- Downstream
- Exploration and Production
- Gas and Energy
- International
Downstream
1. How are gasoline, diesel, and natural gas prices calculated in Brazil?
2. How are the plans to build a new refinery in the Northeast? What is Petrobras' participation in it?
3. What are the refinery's objectives?
 1. How are gasoline, diesel and natural gas prices calculated in Brazil?
ANSWER:
Oil byproduct prices, including LPG (Liquefied Petroleum Gas, known as cooking or bottled gas) depend on international prices. The reason for this is that both diesel and gasoline and LPG markets in Brazil are currently regulated by the National Oil Agency (ANP, Agência Nacional de Petróleo) administrative rules and by Law 9.478/97. This law flexibilized the oil and natural gas sector monopoly, which deregulated both products' imports and the producing market in January 2002. This way, the oil and LPG prices fluctuate, basically according to the international market.
The price is composed of several parts: Petrobras only controls the realization price, which is the product's price when it leaves its refineries. By and large, this value corresponds to 39% of the natural gas price; 60% of the diesel price; and 28% of the gasoline price.
Federal and state taxes (CIDE, PIS/COFINS and total ICMS) also incur on the LPG price, with a 20% participation in the final price, and the marketing parcel, which corresponds to another 41%.
In the case of diesel, the parcels are: taxes (26%) and marketing (14%).
In Brazil, there is a Ministry of Agriculture determination that requires that the gasoline used in the country be mixed with alcohol at the current proportion of 3/1 (75% gasoline, 25% alcohol). Therefore, in addition to the tax (53%) and marketing (14%) parcels, the final consumer price also includes a 7% parcel referring to the anhydrous alcohol costs.
It must be emphasized that Petrobras only controls one of the parcels that forms the final price for the consumer: the refinery prices, which do not include taxes or distribution and retail margins (and without the alcohol, in the case of gasoline). Any change made to at least one of these parcels will reflect, upwards or downwards, on the consumer's final prices. There are also situations in which Petrobras does not participate in the product's marketing chain, as is the case, for example, of imported gasoline or gasoline that is produced by an agent other than Petrobras. For more information, check Price composition.
2. How are the plans to build a new refinery in the Northeast? What is Petrobras' participation in it?
ANSWER:
The Strategic Plan foresees building a new refinery and operations are expected to start in the end of 2010 or in the beginning of 2011. It will be built in the State of Pernambuco together with the state-owned company Petróleos de Venezuela S.A. - PDVSA, with a projected investment in the order of $2.5 billion (50% for each company) and capacity to process 200,000 bpd of heavy oil, half belonging to Petrobras and half to the Venezuelan company.
3. What are the refinery's objectives?
ANSWER:
The refinery aims, prioritarily, at substituting the imports of byproducts such as diesel oil, liquefied petroleum gas (LPG), and naphtha. Another one of the venture's characteristics will be the usage of Brazilian and Venezuelan heavy oil as raw material, since these countries that have large reserves of this type of oil. The project will have a significant conversion capacity aimed at capturing the current refining margin to transform heavy oil into medium distilled oils (gasoline and diesel).
Exploration and Production
1. What are the differences among the ANP, PRMS/SPE and SEC criteria for reserve approval?
2. What is the difference between proved reserves and unproved reserves?
3. What are the criteria used to define a reserve as proved?
4. What are the criteria used to define a reserve as probable?
5. What are the criteria used to define a reserve as possible?
6. What is a discovery well?
 1. What are the differences among the ANP, PRMS/SPE and SEC criteria for reserve approval?
ANSWER:
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ANP 1997 (Natural Petroleum Agency)
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PRMS/SPE 2007 (Petroleum Resources Management System/Society of Petroleum Engineers)
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SEC 2009 (Securities and Exchange Commission)
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| Definition of Reserve |
Discovered oil and natural gas resources that are commercially recoverable from a given date forward.
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Volume of oil that can be commercially recoverable from known reservoirs from a given date forward under defined conditions. This must meet 4 criteria: the volumes must be discovered, recoverable (with current technology), commercial (social and economic conditions must be met) and remaining (from the date of the assessment) based on development projects.
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Remaining amount of oil and gas it is not economically feasible to develop, from a certain date on, through known reservoirs.
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Definition of Proved Reserve
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Oil and natural gas reserves which, based on the analysis of the geological and engineering data, are estimated to be recovered commercially from discovered and assessed reservoirs, with a high degree of certainty, and the estimate of which takes the prevailing economic conditions, operating methods that are usually viable, and regulations established by the oil and tax legislation in Brazil into account. The facilities to process and handle the fluids that are produced are developed or a budget has been approved in order for such facilities to be developed.
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Volumes which, based on the analysis of geological and engineering data, will be commercially recovered with reasonable certainty, from a date forward, from known reservoirs under the economic conditions, operating methods and government regulations that have been defined.
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Volumes of oil and gas which, based on the analysis of geoscientific and engineering data, can be estimated with reasonable certainty to be economically viable, from a given date forward, from known reservoirs and under economic conditions, operating methods and government regulations existing before the end of the operation contracts, unless there is evidence that renewal has occurred.
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| Improved Recovery |
The application of methods of enhanced oil and natural gas recovery is considered proven when: there is a successfully tested pilot project or a project implemented in the same reservoir or in a reservoir with similar rock and fluid properties. Although not yet in operation, there must be reasonable certainty that the project will be implemented.
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The commercial viability of an enhanced recovery project shall be evaluated based on a pilot or on the comparison with a project implemented successfully in an analogous reservoir.
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An enhanced recovery project may be considered proven when a pilot project has been undertaken successfully in a part of the reservoir, with properties that are not more favorable than those of the reservoir as a whole. In addition, the project must have been approved by all necessary stages, including government approval.
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| Prices and Costs |
Prices and costs in effect based on historical data |
Forecasts made by the company. |
Arithmetic average of the price on the first day of the month during the 12 months before December 31 of the year of disclosure.
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| Developed Reserve |
These are volumes recovered through existing wells and when all of the equipment required for production is already installed. The reservoirs can be put into production by recompleting wells or reopening closed wells, provided that the investments needed to do so are not significant.
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These are volumes recovered through existing wells and all the equipment required for production is already installed or the required costs are lower than that of drilling a well in the area.
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This can be attributed to forecast oil and gas production through wells, equipment and operating methods or via equipment that will be in operation during the estimate period. Investments in any equipment to be worn out should be relatively minor compared with investing in a new well in the area.
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| Undeveloped Reserve |
New wells are required in areas that have not yet been drilled in, there is a need for re-entry or recompleting existing wells or to install production and transportation equipment, as foreseen in the conventional or improved recovery projects. To kick-off production, there is a need for significant investments in well recompletion and in the installation of production and handling equipment.
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New wells must be drilled in areas where no drilling has been done yet (in known reservoirs), wells in different (but known) reservoirs must be deepened, wells must be further densified to increase the recovery factor, or significant investments are needed to refit an existing well or wells that require the installation of production and transportation equipment, as foreseen in the projects.
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Volumes that will be recoverable through new wells or areas that have not been drilled in yet or from existing wells in which most of the investments have yet to be made. Undeveloped reserves in areas that have not been drilled yet should be limited in the space foreseen for the field, in which there is reasonable certainty of production if drilled, unless there is evidence of reliable technology in order to establish greater distances than the spacing.
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2. What is the difference between proved reserves and unproved reserves?
ANSWER:
A reserve can be considered proved when, based on the analysis of the geological and technical data, it is possible to determine with significant certainty (no less than 90% - when using the probabilistic estimation) that the natural resource will be commercially recoverable based on the industry's political, economic, and technological conditions.
Proved reserves can still be divided into developed and undeveloped. Developed proved reserves are those that can be developed with wells that have already been drilled and the existing infrastructure or which require limited additional investments to be exploited.
Proved undeveloped reserves are those that require additional investments (for example, drilling new wells, etc.) to develop production there.
Unproved reserves are those which, as proved reserves, are based on geological and technical data; however, they present uncertainties with regard to contractual, technical, economic and/or regulatory issues that prevent them from being considered as proved. The reserves will then be classified as Probable and Possible, depending on the degree of uncertainty regarding the implementation of new technological developments and future economic conditions.
3. What are the criteria used to define a reserve as proved?
ANSWER:
To be considered proved, a reserve must meet certain criteria depending on the methodology that is being used. However, in general, a reserve is considered proved when, based on the analysis of the geo-engineering data, it can be estimated, with reasonable certainty, it is commercial, in a known reservoir, under defined economic conditions, known methods of operation, and under the current regulatory conditions, on a given date.
4. What are the criteria used to define a reserve as probable?
ANSWER:
In a comprehensive manner, the reserve can be considered probable in cases in which the geological and engineering data indicate greater uncertainty in its recovery as compared to estimates of proved reserves. Reserves in formations that are expected to be producers based on their profile characteristics, but which do not have witness data, well tests or correlations with proved reservoirs in the area, can be considered as probable.
5. What are the criteria used to define a reserve as possible?
ANSWER:
By and large, reserves can be considered possible if the geological and engineering data indicate greater uncertainty in their recovery as compared to estimates of proved reserves. Volumes for which there is a high degree of uncertainty regarding their ability to produce at commercial flow rates can be considered as possible.
6. What is a discovery well?
ANSWER:
A discovery well is one that resulted in a discovery of a new oil and/or natural gas producing or potentially producing area.
Gas and Energy
1. What is an Energy Conversion Contract (ECC)?
2. How is the natural gas realization price devised?
3. Has Petrobras preference to transporting its own natural gas production from Bolivia using the GASBOL pipeline regarding the starting production in San Alberto and San Antonio fields?
4. What is the summary of the Administrative Rule (Portaria) enacted in relation to the natural gas activities regarding the exchange variation risks?
5. What is the GASENE Project? When is it expected to go into operation?
6. What is the logic behind Petrobras' recent thermoelectric plant acquisitions?
1. What is an Energy Conversion Contract (ECC)?
ANSWER:
The ECC is a contract between the off-taker (Petrobras) and the Thermopower Plant (SPC). Petrobras will delivery the natural gas to the Plant, will pay a tax for the conversion (tolling fee) and will get all the energy from it. From this time Petrobras will evaluate the destiny of the energy that could be for retail or own consumption
2. How is the natural gas realization price devised?
ANSWER:
The price for the natural gas follows a list of American and European fuel oils according to the MME and MF #03 Laws, of February 17th, 2000:
a) The law states that the maximum retail prices (Pm) for the industrial usage of the natural gas when sold on cash to the authorized piped gas companies, must be calculated through the following formula:
Pm= Pgt + Tref
Pgt = natural gas referential price at the transing gas pipeline gate
Tref = referential transing tariff between the reception and delivery points for the natural gas.
PGT = 0,50 X PGT (ant) + 0,50 X PGT (0) X [0,50 X F1/F10 + 0,25 X F2/ F20 + 0,25 X F3/ F30 ] X TC/TC0
With the following values:
PGT (ant) - PGT value current on the previous quarter to the one for which the new PGT is being calculated.
PGT (0) - PGT's initial value equals to R$ 110.80/thousand m3
TC - average of the US dollar's commercial sales exchange rates, PTAX-800 ¾ published in the Brazilian Central Bank System (SISBACEN) ¾ related to the months m-4, m-3 and m-2. Having "m" as the first quarter to which the new PGT value is being calculated.
TC0 - average of the US dollar's commercial sales exchange rates, PTAX-800 ¾ published in the Brazilian Central Bank System (SISBACEN) ¾ related to the period from June to August of 1999, inclusive.
F1, F2 e F3 = average of the daily medium points from the higher and lower quotations, published on the Platt's Oilgram Price Reing, table Spot Price Assessment, relevant to the months of m-4, m-3 and m-2, having:
F1= product cited on the referred publication by Fuel Oil 3.5% Cargoes FOB Med Italy;
F2= product cited on the referred publication by Fuel Oil #6 Sulphur 1% US Gulf Coast Waterborne;
F3= product cited on the referred publication by Fuel Oil 1% Sulphur Cargoes FOB NWE;
F10, F20 e F30 = average of the daily medium points from the higher and lower quotations, published on the Platt's Oilgram Price Reing, table Spot Price Assessment, relevant to the products that correspond to F1, F2 and F3 above classified, in the period from June to August of 1999, inclusive.
The transing reference tariff, to which this article's caput refers, for the period from April to June 2000, will be one for the whole country and equal to R$ 19.40/thousand m3.
b) In May/2000, an alternative proposal for the price of the natural gas was presented, firming it at US$ 2.475/MMBTU with the same basis as in April/2000. This value will remain the same for 12 months and the correction will be done by the American inflation. This second option goals to make the natural gas price readjustment compatible with the electric energy's tariffs, which happens once every year.
On June 1, 2001, the Ministry of Mines and Energy and the Ministry of Finance adopted ingaria Interministerial No. 176, establishing a ceiling price for natural gas to be sold to the thermoelectricity plants that are part of the Thermoelectricity Priority Program of the federal government (Programa Prioritário de Termeletricidade) and are operating commercially by June 30, 2003. This ceiling price applies to a maximum of 40 million cubic meters per day purchased by all of these qualifying thermoelectricity plants. For a 12-year period, each qualifying thermoelectricity plant will have the right to purchase natural gas at prices that are determined as described below.
For the initial consecutive 12-month period, a fixed Real price will be set based on the reference price in United States dollars per MMBTU, initially set at U.S.$2.58 per MMBTU, converted into a Real price based on the exchange rate in effect at the start of that 12-month period.
For subsequent consecutive 12-month periods, the ceiling price will be adjusted annually for changes in the United States producer price index and the U.S. dollar exchange rate with respect to the ingion of the ceiling price relating to iminged natural gas (set by the regulation at 80%) and for changes in the Brazilian market price index (Índice Geral de Preços do Mercado-IGPM) with respect to the ingion of the ceiling price relating to domestic natural gas (set by the regulation at 20%), reflecting the current mix of natural gas supplied to these qualifying thermoelectricity plants.
Based on 80% of the volume of natural gas purchased by each of the qualifying thermoelectricity plants during each 12-month period and the projected volume of natural gas to be sold to that qualifying thermoelectricity plant during the immediately succeeding 12-month period, the ceiling price for the immediately succeeding 12-month period will also be adjusted to reimburse the natural gas supplier for shortfalls, calculated on a per invoice basis, in the U.S. dollar amount realized by the natural gas supplier in respect of sales to that qualifying thermoelectricity plant during the preceding 12-month period due to a devaluation of the Real, or, conversely, to reimburse that qualifying thermoelectricity plant for overpayments, calculated on a per invoice basis, resulting from appreciation of the Real during the period. Interest on the net shortfall or overpayment amount with respect to each qualifying thermoelectricity plant at the SELIC rate, the interest rate applicable to bonds issued by the federal government of Brazil, will also be added. In addition, interest projected to be accrued during the immediately succeeding 12-month period on the netshort fal l or overpayment amount will be added. Any ingion of the shortfall or overpayment amount that is not reimbursed through these adjustments in the ceiling price will be included in the adjustment to the ceiling price for subsequent consecutive 12-month periods until reimbursed in full.
The Thermoelectricity Priority Program allows qualifying thermoelectricity plants to pass on to their customers any increases in pricing resulting from these adjustments.
We cannot predict what impact this new regulatory framework for natural gas prices in Brazil will have on our financial condition and results of operations.
3. Has Petrobras preference to transporting its own natural gas production from Bolivia using the GASBOL pipeline regarding the starting production in San Alberto and San Antonio fields?
ANSWER:
For the 30 Million-m3/day capacity of the GASBOL, San Alberto and San Antonio have the right to pass 21,78 Million-m3/day. As Petrobras has 35% stake in these fields its own production will be round 7,7 Million-m3/day.
Above 30 Million-m3/day the market is free. Obviously Petrobras will buy production from these fields.
4. What is the summary of the Administrative Rule (Portaria) enacted in relation to the natural gas activities regarding the exchange variation risks?
ANSWER:
Natural gas Price policy to suping the building of the Thermo power plants
Summary Of Administrative Rule of June 1st, 2001. (Portaria Interministerial 176, June 01 2001) Resource: Mines and Energy Ministry.
In accordance with the Administrative Rule published today, the natural gas destined for the Priority Thermoelectric Power Plant Program (Programa Prioritário de Termelétricas - PPT) will bear a fixed price in Reais for the period of 12 months. It should be noted that 80% of the natural gas used in this Program is iminged - currently from Bolivia - and therefore subject to foreign exchange rate fluctuations.
At present, only Petrobras supplies the domestic market with iminged gas although with the increase in domestic demand, other suppliers are expected to enter the market.
For the 12-month period in which the price of natural gas remains at the same fixed price, the supplier will bear the difference in cost between the price in dollars (paid to the exinger) and the price in Reais (paid by the electric energy generator).
In order to avoid the supplier incurring financial losses or gains, the difference between the price paid by the latter (at present, Petrobras) and the price paid by the generating company, will be accumulated and capitalized during the 12 month period according to the Selic basic rate of interest, whether this is above or below the fixed price, or in other words, independent of whether the Real has depreciated or appreciated.
At the end of the period, the fluctuations in the foreign exchange rate (appreciation or depreciation of the Real) will be passed on through the supply chain to distributors and consumers. Under this mechanism, the price of energy generated may not only increase but may also decrease from one year to the next depending upon the depreciation or appreciation of the currency against the dollar.
To have an idea of the impact of foreign exchange rate fluctuations on energy tariffs exclusively as a reflection of the measure announced today, it is imingant to be clear that at the end of the PPT program, thermal energy will account for approximately 7% of total energy generated in Brazil. The price of gas in turn, represents approximately 50% of the cost of energy generated by a thermal electric power station.
Thus, for example, the effect of an exchange rate depreciation of 10% in isolation would be an increase of 8% in the price of gas (proingional to the percentage of gas iminged from Bolivia), thus raising the generation price of a thermoelectric power station by 4% (50% of 8%). The increase in the average price of energy generated in Brazil would be of the order of 0.28% (7% of 4%).
Since in addition to generation, there are other links in the chain before electric energy reaches its final destination either to the residential or corporate consumer (transmission, distribution and sale), the average increase in the tariff would be of the order of 0.15%, based on the example of a foreign exchange rate depreciation of 10% at the end of 12 months. Adding in the effect of the compensation (parcela de compensação - PC) to Petrobras for the period, we would have an additional impact of 0.07%. Thus, the total effect of a depreciation of 10% in the foreign exchange rate would be an increase of about 0.22% in the electric energy tariff.
This calculation does not take into account the impact of energy generated by Itaipu, the price of which is also influenced by the foreign exchange rate, but for which the mechanism described in the Administrative Rule published today does not apply.
It is imingant to note here that under the floating exchange rate system currently prevailing in Brazil, the Real can depreciate against the dollar just as it can appreciate. In the case of a hypothetical appreciation of 10%, there would be an average reduction in the final tariff to the consumer of the order of 0.22%.
Based on this mechanism, the exposure to the potential risk of a foreign exchange rate mismatch on the part of the thermal-electric generators is eliminated thus allowing them to obtain a stable rate of return on investments in the expansion of electric energy supplies using natural gas.
5. What is the GASENE Project? When is it expected to go into operation?
ANSWER:
It is a 1,100-km pipeline connecting Cacimbas, in Espírito Santo, to Catu, in Bahia, unifying the Southeastern and the Northeastern networks. The Gasene has three sections: Cabiúnas (RJ) - Vitória (ES), Cacimbas (ES) - Vitória and Cacimbas - Catu (BA), which is the biggest section, extending nearly 900 kilometers.
The Cacimbas-Vitória section's construction work is at full speed, and is slated to be operational by December 2005 with the flow of natural gas from the Peroá-Cangoá fields, initially towards Vitória. The Cabiúnas-Vitória section is being planned, and an international bidding process is expected to take place soon and articulated with the Sinopec. The project is planned to be concluded in 2008.
6. What is the logic behind Petrobras' recent thermoelectric plant acquisitions?
ANSWER:
The thermoelectric plants that are being purchased are of the Merchant type. One of the main characteristics of the Merchant agreements is that they have a provision which foresees that if in certain months, exceptionally, the income calculated with the energy purchase and sale agreements does not suffice to cover certain costs, Petrobras must make a "Contingency Contribution" for a total that is sufficient to bear these costs.
The "Contingency Contribution" serves the purpose of, in the event of possible, sporadic revenue insufficiencies, guaranteeing, for five years, the necessary cash flow to cover the plant's fixed and variable costs. With the scenario adopted at the time, the partners understood that the need for such contribution would be occasional.
The demand projections made at the time did not concretize due to several factors, particularly the consumption restriction measures adopted in 2001 by the Electric Energy Crisis Management Chamber, created in 2001. Even after these consumption restrictions were lifted, it was noticed that demand did not return to the previous levels as a result of a structural change that occurred in the country's consumption standard.
As a result, the Contingency Contributions, which should have been occasional, started being made systematically, every month, since the revenues that had been foreseen, resulting form the sales in the spot market, did not materialize. After carrying out studies, Petrobras decided to make acquisitions that would lead to contingency payment reductions.
In May 2005, the acquisition of the Sociedade Fluminense de Energia - SFE, owner of the Eletrobolt Thermoelectric Plant, located in Seropédica, State of Rio de Janeiro, with a nominal capacity of 388 MW, was concluded. In June that same year, we purchased the Termoceará Thermoelectric Plant, located in the Pacém Industrial Complex, State of Ceará, with capacity for 220 MW. The only Merchant-type thermoelectric plant for which contingency payments are still made is Macaé Merchant.
International
1. What is Petrobras' strategy in the international segment?
2. Why were the production goals for 2010 reduced compared to the previous Plan?
3. Does Petrobras have any activities in Sudan?
4. Does Petrobras have any activities in Iran?
1. What is Petrobras' strategy in the international segment?
ANSWER:
While reviewing its Strategic Plan, Petrobras opted to maintain its international expansion aimed at the focus areas, which are East Africa, South America, and the Gulf of Mexico. However, we are always monitoring business opportunities in other important areas of the world.
2. Why were the production goals for 2010 reduced compared to the previous Plan?
ANSWER:
The reduction of the total international production goals from 613 to 545 thousand barrels a day results mainly from delays in projects in Nigeria. It must be emphasized that there was no implication in terms of future production; it is simply a matter of a delay in the beginning of the production in two major fields in Nigeria, Akpo and Agbami, which Petrobras is a partner of and whose production is expected to begin a year late.
3. Does Petrobras have any activities in Sudan?
ANSWER:
Petrobras would like to inform that neither in the past, nor presently, Petrobras or any of its Affiliated Business Entities have had any asset, Joint Venture, investment, or direct or indirect business activities in Sudan, and the Company has no intention to do so, directly or indirectly in the foreseeable future.
Consequently, Petrobras inform:
a) Neither Petrobras, nor a subsidiary of Petrobras, or joint venture thereof ("Affiliated Business Entity") are not engage in any direct or indirect business activity in Sudan.
b) Neither Petrobras nor any Affiliated Business Entity's current has any revenue stream from any direct or indirect business activity in Sudan.
c) Neither Petrobras nor any Affiliated Business Entity has ever made any capital investment in Sudan.
d) Neither Petrobras nor any Affiliated Business Entity has ever entered into any licensing or other form of granting document to engage in business activities in Sudan.
e) Neither Petrobras nor any Affiliated Business Entity is doing business with any corporation owned by Sudan Government.
f) Neither Petrobras nor any Affiliated Business Entity has any employee in Sudan.
g) Neither Petrobras nor any Affiliated Business Entity pays any fee or tax to the Sudan Government.
h) Since our company does not operate or has intention to operate in Sudan, no policy concerning that country has been adopted or implemented.
i) Petrobras is a signatory to and active participant in the UN Global Compact, the two first principles of which deal specifically with human rights. As regards payment of taxes, Petrobras is a signatory to the World Economic Forum's Partnering Against Corruption Initiative (PACI) and the World Bank supported Extractive Industries Transparency Initiative (EITI). As a reflection of the company's position concerning the issue of human rights in general, Petrobras share price performance is reflected in the Dow Jones Sustainability Index that reflects the performance of only those companies that meet specific criteria, one of which reflects human rights, in all its aspects (gendre, race, age, creed, political beliefsa, etc.).
4. Does Petrobras have any activities in Iran?
ANSWER:
With regard to our activities in Iran, on July 2004, Petrobras Middle East B.V. (“Petrobras ME”), a wholly owned subsidiary of Petrobras’ subsidiary Petrobras International Braspetro B.V. (“PIBBV”) with headquarters in the Netherlands, signed a service contract with the National Iranian Oil Company (“NIOC”) to explore the Tusan block in the Iranian Persian Gulf. The agreement called for seismic data acquisition and processing and the drilling of at least two exploratory wells. Also, Petrobras would drill additional appraisal wells to confirm the economic viability of any possible discovery. Petrobras has not provided any products, technologies, or equipment to the NIOC or to the Iranian government in connection with its operations in the Tusan bloc.
Since the contract was signed we were engaged in meeting the contractual obligations. Given time delays caused by operational constraints, the contract that initially had a 42 month term was extended by 18 months. The contract expired on July 13, 2009.
During the term of the contract, Petrobras acquired and processed seismic data at a cost of approximately U.S.$22 million and drilled two wells at a cost of approximately U.S.$156 million. In February 2008, we discovered evidence of hydrocarbons in the Tusan block. The discovery was not considered economically viable.
Petrobras has fulfilled the minimum financial obligations under the Tusan Exploration Service Contract. Therefore our contractual obligations with the NIOC regarding the Tusan block commitments are completed and at this time we have no additional activities or further plans in Iran.
Petrobras has not had any assets, material liabilities, revenues or proved reserves associated with its operations in Iran in any of the last three years. Over the past six years, Petrobras’ expenditures on Iranian operations have averaged approximately 0.2% of its total expenditures.
Petrobras’ activities in the Tusan block were structured as “service contract” arrangements, meaning that its expenditures are reimbursed only if exploration results in economically viable oil discoveries.
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