Item 1. Business
Executive Summary
Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated under Delaware law in 1989. Our focus is on acquiring exploration, development and producing properties in geological basins with proven active hydrocarbon systems. Our experienced technical, business development and operating personnel have identified low entry cost exploration opportunities in areas with large hydrocarbon resource potential. We operate from our Houston, Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Republic of Indonesia (“Indonesia”); Port Gentil, Republic of Gabon (“Gabon”); and Muscat, Sultanate of Oman (“Oman”) to support field operations in those areas.
We have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). Our ownership of HNR Finance is through several corporations in all of which we have direct controlling interests. Through these corporations, we indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.
Through the pursuit of technically-based strategies guided by conservative investment philosophies, we are building a portfolio of exploration prospects to complement the low-risk production, development and exploration prospects we hold in Venezuela. In addition to our interests in Venezuela, we hold exploration acreage mainly onshore West Sulawesi in Indonesia, offshore of Gabon, onshore in Oman, and offshore of the People’s Republic of China (“China”).
From time to time we learn of possible third party interests in acquiring ownership in certain assets within our property portfolio. We evaluate these potential opportunities taking into consideration our overall property mix, our operational and liquidity requirements, our strategic focus and our commitment to long-term shareholder value. For example, we have received such expressions of interest in acquiring some of our international exploration assets, and we are currently evaluating these potential opportunities. There can be no assurances that our discussions will continue or that any transaction may ultimately result from our discussions.
As of December 31, 2011, we had total assets of $513.0 million, unrestricted cash of $58.9 million and long-term debt of $31.5 million. For the year ended December 31, 2011, we had no revenues from continuing operations and net cash used in operating activities of $52.7 million. As of December 31, 2010, we had total assets of $485.5 million, unrestricted cash of $58.7 million and long-term debt of $81.2 million. For the year ended December 31, 2010, we had no revenues from continuing operations and net cash used in operating activities of $5.3 million.
Petrodelta’s Proved reserves, net to our 32 percent interest, are 43.3 MMBOE at December 31, 2011. Petrodelta’s Probable reserves, net to our 32 percent interest, are 60.5 MMBOE at December 31, 2011. Petrodelta’s Possible reserves, net to our 32 percent interest, are 106.8 MMBOE. Proved plus Probable reserves at 103.8 MMBOE are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies - Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.
In September 2010, our ownership interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) increased from 47 percent to 54.4 percent. In March 2011, the Government of Indonesia and BPMIGAS, Indonesia’s oil and gas regulatory authority, approved the change in ownership interest. In January 2011, our ownership interest in the Budong PSC increased from 54.4 percent to 64.4 percent. In August 2011, the Government of Indonesia and BPMIGAS approved the change in ownership interest. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia - General.
The Lariang-1 (“LG-1”), the first exploratory well on the Budong PSC, spud January 6, 2011. The Karama-1 (“KD-1”), the second exploratory well on the Budong PSC, spud June 20, 2011. See Item 1. Business, Operations, Budong-Budong, Onshore Indonesia - Drilling and Development Activity.
On January 28, 2011, Fusion Geophysical, LLC’s (“Fusion”) 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations - Fusion Geophysical, LLC.
In March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved another one year extension to May 27, 2012 of the second exploration phase on the Dussafu Marin Permit (“Dussafu PSC”). See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon - General.
In March 2011, China National Offshore Oil Corporation (“CNOOC”) granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area to May 2013. See Item 1. Business, Operations, Wab-21, South China Sea - General.
The Dussafu Ruche Marin-A (“DRM-1”), our first exploratory well on the Dussafu PSC, spud April 28, 2011. The DRM-1 is currently suspended pending further exploration and development activities. In November 2011, an additional 545 square kilometers of seismic was acquired on the Dussafu PSC and is being processed. See Item 1. Business, Operations, Dussafu Marin, Offshore Gabon - Drilling and Development Activity.
On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets in Utah’s Uinta Basin (“Antelope Project”). The transaction included the Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”), the Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). See Item 1. Business, Operations, United States Operations, Western United States - Antelope.
Pursuant to the terms of the term loan facility with MSD Energy Investments Private II, LLC, on May 17, 2011, we paid amounts outstanding under the term loan facility with the net cash proceeds received from the sale of our Antelope Project. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 - Long-Term Debt.
In June 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. See Item 1. Business, Operations, United States Operations, Gulf Coast - West Bay Project.
In August 2011, Oman’s Ministry of Oil and Gas approved a one-year extension to May 23, 2013 of the Initial Period of the Exploration and Production Sharing Agreement (“EPSA”) for the Al Ghubar/Qarn Alam License (“Block 64 EPSA”). See Item 1. Business, Operations, Block 64 EPSA, Oman - General.
The Mafraq South-1 (“MFS-1”), the first exploratory well on the Block 64 EPSA, spud October 29, 2011. The Al Ghubar North-1 (“AGN-1”), the second exploratory wells on the Block 64 EPSA, spud December 21, 2011. See Item 1. Business, Operations, Block 64 EPSA, Oman - Drilling and Development Activity.
See Item 1. Business, Operations, Item 1A.
Item 1A. Risk Factors
In addition to other information set forth elsewhere in this Annual Report on Form 10-K, the following factors should be carefully considered when evaluating us.
Our cash position and limited ability to access additional capital may limit our growth opportunities. At December 31, 2011, we had $58.9 million of available cash and, until Petrodelta pays a dividend, our available cash may not be sufficient to meet capital and operational commitments. Having a Petrodelta dividend as our primary source of cash flow limits our access to additional capital, and our concentration of political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, success with our exploration program, possible delay of discretionary capital spending to future periods, or possible sale, farm-out or otherwise monetization of assets as necessary to maintain the liquidity required to run our operations. While we believe that Petrodelta will reinvest any excess cash into Petrodelta in 2012 and 2013 which might otherwise be available for payment of dividends, there is no assurance this will be the case, nor that if the cash is not reinvested that it will be paid as dividends. These factors could have a material adverse effect on our financial condition and liquidity and may limit our ability to grow through the acquisition or exploration of additional oil and gas properties and projects.
We have incurred long-term indebtedness obligations, which significantly increased our leverage. On February 17, 2010, we closed a debt offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes due March 1, 2013. Prior to February 2010, we had no long-term debt obligations. The degree to which we are leveraged could, among other things:
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make it difficult for us to make payments on the debt;
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make it difficult for us to obtain financing for working capital, acquisitions or other purposes on favorable terms, if at all;
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make us more vulnerable to industry downturns and competitive pressures; and
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limit our flexibility in planning for, or reacting to, changes in our business.
Our ability to meet our debt service obligation will depend upon our future performance, which will be subject to financial, business and other factors affecting our operations, many of which are beyond our control. Additionally, the covenants contained in the indenture governing the notes restrict, among other things, our ability to incur certain indebtedness. Any failure to comply with these covenants could result in an event of default under the indenture, which could permit acceleration of the indebtedness under the notes. If our indebtedness were to be accelerated, we cannot assure you that we would be able to repay it.
Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our business, financial condition and results of operations. A general slowdown in economic activity could adversely affect our business by impacting our ability to access additional capital as well as the need to preserve adequate development capital in the interim.
We may not be able to meet the requirements of the global expansion of our business strategy. We have added a significant global exploration component to diversify our overall portfolio. In many locations, we may be required to post performance bonds in support of a work program or the work program may include minimum funding requirements to keep the contract. We may not have the funds available to meet the minimum funding requirements when they come due and be required to forfeit the contracts.
Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins globally carries greater deal execution, operating, financial, legal and political risks. The environments in which we operate are often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant influence over operations and financial control.
We do not directly manage operations of Petrodelta. PDVSA, through CVP, exercises substantial control over Petrodelta’s operations, making Petrodelta subject to some internal policies and procedures of PDVSA as well as being subject to constraints in skilled personnel available to Petrodelta. These issues may have an adverse effect on the efficiency and effectiveness of Petrodelta’s operations.
We hold a minority equity investment in Petrodelta. Even though we have substantial negative control provisions as a minority equity investor in Petrodelta, our control of Petrodelta is limited to our rights under the Conversion Contract and its annexes and Petrodelta’s charter and bylaws. As a result, our ability to implement or influence Petrodelta’s business plan, assure quality control, and set the timing and pace of development may be adversely affected. In addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions that can impact our minority equity investment.
Petrodelta’s business plan will be sensitive to market prices for oil. Petrodelta operates under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected.
A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta. Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, Petrodelta must pay the government of Venezuela the difference. In the event of a significant decline in crude prices, the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying Petrodelta’s business plan or restricting the budget is limited under the Conversion Contract.
An increase in oil prices could result in increased tax liability in Venezuela affecting Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil fluctuate widely. In April 2011, the Venezuelan government published the amended Windfall Profits Tax which establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011[$50 per barrel for 2012]) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds $70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) 95 percent when the average price of the VEB exceeds $100 per barrel. Any increase in the taxes payable by Petrodelta, including the Windfall Profits Tax, as a result of increased oil prices will reduce cash available for dividends to us and our partner, CVP.
Oil price declines and volatility could adversely affect Petrodelta’s operations and profitability, which in turn could affect our dividends and profitability. Prices for oil also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include:
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relatively minor changes in the global supply and demand for oil;
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export quotas;
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market uncertainty;
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the level of consumer product demand;
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weather conditions;
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domestic and foreign governmental regulations and policies;
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the price and availability of alternative fuels;
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political and economic conditions in oil-producing and oil consuming countries; and
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overall economic conditions.
The total capital required for development of Petrodelta’s assets may exceed the ability of Petrodelta to finance such developments. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Petrodelta’s future capital requirements for the development of its assets may exceed the cash available from existing cash flow. Petrodelta’s ability to secure financing is currently limited and uncertain, and has been, and may be, affected by numerous factors beyond its control, including the risks associated with operating in Venezuela. Because of this financial risk, Petrodelta may not be able to secure either the equity or debt financing necessary to meet its future cash needs for investment, which may limit its ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. This could negatively impact our minority equity investment. If we are called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited. Since Petrodelta only executed approximately 69 percent its 2011 planned capital expenditures primarily due to insufficient monetary and contractual support by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2012 budget. Should PDVSA continue in insufficient monetary and contractual support of Petrodelta, underinvestment in the development plan may lead to continued under-perfomance.
The legal or fiscal framework for Petrodelta may change and the Venezuelan government may not honor its commitments. While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the investment necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our experiences in Venezuela demonstrate that such stability cannot be assured. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our minority equity investment in Petrodelta.
PDVSA’s failure to timely pay contractors could have an adverse effect on Petrodelta. PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta is continuing to experience difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is continuing to have an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.
You should not assume that the present value of future net revenues referred to in Item 15. Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A., TABLE V - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the unweighted average price of the first day of the month during the 12-month period before the ending date of the period covered by the reserve report and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in demand, changes in our ability to produce or changes in governmental regulations, policies or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.
We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot give any assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
Our future operations and our investments in equity affiliates are subject to numerous risks of oil and natural gas drilling and production activities. Oil and natural gas exploration and development drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
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shortages or delays in the delivery of equipment;
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shortages in experienced labor;
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pressure or irregularities in formations;
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unexpected drilling conditions;
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equipment or facilities failures or accidents;
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remediation and other costs resulting from oil spills or releases of hazardous materials;
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government actions or changes in regulations;
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delays in receiving necessary governmental permits;
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delays in receiving partner approvals; and
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weather conditions.
The prevailing price of oil also affects the cost of and availability for drilling rigs, production equipment and related services. We cannot give any assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
Operations in areas outside the United States are subject to various risks inherent in foreign operations. Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties
arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States.
Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of the flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:
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the amounts and types of substances and materials that may be released into the environment;
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response to unexpected releases to the environment;
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reports and permits concerning exploration, drilling, production and other operations; and
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taxation.
Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.
The oil and gas business involves many operating risks that can cause substantial losses, and insurance may not protect us against all of these risks. We are not insured against all risks. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:
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fires and explosions;
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blow-outs;
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uncontrollable or unknown flows of oil, gas, formation water or drilling fluids;
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adverse weather conditions or natural disasters;
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pipe or cement failures and casing collapses;
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pipeline ruptures;
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discharges of toxic gases;
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build up of naturally occurring radioactive materials; and
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vandalism.
If any of these events occur, we could incur substantial losses as a result of:
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injury or loss of life;
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severe damage or destruction of property and equipment, and oil and gas reservoirs;
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pollution and other environmental damage;
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investigatory and clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations; and
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repairs to resume operations.
If we experience any of these problems, our ability to conduct operations could be adversely affected.
We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not insurable.
Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major, national and independent oil and natural gas companies for the acquisition of desirable oil and natural gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.
The loss of key personnel could adversely affect our ability to successfully execute our strategy. We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.
Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition. The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences.
Potential regulations regarding climate change could alter the way we conduct our business. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change and the Kyoto Protocol address greenhouse gas emissions, and several countries including the European Union have established greenhouse gas regulatory systems. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and gas that we produce and as a result, negatively impact our financial condition, results of operations and cash flows.
Our business is dependent upon the proper functioning of our internal business processes and information systems and modification or interruption of such systems may disrupt our business, processes and internal controls. The proper functioning of our internal business processes and information systems is critical to the efficient operation and management of our business. If these information technology systems fail or are interrupted, our operations may be adversely affected and operating results could be harmed. Our business processes and information systems need to be sufficiently scalable to support the future growth of our business and may require modifications or upgrades that expose us to a number of operational risks. Our information technology systems, and those of third party providers, may also be vulnerable to damage or disruption caused by circumstances beyond our control. These include catastrophic events, power anomalies or outages, natural disasters, computer system or network failures, viruses or malware, physical or electronic break-ins, unauthorized access and cyber attacks. Any material disruption, malfunction or similar challenges with our business processes or information systems, or disruptions or challenges relating to the transition to new processes, systems or providers, could have a material adverse effect on our financial condition, results of operations and cash flows.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
We have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman to support field operations in those areas. The field office in Port Gentil, Gabon is a month-to-month agreement. At December 31, 2011, we had the following lease commitments for office space:
See Item 1. Business, Operations for a description of our oil and gas properties.
Item 3.
Item 3. Legal Proceedings
In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party with respect to the Antelope Project. On January 11, 2011, in connection with the sale of each party’s interests in the Antelope Project (see Note 4 - Dispositions), we entered into a letter agreement with the private third party wherein the private third party agreed to reimburse us for certain expenses related to the sale of the two parties’ interests in the Antelope Project. The private third party disputes our calculation of the amount owed to us pursuant to the January 11, 2011 letter agreement. On March 11, 2011, we entered into a letter agreement with the private third party regarding certain obligations between the parties related to the JEDA. The private third party disputes our calculation of the amount due pursuant to one of the items in the March 11, 2011 letter agreement. At December 31, 2011, we have a note receivable outstanding from the private third party of $3.3 million (see Note 2 - Summary of Significant Accounting Policies, Accounts and Notes Receivable) and an account payable outstanding to the private third party of $3.6 million related to the purchase in July 2010 of an incremental 10 percent interest in the Antelope Project. In the event that the dispute is not resolved, the parties would arbitrate pursuant to the JEDA. At this time, we cannot predict the outcome of this dispute with the private third party.
On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”), because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Unless that application is approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released.
On June 30, 2011, we filed a voluntary self-disclosure with OFAC to report that we had possibly violated the U.S. sanctions by attempting to remit funds to LOGSA. On September 20, 2011, we received a response from OFAC which stated that OFAC had decided to address the matter by issuing us a cautionary letter instead of pursuing a civil penalty. The cautionary letter represents OFAC’s final response to the apparent violation, but does not constitute a final agency determination as to whether a violation occurred.
On June 30, 2011, we applied for a license with OFAC that would authorize us to pay LOGSA for the fuel provided. In late 2011 and while our June 30, 2011 application was pending with OFAC, OFAC issued a series of general licenses easing U.S. sanctions against Libya which allowed us to pay the full amount we owed LOGSA. As of December 31, 2011, all monies owed to LOGSA had been paid. Our October 26, 2011 application for the return of the blocked funds remains pending with OFAC.
Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe - Energy & Minerals Department and intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler has received nine assessments from a tax inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
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Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.
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Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
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Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
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Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
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One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim.
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Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
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Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock is traded on the NYSE under the symbol “HNR”. As of December 31, 2011, there were 34,317,087 shares of common stock outstanding, with approximately 457 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.
On March 2, 2012, the last sales price for the common stock as reported by the NYSE was $6.31 per share.
Our policy is to retain earnings to support the growth of our business. Accordingly, our Board of Directors has never declared a cash dividend on our common stock.
STOCK PERFORMANCE GRAPH
The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2011, assuming an investment of $100 on December 31, 2006 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.
This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2006 and that all dividends were reinvested.
PLOT POINTS
(December 31 of each year)
Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.
Item 6.
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2011 In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. The selected consolidated financial data have been derived from and should be read in conjunction with our annual audited consolidated financial statements, including the notes thereto.
(1) Certain amounts have been revised. See Notes to Consolidated Financial Statements, Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
(2) Activities under our former Operating Service Agreement in Venezuela are reflected under the equity method of accounting effective April 1, 2006. The results of Petrodelta’s operations from April 1, 2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed.
(3) No cash dividends were declared or paid during the periods presented.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operations
Venezuela
In January 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate for purchases and the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency which was established in the January 2010 Exchange Agreement. The elimination of the 2.60 Bolivars per U.S. Dollar exchange rate for purchases and the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency did not have an impact on our business in Venezuela.
In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The establishment of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.
Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar, and they do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2011,
Harvest Vinccler exchanged approximately $1.2 million (2010: $0.2 million) through SITME and received an average exchange rate of 5.19 Bolivars (2010: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.
The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At December 31, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 4.3 million Bolivars and 6.0 million Bolivars, respectively. At December 31, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 172.8 million Bolivars and 2,535.0 million Bolivars, respectively.
Petrodelta
In Item 1A. Risk Factors, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. During the year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Advances to equity affiliate has increased $0.7 million, to a balance of $2.4 million, during the year ended December 31, 2011. During the year ended December 31, 2010, we advanced Petrodelta $2.0 million for continuing operations costs, and Petrodelta repaid $4.8 million of the advances. Although payment is slow, payments continue to be received. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of recording an allowance for doubtful accounts on its receivable from Petrodelta. After considering many factors, including the slow but continuous payments received from Petrodelta, Harvest Vinccler determined that an allowance for doubtful accounts is not required.
We are unable to provide an indication of when PDVSA will become and remain current in its payment obligations. However, we believe that PDVSA’s debt will not disappear completely in the short term, but the risk of contractor work stoppage is minimal due to PDVSA guaranteeing payments as publicly stated by top officials. Increased costs due to PDVSA’s debt financing are already imbedded in current contractor’s rates.
Petrodelta’s 2011 capital expenditures were expected to be approximately $200 million. Petrodelta’s 2011 proposed business plan included a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and further drilling in the Isleño field. It also included engineering work for production facilities required for the full development of the El Salto and Temblador fields. Due to insufficient monetary and contractual support by PDVSA, Petrodelta incurred only $137.5 million of its 2011 planned capital expenditures.
As of March 7, 2012, the 2012 budget for Petrodelta’s business plan had not yet been approved by its shareholders. Since Petrodelta only executed approximately 69 percent of its 2011 planned capital expenditures primarily due to insufficient monetary and contractual support by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2012 budget. Should PDVSA continue in insufficient monetary and contractual support of Petrodelta, underinvestment in the development plan may lead to continued under-performance. However, Petrodelta’s 2012 proposed business plan includes a planned drilling program to utilize three rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto and Isleño fields. It also includes engineering work for the additional infrastructure enhancement projects in El Salto and Temblador.
In April 2011, the Venezuelan government published in the Official Gazette the amended Windfall Profits Tax. The amended Windfall Profits Tax establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011[$50 per barrel for 2012]) and $70 per barrel. The
amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the VEB exceeds $70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) 95 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax caps the cash royalty paid on production at $70 per barrel. By placing a cap on the royalty barrels, the amended Windfall Profits Tax reduces the royalties paid to the government and increases payments to the National Development Fund (“FONDEN”).
Windfall Profits Tax is deductible for Venezuelan income tax purposes. Petrodelta recorded $237.6 million for Windfall Profits Tax during the year ended December 31, 2011(2010: $14.1 million, 2009: $0.9 million).
There are many sections of the amended Windfall Profits Tax which have yet to be clarified. One section for which Petrodelta is waiting for clarity is how the $70 cap on royalty barrels will be applied to royalties paid in-kind. Petrodelta pays royalties on production of 30 percent in-kind and 3.33 percent in cash. In October 2011, Petrodelta received preliminary instructions from PDVSA that royalties, whether paid in cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. PDVSA also instructed Petrodelta to make the reporting change retroactive to April 18, 2011, the date of enactment of the amended Windfall Profits Tax. From April 18, 2011 to December 31, 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $85.0 million ($27.2 million net to our 32 percent interest). Net oil sales (oil sales less royalties) are the same under the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels; however, the method advised by PDVSA understates gross oil sales.
Per our interpretation of the amended Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. Pending receipt of final guidance from the Ministry of the People’s Power for Energy and Petroleum (“MENPET”), we have applied the $70 cap to only the 3.33 percent royalty paid in cash and the current oil sales price to the 30 percent royalty paid in-kind. With the assistance of Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the year ended December 31, 2011. From April 18, 2011 to December 31, 2011, net oil sales (oil sales less royalties) are slightly higher, $8.5 million ($2.7 million net to our 32 percent interest), under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.
Another section of the amended Windfall Profits Tax for which Petrodelta is waiting for clarity relates to an exemption of this tax that can be granted by MENPET for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots developments, as well as guidance on the process for applying for the exemption.
LOCTI requires major corporations engaged in activities covered by the OHL to contribute 0.5 percent (two percent prior to January 1, 2011) of their gross revenue generated in Venezuela from activities specified in the OHL on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. The contribution is based on the previous year’s gross revenue and is due the following year. Each company is required to file a separate declaration. Prior to January 1, 2011, contributions were allowed to be paid in-kind through self-funded programs and direct contributions to projects performed by other institutions. Effective January 1, 2011, LOCTI requires all contributions to be paid in cash directly to FONDACIT, the entity responsible for the administration of LOCTI contributions. Self-funded programs and direct contributions to projects performed by other institutions are no longer allowed. Since all contributions are now to be paid in cash, Petrodelta has accrued the 2011 liability to LOCTI.
Because contributions were allowed to be paid in-kind prior to January 1, 2011, LOCTI had granted waivers to allow PDVSA to file declarations on a consolidated basis covering all of its and its consolidating entities liabilities. For filing years 2007, 2008 and 2010, PDVSA provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest).
In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.
During the year ended December 31, 2011, Petrodelta drilled and completed 15 development wells, one successful appraisal well and two water injector wells compared to 16 development wells in the year ended December 31, 2010. Petrodelta delivered approximately 11.4 million barrels (“MBls”) of oil and 2.3 billion cubic feet (“Bcf”) of natural gas, averaging 32,240 barrels of oil equivalent (“BOE”) per day during the year ended December 31, 2011 compared to deliveries of 8.6 MBls of oil and 2.2 Bcf of gas, averaging 23,455 BOE per day during the year ended December 31, 2010.
During the year ended December 31, 2011, Petrodelta completed facilities at EPM transfer point for El Salto field. Completion of the facilities has enabled Petrodelta to increase production from the El Salto field. Petrodelta is continuing additional infrastructure enhancement projects in El Salto and Temblador. Petrodelta took possession of a third drilling rig at the end of September 2011. Currently, one drilling rig is operating in the El Salto field, and two drilling rigs are operating in the Temblador field. A workover rig is operating in the Tucupita field.
Petrodelta’s Proved reserves, net to our 32 percent interest, are 43.3 MMBOE at December 31, 2011. Petrodelta’s Probable reserves, net to our 32 percent interest, are 60.5 MMBOE at December 31, 2011. Petrodelta’s Possible reserves, net to our 32 percent interest, are 106.8 MMBOE. Proved plus Probable reserves at 103.8 MMBOE are virtually unchanged from last year. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies - Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.
Certain operating statistics for the years ended December 31, 2011, 2010, and 2009 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent.
Petrodelta’s results and operating information is more fully described in Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements, Note 11 - Investment in Equity Affiliates - Petrodelta, S.A.
Diversification
Beginning in 2005, we recognized the need to diversify our asset base as part of our strategy. We broadened our strategy from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources through the opening of our London and Singapore offices, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and exploration. While exploration has become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.
Exploration will be technically driven with a low entry cost and high resource potential that provides sustainable growth.
United States
Gulf Coast - West Bay
We held exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Interest (“AMI”) agreement with two private third parties. As of June 30, 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. The relinquishment was completed with an effective date of October 31, 2011. Neither we nor our partners intend to continue any activity in West Bay. Based on the decision in the second quarter 2011 to relinquish the exploration acreage, the carrying value of West Bay of $3.3 million was impaired as of June 30, 2011.
Western United States - Antelope
On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets located in our Antelope Project area in the Uinta Basin of Utah which consisted of approximately 69,000 gross acres (47,600 net acres), and the related contracts, reserves, production, wells, pipelines production facilities and other rights, title and interests located in the Uintah Basin in Duchesne and Uintah Counties, Utah. The transaction included the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte Extension. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch, an approximate 60 percent working interest in one well in the Monument Butte Extension, an approximate 43 percent working interest in the initial eight well program in the Monument Butte Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte Extension. The initial eight well program and follow-up six well program in the Monument Butte Extension were non-operated. The sale had an effective date of March 1, 2011 (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 - Dispositions). We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. All activities associated with the Antelope Project have been reflected as discontinued operations on the statement of operations.
Budong-Budong Project, Indonesia
Operational activities during 2011 focused on drilling of the first two exploratory wells, the LG-1, which spud on January 6, 2011, and the KD-1, which spud on June 20, 2011.
The LG-1, the first of the two exploratory wells in the Budong PSC, targeted the Miocene and Eocene reservoirs to a planned depth of approximately 7,200 feet. The LG-1 was drilled to a total depth of 5,311 feet and encountered multiple hydrocarbon shows and overpressure in Late Miocene rocks requiring up to 16.5 pound per gallon mud. After encountering difficulty in controlling the well due to high pressures, the well was plugged and abandoned on April 8, 2011. The primary Eocene targets had not yet been reached, as the well was planned for a total measured depth of approximately 7,200 feet. Fluid samples and log evaluation confirmed the presence of a proven petroleum system in the Lariang Sub-Basin. The costs for drilling the LG-1, $14.0 million, were suspended at March 31, 2011 pending further evaluation and appraisal.
The KD-1, the second of the two exploratory wells in the Budong PSC, is located approximately 50 miles south of the LG-1. The KD-1 was initially drilled to a total depth of 9,633 feet and sidetracked after the drill string was severed. The KD-1ST was initially drilled to 11,880 feet and logged. Evaluation of cuttings, logs and sidewall cores demonstrated presence of oil over a 200 foot section of low permeability and porosity clastics in the Early Miocene. The presence of oil shows proved the existence of a working petroleum system. On November 4, 2011, we elected to deepen the KD-1ST to a final total depth of 14,437 feet (13,576 feet TVD) as a sole risk operation. The KD-1ST encountered both Oligocene and Eocene rocks before drilling had to be stopped as the well reached the blow-out-preventer pressure limit. This resulted in the primary Eocene fluvial reservoir target not being reached. On January 2, 2012, the KD-1ST was plugged and abandoned with oil shows. Drilling costs of $26.0 million related to the drilling of the KD-1 and KD-1ST have been expensed to dry hole costs as of December 31, 2011.
In January 2012, after completion of drilling of the KD-1, all information gathered from the drilling of the LG-1 and KD-1 was reevaluated in connection with our plans for the Budong PSC and overall corporate strategy.
Based on this reevaluation, we determined that the original LG-1 well bore would not be used for re-entry. Since plans for the Budong PSC no longer include re-entry of the LG-1 well bore, the drilling costs of $14.0 million related to the drilling of the LG-1 have been expensed to dry hole costs as of December 31, 2011. Based on the multiple oil and gas shows encountered in both the LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene targets encountered in the previous two wells. As such, the other costs incurred related to the Budong PSC of $6.8 million remain capitalized on our balance sheet as of December 31, 2011.
During the year ended December 31, 2011, we had cash capital expenditures of $19.7 million for drilling, construction and plugging and abandonment costs and $3.7 million for the purchase of the additional 10 percent equity interest. The 2012 budget for the Budong PSC is $4.6 million.
Dussafu Project - Gabon
Operational activities during 2011 focused on the drilling of our first exploratory well, the DRM-1, which spud April 28, 2011, and appraisal sidetracks. The DRM-1 was drilled in a water depth of 380 feet to test multiple stacked pre-salt targets to a planned total measured depth of approximately 11,450 feet.
The DRM-1 reached an initial total depth of 10,044 feet (9,953 feet of TVDSS) within the Upper Dentale Formation. Log evaluation, pressure data and samples indicated an oil discovery of approximately 55 feet of oil pay in a 90 foot oil column within the Gamba Formation.
Subsequently the DRM-1 was deepened to reach a final total depth of 11,450 feet (11,355 feet TVDSS) to test the prospectivity of both the Middle and Lower Dentale Formations. Log evaluation, pressure data and a fluid sample indicated the discovery of a second oil accumulation with approximately 35 feet of oil pay within the secondary objective of the Middle Dentale Formation.
The first sidetrack, the DRM-1ST1, 0.75 miles to the southwest, was drilled to a total depth of 11,562 feet (9,428 feet TVDSS) in the Upper Dentale and found 19 feet of oil pay in the Gamba reservoir. The second sidetrack, the DRM-1ST2, 0.5 miles to the northwest of the DRM-1, was drilled to a total depth of 10,615 feet (9,429 feet TVDSS) in the Upper Dentale and found 40 feet of oil pay in the Gamba reservoir.
Drilling operations on the Dussafu PSC are currently suspended pending further exploration and development activities. The DRM-1 information is being used to refine the 3-D seismic depth model and improve our understanding for predicting the Gamba structure under the salt to define potential resources in the nearby satellite structures for future drilling targets. Reservoir characterization and concept engineering studies have started with the aim of evaluating the potential for commerciality of the discovered oil.
The partners in the Dussafu PSC began a 3-D seismic acquisition in a joint program with a third party. The program, which was operated by the third party and commenced on October 23, 2011, was completed November 18, 2011. We acquired an additional 545 square kilometers of seismic which is currently being processed. The seismic data was acquired in the northern area of the Dussafu PSC between the two existing 3-D seismic surveys acquired in 1994 and 2005 and the 2-D seismic survey we acquired in 2008.
During the year ended December 31, 2011, we had cash capital expenditures of $40.6 million for well planning and drilling. The 2012 budget for the Dussafu PSC is $5.6 million.
Block 64 EPSA Project - Oman
Operational activities during 2011 included well planning and procurement of long lead items. On October 21, 2011, a Standby Letter of Credit in the amount of $1.2 million was issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Block 64 EPSA.
The first of the two exploratory wells, the MFS-1, spud October 29, 2011. The MFS-1 was drilled to test the Mafraq South fault block. The MFS-1 reached a revised final total depth of 10,348 feet. The logs indicated no presence of hydrocarbons within the stacked reservoir targets of the Haima Group. On December 11, 2011, the MFS-1 was plugged and abandoned. Drilling costs of $6.9 million related to the drilling of the MFS-1 have been expensed to dry hole costs as of December 31, 2011.
The AGN-1, the second exploratory wells on the Block 64 EPSA, spud December 21, 2011 and was drilling at December 31, 2011. On February 3, 2012, the AGN-1 reached a final total depth of 10,482 feet. The logs indicated no presence of moveable hydrocarbons within the stacked reservoir targets of the Haima Group, although residual gas saturations appear to be present in the overlying Permian carbonate and dolomites of the Khuff Formation. Gas shows and saturations on the logs were recorded. On February 6, 2012, the AGN-1 was plugged and abandoned with gas shows. Total estimated drilling costs for the AGN-1 are approximately $7.6 million. Drilling costs incurred through December 31, 2011 of $2.8 million have been expensed to dry hole costs as of December 31, 2011. Drilling costs incurred after December 31, 2011 will be expensed to dry hole costs in the first quarter of 2012.
During the year ended December 31, 2011, we had cash capital expenditures of $10.2 million for well planning, drilling and plugging and abandonment costs. The 2012 budget for the Block 64 EPSA is $14.3 million.
WAB-21 Project - China
In March 2011, CNOOC granted us an extension of Phase One of the Exploration Period for the WAB-21 contract area to May 2013. Operational activities during 2011 include costs related to maintenance of the license. The 2012 budget for WAB 21 is minimal consisting of costs required to maintain the license.
Other Exploration Projects
Relating to other projects, we incurred $0.3 million during the year ended December 31, 2011. The 2012 budget for other projects is minimal consisting of costs required to complete projects started in 2011.
Fusion Geophysical, LLC (“Fusion”)
On January 28, 2011, Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger included an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. Based on the financial results for the period January 29, 2011 through January 28, 2012, FusionGeo’s gross profit did not exceed $5.6 million, the 2011 Earn Out Threshold, as described in the Agreement and Plan of Merger. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 11 - Investment in Equity Affiliates - Fusion Geophysical LLC.
Business Strategy
In Item 1. Business and Item 1A. Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next two yearshas restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.
We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:
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maintain financial prudence and rigorous investment criteria;
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access capital markets;
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continue to create a diversified portfolio of assets;
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preserve our financial flexibility;
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use our experience and skills to acquire new projects; and
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keep our organizational capabilities in line with our rate of growth.
To accomplish our strategy, we intend to:
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Diversify our Political Risk: Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio.
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Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments.
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Establish a Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs.
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Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.
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Provide Technical Expertise: We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally.
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Maintain a Prudent Financing Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets.
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Manage Exploration Risks: We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure.
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Establish Various Sources of Production: We seek to establish new production from our exploration and development efforts in a number of diverse markets and expect to monetize production through operations or the sale of assets.
Results of Operations
We had net income attributable to Harvest of $53.9 million, or $1.37 per diluted share, for the year ended December 31, 2011 compared to net income attributable to Harvest of $15.4 million, or $0.42 per diluted share, for the year ended December 31, 2010. Net income attributable to Harvest for the year ended December 31, 2011 includes $13.7 million of exploration expense and the net equity income from Petrodelta’s operations of $72.1 million. Net income attributable to Harvest for the year ended December 31, 2010 includes $8.0 million of exploration expense and the net equity income from Petrodelta’s operations of $66.3 million.
The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2011 and the financial condition as of December 31, 2011 and 2010 in conjunction with our consolidated financial statements and related notes thereto.
Years Ended December 31, 2011 and 2010
We reported net income attributable to Harvest of $53.9 million, or $1.37 diluted earnings per share, for the year ended December 31, 2011, compared with net income attributable to Harvest of $15.4 million, or $0.42 diluted earnings per share, for the year ended December 31, 2010.
Total expenses and other non-operating (income) expense (in millions):
Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2011, we incurred $10.1 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $3.3 million of impairment for the carrying value of West Bay (see Item 1. Business, Operations - United States Operations, Gulf Coast - West Bay Project). During the year ended December 31, 2010, we incurred $6.4 million of exploration costs for seismic, geological and geophysical, and exploration support costs and $1.6 million related to other general business development activity. Included in the $6.4 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation.
During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on the Budong PSC, $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC, $6.9 million related to the drilling of the MFS-1 on the Block 64 ESPA and $2.8 million related to the drilling of the AGN-1 on the Block 64 EPSA (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 13 - Indonesia and Note 15 - Oman).
The decrease in general and administrative costs in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to lower general office expense and overhead ($2.7 million), employee related costs ($0.9 million) and public relations ($0.3 million) offset by higher travel costs ($0.3 million) and contract services ($0.2 million). The employee related costs include $0.5 million of special consideration bonuses related to the sale of our Antelope Project.
The increase in investment earnings and other in the year ended December 31, 2011 from the year ended December 31, 2010 was due to income earned on transition services provided on the Antelope Project after closing of the sale.
The increase in interest expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the interest associated with our $32 million convertible debt offering in February 2010, our $60 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $2.3 million.
During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($7.2 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.3 million), and the cost to repurchase 4.4 million unvested warrants issued in connection with the term loan facility.
The decrease in loss on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 is due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. There was no Bolivar/U.S. Dollar exchange rate devaluations in the year ended December 31, 2011.
The decrease in other non-operating expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the sale of our Antelope Project.
The increase in income tax expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to higher income tax assessed in 2011 in the Netherlands offset by a U.S. tax refund received in 2010.
For the year ended December 31, 2011, net income from unconsolidated equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes and prices which was partially offset by the amended Windfall Profits Tax. The increase in operating expense and workovers in the year ended December 31, 2011 from the year ended December 31, 2010 was due to increased oil production and having a workover rig on location for the full year of 2011. Petrodelta took possession of the workover rig in September 2010 and operated it for only four months in the year ending December 31, 2010. The decrease in gain on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 was due to there not being a Bolivar/U.S. Dollar currency exchange rate devaluation during 2011. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. The decrease in Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from unconsolidated equity affiliate) in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to the tax effects of the currency devaluation in 2010 partially offset by an increase in current tax on increased earnings.
At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net losses incurred by Fusion of $0.2 million ($0.1 million net to our 49 percent interest) in the year ended December 31, 2011 (2010: $2.4 million [$1.2 million net to our 49 percent interest]), as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.4 million gain on the sale of Fusion in the year ended December 31, 2011.
Discontinued Operations
On May 17, 2011, we closed the transaction to sell our Antelope Project. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 - Dispositions. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in the second quarter of 2011.
Revenue and net income on discontinued operations for the years ended December 31, 2011 and 2010 are shown in the table below:
Net income from discontinued operations for the year ended December 31, 2011 includes $106.0 million gain on the sale of our Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the sale of our Antelope Project. Severance costs for key employees include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination.
Years Ended December 31, 2010 and 2009
Revisions for the Years Ended 2010 and 2009
We are revising our historical financial statements for the year ended December 31, 2010 and quarterly information for the quarters ended March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011 and September 30, 2011 (see Item 15. Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The revisions relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“USGAAP”) and recorded within Net income from unconsolidated equity affiliates. Previously, Petrodelta had an incorrect tax basis associated with its asset retirement cost which caused us to overstate or understate the deferred tax expense associated with this temporary difference for USGAAP purposes. We have revised the tax basis to record the correct deferred tax expense in each reporting period. The error has no impact to the consolidated statements of cash flows.
We have determined that the impact of this error is not significant to the previously issued annual and interim financial statements as defined by Accounting Standards Codification (“ASC”) 250 - Accounting Changes and Error Corrections (“ASC 250”). The audited financial statements, related notes and analyses for the years ended December 31, 2011, 2010 and 2009 have been retrospectively revised in this Annual Report on Form 10-K for the year ended December 31, 2011. All future filings, including interim financial statements, will be revised appropriately.
We reported net income attributable to Harvest of $15.4 million, or $0.42 diluted earnings per share, for the year ended December 31, 2010, compared with a net loss attributable to Harvest of $3.5 million, or $(0.10) diluted earnings per share, for the year ended December 31, 2009.
Total expenses and other non-operating (income) expense (in millions):
Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2010, we incurred $6.4 million of exploration costs for seismic, geological and geophysical, and exploration support costs and $1.6 million related to other general business development activity. Included in the $6.4 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation. During the year ended December 31, 2009, we incurred $4.5 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.8 million related to other general business development activities and $0.5 million related to the write off of the remaining carrying value of the first prospect in the AMI.
The increase in general and administrative costs in the year ended December 31, 2010 from the year ended December 31, 2009 was primarily due to higher employee related costs ($3.0 million), the reversal in 2009 of accruals no longer required ($1.3 million) offset by a reduction in other general office costs ($0.8 million).
The decrease in investment earnings and other in the year ended December 31, 2010 from the year ended December 31, 2009 was due to lower interest rates earned on lower average cash balances.
The increase in interest expense in the year ended December 31, 2010 from the year ended December 31, 2009 was due to interest associated with our $32.0 million senior convertible note offering in February 2010, our $60.0 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $1.8 million.
The increase in other non-operating expense in the year ended December 31, 2010 from the year ended December 31, 2009 was due to the expensing of $2.9 million of costs related to a future financing which was no longer being pursued and $1.1 million of costs related to other strategic alternatives.
The decrease in income tax expense in the year ended December 31, 2010 from the year ended December 31, 2009 was due to the receipt a $1.0 million U.S. income tax refund related to the recovery of alternative minimum tax for the tax years 2005 and 2007,$0.2 million reversal of a tax provision no longer needed, and lower tax assessed in the Netherlands of $0.7 million offset by $0.5 million of additional income taxes assessed to Harvest Vinccler in 2010 for the 2007 and 2008 tax years. The 2010 tax assessment for Harvest Vinccler was the result of a tax audit conducted by the SENIAT.
Net income from unconsolidated equity affiliates includes an $84.4 million remeasurement gain on revaluation of monetary assets and liabilities due to the Bolivar devaluation in January 2010 and a $19.5 million financing charge related to the blended exchange rate charged by the Central Bank of Venezuela for the purchase of foreign currency.
At December 31, 2009, we recorded a $1.6 million charge to fully impair the carrying value of our equity investment in Fusion. For the year ended December 31, 2010, Fusion reported a net loss of $2.4 million ($1.2 million net to our 49 percent interest) (2009: $4.8 million [$2.4 million net to our 49 percent interest]). The loss for 2010 is not reported in the year ended December 31, 2010 net income from unconsolidated equity affiliates as reporting it would take our equity investment into a negative position. On January 28, 2011, our minority equity investment in Fusion’s 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. See Item 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements, Note 11 - Investment in Equity Affiliates - Fusion Geophysical, LLC for additional information.
Discontinued Operations
On May 17, 2011, we closed the transaction to sell all of our oil and gas assets in Utah’s Uinta Basin (Antelope Project) for $217.8 million in cash. Accordingly, these operations have been classified as discontinued operations.
Revenue and net income (loss) on discontinued operations for the years ended December 31, 2010 and 2009 are shown in the table below:
Capital Resources and Liquidity
The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. In Item 1A. Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and that there may be operational or contractual consequences due to this inability.
Our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. For calendar year 2012, we have established a preliminary exploration and drilling budget of approximately $25.5 million of which approximately $10.0 million is non-discretionary. A substantial portion of this budget is for the completion of the drilling program on the Block 64 EPSA.
As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations. The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest). We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two year period. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidation Financial Statements, Note 13 - Indonesia and Note 14 - Gabon.
Our primary ongoing source of cash is still dividends from Petrodelta. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay dividends in 2012 or 2013.
Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. As of March 7, 2012, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 16 - Related Party Transactions.
We incurred debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our semi-annual interest expense has increased significantly, and our senior convertible notes impose restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses. Our inability to satisfy the covenants contained in our senior convertible notes would constitute an event of default, if not waived. An uncured default could result in the senior convertible notes becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of December 31, 2011, we were in compliance with all of our long term debt covenants.
At December 31, 2011, we had cash on hand of $58.9 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least December 31, 2012. Our 8.25 percent senior convertible notes are due March 1, 2013. We expect some, if not all, debt holders will convert their debt into shares of our common stock on or before the March 1, 2013 due date. However, if the debt is not converted or is only partially converted, we believe that Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures will be sufficient to repay the outstanding debt at March 1, 2013. However, if the Petrodelta dividend payment is not received or our cash sources and requirements are different than expected, it could have a material adverse effect on our operations.
In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including our ability to delay discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of asset as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, and cost reductions. However, there is no assurance that our plans will be successful. Although we believe that we will have adequate liquidity to meet our near term operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.
Working Capital. Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. However, in November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. There is no certainty that Petrodelta will pay dividends in 2012 or 2013. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a complete description of the situation in Venezuela and other matters.
At December 31, 2011, we had cash on hand of $58.9 million, of which approximately $7.5 million is held by our foreign affiliates. Such amounts are permanently invested in our foreign operations and not available to fund domestic operations. If such funds were to be repatriated to the U.S., we would need to accrue and pay U.S. income tax on the amount repatriated. However, it is not our intention to repatriate these funds.
The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
The decrease in working capital of $70.7 million at December 31, 2011 from December 31, 2010 was primarily a result of the completion of the sale of the Antelope Project, which was classified as a current asset at December 31, 2010, and the reclassification of a value added tax (“VAT”) receivable from current to long-term offset by an increase in capital expenditures and accounts payable due to drilling activities and income taxes related to the sale of the Antelope Project.
Cash Flow from Operating Activities. During the year ended December 31, 2011, net cash used in operating activities was approximately $52.7 million (2010: $5.3 million). The $47.4 million increase in use of cash was primarily due to drilling activities.
Cash Flow from Investing Activities. Our cash capital expenditures for property and equipment are summarized in the following table:
(1) See Notes to Consolidated Financial Statements, Note 4 - Dispositions.
During the year ended December 31, 2011, we:
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Received $217.8 million for the sale of our Antelope Project (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 4 - Dispositions);
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Received $1.0 million for the sale of pipe inventory associated with the Antelope Project;
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Received $1.4 million from the sale of our equity investment in Fusion (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 11 - Investments in Equity Affiliates, Fusion Geophysical, LLC);
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Deposited with a U.S. bank $1.2 million as collateral for a Standby Letter of Credit issued as a payment guarantee for drilling activities on the Block 64 EPSA (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 15 - Oman); and
During the year ended December 31, 2010, we:
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Expensed $0.5 million of investigative costs related to new business development projects which are no longer being pursued; and
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Expensed $2.9 million of costs related to a future financing which is no longer being pursued.
Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $25.5 million for 2012 for U.S., Indonesia, Gabon and Oman operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.
Cash Flow from Financing Activities. During the year ended December 31, 2011, we:
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Repaid $60.0 million of our term loan facility (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 - Long-Term Debt);
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Recorded $2.5 million of tax benefits related to the difference between book and tax deductions allowed for equity compensation; and
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Incurred $0.2 million in legal fees associated with financings.
During the year ended December 31, 2010, we:
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Closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 - Long-Term Debt);
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Closed a $60.0 million term loan facility (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 - Long-Term Debt);
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Incurred $2.5 million in deferred financings costs related to the $32.0 million convertible debt offering that is being amortized over the life of the convertible debt;
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Incurred $0.4 million in deferred financings costs related to the $60.0 million term loan facility that is being amortized over the life of the term loan facility; and
Contractual Obligations
At December 31, 2011, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman that support field operations in those areas. The field office in Port Gentil, Gabon is a month-to-month agreement.
We have various contractual commitments pertaining to exploration, development and production activities:
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We have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations.
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The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest).
We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two year period.
Senior Convertible Note
On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Capital Resources and Liquidity.
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned development activities and capital expenditure program.
Our net foreign exchange losses attributable to our international operations were minimal for the year ended December 31, 2011 and $1.6 million for the year ended December 31, 2010. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.
Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010 and again in January 2011. On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011.
Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2011, Harvest Vinccler exchanged approximately $1.2 million through SITME and received an average exchange rate of 5.19 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela for a more complete discussion of the exchange agreements and their effects on our Venezuelan operations.
Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela.
Critical Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.
Reporting and Functional Currency
The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence.
Investment in Equity Affiliates
Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting (ASC 323). Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.
There are many factors we consider when evaluating our equity investments for possible impairment, including, but not limited to, currency devaluations, inflationary economies and cash flow analysis.
Capitalized Interest
We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation.
Property and Equipment
We follow the successful efforts method of accounting for our oil and gas properties. Under this method, oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, conclusive formation test or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of crude oil and natural gas, are capitalized.
Depletion, depreciation, and amortization (“DD&A”) of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is proved reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
Assets are grouped in accordance with ASC 932. The basis for grouping is reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
We account for impairments of proved properties under the provisions of ASC 360. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the amortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
Suspended Exploratory Drilling Costs
In some circumstances, it may be uncertain whether proved reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the projects is being made.
Reserves
In December 2009, we adopted the SEC’s Modernization of Oil and Gas Reporting and the FASB’s guidance on extractive activities for oil and gas (ASC 932). ASC 932 requires the unweighted average, first-day-of-the-month price during the 12-month period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes.
Proved reserves are those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, government regulations, etc. Prices include consideration of changes in existing prices provided only by contractual arrangements and do not include adjustments based upon expected future conditions. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.
The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.
The estimate of reserves is made using available geological and reservoir data as well as production performance data. These estimates are prepared by an independent third party petroleum engineering consulting firm and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment.
Accounting for Asset Retirement Obligation
If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or “ARO”) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depleted on a unit-of-production basis within the related asset group. Accretion is included in operating expenses and depletion is included in DD&A on our consolidated statement of income.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are reinvested as port of our ongoing business.
New Accounting Pronouncements
In April 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, which is included in ASC 820, “Fair Value Measurement” (“ASC 820”). This update explains how to measure fair value. It does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. ASU No. 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is not permitted. The adoption of ASU No. 2011-04 will not have a material impact on our consolidated financial position, results of operation or cash flows.
In June 2011, the FASB issued ASU No. 2011-05, which is included in ASC 220, “Comprehensive Income” (“ASC 220”). This update requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-05 will impact the presentation of our results of operations.
In September 2011, the FASB issued ASU No. 2011-08, which is included in ASC 350, “Intangibles - Goodwill and Other” (“ASC 350”). The objective of this update is to simplify how entities, both public and nonpublic, test goodwill for impairment. This update permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350. ASU No. 2011-08 is effective for annual and interim fiscal years beginning after December 15, 2011. Early adoption is permitted. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.
In December 2011, The FASB issued ASU No. 2011-11, which is included in ASC 210, “Balance Sheet” (ASC 210”). The amendments in ASU No. 2011-11 require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. An entity is required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. ASU No. 2011-11 will be applied retrospectively. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.
In December 2011, the FASB issued ASU No. 2011-12, which is included in ASC 220. ASU No. 2011-12 defers those changes in ASU 2011-05 that pertain to how, when, and where reclassification adjustments are presented. All other requirements of ASU No. 2011-05 are not affected by ASU No. 2011-12. ASU No. 2011-12 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-12 will not impact the presentation of our results of operations.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk from adverse changes in oil and natural gas prices and foreign exchange risk, as discussed below.
Oil Prices
Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Being primarily a crude oil producer, we are more significantly impacted by changes in crude oil prices than by changes in natural gas prices. As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas.
We currently do not have any oil production that is hedged. While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements.
Interest Rates
Total long-term debt at December 31, 2011 consisted of $31.5 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted. A hypothetical 10 percent adverse change in the prime rate would not have a material effect on our results of operations for the year ended December 31, 2011.
Foreign Exchange
The Bolivar is not readily convertible into the U.S. Dollar. We have not utilized currency hedging programs to mitigate any risks associated with operations in Venezuela, and, therefore, our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in that country. Venezuela has imposed currency exchange controls. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Effects of Changing Prices, Foreign Exchange Rates and Inflation above.
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required by this item is included herein on pages S-1 through S-40.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures that are designed to ensure the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Management of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation as of December 31, 2011, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.
Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Changes in Internal Control over Financial Reporting. There have been no changes in internal control over financial reporting during the quarter ended December 31, 2011 that have materially affected or are reasonably likely to materially affect that Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.
Item 11.
Item 11. Executive Compensation
Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.
Item 14.
Item 14. Principal Accountant Fees and Services
Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 2012 Annual Meeting of Stockholders.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.
(b) 3. Exhibits:
 Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a) and (b) of Form 10-K.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)1 present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing as Schedule II in Item 15(a)2 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included inManagement’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 15, 2012
S-1
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
* Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
See accompanying notes to consolidated financial statements.
S-2
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
* Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
See accompanying notes to consolidated financial statements.
S-3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
* Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
See accompanying notes to consolidated financial statements.
S-4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
* Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
See accompanying notes to consolidated financial statements.
S-5
Supplemental Schedule of Noncash Investing and Financing Activities:
During the year ended December 31, 2011, we issued 0.2 million shares of restricted stock valued at $2.0 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 45,532 shares being added to treasury stock at cost.
During the year ended December 31, 2010, we issued 0.3 million shares of restricted stock valued at $1.8 million. Also some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis, which resulted in 26,260 shares being added to treasury stock at cost; and 1,000 shares held in treasury that had been reissued as restricted stock were forfeited and returned to treasury.
During the year ended December 31, 2009, we issued 0.2 million shares of restricted stock valued at $0.7 million. Also, some of our employees elected to pay withholding tax on restricted stock grants on a cashless basis which resulted in 3,757 shares being added to treasury stock at cost.
See accompanying notes to consolidated financial statements.
S-6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1 - Organization
Harvest Natural Resources, Inc. (“Harvest”) is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural gas properties since 1989, when it was incorporated under Delaware law.
We have significant interests in the Bolivarian Republic of Venezuela (“Venezuela”). Our Venezuelan interests are owned through HNR Finance, B.V. (“HNR Finance”). Our ownership of HNR Finance is through several corporations in all of which we have direct controlling interests. Through these corporations, we indirectly own 80 percent of HNR Finance and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), indirectly owns the remaining 20 percent interest in HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (“Petrodelta”). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A. (“CVP”) owns the remaining 60 percent of Petrodelta. HNR Finance also has a direct controlling interest in Harvest Vinccler S.C.A. (“Harvest Vinccler”). Harvest Vinccler’s main business purposes are to assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (“PDVSA”). We do not have a business relationship with Vinccler outside of Venezuela.
In addition to our interests in Venezuela, we have exploration acreage mainly onshore in West Sulawesi in the Republic of Indonesia (“Indonesia”), offshore of the Republic of Gabon (“Gabon”), onshore in the Sultanate of Oman (“Oman”), and offshore of the People’s Republic of China (“China”). See Note 13 - Indonesia, Note 14 - Gabon, Note 15 - Oman and Note 16 - China.
Note 2 - Summary of Significant Accounting Policies
Revision to Prior Period Financial Statements
We are revising our historical financial statements for the year ended December 31, 2010 and quarterly information for the quarters ended March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011 and September 30, 2011 (see Item 15. Exhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited)). The revisions relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s net income reported under International Financial Reporting Standards (“IFRS”) to that required under accounting principles generally accepted in the United States of America (“USGAAP”) and recorded within Net income from unconsolidated equity affiliates. Previously, Petrodelta had an incorrect tax basis associated with its asset retirement cost which caused us to overstate or understate the deferred tax expense associated with this temporary difference for USGAAP purposes. We have revised the tax basis to record the correct deferred tax expense in each reporting period. The error has no impact to the consolidated statements of cash flows.
We have determined that the impact of this error is not material to the previously issued annual and interim financial statements as defined by Accounting Standards Codification (“ASC”) 250 - Accounting Changes and Error Corrections (“ASC 250 “). The audited financial statements, related notes and analyses for the years ended December 31, 2011, 2010 and 2009 have been retrospectively revised in this Annual Report on Form 10-K for the year ended December 31, 2011. All future filings, including interim financial statements, will be revised appropriately.
The following tables set forth the effect of the adjustments described above on the consolidated statement of operations for the years ended December 31, 2010 and 2009 and the consolidated balance sheet as of December 31, 2010. There was no impact on net cash used in operating activities in the consolidated statements of cash flows.
S-7
Consolidated Statements of Operations
Consolidated Balance Sheets
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.
Reporting and Functional Currency
The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.
See Note 10 - Venezuela for a discussion of currency exchange risk on Harvest Vinccler’s and Petrodelta’s businesses.
S-8
Cash and Cash Equivalents
Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months.
Restricted Cash
Restricted cash is classified as current or non-current based on the terms of the agreement. Restricted cash at December 31, 2011 represents cash held in a U.S. bank used as collateral for a standby letter of credit issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Oman Exploration and Production Sharing Agreement Al Ghubar / Qarn Alam license (“Block 64 EPSA”) (see Note 15 - Oman).
Financial Instruments
Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable and notes payable. Cash and cash equivalents are placed with commercial banks with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk.
Total long-term debt at December 31, 2011 consisted of $31.5 million of fixed-rate unsecured senior convertible notes maturing on March 1, 2013 unless earlier redeemed, purchased or converted. Total long-term debt at December 31, 2010 consisted of $32 million of fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60 million of fixed-rate unsecured term loan facility, which was repaid in May 2012. See Note 5 - Long-Term Debt.
Accounts and Notes Receivable
Notes receivable bear interest and can have due dates that are less than one year or more than one year. Amounts outstanding under the notes bear interest at a rate based on the current prime rate and are recorded at face value. Interest is recognized over the life of the note. We may or may not require collateral for the notes.
Each note is analyzed to determine if it is impaired pursuant to Accounting Standards Updates (“ASU”) 2010-20. A note is impaired if it is probable that we will not collect all principal and interest contractually due. We do not accrue interest when a note is considered impaired. All cash receipts on impaired notes are applied to reduce the accrued interest on the note until the interest is made current and, thereafter, applied to reduce the principal amount of such notes.
At December 31, 2011 and 2010, our note receivable relates to a prospect leasing cost financing arrangement. The note receivable plus accrued interest was approximately $3.3 million at December 31, 2011 (2010: $3.4 million), and was secured by a portion of the production from the Bar F #1-20-3-2 in Utah. With the sale of our oil and gas assets in Utah’s Uinta Basin (“Antelope Project”) effective March 1, 2011, the note receivable plus accrued interest will be settled upon finalization of certain terms of the Joint Exploration and Development Agreement (“JEDA”) which defined the participating parties’ obligations over our Antelope Project. See Note 4 - Dispositions and Note 6 - Commitments and Contingencies.
Other Assets
Other assets consist of investigative costs associated with new business development projects, deferred financing costs and a long-term receivable for value added tax (“VAT”) credits related to the Budong PSC. Investigative costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the likely outcome of the project. Deferred financing costs relate to specific financing and are amortized over the life of the financing to which the costs relate. See Note 5 - Long-Term Debt.
At December 31, 2011, other assets consisted of $0.4 million of investigative costs, $1.0 million of deferred financing costs and $3.3 million of long-term VAT receivable. During the year ended December 31, 2011, $0.1 million of investigative costs were reclassified to expense. At December 31, 2010, other assets consisted of $0.3 million of investigative costs and $2.2 million of deferred financing costs. During the year ended December 31, 2010, $2.9 million of costs related to a future financing which we ceased to pursue and $0.5 million of investigative costs were reclassified to expense.
S-9
Other Assets at December 31, 2011 also includes a blocked payment of $0.7 million net to our 66.667 percent interest related to our drilling operations in Gabon in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”). See Note 6 - Commitments and Contingencies.
Investment in Equity Affiliates
Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting (ASC 323). Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a decline in the recoverability of its carrying value.
There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the factors we consider in our evaluation for possible impairment. At December 31, 2011 and December 31, 2010, there were no events that caused us to evaluate our investment in equity affiliates for impairment.
Oil and Gas Properties
The major components of property and equipment at December 31 are as follows (in thousands):
Properties and equipment are stated at cost less accumulated depletion, depreciation and amortization (“DD&A”). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gains or losses are recognized in investment earnings and other.
We follow the successful efforts method of accounting for our oil and gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that proved reserves, as that term is defined in Securities and Exchange Commission (“SEC”) regulations, have not been discovered, capitalized costs associated with the drilling of the exploratory well are charged to expense. Costs of drilling successful exploratory wells, all development wells, and related production equipment and facilities are capitalized and depleted or depreciated using the unit-of-production method as oil and gas is produced. At December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the Lariang-1 (“LG-1”) on the Budong-Budong Production Sharing Contract (“Budong PSC”), $26.0 million related to the drilling of the Karama-1 (“KD-1”) and first sidetrack, the KD-1ST on the Budong PSC, $6.9 million related to the drilling of the Mafraq South-A (“MFS-1”) on the Exploration and Production Sharing Agreement (“EPSA”) for the Al Ghubar/Qarn Alam License (“Block 64 EPSA”) and $2.8 million related to the drilling of the Al Ghubar North-A (“AGN-1”) on the Block 64 EPSA (see Note 13 - Indonesia and Note 15 - Oman.) Total drilling costs for the AGN-1 are estimated to be approximately $7.6 million. Drilling costs incurred after December 31, 2011 will be expensed to dry hole costs in the first quarter of 2012.
S-10
Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period. Costs of maintaining and retaining undeveloped leaseholds, as well as amortization and impairment of unsuccessful leases, are included in exploration expense. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties.
Proved oil and gas properties are reviewed for impairment at a level for which identifiable cash flows are independent of cash flows of other assets when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are determined based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these undiscounted estimated future net cash flows is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value, which is generally based on discounted future net cash flows. No impairment of proved oil and gas properties was required in 2011, 2010 or 2009.
Costs of drilling and equipping successful exploratory wells, development wells, asset retirement liabilities and costs to construct or acquire offshore platforms and other facilities, are depleted using the unit-of-production method based on total estimated proved developed reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds, are depleted using the unit-of-production method based on total estimated proved reserves. All other properties are stated at historical acquisition cost, net of allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets.
Undeveloped property costs, excluding oilfield inventories, consist of (in millions):
Other Administrative Property
Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which ranges from three to five years. Leasehold improvements are recorded at cost and amortized using the straight-line method over the life of the applicable lease. For the year ended December 31, 2011, depreciation expense was $0.5 million (2010: $0.5 million, 2009: $0.4 million).
Reserves
We adopted the SEC’s Modernization of Oil and Gas Reporting and the Financial Accounting Standards Board’s (“FASB”) guidance on extractive activities for oil and gas (ASC 932) as of December 31, 2009.
Capitalized Interest
We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation. During the year ended December 31, 2011, we capitalized interest costs for qualifying oil and gas property additions of $2.3 million (2010: $1.8 million).
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Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
At December 31, 2011, cash and cash equivalents include $51.4 million (2010: $51.0 million) in a money market fund comprised of high quality, short term investments with minimal credit risk which are reported at fair value. The fair value measurement of these securities is based on quoted prices in active markets (level 1 input) for identical assets. The estimated fair value of our senior convertible notes based on observable market information (level 2 input) as of December 31, 2011 is $39.2 million (2010: $61.7 million). The estimated fair value of our term loan facility based on internally developed discounted cash flow model and inputs based on management’s best estimates (level 3 input) for identical liabilities as of December 31, 2010 was $49.2 million.
Our current assets and liabilities accounts include financial instruments, the most significant of which are accounts receivables and trade payables. We believe the carrying values of our current assets and liabilities approximate fair value with the exception of the note receivable. Because this note receivable is not publicly-traded and not easily transferable, the estimated fair value of our note receivable is based on the market approach and time value of money which approximates the note receivable book value of $3.3 million at December 31, 2011 (2010: $3.4 million). The majority of inputs used in the fair value calculation of the note receivable are Level 3 inputs and are consistent with the information used in determining impairment of the note receivable.
The following is a reconciliation of the net beginning and ending balances recorded for financial assets and liabilities classified as Level 3 in the fair value hierarchy.
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Asset Retirement Liability
ASC 410, “Asset Retirement and Environmental Obligations” (“ASC 410”) requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the years ended December 31, 2011 or 2010. Changes in asset retirement obligations during the years ended December 31, 2011 and 2010 were as follows:
Share-Based Compensation
We use a fair value-based method of accounting for stock-based compensation. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and stock appreciation rights (“SARs”). Restricted stock and restricted stock units (“RSUs”) are measured at their intrinsic values. See Note 8 - Stock-Based Compensations and Stock Purchase Plans.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are reinvested as port of our ongoing business.
Noncontrolling Interests
We adopted the accounting standard for noncontrolling interests in consolidated financial statements (ASC 810) as of January 1, 2009. Our noncontrolling interest relates to Vinccler’s indirectly owned 20 percent interest in HNR Finance (see Note 1 - Organization).
Liquidity
The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. There are a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and that there may be operational or contractual consequences due to this inability.
Our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations. The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest). We do not have any remaining work commitments for the current
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exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two-year period.
Our primary ongoing source of cash is still dividends from Petrodelta. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. We expect to receive future dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most of its earnings into the company in support of its drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay additional dividends in 2012 or 2013.
Additionally, any dividend received from Petrodelta carries a liability to our non-controlling interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for us and our non-controlling interest holder, Vinccler, to receive our respective shares of Petrodelta’s dividends. A dividend from HNR Finance is due upon demand. As of March 7, 2012, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Note 17 - Related Party Transactions.
We incurred debt during 2010 which has imposed restrictions on us and increased our vulnerability to adverse economic and industry conditions. Our semi-annual interest expense has increased significantly, and our senior convertible notes impose restrictions on us that limit our ability to obtain additional financing. Our ability to meet these covenants is primarily dependent on meeting customary affirmative covenant clauses. Our inability to satisfy the covenants contained in our senior convertible notes would constitute an event of default, if not waived. An uncured default could result in the senior convertible notes becoming immediately due and payable. If this were to occur, we may not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. As of December 31, 2011, we were in compliance with all of our long term debt covenants.
At December 31, 2011, we had cash on hand of $58.9 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at least December 31, 2012. Our 8.25 percent senior convertible notes are due March 1, 2013. We expect some, if not all, debt holders will convert their debt into shares of our common stock on or before the March 1, 2013 due date. However, if the debt is not converted or is only partially converted, we believe that Petrodelta dividends and funding from debt or equity financing combined with our ability to vary the timing of our capital expenditures will be sufficient to repay the outstanding debt at March 1, 2013. However, if the Petrodelta dividend payment is not received or our cash sources and requirements are different than expected, it could have a material adverse effect on our operations.
In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing a number of actions including our ability to delay discretionary capital spending to future periods, possible farm-out or sale of assets, or other monetization of assets as necessary to maintain the liquidity required to run our operations. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, and cost reductions. However, there is no assurance that our plans will be successful. Although we believe that we will have adequate liquidity to meet our near term operating requirements and to remain compliant with the covenants under our long term debt arrangements, the factors described above create uncertainty. Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can be raised. Accordingly, there can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.
New Accounting Pronouncements
In April 2011, the FASB issued ASU No. 2011-04, which is included in ASC 820, “Fair Value Measurement” (“ASC 820”). This update explains how to measure fair value. It does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of
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financial reporting. ASU No. 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is not permitted. The adoption of ASU No. 2011-04 will not have a material impact on our consolidated financial position, results of operation or cash flows.
In June 2011, the FASB issued ASU No. 2011-05, which is included in ASC 220, “Comprehensive Income” (“ASC 220”). This update requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-05 will impact the presentation of our results of operations.
In September 2011, the FASB issued ASU No. 2011-08, which is included in ASC 350, “Intangibles - Goodwill and Other” (“ASC 350”). The objective of this update is to simplify how entities, both public and nonpublic, test goodwill for impairment. This update permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350. ASU No. 2011-08 is effective for annual and interim fiscal years beginning after December 15, 2011. Early adoption is permitted. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.
In December 2011, The FASB issued ASU No. 2011-11, which is included in ASC 210, “Balance Sheet” (ASC 210”). The amendments in ASU No. 2011-11 require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. An entity is required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. ASU No. 2011-11 will be applied retrospectively. The adoption of ASU No. 2011-08 will not have a material impact on our consolidated financial position, results of operation or cash flows.
In December 2011, the FASB issued ASU No. 2011-12, which is included in ASC 220. ASU No. 2011-12 defers those changes in ASU 2011-05 that pertain to how, when, and where reclassification adjustments are presented. All other requirements of ASU No. 2011-05 are not affected by ASU No. 2011-12. ASU No. 2011-12 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and will be applied retrospectively. Early adoption is permitted. The adoption of ASU No. 2011-12 will not impact the presentation of our results of operations.
Use of Estimates
The preparation of financial statements in conformity with USGAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserve volumes and future development costs. Actual results could differ from those estimates.
Reclassifications
Certain items in 2010 and 2009 have been reclassified to conform to the 2011 financial statement presentation.
Note 3 - Earnings Per Share
Basic earnings per common share (“EPS”) are computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock.
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(a) Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
(b)
Excludes net income attributable to noncontrolling interest.
The year ended December 31, 2011 per share calculations above exclude 0.7 million options and 1.6 million warrants because they were anti-dilutive. The year ended December 31, 2010 per share calculations above exclude 2.9 million options and 1.6 million warrants because they were anti-dilutive. The year ended December 31, 2009 per share calculations above exclude 3.7 million options because they were anti-dilutive. We did not have any warrants outstanding during the year ended December 31, 2009.
Note 4 - Dispositions
Assets Held for Sale
On May 17, 2011, we closed the transaction to sell our Antelope Project (see Note 12 - United States Operations, Western United States - Antelope). The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We donot have any continuing involvement with the Antelope Project. The related gain on the sale was reported in discontinued operations in the second quarter of 2011.
The Antelope Project has been classified as discontinued operations. The Antelope Project assets and liabilities held for sale as of December 31, 2010, are reported in the consolidated balance sheet as follows:
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Discontinued Operations
Revenue and net income (loss) on the disposition of the Antelope Project are shown in the table below:
Net income from discontinued operations for the year ended December 31, 2011 includes $106.0 million gain on the sale of our Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the sale of our Antelope Project.
Special accomplishment bonuses of $1.2 million directly related to the sale of the Antelope Project were paid at the closing of the sale. Employee severance costs of $0.1 million were paid in the three months ended June 30, 2011, and $1.3 million was paid in January 2012. Severance costs for key employees include $0.5 million of restricted stock units which was paid in July 2011. Severance costs for key employees also include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination.
Note 5 - Long-Term Debt
Long-term debt consists of the following (in thousands):
On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of senior convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The notes are general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if any. The notes are also redeemable in certain circumstances at our option and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events. On October 12, 2011, $0.5 million of our 8.25 percent senior convertible notes were converted into 81,478 shares of common stock at a conversion rate of $5.71 per share. Financing costs associated with the senior convertible notes offering are being amortized over the remaining life of the notes and are recorded in other assets. The balance for financing costs was $1.0 million at December 31, 2011(2010: $1.9 million).
On October 29, 2010, we closed a $60.0 million term loan facility with MSD Energy Investments Private II, LLC (“MSD Energy”), an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. Under the terms of the term loan facility, interest was paid on a monthly basis at the initial rate of 10 percent and had a maturity of October 28, 2012. The initial rate of interest was scheduled to increase to 15 percent on July 28, 2011, the Bridge Date. Financing costs associated with the term loan facility were being amortized over the remaining life of the loan and were recorded in other assets. The balance for financing costs was $0.3 million at December 31, 2010. See Note 8 - Stock-Based Compensation and Stock Purchase Plans - Common Stock Warrants for a discussion of the warrants that were issued in connection with the $60.0 million term loan facility.
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The proceeds from the sale of our Antelope Project were considered an “Extraordinary Receipt” as defined in the term loan facility with MSD Energy. Pursuant to the terms of the term loan facility, on May 17, 2011, we paid amounts outstanding under the term loan facility, including principal, accrued and unpaid interest and a prepayment premium of 3.5 percent of the amount outstanding, or an aggregate $62.1 million, with the net cash proceeds received from the sale of our Antelope Project. With the payment of the term loan facility, the balance of the financing costs related to the issuance of the term loan facility of $0.3 million was expensed to loss on extinguishment of debt in the six months ended June 30, 2011.
The principal payment requirements for our long-term debt outstanding at December 31, 2011 are as follows (in thousands):
Note 6 - Commitments and Contingencies
We have employment contracts with five executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus, excise tax reimbursement, outplacement services and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on or after May 31, 2012.
We have regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Omanto support field operations in those areas. The field office in Port Gentil, Gabon is a month-to-month agreement. At December 31, 2011, we had the following lease commitments for office space:
We have various contractual commitments pertaining to exploration, development and production activities. Currently, we have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2013. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations. We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two year period. The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest).
In October 2007, we entered into a Joint Exploration and Development Agreement (“JEDA”) with a private third party with respect to the Antelope Project. On January 11, 2011, in connection with the sale of each party’s interests in the Antelope Project (see Note 4 - Dispositions), we entered into a letter agreement with the private third party wherein the private third party agreed to reimburse us for certain expenses related to the sale of the two
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parties’ interests in the Antelope Project. The private third party disputes our calculation of the amount owed to us pursuant to the January 11, 2011 letter agreement. On March 11, 2011, we entered into a letter agreement with the private third party regarding certain obligations between the parties related to the JEDA. The private third party disputes our calculation of the amount due pursuant to one of the items in the March 11, 2011 letter agreement. At December 31, 2011, we have a note receivable outstanding from the private third party of $3.3 million (see Note 2 - Summary of Significant Accounting Policies, Accounts and Notes Receivable) and an account payable outstanding to the private third party of $3.6 million related to the purchase in July 2010 of an incremental 10 percent interest in the Antelope Project. In the event that the dispute is not resolved, the parties would arbitrate pursuant to the JEDA. At this time, we cannot predict the outcome of this dispute with the private third party.
On May 31, 2011, the United Kingdom branch of our subsidiary, Harvest Natural Resources, Inc. (UK), initiated a wire transfer of approximately $1.1 million ($0.7 million net to our 66.667 percent interest) intending to pay Libya Oil Gabon S.A. (“LOGSA”) for fuel that LOGSA supplied to our subsidiary in the Netherlands, Harvest Dussafu, B.V., for the company’s drilling operations in Gabon. On June 1, 2011, our bank notified us that it had been required to block the payment in accordance with the U.S. sanctions against Libya as set forth in Executive Order 13566 of February 25, 2011, and administered by the United States Treasury Department’s Office of Foreign Assets Control (“OFAC”), because the payee, LOGSA, may be a blocked party under the sanctions. The bank further advised us that it could not release the funds to the payee or return the funds to us unless we obtain authorization from OFAC. On October 26, 2011, we filed an application with OFAC for return of the blocked funds to us. Unless that application is approved, the funds will remain in the blocked account, and we can give no assurance when, or if, OFAC will permit the funds to be released.
On June 30, 2011, we filed a voluntary self-disclosure with OFAC to report that we had possibly violated the U.S. sanctions by attempting to remit funds to LOGSA. On September 20, 2011, we received a response from OFAC which stated that OFAC had decided to address the matter by issuing us a cautionary letter instead of pursuing a civil penalty. The cautionary letter represents OFAC’s final response to the apparent violation, but does not constitute a final agency determination as to whether a violation occurred.
On June 30, 2011, we applied for a license with OFAC that would authorize us to pay LOGSA for the fuel provided. In late 2011 and while our June 30, 2011 application was pending with OFAC, OFAC issued a series of general licenses easing U.S. sanctions against Libya which allowed us to pay the full amount we owed LOGSA. As of December 31, 2011, all monies owed to LOGSA had been paid. Our October 26, 2011 application for the return of the blocked funds remains pending with OFAC.
Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and Elton Blackhair in the United States District Court for the District of Utah. This suit was served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other things, intentionally interfered with Plaintiffs’ employment agreement with the Ute Indian Tribe - Energy & Minerals Department and intentionally interfered with Plaintiffs’ prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and attorney’s fees. We dispute Plaintiffs’ claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler, has received nine assessments from a tax inspector for the Uracoa municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
•
Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the Operating Service Agreement (“OSA”). Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims.
•
Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims.
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•
Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim.
•
Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims.
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s, the Venezuelan income tax authority, interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five assessments from a tax inspector for the Libertador municipality in which part of the Uracoa, Tucupita and Bombal fields are located as follows:
•
One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayor’s Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayor’s Office to the protest. If the municipality’s response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim.
•
Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
•
Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims.
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or range of any possible loss. As a result of the SENIAT’s interpretation of the tax code as it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which will have a material adverse impact on our financial condition, results of operations and cash flows.
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Note 7 - Taxes
Taxes on Income
The tax effects of significant items comprising our net deferred income taxes as of December 31, 2011, are as follows:
The U.S. valuation allowance related to our U.S. deferred tax assets of our Utah properties decreased by $26.4 million as a result of U.S. income tax related to the sale of our Antelope Project. Management anticipates that additional losses will be generated and that it is likely that they will be realized through carrybacks to 2011. Management further anticipates that any unremitted foreign earnings will be reinvested outside of the U.S.
The components of loss from consolidated companies continuing operations before income taxes are as follows:
The provision (benefit) for income taxes on consolidated companies continuing operations consisted of the following at December 31:
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A comparison of the income tax expense (benefit) on consolidated companies continuing operations at the federal statutory rate to our provision for income taxes is as follows:
Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions.
We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are reinvested as port of our ongoing business. At December 31, 2011, we have the following net operating losses available for carryforward (in thousands):
Accounting for Uncertainty in Income Taxes
The FASB issued ASC 740-10 (prior authoritative literature: Financial Interpretation No. [“FIN”] 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109 [“FIN 48”]) to create a single model to address accounting for uncertainty in tax positions. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We adopted FIN 48 as of January 1, 2007, as required.
We or one of our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local tax examinations by tax authorities for years before 2008. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2009 and 2010. There was an IRS examination for the year 2008 that was completed in July 2011 resulting in a slight reduction in the income tax liability for that year.
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The cumulative effect of adopting FIN 48 will be recorded in retained earnings and other accounts as applicable. A reconciliation of the beginning amount, and current year additions, of unrecognized tax benefits follows:
If the above tax benefits were recognized, the full amount would affect the effective tax rate. Since our position arose late in the year, we have accrued interest of $662 for one half of December, and have been advised that we would not be subject to penalty at this time. We believe that it is likely that the entire uncertain tax position will be resolved within the next twelve months, and the amount of unrecognized tax benefits will significantly decrease.
Note 8 - Stock-Based Compensation and Stock Purchase Plans
In May 2010, our shareholders approved the 2010 Long Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the issuance of up to 1,700,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”) and other stock-based awards to eligible participants including employees, non-employee directors and consultants of our Company or subsidiaries. Under the 2010 Plan, no more than 500,000 shares may be granted as restricted stock. No individual may be granted more than 1,000,000 options or SARs. The exercise price of stock options granted under the 2010 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date will vest in the manner and subject to the conditions specified in the award agreement and expire five years from grant date. Restricted stock granted vest in the manner and subject to the conditions specified in the award agreement. The 2010 Plan also permits the granting of performance awards and other cash-based awards to eligible employees and consultants. Performance awards may be in the form of performance stock, performance units and other forms of award established by the Board of Directors’ Human Resource Committee (the “HR Committee”) with vesting based on the accomplishment of a performance goal. No individual may be awarded performance related cash awards during a calendar year that could result in a cash payment of more than $5.0 million. In the event of a change in control, the HR Committee shall act to effect one or more of the following alternatives, which may vary among individual holders of awards granted under the 2010 Plan and which may vary among awards held by any individual holder of an award granted under the 2010 Plan: (1) accelerate vesting; (2) require mandatory surrender; (3) assume outstanding awards or have a new award of a similar nature substituted; (4) adjust the number and class of common stock covered by an award; and/or (5) make adjustments deemed appropriate to reflect the change of control.
In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for the issuance of up to 1,825,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2006 Plan, no more than 325,000 shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of restricted stock during any period of three consecutive calendar years. The exercise price of stock options granted under the 2006 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted through December 31, 2006 vest ratably over a three to five year period from their dates of grant and expire seven to ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. The 2006 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. No employee or consultant shall be granted a performance award during a calendar year that could result in a cash payment of more than $5.0 million. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.
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In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “2004 Plan”). The 2004 Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the 2004 Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. The exercise price of stock options granted under the 2004 Plan must be no less than the fair market value of our common stock on the date of grant. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors vests as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date (as amended). The 2004 Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable.
In July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the “2001 Plan”). The 2001 Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible participants including employees of our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the 2001 Plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.
A summary of the status of our stock option plans as of December 31, 2011, 2010 and 2009 and changes during the years ending on those dates is presented below:
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The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:
For options granted during:
The Black-Scholes option pricing model was developed for use in estimating the value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.
A summary of our nonvested options as of December 31, 2011, and changes during the year ended December 31, 2011, is presented below (shares in thousands):
As of December 31, 2011, there was $3.0 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized over the next three to four years. The total fair value of shares vested during the year ended December 31, 2011, was $2.7 million (2010: $2.6 million, 2009: $2.6 million).
In addition to options issued pursuant to the plans, options have been issued to new hire employees as employment inducement grants under a New York Stock Exchange (“NYSE”) exception. These options were granted between 2007 and 2011 between $7.33 and $13.82 and vest over three years. At December 31, 2011, a total of 0.6 million options issued outside of the plans were outstanding and 0.4 million options were exercisable.
Stock options for 0.2 million shares were exercised in the year ended December 31, 2011 resulting in cash proceeds of $0.9 million. Stock options for 0.4 million shares were exercised in the year ended December 31, 2010 resulting in cash proceeds of $1.7 million. Stock options for 0.2 million shares were exercised in the year ended December 31, 2009 resulting in cash proceeds of $0.4 million.
Stock Appreciation Rights (“SARs”)
At December 31, 2011, we had 0.3 million SARs outstanding. These SARs were granted in 2009 at $4.60 and vest over five years. The SARs are held by employees of Harvest. The vesting of these SARs is dependent upon the employee’s continued service to Harvest.
Restricted Stock and Restricted Stock Units (“RSUs”)
At December 31, 2011, we had 0.4 million shares of restricted stock outstanding. These shares were granted between 2008 and 2011 and vest over one to three years. The restricted stock is held by employees and directors of Harvest. The vesting of these shares is dependent upon the employee’s and directors continued service to Harvest.
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At December 31, 2011, we had 0.2 million RSUs outstanding. These RSUs were granted in 2009 and vest over five years. The RSUs are held by employees Harvest. The vesting of these RSUs is dependent upon the employee’s continued service to Harvest.
Common Stock Warrants
In connection with the $60 million term loan facility (see Note 5 - Long-Term Debt), we issued to MSD Energy (1) 1.2 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $15 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche A”); (2) 0.4 million warrants exercisable at any time on or after the closing date for a period of five years from the closing date on a cashless exercise basis at $20 per share until the Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche B”); and (3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis at the lower of $15 per share or 120 percent of the average closing price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date (“Tranche C”). The Tranche C warrants may be redeemed by Harvest for $0.01 per share at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the Bridge Date. On May 17, 2011, in connection with the payment of the term loan facility, we repurchased all of the Tranche C warrants at $0.01 per share. The cost to repurchase the warrants ($44,000) was expensed to loss on extinguishment of debt in the six months ended June 30, 2011. On July 28, 2011, the Bridge Date, Tranche A and Tranche B warrants were repriced to $14.78 per warrant which is the lower of $15 or 120 percent of the average closing bid price of Harvest’s common stock for the 20 trading days immediately preceding the Bridge Date.
The Black-Scholes option pricing model was used in pricing Tranche A and Tranche B. Tranche A was priced at $5.46 per warrant, and Tranche B was priced at $4.60 per warrant. The Monte Carlo option pricing model was used in pricing Tranche C due to the pricing and vesting variables in the agreement. Tranche C was priced at $0.62 per warrant. The value of the warrants was recorded as discount on debt with a corresponding credit to additional paid in capital. On May 17, 2011, in connection with the payment of the term loan facility, the balance of the discount on debt for Tranche A and Tranche B was expensed to loss on extinguishment of debt in the six months ended June 30, 2011. The balance of the discount on debt for Tranche C ($2.7 million) was reversed out of additional paid in capital as the warrants associated with Tranche C were unvested.
The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 2011 were:
Note 9 - Operating Segments
We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Operations included under the heading “United States and other” include corporate management, cash management, business development and financing activities performed in the United States and other countries, which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and other segment and are not allocated to other operating segments.
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* Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
Note 10 - Venezuela
In January 2011, the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated the 2.60 Venezuelan Bolivars (“Bolivars”) per U.S. Dollar exchange rate for purchases and the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency which was established in the January 2010 Exchange Agreement. The elimination of the 2.60 Bolivars per U.S. Dollar exchange rate for purchases did not have an impact on our business in Venezuela.
In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The establishment of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.
Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar, and they do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2011, Harvest Vinccler exchanged approximately $1.2 million (2010: $0.2 million) through SITME and received an average exchange rate of 5.19 Bolivars (2010: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.
The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At December 31, 2011, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate
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changes are 4.3 million Bolivars and 6.0 million Bolivars, respectively. At December 31, 2011, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 172.8 million Bolivars and 2,535.0 million Bolivars, respectively.
Note 11 - Investment in Equity Affiliates
Petrodelta, S.A.
On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract was published in the Official Gazette. Petrodelta is governed by its own charter and bylaws and will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of 20 years from that date. Petrodelta operates a portfolio of properties in eastern Venezuela including large proven oil fields as well as properties with substantial opportunities for both development and exploration. Petrodelta is to undertake its operations in accordance with Petrodelta’s business plan as set forth in its conversion contract. Under its conversion contract, work programs and annual budgets adopted by Petrodelta must be consistent with Petrodelta’s business plan. Petrodelta’s business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta.
The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (“PPSA”) signed on January 17, 2008. The form of the agreement is set forth in the Conversion Contract. Crude oil delivered from the Petrodelta Fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar. PPSA is obligated to make payment to Petrodelta of each invoice within 60 days of the end of the invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Major contracts for capital expenditures and lease operating expenditures are denominated in U.S. Dollars. Any dividend paid by Petrodelta will be made in U.S. Dollars.
As disclosed in previous filings, PDVSA has failed to pay on a timely basis certain amounts owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of Petrodelta’s oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta is continuing to experience difficulty in retaining contractors who provide services for Petrodelta’s operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is continuing to have an adverse effect on Petrodelta’s operations and on Petrodelta’s ability to carry out its business plan.
We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. During the year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Advances to equity affiliate has increased $0.7 million, to a balance of $2.4 million, during the year ended December 31, 2011. During the year ended December 31, 2010, we advanced Petrodelta $2.0 million for continuing operations costs, and Petrodelta repaid $4.8 million of the advances. Although payment is slow, payments continue to be received.
The Science and Technology Law (referred to as “LOCTI” in Venezuela) requires major corporations engaged in activities covered by the OHL to contribute 0.5 percent (two percent prior to January 1, 2011) of their gross revenue generated in Venezuela from activities specified in the OHL on projects to promote inventions or
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investigate technology in areas deemed critical to Venezuela. The contribution is based on the previous year’s gross revenue and is due the following year. Each company is required to file a separate declaration. Prior to January 1, 2011, contributions were allowed to be paid in-kind through self-funded programs and direct contributions to projects performed by other institutions. Effective January 1, 2011, LOCTI requires all contributions to be paid in cash directly to FONDACIT, the entity responsible for the administration of LOCTI contributions. Self-funded programs and direct contributions to projects performed by other institutions are no longer allowed. Since all contributions are now to be paid in cash, Petrodelta has accrued the 2011 liability to LOCTI.
Because contributions were allowed to be paid in-kind prior to January 1, 2011, LOCTI had granted waivers to allow PDVSA to file declarations on a consolidated basis covering all of its and its consolidating entities liabilities. For filing years 2007, 2008 and 2010, PDVSA provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest).
In April 2011, the Venezuelan government published in the Official Gazette the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (the “amended Windfall Profits Tax”). The amended Windfall Profits Tax establishes a special contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011 [$50 per barrel for 2012]) and $70 per barrel. The amended Windfall Profits Tax also establishes a special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the average price of the Venezuelan Export Basket (“VEB”) exceeds $70 per barrel but is less than $90 per barrel; (2) 90 percent when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3) 95 percent when the average price of the VEB exceeds $100 per barrel. The amended Windfall Profits Tax caps the cash royalty paid on production at $70 per barrel. By placing a cap on the royalty barrels, the amended Windfall Profits Tax reduces the royalties paid to the government and increases payments to the National Development Fund (“FONDEN”).
Windfall Profits Tax is deductible for Venezuelan income tax purposes. Petrodelta recorded $237.6 million for Windfall Profits Tax during the year ended December 31, 2011 (2010: $14.1 million, 2009: $0.9 million).
There are many sections of the amended Windfall Profits Tax which have yet to be clarified. One section for which Petrodelta is waiting for clarity is how the $70 cap on royalty barrels will be applied to royalties paid in-kind. Petrodelta pays royalties on production of 30 percent in-kind and 3.33 percent in cash. In October 2011, Petrodelta received preliminary instructions from PDVSA that royalties, whether paid in cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. PDVSA also instructed Petrodelta to make the reporting change retroactive to April 18, 2011, the date of enactment of the amended Windfall Profits Tax. From April 18, 2011 to September 30, 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $85.0 million ($27.2 million net to our 32 percent interest). Net oil sales (oil sales less royalties) are the same under the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels; however, the method advised by PDVSA understates gross oil sales.
Per our interpretation of the amended Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. Pending receipt of final guidance from the Ministry of the People’s Power for Energy and Petroleum (“MENPET”), we have applied the $70 cap to only the 3.33 percent royalty paid in cash and the current oil sales price to the 30 percent royalty paid in-kind. With the assistance of Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the year ended December 31, 2011. From April 18, 2011 to December 31, 2011, net oil sales (oil sales less royalties) are slightly higher, $8.5 million ($2.7 million net to our 32 percent interest), under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.
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Another section of the amended Windfall Profits Tax for which Petrodelta is waiting for clarity relates to an exemption of this tax that can be granted by MENPET for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots developments, as well as guidance on the process for applying for the exemption.
In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary and contractual support, as of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain.
In December 2011, Petrodelta changed its accounting policy under IFRS for calculating deferred tax liabilities associated with asset retirement costs. Petrodelta has recognized the effect of the change in accounting policy for the year 2011, $1.4 million ($0.4 million net to our 32 percent interest), in its Current income tax expense for the year ended December 31, 2011. Petrodelta has recorded the cumulative effect of the change in accounting policy, $6.9 million ($2.2 million net to our 32 percent interest) as an adjustment to retained earnings in its IFRS financial statements.
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Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s financial information is prepared in accordance with IFRS which we have adjusted to conform to USGAAP. All amounts through Net Income Equity Affiliate represent 100 percent of Petrodelta. Summary financial information has been presented below at December 31, 2010, 2009 and 2008, and for the years ended December 31, 2010, 2009 and 2008:
* Certain amounts for 2010 and 2009 have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
Fusion Geophysical, LLC (“Fusion”)
On January 28, 2011, Fusion Geophysical, LLC’s (“Fusion”) 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger. We received $1.4 million for our equity investment and $0.7 million for the repayment in full of the outstanding balance of the prepaid service agreement, short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.’s 2011 gross profit exceeds $5.6 million. Based on the financial results for the period January 29, 2011 through January 28, 2012, FusionGeo’s gross profit did not exceed $5.6 million, the 2011 Earn Out Threshold, as described in the Agreement and Plan of Merger.
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At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net losses incurred by Fusion in the year ended December 31, 2011 of $0.2 million ($0.1 million net to our 49 percent interest) (2010: $2.4 million [$1.2 million net to our 49 percent interest]) as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.4 million gain on the sale of Fusion in the year ended December 31, 2011.
Note 12 - United States
During 2008, we initiated a domestic exploration program in two different basins. We were the operator of both exploration programs.
Gulf Coast - West Bay Project
We held exploration acreage in the Gulf Coast Region of the United States through an Area of Mutual Interest (“AMI”) agreement with two private third parties. As of June 30, 2011, we and our partners in the West Bay project agreed to relinquish the exploration acreage we held to the farmor. The relinquishment was completed with an effective date of October 31, 2011. Neither we nor our partners intend to continue any activity in West Bay. Based on the decision in the second quarter 2011 to relinquish the exploration acreage, the carrying value of West Bay of $3.3 million was impaired as of June 30, 2011.
The West Bay project represents $3.3 million of unproved oil and gas properties on our December 31, 2010 balance sheet.
Western United States - Antelope
On May 17, 2011, we closed the transaction to sell all of our interest in the oil and gas assets located in our Antelope Project area in the Uinta Basin of Utah which consisted of approximately 69,000 gross acres (47,600 net acres), and the related contracts, reserves, production, wells, pipelines production facilities and other rights, title and interests located in the Uintah Basin in Duchesne and Uintah Counties, Utah. The transaction included the Mesaverde Gas Exploration and Appraisal Project (“Mesaverde”), the Lower Green River/Upper Wasatch Oil Delineation and Development Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch, an approximate 60 percent working interest in one well in the Monument Butte Extension, an approximate 43 percent working interest in the initial eight well program in the Monument Butte Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte Extension. The initial eight well program and follow-up six well program in the Monument Butte Extension were non-operated. The sale had an effective date of March 1, 2011 (see Note 4 - Dispositions). We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. All activities associated with the Antelope Project have been reflected as discontinued operations on the statement of operations.
Note 13 - Indonesia
In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner is the operator through the exploration phase as required by the terms of the Budong PSC, and we have an option to become operator, if approved by Government of Indonesia and BPMIGAS, the oil and gas regulatory authority, in any subsequent development and production phase.
We acquired our original 47 percent interest in the Budong PSC by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells under a Farmout Agreement with operator of the Budong PSC. Under the Farmout Agreement, the initial commitment was to fund the first phase of the exploration program up to a cap of $17.2 million. The commitment cap was
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comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment cap of each component was met, all subsequent costs are shared by the parties in proportion to their ownership interests. Prior to drilling the first exploration well, our partner had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The additional carry increased our ownership by 7.4 percent to 54.4 percent. On March 3, 2011, the Government of Indonesia and BPMIGAS approved this change in ownership interest.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by the operator to a third party, which has allowed us to acquire an additional 10 percent equity in the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first exploration well. The $3.7 million was paid on April 18, 2011. On August 11, 2011, we received notice from the Government of Indonesia and BPMIGAS that the transfer of the additional interest has been approved. Closing of this acquisition increased our participating ownership interest in the Budong PSC to 64.4 percent with our cost sharing interest becoming 64.51 percent until first commercial production.
During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of the Budong PSC is for 30 years which provides for an exploration period of up to ten years. Pursuant to the terms of the Budong PSC, at the end of the first three-year exploration phase, 45 percent of the original area was to be relinquished to BPMIGAS. In January 2010, 35 percent of the original area was relinquished and ten percent of the required relinquishment was deferred until 2011. On January 20, 2011, the deferred ten percent of the original total contract area was relinquished to BPMIGAS. The Budong PSC now covers 0.75 million acres.
The LG-1, the first exploratory well on the Budong PSC, spud January 6, 2011. At a depth of 5,300 feet, losses of heavy drilling mud into the formation were encountered which, when coupled with the very high formation pressures, led the partners to the decision to discontinue drilling and plug and abandon the well for safety reasons on April 8, 2011. The primary Eocene targets had not been reached. Since the results at April 8, 2011, did not definitively determine the commerciality of development of the LG-1, we believed that the well results confirmed that the Miocene formation exhibited sufficient quantities of hydrocarbons to justify potential development pending further appraisal. The costs for drilling the LG-1, $14.0 million, were suspended at March 31. In January 2012, after completion of drilling of the KD-1, all information gathered from the drilling of the LG-1 and KD-1 was reevaluated in connection with our plans for the Budong PSC and overall corporate strategy. Based on this reevaluation, we determined that the original LG-1 well bore would not be used for re-entry. Since plans for the Budong PSC no longer include re-entry of the LG-1 well bore, the drilling costs of $14.0 million related to the drilling of the LG-1 have been expensed to dry hole costs as of December 31, 2011.
The KD-1, the second exploratory well on the Budong PSC, spud June 20, 2011. The KD-1 is located approximately 50 miles south of the LG-1. Operational activities during 2011 included the spudding and drilling of the KD-1 and the drilling of the KD-1ST. On November 4, 2011, Harvest continued drilling as our exclusive operation to explore for the main Eocene objective. Although the well encountered both Oligocene and Eocene stratigraphy, the primary Eocene reservoir target had not been reached, and on January 2, 2012, the KD-1ST was plugged and abandoned. Drilling costs of $26.0 million related to the drilling of the KD-1 and KD-1ST have been expensed to dry hole costs as of December 31, 2011.
The remaining work commitment for the current exploration phase on the Budong PSC is for geological and geophysical work to be completed in the year 2012 at a minimum of $0.5 million ($0.3 million net to our 64.51 percent cost sharing interest).
Based on the multiple oil and gas shows encountered in both the LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene targets encountered in the previous two wells. As such, the other costs incurred related to the Budong PSC of $6.8 million remain capitalized on our balance sheet as of December 31, 2011. The Budong PSC represents $6.8 million of unproved oil and gas properties on our December 31, 2011 balance sheet (2010: $10.9 million).
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Note 14 - Gabon
We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area of 680,000 acres with water depths up to 1,000 feet.
The Dussafu PSC partners and the Republic of Gabon, represented by the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (“Republic of Gabon”), entered into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It was agreed that the second three-year exploration phase be extended until May 27, 2011, at which time the partners can elect to enter a third exploration phase. In order to complete drilling activities of an exploratory well, in March 2011, the Direction Generale Des Hydrocarbures (“DGH”) approved another one year extension to May 27, 2012 of the second exploration phase.
Operation activities during 2011 included the spudding and completion of drilling activities of the Dussafu Ruche Marin-A (“DRM-1”) and appraisal sidetracks. Drilling activity has been suspended pending further exploration and development activities. The DRM-1 information is being used to refine the 3-D seismic depth model and improve our understanding for predicting the Gamba structure under the salt to define potential resources in the nearby satellite structures for future drilling targets. Reservoir characterization and concept engineering studies have started with the aim of evaluating the commerciality of the discovered oil.
The partners in the Dussafu PSC began a 3-D seismic acquisition in a joint program with a third party. The program, which was operated by the third party and commenced on October 23, 2011, was completed November 18, 2011. We acquired an additional 545 square kilometers of seismic which is being processed. The seismic data was acquired in the northern area of the Dussafu PSC between the two existing 3-D seismic surveys acquired in 1994 and 2005 and the 2-D seismic survey we acquired in 2008.
We do not have any remaining work commitments for the current exploration phase of the Dussafu PSC, but as of May 28, 2012, the Dussafu PSC enters the third exploration phase. If the partners elect to enter the third exploration phase, there will be a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a two year period.
See Note 6 - Commitments and Contingencies for a discussion of legal matters related to our Gabon operations.
The Dussafu PSC represents $50.4 million of unproved oil and gas properties on our December 31, 2011 balance sheet (2010: $9.2 million).
Note 15 - Oman
In 2009, we signed an EPSA with Oman for the Block 64 EPSA. We have an 80 percent working interest and our partner, Oman Oil Company, has a 20 percent carried interest in the Block 64 EPSA during the initial period. We will pay Oman Oil Company’s participating interest share of costs until the date of a declaration of commerciality. Ninety days following the declaration of commerciality, Oman Oil Company may elect to continue to participate in the Block 64 EPSA. If Oman Oil Company elects to continue to participate, it will reimburse us for its participating interest share of all recoverable costs under the Block 64 EPSA incurred before the declaration of commerciality. Reimbursement is due within 30 days of election to participate.
Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate, which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman (“PDO”). PDO will continue to produce oil from several shallow oil fields within Block 64 EPSA area.
We have a minimum work obligation to reprocess 375 square kilometers of 3-D seismic and drill two exploration wells to penetrate and evaluate at least the potential objectives of the Haima Supergroup during the Initial Term of the EPSA. The parties to the EPSA acknowledge that $22.0 million is indicative of the costs needed to complete the work program during the three-year initial period which expires in May 2012. In order to complete drilling activities of the two exploratory wells, on August 24, 2011, Oman’s Ministry of Oil and Gas approved a one-year extension to May 23, 2013 of the initial period of the EPSA. Through December 31, 2011, we have incurred $16.2 million of the minimum work obligation. As of February 29, 2012, we have expended more than $22.0 million and completed the minimum work obligations.
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Operational activities during 2011 included the completion of the reprocessing and integrating multiple existing 3-D seismic databases, geological and geophysical interpretation of the data, well planning, procurement of long lead items, and contracting a drilling rig and oil field services. On October 21, 2011, a Standby Letter of Credit in the amount of $1.2 million was issued as a payment guarantee for electric wireline services to be provided during the drilling of the two exploratory wells on the Block 64 EPSA. The first of the two exploratory wells, the Mafraq South-1 (“MFS-1”), was spud October 29, 2011. Logs did not indicate the presence of hydrocarbons within the stacked Haima Group reservoir targets. On December 11, 2011, the MFS-1 was plugged and abandoned. Drilling costs of $6.9 million related to the drilling of the MFS-1 have been expensed to dry hole costs as of December 31, 2011.
The AGN-1, the second exploratory wells on the Block 64 EPSA, spud December 21, 2011 and was drilling at December 31, 2011. On February 3, 2012, we announced that interpretation of the mud log and wireline log did not indicate hydrocarbon saturations within the principal stacked Haima targets in the Barik, Miqrat and Amin reservoirs. On February 6, 2012, the AGN-1 was plugged and abandoned with gas shows in the Permian Khuff Formation. Total estimated drilling costs for the AGN-1 are approximately $7.6 million. Drilling costs incurred through December 31, 2011 of $2.8 million have been expensed to dry hole costs as of December 31, 2011. Drilling costs incurred after December 31, 2011 will be expensed to dry hole costs in the first quarter of 2012.
The Block 64 EPSA represents $5.3 million of unproved oil and gas properties on our December 31, 2011 balance sheet (2010: $4.2 million).
Note 16 - China
In December 1996, we acquired a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a border dispute between the People’s Republic of China (“China”) and Socialist Republic of Vietnam (“Vietnam”). Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute. Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during Phase One of the contract. As a result, we have obtained license extensions, with the current extension in effect until May 31, 2013. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.
WAB-21 represents $3.2 million of unproved oil and gas properties on our December 31, 2011 balance sheet (2010: $3.1 million).
Note 17 - Related Party Transactions
Dividends declared and paid by Petrodelta are paid to HNR Finance. HNR Finance must declare a dividend in order for the partners, Harvest and Vinccler, to receive their respective shares of Petrodelta’s dividend. Petrodelta has declared two dividends, totaling $33.0 million, which have been received by HNR Finance and for which HNR Finance has not distributed to the partners. In November 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. As of March 7, 2012, this dividend has not been received, and the timing of the receipt of this dividend is uncertain. At December 31, 2011, Vinccler’s share of the undistributed dividends is $9.0 million inclusive of the unpaid November 2010 dividend.
Note 18 - Subsequent Events
On March 9, 2012, we entered into exchange agreements with certain holders of our 8.25 percent senior convertible notes. These holders will be issued approximately 3.0 million shares of common stock in exchange for $16.0 million in aggregate principal amount of 8.25 percent senior convertible notes and associated interest. See Note 5 - Long-Term Debt for a discussion of the conversion ratio.
We conducted our subsequent events review up through the date of the issuance of this Annual Report on Form 10-K.
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HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Quarterly Financial Data (unaudited)
Summarized quarterly financial data is as follows:
(a) Revision to prior period financial statements - During the fourth quarter of 2011, we identified an error in our consolidated financial statements for the year ended December 31, 2011 related to the income tax expense on the gain on the sale of the Antelope Project. The tax basis used at September 30, 2011 in calculating the tax expense was incorrect. The reconciliation of the tax basis to the book basis of the Antelope Project resulted in a reduction of the income tax payable on the gain on the sale of the Antelope Project of $5.5 million ($2.0 million of the income tax benefit should have been recorded in the second quarter of 2011 and $3.5 million should have been recorded in the third quarter of 2011). The reduction in income tax payable was offset by additional income tax expense related to tax benefits on equity compensation. As a result, Income Taxes Payable were overstated $2.0 million at June 30, 2011, Additional Paid in Capital was understated $2.5 million and Income Tax on Gain was understated $0.5 million, or $0.01 per diluted share, for the second quarter of 2011. Income Taxes Payable were overstated $5.5 million at September 30, 2011, Additional Paid in Capital was understated $2.5 million, and Income Tax on Gain was overstated $3.5 million, or $0.09 per diluted share, for the third quarter of 2011. The error has no impact to the consolidated statements of cash flows. Management concluded the impact of the error is immaterial to the financial statements in the period in which it occurred but are material to the fourth quarter 2011. As such, the amounts presented above have been revised to reflect the second and third quarter 2011 impacts in the appropriate periods. All future filings, including interim financial statements, will be revised appropriately.
(b) Revision to prior period financial statements - During the fourth quarter of 2011, we identified an error related to the deferred tax adjustment in reconciling our share of Petrodelta’s net income reported under IFRS to that required under USGAAP. We revised the financial statements to reflect the correct deferred tax expense under USGAAP in each reporting period. The error has no impact to the consolidated statements of cash flows. Management concluded the impact of the error is immaterial to the financial statements in the period in which it occurred but is material to the fourth quarter 2011 when it was identified. As such, the amounts presented above have been revised to reflect the quarter 2011 impacts in the appropriate periods: first quarter 2011, $0.3 million, or $0.01 per diluted share; second quarter 2011, $0.3 million with no effect per dilute share; and third quarter 2011, $(1.1) million, with no effect per diluted share, net to our 32 percent interest.
* Certain amounts have been revised. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
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(a) Out-of-Period-Adjustment - During the fourth quarter of 2010, we recorded an out-of-period adjustment in our consolidated financial statements for the year ended December 31, 2010. This adjustment related to the accounting for an income tax refund of $1.0 million that had not been accrued at September 30, 2010. The refund was applied for on September 15, 2010 and received on October 25, 2010. We recorded the $1.0 million as an income tax benefit in the fourth quarter of 2010; however, the $1.0 million income tax refund should have been recognized as an income tax benefit in the third quarter of 2010. As a result, Accounts and notes receivable - joint interest and other was understated and net income attributable to Harvest was understated by $1.0 million for the third quarter of 2010, or $(0.03) per diluted share, and net income attributable to Harvest was overstated by $1.0 million for the fourth quarter of 2010, or $0.03 per diluted share. Net income attributable to Harvest is correctly stated for the year ended December 31, 2010. The error has no impact to the consolidated statements of cash flows. Management concluded the impact of the error is immaterial to the financial statements in the period in which it occurred. All future filings, including interim financial statements, will be revised appropriately.
(b) Revision to prior period financial statements - During the fourth quarter of 2011, we identified an error related to the deferred tax adjustment in reconciling our share of Petrodelta’s net income reported under IFRS to that required under USGAAP. We revised the financial statements to reflect the correct deferred tax expense under USGAAP in each reporting period. The error has no impact to the consolidated statements of cash flows. Management concluded the impact of the error is immaterial to the financial statements in the period in which it occurred but is material to the fourth quarter 2011 when it was identified. As such, the amounts presented above have been revised to reflect the quarter 2010 impacts in the appropriate periods: first quarter 2010, $0.3 million, or $0.03 per diluted share; second quarter 2010, no effect; third quarter 2010, $(0.1) million, or $0.01 per diluted share; and fourth quarter 2010, $(0.1) million, or $0.01 per diluted share
* Certain amounts have been revised for insignificant errors. See Note 2 - Summary of Significant Accounting Policies - Revision for additional information.
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Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
TABLE I - Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
TABLE II - Capitalized costs related to oil and natural gas producing activities (in thousands):
We regularly evaluate our unproved properties to determine whether impairment has occurred. We have excluded from amortization our interest in unproved properties and the cost of uncompleted exploratory activities. The principal portion of such costs, excluding those related the acquisition of WAB-21, are expected to be included in amortizable costs during the next two to three years. The ultimate timing of when the costs related to the acquisition of WAB-21 will be included in amortizable costs is uncertain.
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Unproved property costs at December 31, 2011 consisted of the following by year incurred (in thousands):
TABLE III - Results of operations for oil and natural gas producing activities (in thousands):
TABLE IV - Quantities of Oil and Natural Gas Reserves
Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity and continual reassessment of the viability of production under various economic and political conditions. Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir. The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.
We adopted the SEC’s Modernization of Oil and Gas Reporting and the Financial Accounting Standards Board’s (“FASB”) guidance on extractive activities for oil and gas (ASC 932) as of December 31, 2009.
The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for, management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum Engineers.
All reserve information in this report is based on estimates prepared by Ryder Scott Company L.P. (“Ryder Scott”), independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
See the following section Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2011, 2010 and 2009, TABLE IV - Quantities of Oil and Natural Gas Reserves for Petrodelta’s reserves.
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The table shown below represents our interests in the United States. On May 17, 2011, we closed the transaction to sell our Antelope Project (see Item 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statement, Note 12 - United States Operations, Western United States - Antelope). The sale has an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in discontinued operations in the second quarter of 2011. The Antelope Project has been classified as discontinued operations.
TABLE V - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used were $80.95 per barrel for oil and $3.42 per Mcf for gas. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
The table shown below represents our net interest at December 31, 2011.
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TABLE VI - Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves:
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Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Petrodelta S.A.
The following tables summarize the proved reserves, drilling and production activity, and financial operating data at the end of each year for our net 32 percent interest in Petrodelta. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
Petrodelta (32 percent ownership) is accounted for under the equity method, and has been included at its ownership interest in the consolidated financial statements and the following Tables based on a year ending December 31 and, accordingly, results of operations for oil and natural gas producing activities in Venezuela reflect the year ended December 31, 2011, 2010 and 2009.
TABLE I - Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
TABLE II - Capitalized costs related to oil and natural gas producing activities (in thousands):
TABLE III - Results of operations for oil and natural gas producing activities (in thousands):
(1) Expenses include operating expenses, production taxes and Windfall Profits Tax. Net to our 32 percent interest, Windfall Profits Tax for December 31, 2011 was $76.0 million (2010: $4.5 million, 2009: $0.3 million).
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TABLE IV - Quantities of Oil and Natural Gas Reserves
We adopted the SEC’s Modernization of Oil and Gas Reporting and the Financial Accounting Standards Board’s (“FASB”) guidance on extractive activities for oil and gas (ASC 932) as of December 31, 2009.
Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta has both developed and undeveloped oil and gas reserves identified in all six fields. Petrodelta produces the fields in accordance with a business plan originally defined by its Conversion Contract executed in late 2007. Proved Undeveloped (“PUD”) oil and gas reserves are drilled in accordance with Petrodelta’s business plan, but can be revised where drilling results indicate a change is warranted. This was the case in 2009, 2010 and again in 2011 when the wells drilled in El Salto resulted in a modification to the El Salto program.
During 2011, Petrodelta drilled and completed 15 production wells. Four of the wells were previously identified Proved Undeveloped (“PUD”) locations and 11 wells were previously classified Probable, Possible or undefined locations. In 2011, an additional 54 PUD locations were identified through drilling activity, however 69 PUD locations which are scheduled to be drilled 5 years after the wells were originally identified have been reclassified as Probable reserves. At December 31, 2011, Petrodelta had a total of 163 PUD (26.2 MMBOE) locations identified. Since the implementation of its 2007 business plan, Petrodelta has drilled 55 gross production wells (2008 9 wells [1.4 MMBOE], 2009 15 wells [2.0 MMBOE], 2010 16 wells [2.0 MMBOE] and 2011 15 wells [2.1 MMBOE]) which have moved to the proved developed producing (“PDP”) category. Of these 55 locations drilled since 2008, 27 (4.4 MMBOE) represent the movements of PUD locations to PDP locations. The other 28 new producing wells (3.0 MMBOE) were previously classified Probable, Possible or un-defined.
Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP locations in accordance with the business plan defined by the conversion contract executed in 2007 and subsequent updates. However, the timing and pace of the development is controlled by the majority owner, PDVSA through CVP, although we have substantial negative control provisions as a noncontrolling interest shareholder. In 2010, Petrodelta submitted a revised business plan to PDVSA which substantially increases the total projected drilling activity and production volumes compared to the 2007 business plan, but which is otherwise consistent with the 2007 business plan. The 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities through the year 2024 to fully develop the El Salto and Temblador fields. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has limited ability to control the development plans that are periodically prepared and/or approved by the Venezuelan government. Since this constraint represents a hindrance to development not experienced by typical operations, the PUD locations which are now scheduled to be drilled 5 years after they were originally identified have been reclassified as Probable reserves.
Probable undeveloped reserves of 60.3 MMBOE include 16.1 MMBOE from 69 gross undeveloped locations that would otherwise meet the definition of proved undeveloped reserves, except that they are scheduled to be drilled at least 5 years after the date that they were originally identified. These 69 locations are all scheduled to be drilled from 2013 to 2016.
Proved undeveloped reserves of 26.2 MMBOE from 163 gross PUD locations are all scheduled to be drilled within the period from 2012 to 2015 and within 5 years from when these locations were first identified. All above MMBOE represent our net 32 percent interest, net of a 33.33 percent royalty.
The tables shown below represent HNR Finance’s 40 percent ownership interest and our net 32 percent ownership interest, both net of a 33.33 percent royalty, in Venezuela in each of the years.
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TABLE V - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of the accounting standard on disclosures about oil and gas producing activities. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by an applying the average price during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for fixed and determinable escalations provided by the contract, to the estimated future production of year-end proved reserves. Our average prices used were $98.37 per barrel for oil and $1.54 per Mcf for gas.
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Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
The table shown below represents HNR Finance’s net interest in Petrodelta.
(1) Future production costs include operating costs, production taxes and Windfall Profits Tax. Windfall Profits Tax equates to $1.6 million, or 68 percent, of the $2.4 million of discounted future production costs.
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TABLE VI - Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands):
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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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 15th of March 2012, on behalf of the registrant and in the capacities indicated:
Signature
Title
/s/ JAMES A. EDMISTON
James A. Edmiston
Director, President and Chief Executive Officer (Principal Executive Officer)
/s/ STEPHEN C. HAYNES
Stephen C. Haynes
Vice President - Finance, Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)
/s/ STEPHEN D. CHESEBRO’
Stephen D. Chesebro’
Chairman of the Board and Director
/s/ IGOR EFFIMOFF
Igor Effimoff
Director
/s/ H. H. HARDEE
H. H. Hardee
Director
/s/ R. E. IRELAN
R. E. Irelan
Director
/s/ PATRICK M. MURRAY
Patrick M. Murray
Director
/s/ J. MICHAEL STINSON
J. Michael Stinson
Director
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SCHEDULE Valuation and Qualifying Accounts SCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
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Financial Statements SCHEDULE III
Financial Statements and Notes
for Petrodelta, S.A.
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INDEPENDENT AUDITOR’S REPORT
To the Stockholders and Board of Director of
PETRODELTA, S.A.
REPORT ON THE FINANCIAL STATEMENTS
We have audited the accompanying financial statements of PETRODELTA, S.A. (a subsidiary 60% owned by Corporacion Venezolana del Petroleo, S.A. CVP), which comprise the statements of financial position as at December 31, 2011, 2010 and 2009, and the statements of comprehensive income, statements of changes in equity, and statements of cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information.
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
AUDITOR’S RESPONSIBILITY
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
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OPINION
In our opinion, the financial statements present fairly, in all material respects, the financial position of Petrodelta, S.A. as at December 31, 2011, 2010 and 2009, and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards.
EMPHASIS OF MATTER
Without qualifying our opinion as indicated in Note 21 to the financial statements, the Company belongs to a group of related companies and conducts transactions and maintains balances for significant amounts with other members of the group, with significant effects on the results of its operations and financial position. Because of those relationships, these transactions may have taken place on terms other than those that would characterize transactions between unrelated companies.
Without qualifying our opinion, as indicated in Note 21, from April 2011 the Company set the price of US$.70 as a maximum price for the calculation and accounting of the royalties instead of the sale price of barrel of oil as had been calculated and recorded in previous accounting periods, based on the Decree No.8163 dated 18 April 2011 which creates the Special Tax on Extraordinary Prices and Exorbitant Prices in the International oil Market. Have registered in accordance with the procedures followed in previous years, revenues from crude sales and royalty expense for the year ended December 31, 2011, have increased in thousands US$.76,966 (Bs.330,952). This accounting procedure has no effect on Company net income.
Por PGFA PERALES, PISTONE & ASOCIADOS
José G. Perales S.
C.P.C. Nº 9.578
February 23, 2012
Except for the matters indicated in Note 25 whose
dates are February 27 and 28, 2012.
Valencia, Venezuela.
S-52
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Financial Position
(Expressed in thousands)
The accompanying notes (1 to 26) are an integral part of these financial statements.
S-53
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Comprehensive Income
(Expressed in thousands)
The accompanying notes (1 to 26) are an integral part of these financial statements.
S-54
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of changes in equity
Years ended December 31, 2011, 2010, 2009
(Expressed in Thousands of U.S. Dollars)
The accompanying notes (1 to 26) are an integral part of these financial statements.
S-55
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of changes in equity
Years ended December 31, 2011, 2010 and 2009
(Expressed in Thousands of Bolivars)
The accompanying notes (1 to 26) are an integral part of these financial statements.
S-56
PETRODELTA, S.A
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Cash Flow
(Expressed in thousands)
The accompanying notes (1 to 26) are an integral part of these financial statements.
S-57
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(1)
Reporting Entity
Petrodelta, S.A. was incorporated and is domiciled in the Bolivarian Republic of Venezuela Venezuela. Its main offices are located at Avenida Alirio Ugarte Pelayo, Edificio Petrodelta, Ala Norte, Planta Baja in Maturín, Monagas State. Its legal address is: Avenida Veracruz con Calle Cali, Urbanización Las Mercedes, Edificio Pawa, Piso 5, Caracas, Distrito Capital.
Petrodelta, S.A. (the Company) was incorporated in October 2007, as published in Official Gazette No. 38,786. Its business objective is primary exploration to discover oil reserves, extraction of oil in its natural state, and its subsequent collection, transportation and storage pursuant to Article No. 9 of the Venezuelan Hydrocarbon Law (LOH). The Company operates within an area of approximately 1,000 square kilometers in the Uracoa, Bombal, and Tucupita fields (formerly the Monagas Sur Unit) and in the El Salto, El Isleño, and Temblador fields in the Monagas and Delta Amacuro states in Venezuela (the assigned operating area).
The Company was created as a result of the process for conversion into mixed-capital companies of the Operating Agreement signed on July, 1992 between PDVSA Petróleo, S.A. (PDVSA Petróleo) (formerly Lagoven, S.A.), Harvest Natural Resources, Inc. (Harvest) (formerly Benton Oil and Gas Company) and Venezolana de Inversiones y Construcciones Clérico, C.A. (Vinccler). As part of this process, on March 31, 2006, PDVSA Petróleo, S.A., Corporación Venezolana del Petróleo, S.A. (CVP) and Harvest Vinccler, S.C.A. (HVSCA), the agreement operator and a related company of Harvest and Vinccler, signed a memorandum of understanding for conversion into a mixed company. In June 2007, the National Assembly of the Bolivarian Republic of Venezuela approved the incorporation of the mixed company Petrodelta, S.A. In August 2006, the National Assembly approved the inclusion of the Temblador, El Isleño and El Salto areas into the Monagas Sur Unit for further development of the Company’s primary activities. An agreement for conversion into a mixed company was signed between CVP and HNR Finance B.V. (HNR Finance) in September 2007. The Company will operate for 20 years as from October 2007 when the decree for transfer of field operations was published in the Official Gazette.
The capital stock of the Company is 60%-owned by Corporación Venezolana del Petróleo (CVP), a wholly owned subsidiary of Petróleos de Venezuela, S.A. (PDVSA), and the remaining 40%-owned by HNR Finance.
Company management considers that it operates in a single business segment (hydrocarbons) and in one country, the Bolivarian Republic of Venezuela, in conformity with its social statutes.
During the transition period from April 1, 2006 to December 31, 2007, Harvest Vinccler, S.C.A. (HVSCA) was in charge of managing and developing the Company’s activities and provided its financial and operational structure for this purpose. The Company’s operating costs during this period were paid by HVSCA and CVP and subsequently charged to PDVSA, which, in turn, billed the Company. These costs were recognized in the statements of comprehensive income for the respective periods. These costs include, but are not limited to, general, administrative, operating and capital expenses required to continue activities in the assigned operating area.
At December 31, 2011 the Company had not received information regarding production from Temblador field from the period starting October 23, 2007, official date of the decree of transferring field operations to the Company, and ending February 1, 2008. Because production was handled during this period by PDVSA as well as related operational expenses, investments, tributes and contributions by law associated, the Company started discussions to obtain information and evaluate if merits exists for an eventual reconciliation of actual crude produced during the period mentioned.
S-58
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
During the years ended December 31, 2011, 2010 and 2009, the Company has operated with employees assigned by its shareholders or their related companies since it has no direct employees. At December 31, 2011, 2010 and 2009, the Company has 527, 432 and 356 employees, respectively, assigned by its shareholders or their related companies.
During the year ended December 31, the Company drilled 15 (2011), 16 (2010) and 18 (2009) development wells, produced approximately 11.4 (2011), 8.6 (2010) and 7.8 (2009) million barrels of oil and sold 2.3 (2011), 2.2 (2010) and 4.4 (2009) billion cubic feet of natural gas.
Regulations
The Company’s main activities are regulated by the Venezuelan Hydrocarbon Law (LOH), effective from January 2002 and its partial reforme of May 2006. Gas-related operations are regulated by the Venezuelan Gaseous Hydrocarbon Law effective since September 1999 and its Regulation of June 2000, by the provisions of the bylaws and common rights norms applicable.
Below are the main regulations included in the LOH:
a) A 30% royalty on volumes of hydrocarbon extracted (see Note 7-(g).
b) A Partial Reform of the Extraction Tax was enacted and published in Official Gazette No. 38,443 of May 24, 2006, establishing a rate equivalent to one-third of the value of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis set out in the Law for royalty calculation. The taxpayer has the right to deduct from the extraction tax any sum payable as royalties (30%), including the additional royalty paid for special advantages (3.33%).
c) A surface tax equivalent to 100 tax units for each square kilometer or fraction thereof per year for licensed areas that are not under production. This tax will increase by 2% during the first five years, and by 5% during all subsequent years.
d) An internal consumption tax equivalent to 10% of the value of each cubic meter of hydrocarbon derivatives produced and consumed as fuel in internal operations, calculated on the final selling price. Company management considers that, other than associated gas, no hydrocarbon derivatives are consumed.
Hydrocarbon Purchase Sale Agreement
On January 17, 2008, the Company signed a hydrocarbon purchase sale agreement with PDVSA Petróleo, whereby the Company undertakes to sell to the latter all hydrocarbons produced within the delimited operating area that are not being used in its operations. The Company may assign or transfer this agreement, or any rights and obligations thereunder, to another company in accordance with Article No. 27 of the LOH. This agreement is for 20 years.
(2)
Basis of Preparation
S-59
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(a) Statement of Compliance
The financial statements as of December 31, 2011, 2010 and 2009 are prepared in accordance with International Financial Reporting Standards (IFRS) adopted by the International Accounting Standards Board (IASB) and their interpretations, issued by the International Financial Reporting Interpretations Committee (IFRIC) of the IASB.
On February 23, 2012, the Board of Directors of the Company resolved to submit for consideration of the Shareholders of the Company the financial statements for the year ended December 31, 2011.
On March 10, 2011, the Board of Directors of the Company resolved to submit for consideration of the Shareholders of the Company the financial statements for the year ended December 31, 2010. The financial statements as of December 31, 2011 and 2010 will be presented in the coming Shareholder meeting and expect their approval with no modifications. The financial statements for the year ended December 31, 2009 were approved by the Shareholders of the Company on August 4, 2010.
(b) Basis of Measurement
The financial statements have been prepared on the historical cost basis, except for certain assets and liabilities measured at fair value. Assets measured and presented at fair value are: recoverable tax credits, accounts receivable and cash.
The methods used for measuring fair value are discussed in more detail in Note 5.
(c) Functional and Presentation Currency
The financial statements are presented in U.S. dollar (U.S. Dollar or US$) and bolivars (bolivar or Bs.). The Company’s functional currency is the U.S. dollar, since the main economic environment in which Petrodelta, S.A. operates is the international market for crude oil and its products. In addition, a significant portion of its revenues, as well as most costs, expenses and investments are denominated in U.S. dollars.
The financial statements in bolivars are presented for statutory purposes.
All financial information presented in U.S. dollars and bolivars has been rounded in thousands.
(d) Use of estimates and judgments
The preparation of financial statements in conformity with IFRS requires management to make estimates, judgments and assumptions that affect the application of accounting policies and the amounts of assets, liabilities, income and expense. The Company applies its best estimates and judgments; however, actual results may differ from initial estimates. Estimates and assumptions are reviewed periodically, and the effects of the revisions, if any, to accounting estimates are recognized in the period in which the estimate is revised and in any future periods affected.
S-60
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Significant areas of critical judgment in the application of accounting policies, which significantly affect financial statement amounts, are described in the following notes:
•
Note 8-depletion, depreciation and amortization
•
Note 9-provision for asset retirement obligation
•
Note 19-valuation of financial instruments
Information on areas of uncertainty affecting management’s estimates which significantly affect financial statement amounts in future periods are described in the following notes:
•
Note 3 -r- measurement of contract-based retirement benefit obligations and other post-retirement benefits other than pensions, which is a PDVSA obligation with the employees assigned to the Company for subsequent billing once the employee is considered eligible for pension.
•
Note 7 -f- deferred income tax
•
Note 20-commitments, contingencies and accruals in respect of environmental issues
The Company’s operations may be affected by the political, legislative, regulatory and legal environment, both at the national and international level. In addition, significant changes in prices or availability of crude oil and its products may have an impact on the Company’s results of operations in any given year.
(e) Financial Statements Presentation
In the preparation and presentation of its financial statements, up until December 31, 2009, the Company has used a scheme of presentation on comparative information where two years of financial data was disclosed for each financial report and its corresponding note. During the year ended December 31, 2011 and 2010, the Company following guidelines from its main shareholder, CVP, and based on pertinent evaluation and because it considers it reflects appropriately the nature of its operations and tendencies of the oil industry, have opted for presenting comparative information disclosing data for three periods for each financial report and its corresponding note.
Certain financial statement items at December 31, 2010 and 2009 have been reclassified to conform to the presentation of the year 2011.
S-61
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(3)
Summary of Significant Accounting Policies
The accounting policies used for the preparation of these financial statements have been applied consistently for all periods presented.
(a) Foreign Currency
Transactions in Foreign Currency
Transactions in foreign currency (any currency different than the functional currency) are translated into the Company’s functional currency using the exchange rate in effect at the transaction date. Monetary assets and liabilities denominated in foreign currency are translated into U.S. dollars using the exchange rate prevailing at the date of the statement of financial position. Exchange gains or losses on monetary assets and liabilities resulting from this translation are presented as financial income or expenses in the statements of comprehensive income. Nonmonetary assets and liabilities in foreign currency are stated at fair value and translated to the functional currency using the exchange rate prevailing at the date fair value was determined. All other nonmonetary items denominated in foreign currency measured at historical cost are converted at the exchange rate at the date of the transaction.
Translation to the Presentation Currency
The Company’s financial statements were translated from dollars into bolivars, a currency other than the functional currency, in accordance with International Accounting Standard No. 21 The Effects of Changes in Foreign Exchange Rates. This standard requires each entity to determine its functional currency based on an analysis of the primary economic environment in which the entity operates, which is normally the one in which it primarily generates and expends cash.
The financial statements were translated into bolivars using the following procedures:
•
Assets and liabilities in each statement of financial position at the exchange rates in effect at the date of such statement.
•
Income and expenses in the statements of comprehensive income at the exchange rate at the date of transaction.
•
All exchange gain and losses generated as a result of the above, are recognized in the statement of comprehensive income as other comprehensive income and accumulated as a separate component of equity.
•
Equity accounts are translated at the exchange rate in effect at the date of each related transaction, except for retained earnings which are translated at the weighted-average rate for the relevant year.
S-62
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(b) Revenue Recognition
Income from sales of crude oil and gas, are measured at fair value of the cash receipts or amounts to be received, net of commercial discounts, and is recorded in the statements of comprehensive income when risks and significant rights of ownership are transferred to PDVSA Petróleo and MPPEP as stipulated in the hydrocarbon purchase sale agreement. Income is recognized when it can be reasonably measured and it is probable that future economic benefits will flow to the Company. Income from activities other than the Company’s main business is recognized when realized. Income is not recognized when there is significant uncertainty as to the recoverability of the obligation acquired by the buyer. All of the Company results are from continuing operations. At December 31, 2011, the Company received accounting guidelines from its main shareholder, CVP, to recognize revenue from the sale of crude, royalty and extraction tax in accordance with the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (see Note 7-g and Note 21).
(c) Financial Income and Expenses
Financial income included in the statements of comprehensive income represents mainly the effects originated by modifications and dispositions in relation to exchange rates (see Note 18).
Financial expenses included in the statements of comprehensive income represents changes (losses) in the fair value of financial assets (see Note 7-k) and the asset retirement obligation (see Note 3-g and Note 3-m)
Income and losses in foreign currencies are recognized on a net basis, either as financial income or financial expense, depending on the effect of foreign currency fluctuations resulting from a net asset or liability position.
(d) Income Tax
Income tax expense comprises current and deferred income tax. Income tax expense is recognized in the results for each year, except to the extent that it relates to items that should be directly recognized in other comprehensive income.
Current income tax is the expected tax payable based on the taxable income for the year, using the methodology established by current laws and tax rates at the reporting date and any adjustment to taxes payable from previous years. Current income tax payable also includes tax responsibility derived from dividends declared.
Deferred income tax is recognized using the balance sheet liability method. Deferred tax assets and liabilities are recognized by the timing differences that exist between assets and liabilities values presented in the statement of financial position and their corresponding tax value, as well as operating losses and tax credit carry-forwards. The value of deferred tax assets and liabilities is determined based on tax rates expected to be applicable to taxable income for the year in which temporary differences will be recovered or settled pursuant to law. The effect on deferred assets and liabilities of changes in tax rates is recorded in the results for the year in which such changes become effective.
S-63
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
A deferred tax asset is recognized only to the extent that future taxable income will be available for offsetting. Deferred tax assets are reviewed at each reporting date and reduced to the extent that it is no longer probable that the related tax benefit will be realized.
(e) Contributions and Fundings for Social Development
Corresponds to contributions and fundings the Company is obliged by law to carry out and are paid and recovered by PDVSA. These contributions are funding for endogenous projects, programs related to science, technology and innovation and funding of national programs in relation to antidrug activities and Sports Organic Law.
(f) Financial Instruments
Non-derivative financial instruments consist of cash and cash equivalents, recoverable tax credits, accounts receivable, accounts payable to suppliers, and other liabilities (see Note 5).
Non-derivate financial instruments classified as at fair value through profit or loss are initially recognized at fair value, plus any direct transaction costs.
Recoverable tax credits are accounted for at fair value after its initial recognition (see Note 7-k). Liabilities for asset retirement obligations are accounted for at present value (see Note 16). All other non-derivative financial assets and liabilities are maintained at its original recognized value.
A financial instrument is recorded when the Company engages or commits to the contractual clauses thereof. Financial assets are reversed if the Company’s contractual rights over the asset’s cash flows expire or if the Company transfers the financial asset to another entity without retaining control or a significant portion of the asset’s risks and rewards. Regular purchases and sales of financial assets are accounted for at trade date, which is generally the date on which the Company commits to purchase or sell the asset. Financial liabilities are derecognized when the Company’s specific contractual obligation expires or is paid.
During the years ended December 31, 2011, 2010 and 2009, the Company conducted no transactions with derivative instruments.
The balance of financial assets and liabilities are offset and the net amount shown in the statement of financial position when and only when, the Company has a legal right to offset amounts and intends to settle on a net basis or to realize the asset and settle the liability simultaneously.
S-64
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(g) Property, Plant and Equipment
Recognition and measurement
Property, plant and equipment are stated at cost, net of accumulated depreciation and impairment losses (see Note 3-l). The successful efforts accounting method is used for exploration and production activities of crude oil and natural gas, taking into consideration what is established under IFRS 6 Exploration For and Evaluation of Mineral Resources in relation to accounting for exploration and evaluation expenditures, including the recognition of exploration and evaluation assets. All costs for development wells, related plant and equipment, and property used for oil recovery are capitalized. Costs of exploratory wells are capitalized until it is determined whether they are commercially feasible; otherwise, such costs are charged to operating expenses. Other exploratory expenditures, including geological and geophysical costs, are expensed as incurred.
The cost of property, plant and equipment includes disbursements that are directly attributable to the acquisition of such assets and the amounts associated with asset retirement obligations (see Note 3-h).
Finance costs of projects requiring major investments, and costs incurred for specific financing of projects, are recognized as part of property, plant and equipment, when can be directly related to the construction or acquisition of a capable asset. Capitalization of such costs is suspended during periods when the development of construction activity is interrupted, and capitalization ends when necessary activities are substantially complete for the utilization of a capable asset. An asset is considered capable, when it requires a period of substantially time necessary before is ready for use.
The cost of assets built by the Company includes materials and direct labor, as well as any other direct cost attributable to bringing the asset to working condition. Costs for dismantling and removal from the construction site are also included.
All disbursements relating to construction or purchase of property, plant and equipment in the stage prior to implementation are stated at cost as work in progress. Once the assets are ready for use, they are transferred to the respective component of property, plant and equipment and depreciation or amortization commences.
Gain or loss generated by the sale, retirement or disposal of an asset from property, plant and equipment, is determined by the difference between the amount received from sale, retirement or disposal, if any, and the net carrying value in the books of the Company, and is recognized as other income or expense, net in the statements of comprehensive income.
Certain materials and supplies accounted for as inventory and considered strategic since they will be used as spare parts for two years operation in the production facilities and in specific investment projects are reported under property, plant and equipment.
S-65
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Subsequent Costs
Costs for major maintenance or general repairs, as well as replacement of significant parts or property, plant and equipment are capitalized when identified as a separate component of the asset to which such maintenance, repair and replacement corresponds and are depreciated between one maintenance period and the other. Disbursements for minor maintenance, repairs and renewals incurred to maintain facilities in operating conditions are expensed.
Depletion, Depreciation and Amortization
Depletion, depreciation and amortization of capitalized costs related to wells and facilities for the production of crude oil and gas are determined by the units of production method by field, based on proved developed reserves, which include quantities of oil and gas that can be recovered from existing wells, with, equipment and methods currently in use. The rates used are reviewed annually based on an analysis of reserves and are applied retroactively at the beginning of the year. Capitalized costs of other plant and equipment are depreciated over their estimated useful lives, mainly using the straight-line method with an average useful life of 15 years for administrative buildings and between 3 and 5 years for the remaining assets
When parts of a property, plant and equipment asset have different useful lives, they are recorded separately as a significant component of that asset.
Depreciation methods and average useful lives of property, plant and equipment are reviewed annually. Land is not depreciated.
(h) Costs associated with Asset Retirement Obligations
The Company capitalizes estimated costs associated with obligations from retirement of assets used for exploration and crude oil and natural gas production activities, based on the future retirement plan for those assets. Cost is capitalized as part of the related long-lived asset and is amortized over its useful life with a charge to operating costs (see Note 3-m).
(i) Inventories
Inventories are stated at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the normal course of business, less costs to complete and estimated selling costs.
The cost of inventories of crude oil and its products is determined using the average cost method.
Materials and supplies are valued mainly at average cost, less an allowance for possible losses, and are classified into two groups: current assets and non-current assets.
S-66
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(j) Accounts Receivable
Accounts receivable are accounted for according to price formulas established in the Hydrocarbon Purchase Sale Agreement between the Petrodelta, S.A. and PDVSA Petróleo, S.A. whereby the former undertake to sell and PDVSA Petróleo, S.A. undertakes to buy all hydrocarbons produced that are not being used in their operations within the delimited operating areas. At December 31, 2011, 2010 and 2009, the Company does not expect to incur losses on uncollectible accounts and, therefore, has not set aside a provision in this connection other than those described in the hydrocarbon purchase sale agreement with PDVSA Petróleo, S.A.
(k) Cash and Cash Equivalent
Petrodelta, S.A. considers as cash and cash equivalents the cash in hands and banks. At December 31, 2011, 2010 and 2009 amounted to approximately US$2,342 thousands, US$3,465 thousands and US$3.062 thousands (Bs.10,071 thousands, Bs.14,900 thousands and Bs.6.583 thousands), respectively.
(l) Impairment in the Value of Assets
Non-derivative Financial Assets
Financial assets are assessed by the Company at the date of the financial statements to determine whether there is any objective evidence of impairment. A financial asset is impaired if there is objective evidence that one or more events have had a negative effect on the estimated future cash flows of the asset (see Note 6).
Objective evidence that financial assets are impaired can include default or lack of compliance from debtors, restructuring a balance due to the Company in terms that may not be considered in other circumstances, signs that a debtor or issuer declares bankrupt or the instrument no longer has a market.
Significant financial assets are reviewed individually to determine their impairment. The remaining financial assets with similar credit risk characteristics are evaluated as a group.
In evaluating impairment, the Company uses historical trends of the probability of defaults, timing of recoveries and the amount of loss incurred, adjusted for management’s judgment as to whether current economic and credit conditions are such that the actual losses are likely to be greater or less than the suggested by historical trends.
An impairment loss related to a financial asset is calculated as the difference between its carrying amount and the present value of the estimated future cash flows, discounted at the effective interest rate. Impairment losses are recognized in the statements of comprehensive income. An impairment loss is reversed if the amount can be related objectively to an event occurring after the impairment loss was recognized (see Note 19).
S-67
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Non-Financial Assets
The carrying amounts of non-financial assets, excluding inventory and deferred tax, are reviewed at each reporting date of the statement of financial position to determine whether evidence of impairment exists. If any such indication exists, then the recoverable value of the asset is estimated.
The recoverable value of an asset o cash-generating unit is the greater of its carrying value and its fair value, less direct selling expenses. When determining the carrying value, expected future net cash flows are discounted using present value techniques, using a discount rate before tax that reflects current market conditions over the time value of money and specific risks that the asset may bear. Impairment is determined by the Company based on cash-generating units, in accordance with its business segments, geographical locations and the final use of the production generated by each unit. A cash-generating unit is the assets grouped at the lowest levels for which there are separately identifiable cash flows. When evaluating impairment, goodwill acquired during business combinations is allocated among cash-generating units that are expected to benefit from combination synergies.
An impairment loss is recognized when the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. Impairment loss is recognized in the statements of comprehensive income for the year and the asset cost is shown net of this impairment charge.
Impairment losses can be reversed only if the reversion is related to a change in the estimates used after the impairment loss was recognized. This reversion shall not exceed the book value of assets net of depreciation or amortization as if the impairment had never been recognized. Impairment losses associated to goodwill are not reversed.
(m) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be reliably estimated, and it is probable that an outflow of economic benefits will be required to settle the obligation. When the effect of the time value of money is significant, the provision is determined by applying a discount rate associated with the estimated payment terms, if the terms can be estimated reliably as well as the risk associated with those obligations (see Note 16 and Note 20).
Environmental Issues
In conformity with the environmental policy established by the Company and following instructions from PDVSA and applicable current legislation, the Company a liability is recognized when costs are likely and can be reasonably estimated. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures for past operations that do not contribute to generating current or future income are charged to expense. Recognition of these provisions coincides with the identification of an obligation for environmental remediation where Petrodelta, S.A. has sufficient information to determine a fair estimate of the respective cost. Subsequent adjustments to estimates, if necessary, are made upon obtaining additional information (see Note 16 and Note 20).
S-68
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Asset Retirement
Obligations associated with the retirement of long-lived assets are recognized at fair value on the date on which such obligation is incurred, based on future discounted cash flows. The fair values are determined based on current regulations and technologies.
Changes in fair values of obligations are added to or deducted from the cost of the respective asset. The adjusted depreciation amount of the asset is depreciated over its remaining useful life. Therefore, once its useful life has ended all subsequent changes in the fair value of the obligation are recognized in the statements of comprehensive income. The increase in the obligation for each year is recognized in the results of operations as financial expenses.
Litigation and Other Claims
Provision for litigations and claims are recognized in the event that legal action has been lodged, government investigations have been initiated and other legal actions are outstanding or subject to be filed in the future against the Company, as a result of past events, which may result in a probable outflow of economic benefits to pay for that obligation which may be reliably estimated. The Company has no legal suits or claims that need to be recorded or disclosed in its financial statements (see Note 20).
Damages to Land
Liabilities for damage to land is recorded as a result of the regular activities carried out by the Company to access the different existing areas or new, for which third-party property or economic activity can be or are affected causing the need to compensate the economic effects caused.
As a result of the expansion of the activities during the years 2009 to 2011, the Company caused damages to third parties and currently is in negotiation process with different owners. Management estimated potential liabilities as of December 31, 2011 and 2010 amounting US$1,799 thousands and US$2,093 thousands (Bs.7.736 thousands and Bs.9,000 thousands), respectively, and were included in the results of these years. As of December 31, 2009 there was not obligation for that concept.
(n) Royalties and other Taxes
Royalties and other related taxes are calculated according to the provisions of the Hydrocarbons Law and other laws regulating the oil industry (see Note 1 and 7) and are recognized in the statements of comprehensive income when caused.
S-69
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(o) Equity
Capital Stock
Common shares are classified as equity. For the years ended December 31, 2011, 2010 and 2009, the Company has no preferred shares (see Note 14).
Share Premium
The Company recognizes as share premium any excess in the value of contributions made by shareholders for Company incorporation over the par value at the incorporation date (see Note 14).
Legal Reserve
The Venezuelan Code of Commerce requires companies to set aside 5% of their net income each year to a legal reserve until it reaches an amount equivalent to at least 10% of their capital stock in bolivars (see Note 14).
Other Equity Reserves
The Company has the policy of transferring from retained earnings to other equity reserves the balance of deferred tax asset. This reserve is recognized in retained earnings to the extent that such asset gets realized when the temporary differences that gave rise to it are deducted for tax purposes and consequently would be available for dividend payments (see Note 14).
Dividend Distribution
Dividend distribution to the Company’s shareholders is recognized as a liability in the financial statements in the period in which the dividends are approved by the shareholders of the Company (see Note 14).
(p) Accounting estimates requiring a high degree of Judgment
The Company continually evaluates judgments used to record its accounting estimates, which are recorded based on historical experience and other factors, including expectation of future events that are believed to be reasonable under the circumstances. Significant future changes to assumptions established by management may significantly affect the carrying value of assets and liabilities.
Below is a summary of the most significant accounting estimates made by the Company:
Estimates of oil and gas Reserves
Oil and gas reserves are key elements in the Company’s decision-making process. They are also important in evaluating impairment in the carrying amount of long-lived assets. Calculation of depreciation, amortization and depletion of property, plant and equipment accounts related to hydrocarbon production requires quantification of proved developed
S-70
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
hydrocarbon reserves expected to be recovered by the Company in the future. Reserve estimates are only approximate amounts due to the high degree of judgment and specialization required to develop the information. Reserves are calculated by the support of specialized technical departments at Petróleos de Venezuela, S.A. (PDVSA) (related company that owns the Company’s main shareholder) and results are submitted for approval by MPPEP in order to guarantee the reasonableness of the information. Additionally, reserve studies are regularly updated to guarantee that any change in estimates is timely recorded in the Company’s financial statements.
Reserves studies of crude oil and gas assigned to the Company has been updated as of November 30, 2011 by the superintendence of reservoir of the Company who possesses adequate technological elements necessary to determine reserves, and its impact in the statements of comprehensive income is reflected as of December 31, 2011.
Assessment of impairment in the value of Property, Plant and Equipment
Management annually assesses impairment in the value of property, plant and equipment. The main key assumptions considered by management to determine the recoverable amount of property, plant and equipment were income projections, oil prices, royalties, operating and capital costs and the discount rate. Projections include proved developed reserves to be produced during the development period of production activities in the assigned fields. At December 31, 2011, 2010 and 2009, the Company has not identified impairment in the carrying value of property, plant and equipment as a result of these estimates.
Abandonment Cost Calculation
The Company’s financial statements include an asset and a provision for property, plant and equipment used in hydrocarbon production that is expected to be abandoned in the future and in relation to which the Company will make future disbursements. Assumptions considered for the calculation of this asset and the provision for abandonment (asset abandonment costs, date of abandonment, and inflation and discount rates) may vary depending on factors such as performance in the field, changes in technology and legal requirements. Assumptions made by the Company are recorded based on technical studies and management’s experience and are regularly reviewed (see Note 9).
(q) Related Party Transactions
The Company does not disclose, as part of balances and transactions with related companies (see Note 21), transactions with government entities conducted in the normal course of business, the terms and conditions of which are consistently applied to other public and private entities and for which there are no other suppliers, i.e., electricity, telecommunications, taxes, etc.
S-71
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(r) Accrual for Employee Benefits
Following corporate instructions, the related company PDVSA Petróleo, S.A. assumed the employer role for employees who accepted the transfer, and are working as assigned employees to Petrodelta, S.A. operations. According to this, PDVSA Petróleo, S.A. administer, prepare and pay those employees’ payroll and invoice direct payroll and benefits to the Company, which recognize those costs against a liability to PDVSA Petróleo, S.A. The direct payroll and benefits costs are determined by PDVSA according the following policies:
Termination Benefits
The Company accrues for its liability in respect of employee termination benefits based on the provisions of the Venezuelan Labor Law and the prevailing oil-sector Collective Labor Agreement (see Note 22). Most of this accrual for indemnification has been deposited in trust accounts in the name of each employee.
Profit Sharing and Bonuses
Liabilities in respect of labor benefits and bonuses for staff, vacation leaves, and other benefits are accounted for as incurred along with the staff’s provision of services.
During the years ended December 31, 2011, 2010 and 2009, the Company has not had direct employees and, therefore, has not recorded liabilities derived from these labor-related benefits except for the payroll related cost monthly billed to the Company by PDVSA Petróleos S.A.
Retirement Plan
The amount to be provision for retirement benefits is received from PDVSA based on actuarial studies. Net liabilities in respect of the retirement plan as defined in the contract are accounted for separately per each participant in said plan, by estimating the amount of future benefits to be acquired by staff versus their length of service during current and prior periods; said benefits are discounted in order to determine their current value, then it is deducted the fair market value of those assets associated to the plan. The discount rate reflects the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities. This calculation is made by an actuary by using the projected unit credit method.
Improvements made to the plan’s benefits, in connection with past service cost, are expensed in the statements of comprehensive income over the estimated period that, on average, will last until the time that said benefits will be paid in full. As said benefits fall under irrevocable acquired rights after approval, said expense is recorded, immediately, in the statements of comprehensive income.
The amount accounted for as income or expense is the share corresponding to the total of unrecorded actuarial earnings or loss in excess of 10% of the greater of these sums: a) the current value of liabilities in respect of those benefits defined as of that date; and b) the reasonable value of the plan’s assets as of that date. Said caps are computed and apply separately per each plan’s benefit so defined.
S-72
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Post-retirement Benefits other than Retirement
Net liabilities in respect of post-retirement benefits other than retirement, as defined in the contract, equal the total of future benefits earned by staff along with their length of service during current and prior periods. Said benefits include mainly: health and dental plans, burial and funeral insurance, and food electronic card. Said liabilities are computed by using the projected unit credit method; then they are deducted to reflect their current value and, if applicable, the fair market value of related assets is deducted as well. The discount rate reflects the yield rate that, as of the date of the financial statements, is reported through financial instruments issued by credit institutions with high ratings and maturity dates that are in line with those due dates applicable to said liabilities.
Past service cost and the actuarial income or loss are recorded by using the method set out in the retirement plan per the contract.
The provision for this concept is provided by PDVSA which is based on actuarial studies.
(s) New accounting Standards not yet Adopted
Certain new standards, amendments and interpretations to existing standards were not effective for the year ended December 31, 2010 and have not been applied in the preparation of the Company’s financial statements. The most important standards, amendments and interpretations for the Company are as follows:
•
In December 2011, the IASB issued amendments to IFRS 7 Financial Instruments: Disclosures and IAS 32 Financial Instruments: Presentation. These amendments introduce new disclosure requirements about the effects of offsetting financial assets and financial liabilities and related arrangements on an entity’s financial position. The amendments to IFRS 7 are effective for annual periods beginning on or after 1 January 2013, with the amendments to IAS 32 effective for annual periods beginning on or after 1 January 2014.
•
In December 2011, the IASB also amended IFRS 9 Financial Instruments by deferring the effective application from annual periods beginning January 1, 2013 to annual periods beginning January 1, 2015 as originally issued by the IASB in November 2009.
•
In June 2011, the IASB published an amended version of IAS 19: Employee Benefits, effective for annual periods beginning on or after January 1, 2013. The amendment improve the accounting for pensions and other post-retirement benefits by providing investors and other users of financial statements with a much clearer picture of an entity´s obligations resulting from the provision of defined benefit plans and how those obligations will affect its financial position, financial performance and cash flow.
S-73
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
•
In June 2011, the IASB published amendments to IAS 1 Presentation of Financial Statements. These amendments are effective for annual periods beginning on or after July 1, 2012 and revise the way other comprehensive income is presented.
•
In May 2011, the IASB published amendments and new standards effective for annual periods beginning on or after 1 January 2013. The amendments relates to:
The amendments are:
•
IAS 27 Consolidated and Separate Financial Statements changed its title to IAS 27 Separate Financial Statements and IAS 27 has amended its objective to setting standards to be applied in accounting for investments in subsidiaries, jointly ventures, and associates when an entity elects, or is required by local regulations, to present separate (non-consolidated) financial statements.
•
IAS 28 Investments in Associates and Joint Ventures has the objective to set out the requirements for the application of the equity method when accounting for investments in associates and joint ventures.
The new standards are:
•
IFRS 10 Consolidated Financial Statements which is a replacement of sections of IAS 27 Consolidated and Separate Financial Statements and in its entirety of SIC 12 Consolidation - Special Purposes Entities, looks for having a single basis for consolidation for all entities, regardless of the nature of the investee, and that basis is control.
•
IFRS 11 Joint Arrangements which supersedes IAS 31 Interests in Joint Ventures and SIC -13 Jointly Controlled Entities - Non Monetary Contributions by Venturers, classifies joint arrangements as either joint operations or joint ventures based on the parties rights and obligations and eliminates proportionate consolidation method requiring the use of equity accounting method for interests in joint ventures.
•
IFRS 12 Disclosure of Interests with Other Entities require extensive disclosures relating to an entity´s interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities to help users of its financial statements evaluate the nature of and risks associated with its interests in other entities and the effect of those interests in its financial statements.
•
IFRS 13 Fair Value Measurement establishes a single framework for measuring fair value required by other Standards and applies to both financial and non-financial items measured at fair value.
•
In December 2010, the IASB published amendments to IAS 12 Income Taxes effective for accounting periods beginning on or after January 1, 2012. The amendments set out in Deferred Tax: Recovery of Underlying Assets, provides a practical solution to the problem by introducing a presumption that recovery of the carrying amount will, normally be through sale. As a result of the amendments, SIC-21 Income Taxes-Recovery of
S-74
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Revalued Non-Depreciable Assets would no longer apply to investment properties carried at fair value. The amendments also incorporate into IAS 12 the remaining guidance previously contained in SIC-21, which is accordingly withdrawn.
•
In November 2009, the IASB issued IFRS 9 Financial Instruments, effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. IFRS 9 replaces those parts of IAS 39 relating to the classification and measurement of financial assets. Key features are as follows:
•
Financial assets are required to be classified into two measurement categories: those to be measured subsequently at fair value, and those to be measured subsequently at amortized cost. The decision is to be made at initial recognition. The classification depends on the entity’s business model for managing its financial instruments and the contractual cash flow characteristics of the instrument.
•
An instrument is subsequently measured at amortized cost only if it is a debt instrument and both (i) the objective of the entity’s business model is to hold the asset to collect the contractual cash flows, and (ii) the asset’s contractual cash flows represent only payments of principal and interest (that is, it has only “basic loan features”). All other debt instruments are to be measured at fair value through profit or loss.
•
All equity instruments are to be measured subsequently at fair value. Equity instruments that are held for trading will be measured at fair value through profit or loss. For all other equity investments, an irrevocable election can be made at initial recognition, to recognize unrealized and realized fair value gains and losses through other comprehensive income rather than profit or loss. There is to be no recycling of fair value gains and losses to profit or loss. This election may be made on an instrument-by instrument basis. Dividends are to be presented in profit or loss, as long as they represent a return on investment.
The Company completed the analysis of these standards and determined no significant effects on its financial statements.
(t) Recently Adopted Accounting Pronouncements
The following standards and interpretations became effective during 2011:
•
In October 2010, the IASB published amendments to IFRS 7 Financial Instruments Disclosure effective for accounting periods beginning on or after July 1, 2011. The amendments will allow users of financial statements to improve their understanding of transfer transactions of financial assets (for example, securitizations), including understanding the possible effects of any risks that may remain with the entity that transferred the assets. The amendments also require additional disclosures if a disproportionate amount of transfer transactions are undertaken around the end of a reporting period.
S-75
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
•
In May 2010, the IASB published improvements to International Financial Reporting Standards effective from January 1, 2011. The improvements consist of a mixture of substantive changes and clarifications in the following standards and interpretations considered most important for the Company: IFRS 7 Financial Instruments Disclosure; IAS 1 Presentation of Financial Statements and IAS 27 Consolidated and Separate Financial Statements.
•
In November 2009, the IASB published amendments is to IFRIC 14 Prepayments of a Minimum Funding Requirement, which has an effective date for annual periods beginning on or after January 1, 2011 and which itself is an interpretation of IAS 19 Employee Benefits. The amendment applies in the limited circumstances when an entity is subject to minimum funding requirements and makes an early payment of contributions to cover those requirements. The amendment permits such an entity to treat the benefit of such an early payment as an asset.
•
In November 2009, the IASB published an amendment to IAS 24 Related Party Disclosures which is effective for annual periods beginning on or after January 1, 2011. IAS 24 was revised in 2009 by: (a) simplifying the definition of a related party, clarifying its intended meaning and eliminating inconsistencies from the definition and by (b) providing a partial exemption from the disclosure requirements for government-related entities.
The Company’s accounting policies have been revised and modified, when necessary, to adopt the requirements established in these new standards or interpretations. Adoption of these standards and interpretations did not significantly affect the Company’s financial statements.
(4)
Exchange Agreement with the Central Bank of Venezuela (BCV)
On January 8, 2010, Official Gazette 39,342 was published containing Foreign Exchange Agreement No. 14, effective as of January 11, 2010, establishing exchange rates for the purchase and sale of currency, other than local currency, for legal entities as follows:
•
Payment in currency, other than local currency, transactions aimed at imports by the sector of food, health, education, machinery and equipment and science and technology, as well as payments for the activities of the public sector not related to petroleum, will be made at an exchange rate of Bs.2.60 per U.S. Dollar; payments of all other foreign currency sale transactions will be made at an exchange rate of Bs.4.30 per U.S. Dollar.
•
Payment of purchase of currency, other than local currency, obtained: i) by the public sector, other than those originating from hydrocarbon imports regulated by Foreign Exchange Agreement 9, will be made at an exchange rate of Bs.2.5935 per U.S. Dollar; and ii) the remaining purchases of foreign currency will be made at an exchange rate of Bs.4.2893 per U.S. Dollar.
•
Payment of currency purchase, other than local currency, transactions, originating from export of hydrocarbons, regulated under Foreign Exchange Agreement No. 9, will be
S-76
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
made at an exchange rate of Bs.4.2893 and Bs.2.5935 per U.S. Dollar, pursuant to the provisions of the BCV, and proportions determined by that entity for payment of sale transactions. An exchange rate of Bs.2.5935, per U.S. Dollar will be applicable to at least 30% of those currencies purchase transactions, other than the local currency (see Note 18).
The previous paragraph is applicable to mix companies affiliates of PDVSA.
In addition, this Agreement enables legal entities, other than PDVSA, in the area of exports of goods and services to withhold and manage up to thirty percent (30%) of income in foreign currency from the exports made; this percentage will be used to cover expenses from export activities other than long-term debt. This Agreement also established that purchase and sale transactions of foreign currency with payment requested to the BCV before the effective date will be paid at an exchange rate of Bs.2.14 per U.S. Dollar and Bs.2.15 per U.S. Dollar, respectively, as established in Foreign Exchange Agreement No. 2, dated March 1, 2005.
In May 2010, the Venezuelan Government established the Transactions System with Foreign Currency Securities (Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”)) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuelan bonds. The Company does not have, and has not had, any transaction through SITME.
On December 30, 2010, Foreign Exchange Agreement No. 14, effective as of January 1, 2011, was published in Official Gazette 39,584. This Agreement sets the exchange rate at Bs.4.2893 per U.S. Dollar for purchases and Bs.4,30 per U.S. dollar for sales. This resolution supersedes Foreign Exchange Agreement No. 14, dated January 8, 2010, published in Official Gazette of the Bolivarian Republic of Venezuela 39,342, dated January 8, 2010; as well as Foreign Exchange Agreements No. 15, No. 16, No. 17, and any other provision that may come into conflict with this Foreign Exchange Agreement.
The pronouncement of the Exchange Agreement No. 14 did not have an effect on the Company’s right to maintain foreign currency funds at financial institutions outside the country on revenues proceeds from sale of crude in order to make payments and disbursements outside the Bolivarian Republic of Venezuela.
On November 21, 2005, the Exchange Agreement No. 9 was published in the Official Gazette No. 38,318, later revised on March 22, 2007 and published in the Official Gazette No. 38.650, which establishes that foreign currency obtained from hydrocarbon exports, must be sold to the Venezuelan Central Bank (BCV), except for foreign currency earmarked for activities conducted by PDVSA in conformity with the BCV Law Reform. Under this agreement, PDVSA and its subsidiaries may not maintain foreign currency funds in Venezuela for more than 48 hours, and establishes how these funds will be used by PDVSA.
S-77
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(5)
Determination of Fair Values
Certain of the Company’s accounting policies and disclosures require the determination of fair values for financial and non-financial assets and liabilities. Fair values have been estimated for purposes of valuation and disclosure using available market information and appropriate valuation methods. When applicable, additional information on fair value estimates of assets and liabilities is disclosed in the specific notes to the statements of financial position.
Non-Derivative Current Financial Assets and Liabilities
The carrying amounts of financial assets and liabilities included in prepaid expenses and other assets, accounts receivable, cash and cash equivalents and accounts payable to suppliers approximate their fair value because of the short-term maturities of these instruments.
The fair value of recoverable tax credits and other liabilities has been determined by discounting their carrying value based on estimation of future collections and payments, using interest rates calculated according to the inherent risk of the assessed instrument such as credit quality, liquidity, currency among others (see Note 7-k).
The net carrying value of the account payable to PDVSA approximates the estimated fair value since its payment depends on the volume and nature of transactions conducted by the Company with the parent Company and its subsidiaries.
Derivative Financial Assets and Liabilities
The fair value of derivative financial instruments is based on the amount that the Company will receive or pay to terminate the agreements, taking into account current commodity prices, interest rate and the current creditworthiness of the parties involved. During the years ended December 31, 2011, 2010 and 2009, Petrodelta, S.A. did not engage in operations involving derivative financial instruments.
Non-Derivative Financial Obligations
The fair value of non-derivative financial obligations, which is determined for disclosure purposes, is calculated based on information provided by financial institutions and the present value of future principal and interest cash flows, discounted at the market interest rate at the reporting date, based on the inherent risk of those obligations.
Accounts Payable with Related Parties
The value of accounts payable to related parties approximate its fair value and are settle upon decisions adopted by PDVSA.
S-78
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(6)
Financial Risk Management
Local and international conditions, such as recession periods, inflation, interest rates, devaluation, and hydrocarbon price volatility may have a significant effect on the Company’s financial position. The Company is exposed to a variety of financial risks: market risk (including exchange rate fluctuation risk, interest rate risk and price risk), liquidity risk and capital risk. Financial instruments exposed to concentration of credit risk consist primarily of cash and trade accounts receivable.
At December 31, 2011, 2010 and 2009, the Company’s cash is placed with local and foreign financial institutions. In addition, there is some concentration of credit risk in trade accounts receivable since all crude oil and gas produced is sold to PDVSA Petróleo, S.A.
Market Risk
Market risk is the risk that changes in market prices, including foreign exchange rates, interest rates or sales prices, will affect the Company’s income or the value of its financial instruments. The Company’s general risk management focuses on the uncertainty surrounding financial markets and seeks to minimize the potential adverse effects on the Company’s financial performance.
The Company is exposed to risks stemming from changes in the sale price of hydrocarbons, which depend on external market factors. At December 31, 2011, 2010 and 2009, hydrocarbon sales prices are calculated based on predetermined formulas that consider the price of hydrocarbons in different international markets. Price fluctuations may have a significant impact on the Company’s income. At December 31, 2011, 2010 and 2009, the Company has no mechanisms in place to protect against exposure to hydrocarbon sales price fluctuations.
In addition, the Company operates in Venezuela and is exposed to foreign exchange risk from variations in the exchange rate of the Venezuelan Bolívar relative to the U.S. Dollar. Foreign exchange risk is mainly derived from future commercial operations and assets and liabilities recognized in bolivars.
The Company has accounts receivable to PDVSA which earn interest on arrears 45 days after bills are due and is, therefore, exposed to interest rate fluctuation.
Liquidity Risk
Handling prudently liquidity risk implies maintaining sufficient funds in cash and short term marketable securities, as well as having working capital credit facilities available. The approach the Company maintains to manage this risk implies having enough cash and temporary investments as well as the availability of funds provided by its main shareholder, who supplies funds according to the Company needs. The Company permanently evaluates its future cash flows through short and long term projections from estimated sales and cash requirements which correspond mainly to operation and maintenance of production facilities.
S-79
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Capital Risk Management
The Company is focused on safeguarding its ability to continue as a going concern in order to provide returns for the shareholders and maintain an optimal capital structure to reduce capital costs. In order to maintain or adjust the capital structure, the Company may adjust the amount of dividends paid to shareholders, return capital to shareholders or issue new shares.
(7)
Taxes and Royalties
Below is a summary of taxes affecting the Company’s operations, stated (in thousands):
S-80
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(a) Income Tax
Reconciliation between the nominal and the effective income tax rates for each year is shown below (in thousands):
The increase in the effective tax rate as of December 31, 2010 with respect to December 31, 2009 is mainly attributable to:

Increase in taxable income in bolivars, as a result of exchange differences recorded which affected the calculation base of the income tax expense for maintaining assets and liabilities other than the bolivar.

Decrease in the deferred tax assets resulting from the difference between the carrying value of the property, plant and equipment and its tax base.
(b) Tax Loss Carryforwards
The current Income Tax Law allows tax losses to be carried forward for three years to offset future taxable income, except losses resulting from the application of the fiscal inflation adjustment, which can be carried forward one year, During the years ended December 31, 2011, 2010 and 2009 the Company had no tax loss carryforward.
(c) Tax Inflation Adjustment
Venezuelan Income Tax Law requires an initial inflation adjustment to compute taxable income. The Law provides that the initially adjusted values of property, plant and equipment should be depreciated or amortized for tax purposes over the remaining useful lives of such assets. The Law also requires that an annual inflation adjustment be included in income tax reconciliation as a taxable or deductible item.
S-81
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(d) Transfer Pricing
According to the Income Tax Law, taxpayers subject to this tax that conduct import, export and loan transactions with related parties abroad are required to calculate income, costs and deductions applying the methodology set out in the Law.
(e) Income Tax Rate
Official Gazette No. 38,529 of the Bolivarian Republic of Venezuela, published on September 25, 2006, modifies Article No. 11 of the Law regarding the rate applicable to companies engaged in hydrocarbon production and related activities, establishing a 50% general rate. However, only companies that conduct integrated or non-integrated activities related to exploration and production of non-associated gas, and processing, transportation, distribution, storage, marketing and export of gas and its components, or those exclusively engaged in refining of hydrocarbons or enhancement of heavy and extra-heavy crude oil are subject to a 34% tax rate. Therefore, application of the 34% rate for companies incorporated under the joint venture agreements executed under the superseded Law Reserving Hydrocarbon Trade and Industry to the State is eliminated.
(f) Deferred income Tax
The movements of deferred income tax asset (liability) shown in the results of each year are as follows (in thousands):
S-82
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
S-83
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
S-84
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(g) Royalties
According with the Venezuelan Hydrocarbon Law (LOH), royalties are paid based on crude oil produced and associated natural gas processed in Venezuela. Volumes of hydrocarbons produced in traditional areas are taxed with a 30% rate.
The partial reform of the Hydrocarbon Law was approved in May 2006, whereby operators should pay 33.33% of the wellhead value of each barrel to the Venezuelan government by means of royalties and additional taxes.
On November 14, 2006, a new calculation of royalties was established for companies that conduct primary oil activities in the country requiring that contents of sulphur and API gravity of liquid hydrocarbons extracted be measured on a monthly basis and be reported together with taxed production. This information will be part of the royalty payment price and will be used for calculation of any special advantage. This information will result in adjustments for gravity and sulphur, which will be published by Ministry for Energy and Oil (MPPEP).
On April 18, 2011, the Venezuelan government published in the Extraordinary Official Gazette No. 6.022, by means of decree-law No. 8.163 of same date, the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (see Note 23-i and 25-a). This Law, among other things, caps royalty, extraction tax, and export register tax at US$70 per barrel. On October 3, 2011, the Company received accounting guidelines from CVP, to account for revenues from the sale of crude oil, royalty paid in kind and extraction tax according to this law. In regards to royalty for the volume of 30% of produced crude, the Company values and records the amount due for this concept at the US$70 per barrel caps price from the date following the publication of the law and not according to the selling price of the barrel of crude. Royalty under prior Law and current Law for the years ended December 31, 2011, 2010 and 2009 amounted to US$263,422 thousands, US$183,076 thousands and US$137,925 thousands (Bs.1,132,715 thousands, Bs.787,227 thousands and Bs.296,538 thousands), respectively, included in the statements of comprehensive income under royalties and other taxes (see Note 21).
(h) Extraction Tax
The Venezuelan Hydrocarbon Law Reform establishes a rate equivalent to 33.33% of the value of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis as for royalties. In determining this tax, the taxpayer may deduct the amount that would have been paid for royalty, including the additional royalty paid as special advantage. This tax is effective since May 2006. The Company incurred no tax in this connection for 2011, 2010 and 2009.
(i) Surface Tax
The Venezuelan Hydrocarbon Law establishes a surface tax equivalent to 100 tax units for each square kilometer or fraction thereof per year for licensed areas that are not under production. This tax will increase by 2% during the first five years, and by 5% during all subsequent years. Company management considers that there are no nonproductive areas. Petrodelta, S.A. incurred in this tax during 2011, 2010 and 2009 for US$235 thousands, US$201 thousands and US$1,946 thousands (Bs.1,011 thousands, Bs.865 thousands and Bs.4,184 thousands), respectively, included in the statements of comprehensive income under royalties and other taxes.
S-85
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(j) General Consumption Tax
The Venezuelan Hydrocarbon Law Reform establishes an internal consumption tax equivalent to 10% of the value of each cubic meter of hydrocarbon derivatives produced and consumed as fuel in internal operations, calculated on the final selling price.
(k) Value Added Tax (VAT)
On March 26, 2009, under Official Gazette No. 39,147 modification of applicable tax rate for value added tax to 12% was published, having effect from April 1, 2009.
The VAT Law establishes an exemption on trading of certain hydrocarbon-derived fuels and also has authority to recover from the government certain tax credits originated from sales. Recoverable amounts bear no interest.
Below is a summary of the movement of recoverable tax credits (in thousands):
The Company management considers that the efforts made and agreements reached with the government will permit it to recover part of the tax credits during the year 2012.
At December 31, 2011, 2010 and 2009, the Company adjusted the amount of recoverable tax credits to its fair value applying a discount rate of 13.017%. This rate is calculated by its main shareholder annually with the financial statements of the prior year and using outside parameters updated each year. Furthermore, the Company modified the years estimated to recover the tax credits from 2.5 years to 3 years. At December 31, 2011, 2010 and 2009, the adjustment for US$6,623 thousands, US$3,951 thousands and US$1,792 thousands (Bs.28,477 thousands, Bs.16,989 thousands and Bs.3,853 thousands), respectively, is included in the statements of comprehensive income under the category of financial expenses.
S-86
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(l) Law on Special Contributions over Extraordinary Prices of the International Hydrocarbons Market
In April 2008, the National Executive of the Venezuelan Bolivarian Republic, by means of a decree-law, established a special contribution over extraordinary prices of the international hydrocarbons market, amended in July 2008, which levies the sale of crude oil whenever the average price for the month in question of the Venezuelan oil production exceeds the price of US$70/barrel. The amount of said contribution equals 50% of the difference resulting of the average price per month and the aforementioned cap of US$70/barrel. In addition, this decree-law sets forth that whenever the average price per month exceeds the price of US$100/barrel, the total amount of said special contribution will be equivalent to 60% of the above defined difference (see Note 23-j). This law was superseded by the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (see Note 23-i) published on April 18, 2011. During the period this law was in effect until it was superseded on April 19, 2011, Petrodelta, S.A. incurred in this tax during 2011, 2010 and 2009 for US$38,244 thousands, US$14,116 thousands and US$882 thousands (Bs.164,449 thousands, Bs.60,697 thousands and Bs.1,896 thousands), respectively, included in the statements of comprehensive income under royalties.
m) Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market
On April 18, 2011, was published in the Extraordinary Official Gazette No. 6.022, by means of decree-law No. 8.163 of same date, the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market. This law supersedes the law on special contributions over extraordinary prices on the International Hydrocarbons Market (see Note 23-j), modifies the scheme to determine and pay royalty, extraction tax and export registry tax as per the LOH and creates a special contribution for extraordinary prices and exorbitant prices from the day after the law was published (see Note 23-i). From the date this law came into effect, April 19, 2011, Petrodelta S.A. incurred as special contribution from extraordinary prices and special contribution from exorbitant prices included in the statement of comprehensive income for the year ended December 31, 2011 the amounts of US$199,388 thousands (Bs.857,368 thousands), respectively.
n) Other taxes
The Company is subject to special advantage taxes, which are determined based on: a) an interest as additional royalty of 3.33% on volumes of hydrocarbons extracted in the delimited areas assigned to Petrodelta S.A., and b) an amount equivalent to the difference, if any, between (i) 50% of the value of the hydrocarbons extracted in the delimited areas assigned to Petrodelta S.A. in each calendar year and (ii) the sum of payments made by the mixed companies to the Bolivarian Republic of Venezuela, for activities developed during the calendar year, for royalties on hydrocarbons and investments in endogenous development projects, equivalent to 1% of pre-tax income. Taxes for special advantages must be paid before April 20 of each year, pursuant to Exhibit F of the Agreement for Conversion into a Mixed Company. In relation to a) above, and the law that came into effect, published on April 18, 2011, creating a special contribution on extraordinary prices and exorbitant prices in the international hydrocarbons market (see Note 23-i), which establishes a caps price of US$70 per barrel, Petrodelta, S.A. incurred in this tax during 2011, 2010 and 2009 for US$29,187 thousands, US$20,367 thousands and US$15,548 thousands (Bs.125,504 thousands,
S-87
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Bs.87,578 thousands and Bs.33,428 thousands), respectively, included in the statements of comprehensive income under royalties. In relation to b) above, at December 31, 2011, 2010 and 2009, this special advantage tax was lower than what the Company paid and accrued for royalties and special advantages tax.
Official Gazette No. 39.273 of the Bolivarian Republic of Venezuela, published on September 28, 2009, approved the modification of article regulating special advantages tax levied on mix companies to redistribute the use of funds by the additional royalty of 3.33% that mix companies have to pay on hydrocarbons volumes extracted from delimited areas. The modified article establish deliver 1.11% to municipalities where oil activities in the country take place and 2.22% for a special fund to be administered by the Executive branch to finance endogenous development projects.
(8)
Property, Plant and Equipment, Net
Property, plant and equipment, net at December 31 comprises the following (in thousands):
S-88
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
During the years ended December 31, 2011, 2010, and 2009 the Company added production assets and construction in progress for approximately US$137,956 thousands, US$101,799 thousands and US$81,425 thousands (Bs.593,211 thousands, Bs.437.737 thousands and Bs.175,063 thousands), respectively.
During the years ended December 31, 2011, 2010 and 2009, the Company assessed asset impairment, taking into account new market and business conditions, and determined that there was no evidence of impairment of production assets.
At December 31, 2011, 2010 and 2009, accruals and other payables include US$7,644 thousands, US$2,043 thousands and US$3,603 thousands (Bs.32,869 thousands, Bs.8,785 thousands and Bs.7,746 thousands), respectively, in respect of the accrual for asset retirement obligations arising in the year (see Note 9).
S-89
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
The balance of construction in progress mainly comprises investment projects for exploration and production activities related to drilling, maintenance, electrical systems, pipelines, well reconditioning and adaptation, expansion and infrastructure aimed at maintaining production capacity and adapting the infrastructure to production levels set out in the Corporation’s business plan. At December 31, 2011, 2010 and 2009, the balance of construction in progress for investments related to the aforementioned activities amounts to approximately US$111,255 thousands, US$78,755 thousands and US$32,912 thousands (Bs.478,396 thousands, Bs.338,647 thousands and Bs.70,760 thousands), respectively.
(9)
Provision for Asset Retirement Obligations
The movement of the provision for asset retirement obligations at December 31 is shown below (in thousands):
During 2011, Company management reviewed, based on new information, estimates on assumptions used for calculating the provision for abandonment costs.
At December 31, 2011, 2010 and 2009, the variation of the estimation in of the provision for well abandonment cost of US$7,644 thousands, US$2,043 thousands and US$3,603 thousands (Bs.32,869 thousands, Bs.8,785 thousands and Bs.7,746 thousands) is included the balance of property, plant and equipment (see Note 8). The Petrodelta, S.A. business plan as of December 31, 2011, contemplates the realization of hydrocarbons drilling and production activities until the year 2027; therefore, the accrual for asset retirement obligations was calculated based on the disbursements for this concept during this period.
S-90
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(10)
Prepaid Expenses and Other Assets
Prepaid expenses and other assets comprise the following (in thousands):
(11)
Inventories
A summary of inventories is shown below (in thousands):
(12)
Accounts Receivable
Accounts receivable comprise the following (in thousands):
During the years ended December 31, 2011, 2010 and 2009, the Company offset accounts receivables and payables between PDVSA and its affiliates, including CVP with the Company in the amounts approximately of US$374 million, US$281 million and US$419 million, respectively. These offset of accounts were approved by the Board of Directors of the Company. Exposure to credit risk related to accounts receivable are presented in Note 19.
S-91
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(13)
Cash and Cash Equivalents
Cash and cash equivalent comprises the following (in thousands):
(14)
Equity
Capital stock
At December 31, 2011, 2010 and 2009, the Company’s nominal capital stock is represented by 1,500,000 common shares, fully authorized and paid in, with a par value of US$4.65 each (Bs 10 each).
The Company’s capital stock is divided into two types of shares: Class “A” and Class “B” shares. Only the Venezuelan government or Venezuelan state-owned companies can own Class “A” shares. In October 2007, when the Company was incorporated, shareholders made an initial capital contribution of approximately Bs 1,000 thousands (US$465,000). Capital stock has been fully subscribed and paid in as follows:
Legal Reserve
Venezuelan companies are required to set aside a legal reserve. According to Venezuelan Law, the legal reserve is not available for dividend distribution.
Deferred Tax Asset Equity Reserve
In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies have been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve had no effect on the Company financial position, results of operations or cash flows. However, the new reserve reduces the amount of reserves available to pay of dividends in the future. Changes in the deferred tax asset are recorded in appropriation to (transfer from) other reserves.
In August 2009, the Board of Directors of the Company approved the creation of the deferred tax asset equity reserve with retained earnings accumulated to end of June 2009 for US$116,273 thousands (Bs.249,987 thousands). At December 31, 2011, 2010 and 2009, management has
S-92
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
recorded as equity reserve and amount equal to the balance of the net of deferred tax asset and liability at that date equivalent to US$146,456 thousands, US$51,834 thousands and US$134,066 thousands (Bs.629,761 thousands, Bs.222,886 thousands and Bs.288,242 thousands), respectively (see Note 7-f), which has been approved by the Board of Directors of the Company. At this date the financial statements for the year ended December 31, 2010 and the Deferred tax asset equity reserve have not been approved by the shareholders.
At December 31, 2011 the Company recognized a deferred tax liability corresponding to the asset value originated when the Company recorded a provision for asset retirement obligations (see Note 9). In order to recognize this deferred tax liability the Company restructured its financial statements as of December 31, 2010 and 2009 as follows (in thousands):
Cumulative effect from the adjustment mentioned as of December 31, 2008 is presented as a prior period adjustment in the statement of changes in equity for US$6,325 thousands (Bs13,599 thousands).
S-93
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Share premium
The share premium is in respect of contributions of fixed assets and inventories made by shareholders in conformity with the Agreement for Conversion into a Mixed Company, whose value exceeds the par value of common shares issued. At December 31, 2011, 2010 and 2009, the share premium amounts to approximately US$212,451 thousands, equivalent to approximately Bs.456,770 thousands, included in equity.
Class “A” share premiums are in respect of fixed assets contributed by CVP. The value of this share premium amounts to approximately US$191,206 thousands, equivalent to approximately Bs.411,093 thousands, pursuant to Exhibit H of the Agreement for Conversion into a Mixed Company.
Class “B” share premiums are in respect of fixed assets and inventories contributed by HNR Finance. The value of this share premium amounts to approximately US$21,245 thousands, equivalent to approximately Bs.45,677 thousands, pursuant to Exhibit G of the Agreement for Conversion into a Mixed Company.
In conformity with the Company’s bylaws, in case of Company liquidation, all assets will be transferred only to the Class “A” shareholder.
Dividends
In Extraordinary Shareholder meeting celebrated on August 28, 2008, the shareholders resolved to pay dividends in advance based on retained earnings as the end of June 2008 of US$51,876 thousands (Bs 111,533 thousands). In October 2008, the dividend in advance approved was paid to HNR Finance for its share in the Company in the amount of US$20,750 thousands (Bs.44,613 thousands). At December 31, 2009 the Company decided to record the dividend in advance against unappropriated retained earnings at the end of 2009, recording as dividends payable the unpaid portion to CVP for an amount of US$31,126 thousands (Bs.66,921 thousands).
On August 4, 2010, in Extraordinary Shareholders meeting the shareholders resolved to pay dividends based on retained earnings as of December 31, 2009 in the amount of US$30,550 thousands (Bs.131,365 thousands). The dividend approved was paid on October 2010 to HNR Finance for its share in the Company in the amount of US$12,220 thousands (Bs.52,546 thousands). At December 31, 2011 the portion of the dividend corresponding to CVP for US$18,330 thousands (Bs.78,819 thousands) has been paid by means of offsetting accounts receivable and payables between PDVSA and its Affiliates, including CVP and Petrodelta S.A. approved by the board on January 12, 2012 (see Note 21).
On November 12, 2010, in Extraordinary Shareholders meeting the shareholders of the Company resolved to distribute and pay dividends in the amount of US$30,550 thousands (Bs.131,365 thousands). This dividend corresponds to the remaining portion of retained earnings at the end of December 31, 2009 and is recorded as dividends payable at December 31, 2011 in the statements of financial position for the amount resolved.
S-94
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Effect for Variation of the Exchange Rate in the Presentation Currency
The statement of changes in equity expressed in bolivars for the year ended December 31, 2010, includes the following effect originated for the variation of the official exchange rate when converting the financial statements from U.S. Dollars, (functional currency) to bolivars (presentation currency), in conformity with IAS 21 (see Note 3-a) (in thousands, net of restructured):
In Board of Director meeting dated 10 March 2011 it was approved the proposal to submit for consideration to the Shareholders the distribution of the cumulative translation adjustment among the components of equity. At December 31, 2011, this distribution is pending of approval by the shareholders of the Company. The following table shows the amounts at December 31, 2011 of different components of equity with the distribution of the translation adjustment once the shareholders of the Company have approved it (in thousands):
(15)
Accounts Payable
S-95
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Accounts payable comprise the following (in thousands):
Foreign currency and liquidity risk exposure in respect of accounts payable to suppliers is shown in Note 19.
(16)
Provisions, Accruals and Other Payables
Accruals and other payables and provisions at December 31 comprise the following (in thousands):
At December 31, 2011, 2010 and 2009, the provision for retirement benefits for personnel assigned to the Company amounts to US$11,556 thousands, US$8,444 thousands and US$9,184 thousands, (Bs.49,691 thousands, Bs.36,309 thousands and Bs.19,746 thousands), respectively. Retirement benefits were adjusted during 2009 when PDVSA completed an actuarial study for their employee pension and retirement plan. At December 31, 2011 and 2010, PDVSA sent a statement for the liability according to the actuary report. The Company has analyzed demographic and financial data, considers that it reasonably reflects the liability for such concept and adjusted the obligation at the date of the statements of financial position. This pension and retirement plan covers all PDVSA employees and mixed companies payroll. Pension cost is not tax deductible until future periods when the pension is settled in cash. The Company is not required to reimburse the pension costs to PDVSA until PDVSA pays them.
S-96
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Additionally, at December 31, 2011, 2010 and 2009, accruals and other payables include the accruals in respect of drilling services and infrastructure totaling US$63,879 thousands, US$61,231 thousands and US$47,892 thousands (Bs.274,680 thousands , Bs.263,293 thousands and Bs.102,968 thousands), respectively.
Below are the movements of accruals and other payables and provisions during the year 2011, 2010 and 2009, (in thousands):
S-97
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
S-98
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
S-99
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(17)
Operational Expenses
Below is a summary of operational expenses incurred by the Company (in thousands):
S-100
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(18)
Financial Income and Expenses
Financial income and expenses comprised the following (in thousands):
Gain on variation of exchange rate
On January 8, 2010, the Ministry of Finance and BCV published Exchange Agreement No. 14, in the Official Gazette No. 39.342, which went into effect January 11, 2010. This Exchange Agreement modified the official exchange rate for the purchase and sale of foreign currency denominated in U.S. Dollars. Therefore, all transactions and balances in Bolivars were converted to U.S. Dollars as per the new exchange rate, resulting in a net gain for the variation effect in the exchange rate due to the fact of maintaining a net liability monetary position in bolivars at the date when the variation of the exchange rate went into effect (see Note 4).
Financial cost transferred from related party
In accordance with Foreign Exchange Agreement 9, published in Official Gazette 38,318, dated November 21, 2005, currencies from the export of hydrocarbons that the Company sells PDVSA, must be sold to the BCV, except for those to be used at activities performed by PDVSA pursuant to the Amendment to the BCV Law, which compels the Company to sell to the BCV only the cash flows in currencies, other than local currencies, required to meet its obligations in bolivars. As of January 11, 2010, payment of those transactions with the BCV was made at the exchange rates of Bs.4.2893 and Bs.2.5935 per U.S. Dollar, in conformity with the rates established by the BCV for payment of sale transactions under the Foreign Exchange Agreement 14 (see Note 4). During the year 2010, the average exchange rate on those transactions was Bs.3.61 per U.S. Dollar, because of this PDVSA had recorded a financial expense for the difference between this average exchange rate and the official exchange rate.
As a result of PDVSA paying, with resources from the sale of crude and gas, in local and foreign currency the liabilities of the Company for the services incurred as well as payroll related obligations assigned by PDVSA (see Note 21), during the year ended December 31, 2010 the Company recorded US$19,475 thousands (Bs.83,743 thousands) corresponding to its share for the difference in the average exchange rate mentioned before of Bs.3.61 and the official exchange rate of Bs.4.30 (see Note 4).
S-101
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(19)
Financial Instruments
Credit Risk
Exposure to Credit Risk
The book value of financial assets represents the highest level of credit risk exposure. A breakdown is shown below (in thousands):
Aging of the account receivables are shown below (in thousands):
Liquidity risk
Maturity of financial liabilities, including estimated interest payments and excluding the impact of offset agreements, is shown below (in thousands):
S-102
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Foreign Currency Risk
Petrodelta, S.A. has the following monetary assets and liabilities denominated in currencies other than the U.S. Dollar, which were converted into U.S. Dollars at the exchange rate in effect at the statements of financial position (in thousands):
The year-end exchange rate, the average exchange rate for the year and the interannual increases in the National Consumer Price Index (NCPI), as published by BCV, were as follows:
Fair Value of Financial Instruments
The following estimated amounts do not necessarily reflect the amounts at which the instruments could be exchanged in the current market, The use of different market assumptions and valuation methods can significantly affect the estimated fair values, The bases for determining the fair value are disclosed in Note 5 (in thousands):
S-103
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(20)
Commitments and Contingencies
At December 31, 2011, 2010 and 2009, the Company based on its own judgment does not consider necessary to set aside a provision for litigations and other claims. Should the outcome of existing lawsuits and claims be unfavorable to the Company, it could have a material adverse effect on its results of operations. Although it is not possible to predict the outcome, Company management, based in part on the opinion of its legal advisors, does not believe it is likely that losses related to the aforementioned legal procedures will exceed recognized estimated amounts or generate significant amounts that could affect the Company’s financial position or results of operations.
Compliance with Environmental Regulations
The subsidiaries of CVP are subject to different environmental laws and regulations which may require significant expenditures to modify facilities and prevent or remedy the environmental effects from waste disposal and spills of pollutants.
Petrodelta, S.A. and its parent company CVP are taking steps to prevent environmental risks, protect employee health and preserve the integrity of their facilities.
Agreements with the Organization of Petroleum Exporting Countries (OPEC)
The Bolivarian Republic of Venezuela is a member of OPEC, an organization mainly dedicated to establishing agreements to maintain stable crude oil prices by setting production quotas. To date, the reduction in crude oil production resulting from changes in the production quotas set by OPEC and price fluctuations has not significantly affected the Company’s results of operations, cash flows or financial results.
S-104
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(21)
Related Party Transactions
Petrodelta, S.A. considers its shareholders and related subsidiaries and affiliates, Company directors and executives, as well as other governmental institutions, as related parties.
A summary of transactions and balances with related parties is shown below (in thousands):
As of April 2006, due to the migration of operating agreements to mixed companies, PDVSA Petróleo signed purchase and sale agreements with these companies, which set out that mixed companies will notify PDVSA Petróleo of the estimated volume of hydrocarbons expected to be delivered the following month. PDVSA Petróleo must pay the mixed companies for delivered volumes, net of volumes for royalties in kind and paid to the Venezuelan government.
In conformity with the terms and conditions of the agreements, CVP mixed companies agree to sell and deliver to PDVSA Petróleo, and the latter agrees to purchase and receive from these mixed companies, crude oil and natural gas produced in the delimited areas that are not used for primary activities or for payment of royalties in kind to the Venezuelan government.
Crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately US$98.52, US$70.57 and US$57.62 per barrel for the year ended December 31, 2011, 2010 and 2009, respectively.
S-105
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
During the years ended December 31, 2011, 2010 and 2009, the Company sold crude oil and natural gas to PDVSA Petróleo for US$1,048,728 thousands, US$607,586 thousands and US$458,251 thousands (Bs.4,509,530 thousands, Bs.2,612,621 thousands and Bs.985,240 thousands), respectively, included in the statements of comprehensive income under Income. On October 3, 2011, the Company received accounting guidelines from CVP, to account for revenues from the sale of crude oil, royalty and other taxes (see Notes 7-g, 7-h and 7-j) due to the law that came into effect creating a special contribution on extraordinary prices and exorbitant prices in the international hydrocarbons market (see Note 23-i), which sets a maximum price to pay for royalty at US$70 per barrel. These guidelines modified the accounting procedure for recording and recognizing revenues from the sale of crude as well as recording and recognizing expense from royalty and other taxes. Since the Company pays royalty in kind for the crude produced and sells to PDVSA, and recognizes the amounts for revenues from the sale of crude and royalty in the statement of comprehensive income up until the law creating a special contribution on extraordinary prices and exorbitant prices in the international hydrocarbons market came into effect at the sales price, and according to new law and guidelines received recognizes as revenue for the sale of crude 70% of the barrels delivered to PDVSA plus 30% of royalty at the maximum price of US$70 per barrel, income from the sale of crude oil and royalty expense on crude are presented undervalued in the amount of US$76,966 thousands (Bs.330,952 thousands), when compared to the procedure applied in prior periods.
Following is a table, in thousands, that allows comparison of revenues and royalty calculated using prior and current procedure (in thousands):
At December 31, 2011, 2010 and 2009, the statement of financial position includes US$912,652 thousands, US$499,313 thousands and US$361,137 thousands (Bs.3,924,404 thousands, Bs.2,147,046 thousands and Bs.776,445 thousands) of accounts receivable for the crude and gas sales to PDVSA.
During 2011, 2010 and 2009, PDVSA Petróleo charged Petrodelta, S.A. US$615 million, US$246 million and US$278 million (Bs.2,642 million, Bs.1,197 million and Bs.561 million), respectively, for labor and other costs, taxes, royalties, cash advances, dividends, and operating costs which are included in operating expenses and selling, general and administrative.
S-106
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Certain Company directors hold key positions in other related entities; some of their attributions include influencing the operational and financial policies of these entities.
At December 31, 2011, 2010 and 2009, transactions with related parties do not necessarily reflect the results that would have been obtained had these transactions been held with third parties.
At a Board of Directors’ Meeting in December 11, 2008, it was resolved to offset receivables and payables with PDVSA and its affiliates for the amount if US$329.3 million (Bs.708 million). In this regard, it was established that 75% of accounts receivable and 100% of accounts payable and billed to PDVSA would be recorded with no interest charges.
In February 26, 2009, July 3, 2009 and December 4, 2009, the Company’s Board of Directors approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for royalties, taxes and operation expenditures in the amount of US$206.2 million, US$94.7 million and US$118.2 million (Bs.443.3 million, Bs.203.7 million and Bs.254.1 millions) respectively, against the receivable from PDVSA and its affiliates, including CVP, for oil and gas deliveries.
In June 10, 2010, the Company’s Board of Directors approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for 2010 royalties, taxes, dividends payable at the end of 2009 and operational expenditures in the amount of US$40 million (Bs.172 million) against the receivable from PDVSA and its affiliates, including CVP, for 2010 oil and gas deliveries.
During February 2011, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and payables between PDVSA and its affiliates, including CVP with the Company outstanding as of December 31, 2009 at the exchange rate prevailing as of this date, resulting in a netting of US$46 million (Bs.101 million). Additionally, in the same month and year, CVP sent instructions again to the Company to proceed and offset accounts receivables and payables between PDVSA and its affiliates, including CVP with the Company outstanding as of December 31, 2010, resulting in a netting of US$195 million (Bs.838 million). Both nettings have been recorded in the month of December of 2010, and are included in the statements of financial position as of December 31, 2010 and approved by the Board of Directors of the Company on February 23, 2011.
On October 28, 2011, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and payables between PDVSA and its affiliates, including CVP for royalties, contributions, taxes, advances and operational expenses against the Company accounts receivable with PDVSA and its affiliates, including CVP, for the crude and gas sold, outstanding as of September 30, 2011, resulting in a netting of US$169 million (Bs.727 million) at the prevailing exchange rate applicable at such date (see Note 24-a).
S-107
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
(22)
Collective Labor Agreement
On January 20, 2010 the Collective Labor Agreement was signed, valid for the period from October 1, 2009 thru October 1, 2011, among PDVSA and oil labor union (FUTPV) regarding the approval of the new labor contract and the impact on labor cost affecting mix companies. The Collective Labor Agreement establishes a salary raise and payroll and retirement benefits which has a significant impact on the Company’s payroll cost. The most significant impacts are:
i. A salary raise of Bs.35 daily which represents an increase of 80% of current salary. The increase shall be pay in two portions, the first of Bs.25 at the signing of the contract and the second of Bs.10 from January 1st, 2011.
ii. An increase in the monthly amount for electronic card for foods from Bs.1,300 to Bs. 1,700.
iii. An increase in the retirement benefit from Bs. 1,000 to Bs. 1,600.
iv. The increase will be retroactive from October 1, 2009 and not from January 21, 2009, being the date on which the prior contract expired, in compensation it was agreed a one-time bonus of Bs. 8.000 which has no effect in the severance benefits of employees.
In November 2011, discussions and negotiations among the individuals and unions affected by the Collective Labor Agreement and PDVSA started the process to put in place a new Agreement. It was resolved to postpone to 2012 the approval of the new Agreement until FUTPV elections are held and new leaders are elected to resume discussions and negotiations with PDVSA.
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Laws, Resolutions and Legal Contributions
a) Sports Organic Law
On August 24, 2011, the National Assembly published on the Official Gazette 39,741 the Sports Organic Law promoted by the Executive branch of power. This law declares of national and general interest as well as a public service all activities for promoting, organizing and administering sports and physical activity in Venezuela. The law among other things creates the National Fund for the Development of Sports, Physical Activity and Physical Education to be constituted on contributions from companies and organizations, private or public, performing profit seeking economic activities within the national territory. These contributions are not deductible for income tax purposes and shall be 1% over net profit when net profit is above 20.000 tax units. As of December 31, 2011 the Company has recorded as contribution under the Sport Organic Law the amount of US$1,110 thousands (Bs.4,773 thousands) (see Note 25-b).
b) Law to Suppress and Liquidate the Endogenous Development Fund
On May 18, 2011, the National Assembly published on the Official Gazette 39,676 the means of decree-law No. 8.204 promoted by the President of the Bolivarian Republic of Venezuela, the Law to Liquidate and Suppress the Endogenous Development Fund, an autonomous institute created by the Law for the Creation of the Endogenous Development Fund, published in the National Gazette 38.500 on August 15, 2006.
S-108
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
c) Laws enacted under the Enabling Law
On December 17, 2010, the National Assembly approved the Law Authorizing the President of the Republic to issue Decree-Laws. The Enabling law was published in the extraordinary Official Gazette No. 6.009 and covers a range of areas for a term of 18 months after publication thereof. Under this law, the authorization encompasses areas involving the transformation of government institutions, popular participation, as well as economic, social, financial, tax and energy matters.
d) Foreign Exchange Agreement 18
On June 4, 2010, Official Gazette 39,439 was published containing Foreign Exchange Agreement 18, which establishes that the BCV will be in charge of regulating the terms and conditions for the negotiation, in local currency, and through the system accorded for that purpose, of securities of the Bolivarian Republic of Venezuela, its decentralized entities or any other issuing body, whether they are issued or to be issued in foreign currency.
e) Ruling 001-2010 by National Antidrugs Office (Oficina Nacional Antidrogas or ONA)
On February 11, 2010, Official Gazette 39,366 was published containing Ruling 001-2010, which establishes standards for the admissible discounts to the expense set forth under LOCTICSEP and its Regulation for payment corresponding to fiscal years 2006, 2007 and 2008. This ruling establishes that only the following payments made by taxpayers during fiscal years 2006, 2007 and 2008 may be subject to rebates:
•
Conduction of projects for comprehensive social prevention and development.
•
Expenses under non-reimbursable technical assistance agreements.
•
Funding or performance of activities under comprehensive social prevention.
f) Foreign Exchange Agreement 15
On January 27, 2010, as a result of a material error, Foreign Exchange Agreement 15 was republished in Official Gazette 39,355, originally published in Official Gazette 39,349 dated January 19, 2010. This agreement contains new provisions and guidelines complementing the multiple exchange rate system created under Foreign Exchange Agreement 14 (see Note 4). The most relevant aspects of this agreement follow:
•
As to the Value Added Tax (VAT), imports of goods and services are subject to the exchange rate of Bs.2.60 per U.S. Dollar, for the food, health, education, machinery and equipment and science and technology sectors; Bs.4.30 per U.S. Dollar will be used for other sectors. With regards to exports of goods and services, the applicable exchange rate is Bs.4.2893 per U.S. Dollar.
•
In relation to customs, the applicable exchange rate is Bs.2.60 per U.S. Dollar for imports corresponding to the food, health, education, machinery and equipment and science and technology sectors; and Bs.4.30 per U.S. Dollar for all other imports.
S-109
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
g) Organic Law Reserving for the State Assets and Services Related to Primary Hydrocarbons Activities
On May 7, 2009, Official Gazette No. 39,173 was published containing the Organic Law Reserving for the State Assets and Services Related to Primary Hydrocarbons Activities, which reserves for the Republic, as a result of its strategic condition, assets and services associated with the primary activities established under Organic Hydrocarbons Law to be performed by PDVSA or any of its subsidiaries (see Note 25-a).
h) Organic Law on Science and Technology and Innovation (LOCTI)
On December 2010, the Partial Amendment to the Organic Law on Science and Technology and Innovation (LOCTI) was published. This amendment establishes that legal or private or publicly owned entities, domiciled in the Bolivarian Republic of Venezuela or abroad, performing economic activities within the national territory are under the obligation of paying on an annual basis an established percentage of their gross income from the previous year, in respect to their business area, as follows:
•
Two percent when economic activity is framed within those listed in the Law for the Control of Casinos, bingo Halls and Slot Machines, and any area related to industry and trade of Alcohol and snuff.
•
One percent for privately owned enterprises operating in business areas subject to the Organic Law on Hydrocarbons and Gaseous Hydrocarbons, including mining, processing and distribution activities.
•
Half percent for publicly owned companies if the business pursued is one of those listed in the Organic Law on Hydrocarbons and Gaseous Hydrocarbons including mining, processing and distribution activities.
•
Half percent for any other business activity.
On April 28, 2011, the Company received instructions from its shareholder, CVP, to reverse the expense of US$4,583 thousands (Bs.19,707 thousands) and accrued at December 31, 2010, due to the fact that PDVSA has opted to file declaration on behave of its affiliates, including mix companies, and waive the liability on them, including Petrodelta, S.A. As of December 31, 2011, CVP sent instructions to the Company to record its share according to the law for its obligation corresponding to the year ended December 2011 only. The provision recorded in the statements of financial position corresponding to the year ended December 31, 2011 amounts to US$3,054 thousands (Bs.13,132 thousands). For the year ended December 31, 2009 the Company received instructions from its shareholder CVP to grant exemption from paying the contribution since it will be PDVSA who will file on a consolidated basis the contribution established in this Law. Therefore, the Company has not made any provision in relation to the contribution corresponding to the year ended December 31, 2009.
i) Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market
S-110
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
On April 18, 2011, the Venezuelan government published in the Extraordinary Official Gazette No. 6.022, by means of decree-law No. 8.163 of same date, the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market. This law modifies calculation and payment of royalty, extraction tax and export registry tax as per LOH and the special contribution for extraordinary prices and exorbitant prices from the date published. The law defines the contribution on Extraordinary Prices for 20 percent to be applied to the difference between the average monthly price up to US$70 or less per barrel, on international markets for the Venezuelan liquid basket of hydrocarbons and the price fixed by the Venezuela budget for the relevant fiscal year (set at $40 per barrel for 2011). The law also defines the contribution on Exorbitant Prices for (1) 80 percent when the average price mentioned before exceeds US$70 per barrel but is less than US$90 per barrel; (2) 90 percent when the average price mentioned before exceeds US$90 per barrel but is less than US$100 per barrel; and (3) 95 percent when the average price mentioned before exceeds US$100 per barrel. The law also established the maximum price to be used for calculating royalty paid in cash on production at US$70 per barrel. This law supersedes the Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices (see Note 23-j).
j) Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices
On April 15, 2008, the Law for Special Contributions on Extraordinary International Hydrocarbon Market Prices was published in Official Gazette No. 38,910. Subsequently, Resolutions No. 151 and No. 195 of MPPEP were published in Official Gazette No. 38,939 of May 27, 2008 and Official Gazette No. 38,970 of July 10, 2008. This Law and its resolutions require entities that export or transport liquid hydrocarbons and hydrocarbon derivatives abroad to pay a special monthly contribution. The contribution will be equivalent to: a) 50% of the difference between the average monthly price of the Venezuelan crude oil basket and the threshold price of US$70 per barrel and b) 60% of the difference between the average monthly price of the Venezuelan crude oil basket and the threshold price over US$100 per barrel. This contribution shall be paid on every barrel of oil exported or transported abroad and shall be collected and paid monthly by MPPEP to the National Endowment Development Fund (FONDEN) for execution of infrastructure development projects, production and social development projects aimed at strengthening Communal Power. This Law became effective on April 15, 2008. This law was superseded by the law creating a special contribution on extraordinary prices and exorbitant prices in the international hydrocarbons market (see Note 23-i).
k) Antidrug Oganic Law (LOD)
On September 15, 2010, the Antidrug Organic Law was published in Official Gazette No. 39,510. The LOD eliminates the Law on Narcotic and Psychotropic Substances (LOCTISEP) and its partial regulation published June 5, 1996 under Official Gazette No. 35,986. Among the significant changes are:
•
Taxable base is changed, previously considered base on net profit and now establishes as taxable base current period operating income.
S-111
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
•
Filing and payment of tribute is extended from 15 calendar days of the following taxable period, to 60 calendar days from the closing corresponding taxable period.
•
In relation to sanctions, the law establishes: 1) failure to comply the contribution of 1%, a penalty equivalent to double the amount due, if re-occur the penalty will be 3 times the corresponding contribution due, and 2) for not complying the special contribution of 2%, same penalty, before was 60,000 tax units or suspension of business activities during 1 year in case of re-occurrence.
•
In the prior law, donations made by persons or companies in favor of plans and programs established by the government in relation to drugs matter and approved by ONA, can be deducted for income tax purposes, previously approved by public document. In the new law, this last aspect is eliminated as a requisite for proceeding to deduct from income tax purposes.
•
Incorporates an obligation by government agencies and institutions, as well as public and private companies that employ more than 50 workers, to provide labor to rehabilitated persons, under the programs of social inclusions.
On February 23, 2011, providence No. 0001-2011 was published in the Official Gazette No. 39.622, establishing that labor matters related to Projects for Integral Prevention on Drug Consumption must be presented to the National Antidrug Fund (FONA). The providence establishes that private and public companies must present between January 2 and April 30 the projects and all of their requirements to be executed in order to carry-out technical and economical evaluations necessary for the appropriate approval. Projects for Integral Prevention in regards to labor matters can only be submitted by those companies in which their fiscal year ends before the established time frame mentioned in order to be eligible and once the contribution of 1% has been paid. When companies can not submit projects, they can present them in the same timing period of the following year and the corresponding charge shall be the year immediately before to the year corresponding the contribution determination.
During the years ended December 31, 2011 and 2010, the Company recognized and recorded an expense for US$3,328 thousands and US$4,813 thousands (Bs.14,311 thousands and Bs.20,697 thousands), respectively.
l) Law on Narcotics and Psychotropic Substances (LOCTISEP)
The Law on Narcotic and Psychotropic Substances was published in Official Gazette No. 38,287 on December 16, 2005. This Law repeals the previous Law of September 30, 1993 and requires all companies, public or private, with 50 or more employees to earmark 1% of their annual net income for social programs for the prevention of illegal drug consumption and traffic, one-half of which is to be set aside for child welfare protection programs.
On May 31, 2006, the National Anti-Drug Agency (ONA) published an extension to the process for starting to make contributions according to the Law; therefore as of December 31, 2009 and 2008 no contribution has been made for this concept.
S-112
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
In July 1, 2009, Presidential Decree No.6.776 was published in Official Gazette No. 39,211 where Partial Regulation of LOCTISEP was enacted, with the purpose to define and establish the guidelines, mechanism, modalities, forms and opportunities in which legal entities, public and private as mentioned in the Articles No.96 and No.97 of the Law, comply with the obligation to fund ONA the contributions established.
In December 29, 2009 providence 007-2009 and 008-2009 were published in Official Gazette No. 39,336 whereas the National Anti-Drug Agency (ONA) establishes norms and procedures to collect, control and audit contributions by public and private companies. The providence among other things lay out the amount subject to the calculation set as taxable income and not net income applied in prior years. During the years ended December 31, 2011 and 2010, the Company recorded an expense of approximately US$4,813 thousands and US$3,336 thousands (Bs.20,697 thousands and Bs.7,173 thousands), respectively, in this connection, included net in the statements of comprehensive income for each year under general and administrative expenses. As a result of the change in the methodology used to calculate the contribution from applying the providence No. 007-2009, for the amount recorded during the year ended December 31, 2009 approximately US$1,082 thousands and US$168 thousands (Bs.2,327 thousands y Bs.362 thousands), correspond to 2008 and 2007, respectively.
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Subsequent Events
a) On January 12, 2012, the Company following instructions from its shareholder CVP proceeded to offset accounts receivables and payables between PDVSA and its affiliates, including CVP for royalties, contributions, taxes, advances, operational expenses and dividends payable to CVP approved by the shareholders of the Company on August 4, 3010 (see Note 14) against the Company accounts receivable with PDVSA and its affiliates, including CVP, for the crude and gas sold, outstanding as of December 31, 2011, resulting in a netting of US$205 million (Bs.882 million) at the prevailing exchange rate applicable at such date. On February 23, 2012 the Board of Directors of the Company approved this transaction.
b) On February 16, 2012, providence No. SNAT/2012/0005 from the National Integrated Service on Tributes and Customs Administration (SENIAT) was published in Official Gazette No. 39,866 in which the current tax unit value was adjusted from Bs.76 to Bs.90.
c) On February 23, 2012, the Board of Directors of the Company approved the issuance of these financial statements under International Financial Reporting Standards and resolved to submit these financial statements to the Shareholders of the Company for approval purposes. The financial statements cannot be modified once they have been issued.
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Subsequent events after the date of the Independent Auditor’s Report
a) On February 27, 2012, Official Gazette No. 39,871 was published containing decree-law No. 8.807 on partial reform to the Law Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International Hydrocarbons Market (see Note 23-i). The partial reform reiterates the use of resources derived from this law be used in financing the Large Missions created by the National Executive, as well as infrastructure, health, education, the development of the national production sector, among others areas. The partial reform also stipulates treasury aspects on how the contributions is to handle between PDVSA, the National Development Fund (FONDEN), and BCV.
S-113
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
b) On February 28, 2012, Official Gazette No. 39,872 was published containing decree-law No. 8.820 on partial regulation No.1 to the Sports Organic Law (see Note 23-a). The partial regulation scope the National Fund for the Development of Sports, Physical Activity, duties of the National Sports Institute, guidelines on the executions of resources and taxpayers subject to the law and their responsibilities, as well as means of making contributions.
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Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited)
The following tables provide supplementary information on oil and gas exploration, development and production activities. All exploration and production activities are conducted mainly by CVP and Mixed Companies in Venezuela.
Table I-Crude Oil and Natural Gas Reserves
All crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian Republic of Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and reviewed by the People’s Power Ministry for Energy and Oil (MPPEP) using reserve criteria that are consistent with those prescribed by the American Petroleum Institute (API) of the United States of America.
Proved reserves are the estimated quantities of crude oil and gas which, with reasonable certainty, are recoverable in future years from known deposits under existing economic and operating conditions. Due to the inherent uncertainties and limited nature of reservoir data, reserve estimates are subject to changes over time, as additional information becomes available. Proved reserves do not include additional volumes which may result from the extension of currently explored areas or from the application of secondary recovery processes not yet tested and determined to be economically feasible.
Proved developed oil and gas reserves are the quantities that can be recovered from existing wells with existing equipment and methods. Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage or from existing wells.
It is important to mention an increase for the year 2010 on extensions and discoveries of oil and gas proved reserves. The increase is due to a new revision to Petrodelta’s Business Plan for the period 2011-2027 elaborated for the year ended December 31, 2010. The new revision take into account a Base Case for Development with a much lower risk and a greater potential in reserves to be developed compared to the prior Business Plan and the reason lies in the success obtained from the wells testing and drilling programs executed during the period 2008-2010 in the new fields Temblador and El Salto.
A summary of annual changes in proved crude oil and natural gas reserves is shown below:
(a) Conventional Crude Oil (in thousands of barrels)
S-114
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
At December 31, 2011, 2010 and 2009, certified reserves assigned to the Company amounted to 499.237 thousands, 511,320 thousands and 206,823 thousand barrels, respectively. Production for the year ended December 31, 2011, 2010 and 2009 was 11.390 thousands, 8.561 thousands and 7.835 thousand barrels.
(b) Natural Gas Reserves (in millions of cubic feet)
Natural gas production is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons.
Table II-Costs Incurred in Exploration and Development Activities
Exploration costs include costs incurred from geological and geophysical activities, and drilling and equipping exploratory wells. The Company did not conduct exploration activities in the year 2011. Development costs include those for drilling and equipping development wells, enhanced recovery projects and facilities to extract, treat and store crude oil and natural gas. Annual costs, summarized below, include amounts both expensed and capitalized for the Company’s conventional crude oil reserves (In thousands):
S-115
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Table III-Costs Recorded as Assets in Oil and Gas Production Activities
Costs recorded as assets for oil and gas exploration and production activities, as well as the related accumulated depreciation and amortization at December 31 for PDVSA’s conventional and extra-heavy crude oil reserves are summarized below (In thousands):
Table IV-Results of Operations for Oil and Gas Production Activities for Each Year (In thousands):
Income from oil production is calculated at international market price as if all production were sold (see Note 21).
Production costs are lifting costs incurred to operate and maintain productive wells and related facilities and equipment, including operating labor costs, materials, supplies, fuel consumed in operations and operating costs of natural liquid gas plants.
S-116
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2011, 2010 and 2009
Depreciation and amortization expenses relate to assets used in exploration and production activities. Income tax expense is computed using the statutory rate for the year. For these purposes, the results of production operations do not include finance costs and corporate overhead nor their associated tax effects.
A summary of average per unit sale prices and production costs is shown below:
S-117