrato de Union Transitoria de Empresas agreement by and between the Argentine branch of Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Energia S.A. relating to the Bajada del Palo concession, dated January 26, 2009 (filed on March 16, 2009 as Exhibit 10.13 to Apco Oil and Gas International Inc.’s Form 10-K (File No. 0-8933)) and incorporated herein by reference.
10.14
-
English translation of agreement between the province of Neuquén Argentina, Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Argentina S.A., effective July 23, 2009, relating to the extension of the terms of the Bajada del Palo and Entre Lomas hydrocarbon concessions located in the Neuquén province for an additional 10 years (filed on August 7, 2009 as Exhibit 10.2 to Apco Oil and Gas International Inc.’s Form 10-Q (File No. 0-8933)) and incorporated herein by reference.
* 21
-
Subsidiaries of the registrant
*23.1
-
Consent of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.
*23.2
-
Consent of Independent Petroleum Engineers, RPS Energy.
*24
-
Power of attorney.
*31.1
-
Rule 13a-14(a)/15d-14(a) Certification of the Chief Executive Officer.
*31.2
-
Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer.
**32
-
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*99.1
-
Report of Independent Petroleum Engineers and Geologists, Ralph E. Davis Associates, Inc.
*99.2
-
Report of Independent Petroleum Engineers and Geologists, RPS Energy.
+
In July 2009, the registrant’s name was changed from Apco Argentina Inc. to Apco Oil and Gas International Inc.
*
Filed herewith.
**
Furnished herewith.
#
Management contract or compensatory plan or arrangement.
Schedule S-1
PETROLERA ENTRE LOMAS S.A.
Financial Statements for the fiscal year ended December
31, 2010 with Report of Independent Registered Public
Accounting Firm
PETROLERA ENTRE LOMAS S.A.
TABLE OF CONTENTS TO FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PETROLERA ENTRE LOMAS S.A.:
We have audited the accompanying balance sheets of Petrolera Entre Lomas S.A. (an Argentine corporation) as of December 31, 2010 and 2009, and the related statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Petrolera Entre Lomas S.A. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
Buenos Aires, Argentina
PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
February 25, 2011
(member of Ernst & Young Global)
ENRIQUE C. GROTZ
Partner
PETROLERA ENTRE LOMAS S.A.
BALANCE SHEETS AS OF DECEMBER 31, 2010 AND 2009
(stated in thousands of U.S. dollars)
The accompanying notes are an integral part of these financial statements
PETROLERA ENTRE LOMAS S.A.
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
(stated in thousands of U.S. dollars)
The accompanying notes are an integral part of these financial statements
PETROLERA ENTRE LOMAS S.A.
STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
(stated in thousands of U.S. dollars)
The accompanying notes are an integral part of these financial statements
PETROLERA ENTRE LOMAS S.A.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
(stated in thousands of U.S. dollars)
The accompanying notes are an integral part of these financial statements
PETROLERA ENTRE LOMAS S.A.
NOTES TO FINANCIAL STATEMENTS
(stated in thousands of U.S. dollars, except otherwise indicated)
1. CORPORATE ORGANIZATION
Petrolera Entre Lomas S.A. is an Argentine corporation. As of December 31, 2010 the shareholders of the Company and their participations were as follows:
Apco Argentina S.A. is a wholly owned subsidiary of Apco Oil & Gas International Inc.
The Company is operator and participant in Entre Lomas concession (Entre Lomas, an unincorporated joint venture founded in August 12, 1968) located in Río Negro and Neuquén provinces in southwest Argentina, which is accounted for following the proportional consolidation method.
The concession contract, renegotiated in 1991 and 1994, permitted the concessionaires to freely dispose of their crude oil and natural gas production and extended the concession term through January 21, 2016.
In 2007, the Company acquired a 73.15% participation interest in “Bajada del Palo U.T.E.” joint venture, concessionaire of the hydrocarbons explotation of Bajada del Palo Area, located in the Province of Neuquén. This concession extended through September 7, 2015.
The enactment of Law No. 26,197 in 2007 amending Law No. 17,319, provides the legal framework for the provinces to exercise jurisdiction based on original ownership and to manage the oil and gas fields within their territory. Given this power, the province of Neuquén asked for the renegotiation of the concession terms. The Company accepted to renegotiate the Entre Lomas and Bajada del Palo concessions for another 10 years up to 2026 and 2025, respectively.
During 2009, the Company agreed with the province of Neuquén a 10-year extension to the portion of the exploitation concession of the Entre Lomas area located in such province, and the Bajada del Palo area.
The agreement established a concession fee to be paid in 19 monthly and consecutive installments totaling 12.5 million, which are fully paid as of December 31, 2010, a commitment to make investments and disbursements to operate both areas amounting to 236.6 million to be made between September 1,2008, and the year 2026, and an increase of 3% of the provincial production tax. The Company bears 73.15% of the amounts mentioned, in proportion to the interest it holds in such areas.
PETROLERA ENTRE LOMAS S.A.
The negotiation for the extension of the concession term of the Entre Lomas area located in the province of Río Negro started in October 2010. The Company requested inscription in the Provincial Registry of Concessions Renegotiation and presented the requested documentation. The Province is analyzing the documentation, and once approved, the Company will be notified of the beginning of negotiation.
During 2007, an exploration permit was obtained for Agua Amarga Area in the Province of Río Negro. The permit consists of three periods of three, two and one years respectively. The partners committed investments for 23,2 million mainly in 3D seismic and drilling (17 million relates to 73.15% of PELSA’s interest). To guarantee the fulfillment of all the obligations assumed in the agreement for the first exploration period, the Company purchased a surety bond for the total amount committed. Based on the results of the exploration carried out in the Agua Amarga area, the Company requested the province of Río Negro the exploitation concession of a portion of the area, which was granted for a 25-year term. The remaining area is still subject to the exploratory permit.
The Province of Rio Negro has decided to extend the terms of certain concessions and permits for one year, thus extending the first exploration period of Agua Amarga Area until May 2011. In addition, the completion of the work commitment previously mentioned and the execution of additional works, enable the Company to ask for an additional one-year extension, which has not been granted yet by the Province. If granted, the first exploration period would end on May 2012.
On February 3, 2011, a Joint Venture Agreement between Petrolera Entre Lomas S.A., Petrobras Argentina S.A. and Apco Oil and Gas International Inc- Argentine Branch for the joint exploitation of Agua Amarga block was filed within the Province of Rio Negro.
The partners’ interests in the above mentioned joint ventures as of December 31, 2010 were as follows:
The Company’s interest (73.15%) in assets and liabilities related to the mentioned joint ventures, as of December 2010 and 2009, is as follows:
PETROLERA ENTRE LOMAS S.A.
The Company’s interest (73.15%) in costs and expenses related to joint ventures as of December 2010, 2009 and 2008, is as follows:
2. BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
The financial statements have been prepared in accordance with U.S. generally accepted accounting principles (US GAAP).
The Company has only one business segment and is engaged in the oil and gas exploration, development and production in the Entre Lomas, Bajada del Palo and Agua Amarga joint ventures. All of the Company´s operating revenues and all of its long-lived assets are in Argentina.
Oil and gas operation is high risk in nature. A successful operation requires that a company deal with uncertainties about the subsurface that even a combination of experience, scientific information and careful evaluation cannot always overcome.
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Summary of significant accounting policies
Cash and cash equivalents
Cash and cash equivalents in 2010 and 2009 include highly liquid bank deposits and money market of 32.3 million and 41.7 million, respectively, of which 31.8 million and 41.4 million earned interest with an average rate of 0.53 and 0.56 percent in 2010 and 2009, respectively. The Company considers all investments with an original maturity of three months or less to be cash equivalents. They were valued at quoted prices in active markets (Level 1 of fair value hierarchy).
Other receivables
Mainly includes tax credits.
PETROLERA ENTRE LOMAS S.A.
Inventories
Includes hydrocarbons by 1,135 and 1,333 and material and spare parts by 478 and 400, in 2010 and 2009, respectively, which were accounted for at the lower of cost or market. The cost is determined by the first-in, first-out method.
Other assets
Includes prepaid expenses, long term tax credit and mandatory savings receivable detailed in Note 3.
Property and Equipment
The Company uses the successful-efforts method of accounting for its oil and gas exploration and production activities. Under this method, exploration costs, excluding the costs of exploratory wells, are charged to expenses as incurred. Drilling costs of exploratory wells, including stratigraphic test wells, are capitalized pending determination of whether proved reserves exist which justify commercial development. If such reserves are not found, the drilling costs are charged to exploratory expense of the year. Drilling costs of productive wells and of dry holes drilled for development of oil and gas reserves are capitalized. Non oil and gas property is recorded at cost.
Wells and other oil an gas equipment are depreciated over their productive lives using the unit of production method, by applying the ratio of oil and gas produced to the proved developed oil and gas reserves. The Company’s remaining property and equipment are depreciated by the straight-line method based on their estimated useful lives, resulting in annual rates in a range of 10% to 33%.
Acquisition costs of proved properties are depreciated and depleted by the unit-of-production method, applying the ratio of oil and gas produced to the total proved oil and gas reserves.
The Company reviews its proved properties for impairment and recognizes an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds fair value. For the years ended December 31, 2010, 2009 and 2008, the Company did not experience any impairment indicators.
The oil and gas reserves estimations considered in these financial statements, have been calculated based on technical and economic conditions effective as of each year-end by Petrolera Entre Lomas S.A.’s engineers and are reviewed at least once a year. The Company believes that these estimates are fair and will be adjusted whenever facts or evidence justify it.
As a result of the extension of the concession terms mentioned in Note 1, the present value of the extension cost has been recognized as “Acquisition costs of proved property” as described in Note 5.
Accounting Standards require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset.
PETROLERA ENTRE LOMAS S.A.
The Company’s asset retirement obligation is based on estimates of the number of wells expected to be abandoned through the last year of the concessions term and an estimated cost to plug and abandon a well. Both estimates were provided by the Company’s engineers and are considered to be the best estimates that can be derived today based on present information. Such estimates are, however, subject to significant change as time passes. Given the uncertainty inherent in the process of estimating oil and gas reserves and future oil and gas production streams, the estimate of the number of wells to be plugged and abandoned could change as new information is obtained.
The Company estimates it will not be required to plug and abandon those wells that will continue to be producing wells upon the termination of the concessions. The estimated asset retirement obligation as of December 31, 2010 and 2009 totaled 5,952 and 5,624. The change in total asset retirement obligation from December 31, 2009 to December 31, 2010 mainly relates to the effect of the passage of time, net of wells abandoned during 2010 and changes in the amount of wells planned to be abandoned upon termination of the concessions.
Foreign currency translation
The financial statements have been translated into United States dollars in accordance with ASC 830, Foreign Currency Matters, using the United States dollar as the functional currency.
Fair value of financial instruments
The carrying amount reported in the balance sheet for financial instruments approximates to fair value.
Revenue recognition
The Company recognizes revenues from sales of oil, gas and plant products net of VAT at the time the product is delivered to the purchaser and title has passed. Any product produced that has not been delivered is reported as inventory. When cost is calculated, it includes total per unit operating cost and depreciation. Transportation and storage costs are recorded as expenses when incurred. The Company has had no contract imbalances relating to either oil or gas production.
At the request of the Argentine Government, oil and gas refining companies and oil & gas production companies signed in 2003 an agreement with the intent to maintain the stability of crude oil, gasoline and diesel oil prices (the Agreement).
Under the Agreement crude oil producers and refiners agreed to cap amounts payable for a portion of domestic oil sales contracts at a price of 28.50 per barrel. In addition, producers and refiners also agreed that the excess of the actual price of West Texas Intermediate (WTI), the crude oil type that serves as a reference price for crude oil sales contracts in Argentina, over the 28.50 temporary cap would be payable at such time as WTI fell below 28.50. The debt payable by domestic refiners to producers accrues interest at 7% per annum.
The price stability agreement was renewed until April 30, 2004. However, the decision to not renew the agreement does not terminate the obligation of refiners to reimburse producers for the balances that accumulated from January 2003 through April 2004 if and when the price of WTI falls below 28.50. As of December 31, 2010, the total price credit available to the Company from domestic refiners amounts to 8.4 million and will be recognized in revenues when the price of WTI falls below 28.50 and the Company continues to receive the 28.50 price until its respective price credits are collected. As of December 31, 2010 none of such amounts have been recognized in revenues.
PETROLERA ENTRE LOMAS S.A.
Derivative instruments
The Company does not usually use derivatives to hedge price volatility or for other purposes.
Recently issued accounting pronouncements
Accounting Standards Update 2010-20: Receivables (Topic 310) Disclosures about the credit quality of financial receivables and the allowance for credit losses: requires entities to provide extensive new disclosures about their financial receivables, including credit risk exposures and the allowance for credit losses. Trade receivables with maturities of one year or less that arose from sales of goods or services are excluded from the scope of the new disclosures. Non-public entities will be required to adopt the standard for annual reporting periods ending on or after 15 December 2011.
Accounting Standards Update 2010-06: Fair Value Measurements and Disclosures (Topic 820) Improving disclosures about fair value measurements: requires additional disclosures about fair value measurements, including the amount of transfers between Levels 1 and 2 of the fair value hierarchy, the reasons for transfers in or out of Level 3 of the fair value hierarchy, and activity for recurring Level 3 measures. In addition, the amendments clarify certain existing disclosure requirements and the requirement to provide disclosures about the valuation techniques and inputs used in determining the fair value of assets and liabilities classified as Levels 2 or 3. Effective for reporting periods beginning after 15 December 2009.
The adoption of these rules did not have a significant effect on the Company’s financial statements.
3. MANDATORY SAVINGS RECEIVABLE
The Mandatory Savings Law, enacted in 1988, required all taxpayers to pay a five-year refundable mandatory savings deposit.
After a lengthy process before the courts, the Company paid a 6.7 million mandatory savings deposit in twelve installments during the period July 2000 to June 2001. The deposit is denominated in Argentine pesos and its principal should have been refunded 5 years after the last installment was paid, plus interest based on Banco de la Nación Argentina (Argentine National Bank) savings rate.
The devaluation of the Argentine peso has resulted in a substantial loss in the dollar value of this Argentine peso denominated deposit during 2001 and 2002. As of December 31, 2010, the dollar value of the Company’s deposit is 1.9 million. On June 27, 2006 the Company filed a request for reimbursement and, due to the lack of response from administrative authorities, in 2008, presented a judicial claim pursuing the collection of the total amount paid, plus a market interest rate until its effective collection.
As of the date of issuance of these financial statements, the claim is being processed. According to the Company’s Management and its legal counsel, the Company has solid grounds on which to base its position. The deposit is presented in the balance sheet within other noncurrent assets.
PETROLERA ENTRE LOMAS S.A.
4. INCOME TAX
The Company accounts for income taxes under the liability method in accordance with ASC 740 “Accounting for Income Taxes”.
Under this method, deferred tax assets and liabilities are established for temporary differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities at each year-end.
(1) Amendments to income tax returns for the periods comprised between 2004 and 2008. On August 28, 2009, the Company made use of a tax amnesty implemented by AFIP (Argentine Federal Public Revenue Agency) for the years 2004 through 2007.
Reconciliation of the income tax expense to taxes calculated based on the statutory tax rates is as follows:
The deferred tax assets and liabilities at December 31, 2010 and 2009 are as follows:
PETROLERA ENTRE LOMAS S.A.
Uncertain tax positions
No uncertain tax position as defined in ASC 740-10-25-5 (formerly FIN 48) was identified. The Company does not have unrecognized tax benefits that require disclosure in its financial statements accordingly to that rule. The Company tax years 2005 to 2010 remain subject to examination by the Argentine Tax authority.
5. PROPERTY AND EQUIPMENT
The capitalized cost of property and equipment and the related accumulated depreciation as of December 31, 2010 and 2009 were as follows:
6. RELATED PARTY TRANSACTIONS
As of December 31, 2010 and 2009, the balances from related parties transactions were as follows:
(1) Affiliate of Petrobras Argentina S.A.
PETROLERA ENTRE LOMAS S.A.
For the years ended December 31, 2010, 2009 and 2008, revenues and expenses derived from related parties transactions were as follows:
(1) Affiliate of Petrobras Argentina S.A.
7. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
Major Customers
Sales to customers greater than ten percent of total operating revenues consist of the following:
The balances with Petrobras Argentina S.A. and Esso Petrolera Argentina S.A. are 10,404 and 7,889 as of December 31, 2010 and 14,063 and 5,925 as of December 31, 2009, respectively.
Management believes that the credit risk imposed by this concentration is offset by the creditworthiness of the Company’s customers and that upon expiration, the oil sales contracts of the main customers will be extended or replaced.
PETROLERA ENTRE LOMAS S.A.
8. DEFINED BENEFIT PENSION PLAN
The Company sponsors a defined benefit pension plan which covers all Company employees in payroll as of May 31, 1995. The objective of the plan is to supplement the national social security pension benefits of the employees of the Company. The plan requires from the Company a contribution to a fund, while no contribution is required from employees. The Company invests in high liquidity, low risk investments with minimal or no risk of loss of capital.
The fund's assets have been contributed to a trust and are mainly invested in money market-mutual funds and Treasury federal funds at December 31, 2010. The Bank of New York is the trustee and Towers Watson is the servicing agent.
PETROLERA ENTRE LOMAS S.A.
The prior service cost and actuarial loss included in accumulated other comprehensive income and expected to be recognized in net periodic pension cost during 2011 is 10 and 141, respectively.
The fair value of the plan assets was measured using quoted prices in active markets (Level 1).
The expected long-term rate of return is based on historical performance of the money market-mutual funds.
Contributions
The Company expects to contribute 614 to its pension plan in 2011.
PETROLERA ENTRE LOMAS S.A.
Estimated Future Benefit Payment
The following benefit payments are expected to be paid.
The Company uses a December 31 measurement date for its plan.
9. TAXES PAYABLE AND PAYROLL ACCOUNT AND OTHER LIABILITIES
At December 31, 2010 and 2009, taxes payable and payroll account consisted of the following:
At December 31, 2010 and 2009, current other liabilities consisted of the following:
At December 31, 2010 and 2009, non-current other liabilities consisted of the following:
PETROLERA ENTRE LOMAS S.A.
10. COMPREHENSIVE INCOME
Comprehensive income is as follows:
11. RESTRICTIONS ON RETAINED EARNINGS
Dividends distributed in cash or kind, in excess of taxable income accumulated as of the end of the fiscal year immediately preceding the distribution or payment date, shall be subject to a 35% income tax withholding as single and definitive payment. For the purposes of this tax, accumulated taxable income is defined as net income booked under Argentine GAAP as of the fiscal year-end immediately preceding the effective date of the law plus the taxable income determined as from such year
12. DEBT
On August 15, 2007, the Company arranged a debt agreement with Banco do Brasil S.A., London branch, for a 50 million bank line of credit that bears interest at Libor plus 1.20 percent per annum agreed on a quarterly basis. Such financing is to be used to invest in P&E and exploratory expenses.
Total amount was received by the Company in four disbursements between August 2007 and March2008.
On May 15, 2009, an amendment to the initial agreement was made, whereby the unpaid principal as of such date, amounting to 48.4 million, shall be paid in 15 quarterly installments starting as from February16, 2010. Disbursements cannot be repaid in advance before an average life of two years in accordance with local regulations. Debt accrues interest at an annual rate of Libor plus 2.40%, and interests are payable on a quarterly basis along with the related income tax withholding.
On February 16, 2010, the Company executed a new debt agreement with Banco Santander Río S.A. amounting to USD 3,500,000, to be fully paid in February 2011. It accrues interest at an annual fixed rate of 3.25%, payable every six-month.
On May 14, 2010, the Company arranged a new debt agreement with Banco do Brasil, London Branch, amounting to USD 3,200,000, to be paid in May 2013. It accrues interest at an annual rate of Libor plus 2.50, payable every six months along with the income tax withholding.
PETROLERA ENTRE LOMAS S.A.
On August 17, 2010, the Company executed a new debt agreement with Banco Santander Río S.A., amounting to USD 3,200,000, to be paid in July 2012. It accrues interest at an annual fixed rate of3.85% respectively, payable on quarterly basis.
On November 12, 2010, the Company arranged a new debt agreement with Banco do Brasil S.A., amounting to USD 3,200,000, to be paid in November 2013. It accrues interest at an annual rate of Libor plus 2.75%, payable every six months along with the income tax withholding.
The maturity of debt principal as of year end for the next years is as follows:
As of December 31, 2010, interest and taxes accrued for these loans amount to 1.566 million.
13. CONTINGENCIES
Certain conditions may exist as of the date of financial statements which may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. Such contingent liabilities are assessed by the Company’s management based on the opinion of the Company's legal counsel and the available evidence.
Such contingencies include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company´s business, as well as third party claims arising from disputes concerning the interpretation of legislation.
If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount can be estimated, a liability is accrued. If the assessment indicates that a potential loss contingency is not probable, but is reasonably possible, or is probable but it cannot be estimated, then the nature of the contingent liability, together with an estimate of the possibility of occurrence, is disclosed in a note to the financial statements. Loss contingencies considered remote are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.
As of December 31, 2010 no contingent liabilities have been accrued.
14. SUBSEQUENT EVENTS
Subsequent events have been evaluated through February 25, which is the date these Financial Statements were available to be issud.