With the help of analysts and experts, oil companies have been assessing changes in Brazil's tax laws and new rules by the national petroleum authority, Agencia Nacional de Petroleo (ANP), for the upcoming Round 6 tender.
"The ANP's innovations are bringing its concession contracts and bidding procedures closer and closer to 'typical international standard,' with continuing innovations favoring the participation of medium-sized and smaller companies," said consultants with Macleod Dixon LLP in Rio de Janeiro. "However, indications so far are that the world's largest players are looking seriously at this opportunity to return to Brazil's [exploration and production] scene, after mostly sitting out the last several rounds."
Meanwhile, Petroleo Brasileiro SA (Petrobras) said it's prepared to appeal an expected order from Brazil's top auditing court that it return 16 oil exploration blocks to ANP. Last August, Petrobras and its partners were required to return oil E&P areas where no finds had been made. Some of those were designated Blue Blocks from Round Zero in 1998, said officials of Thompson & Knight LLP. Earlier this month, the auditing court issued a recommendation that Petrobras also return 16 oil exploraton blocks where it has made finds but hasn't yet proven commercial viability. An official decision was expected by July 21.
Interested companies had to present qualification documents to ANP on July 16 for sixth round bidding for oil and natural gas exploration and development concessions in Brazil.
The 912 blocks to be offered in that round span 12 sedimentary basins, representing nearly 250,000 sq km in mature onshore acreage, established producing areas, and exploration frontiers.
Deepwater offerings are in water depths greater than 400 m in Pelotas, Santos, Campos, Espírito Santo, Jequitinhonha, Camamu-Almada, Sergipe-Alagoas, Pará-Maranhão, and Barreirinhas basins. Shallow-water offerings are in Santos, Campos, Espírito Santo, Barreirinhas, and Foz do Amazonas basins. Onshore offerings are in Espírito Santo, Recôncavo, and Potiguar basins. The average onshore block area is 30 sq km, increasing to 180 sq km in shallow water and 720 sq km in waters over 400 m.
ANP is to issue qualification notices of approval or rejection at the beginning of August. Participation fees are due by Aug. 6, with bidding scheduled Aug. 17-18.
The qualification process began with an expression of interest, consisting of a presentation letter, a power of attorney, and a confidentiality agreement. Upon payment of participation fees, ANP will provide data and information packages on basins of interest to applicants. To participate in the bidding process, each company must qualify individually by submitting documentation establishing its technical, legal, and financial qualifications.
Protocol changes
Changes in the tender protocol for the sixth round permit disqualification of companies if the applicant's chain of control is not clearly defined and address the issue of companies incorporated in tax havens.
To guarantee winning bidders' obligations, each company or consortium now must submit bid bonds for each block on which it intends to bid. If a company has already used a bid bond to guarantee a winning bid on any block, it may deliver additional bid bonds for any other block it intends to pursue. But delivery must be made at least an hour before bidding opens for that block to allow time to verify the adequacy of the bid bond. "This new provision provides the company the possibility of bidding on cells which were not considered previously, during the bid process," said Macleod Dixon officials.
Concession contracts
Macleod Dixon consultants also noted "small improvements" in the concession contract for the sixth round, which "now expressly provides that the concessionaire shall formally inform the ANP within 72 hr of any discoveries where a pool extends beyond the applicable concession area" and "provides that evaluation of the unitized area may be required prior to the ANP's approval of the unitization." ANP is to establish terms of a unitization agreement within 60 days of a final evaluation report but may review those terms "once operations provide better knowledge as to the extension of the hydrocarbon reservoirs."
The new contract also provides for the use of "an insurance guarantee" to guarantee performance of the minimum exploration program, as an alternative "to the irrevocable standby letter of credit and the performance bond." ANP may require the concessionaire to increase the value of such a guarantee if there are increases in the expected costs of the minimum exploration program.
Major changes in assignments of concession contracts for the sixth round provides for "a possible partial assignment of areas during the exploration phase" and "expressly provides that amalgamations, spin-offs, and mergers of the concessionaire are to be considered to be a transfer of concession rights. This subjects those transactions to ANP approval," the consultants said.
Participants must bid by cells, designated on the basis of prequalification standards for operators as A for deepwater, B for shallow water, and C for onshore. Qualifications for operatorship are highest for A cells and lowest for C cells. If a bidder or consortium wins more than one cell in a sector, separate concessions will be created for each cell. However, separate concessions may be unified in a single contract that will not impede assignment of concession interests in particular cells at a later date, said Macleod Dixon consultants.
Bids for each cell must incorporate three variables, including a bonus, the value of the minimum work obligation to which the bidder is willing to commit, and the percentage of national content it will employ. New signature bonuses range from 10,000 reals onshore to 30 million reals for the offshore block of SEAL-M-495.
The minimum work obligation will be calculated on the basis of work units, with conventional and 3D seismic and wells allocated as work units according to sector-specific criteria. For onshore cells, ANP also will allocate work units for gravimetric, geochemical, and magnetometric surveys. Companies can satisfy seismic obligations through the purchase of speculative seismic data on the market on a sliding scale value depending upon the age of the data acquisition.
Tax law changes
In late June, Thompson & Knight hosted a workshop on Brazil's tax and fiscal framework in its Houston office that featured Ivan Tauil, a partner who heads Thompson & Knight's tax office in Brazil, and Decion H. Barbosa, an energy consulting associate of Rio de Janeiro-based consultancy Expetro Grupo and former ANP tax division head.
The Brazilian government makes three main levies on oil and gas activities—direct taxes levied on company income, indirect taxes levied as an import duty on a company's supplies or as service tax on services hired, and petroleum levies specific to oil extraction activities, which are "ring-fenced to a block or field as a separate trade," said the tax experts.
The corporate income tax rate is 34%, with no consolidated taxation within a group of companies. Taxable income is based on book income, under Brazil's generally accepted accounting principles (GAAP) as shown in financial statements, with statutory adjustments to arrive at taxable profits.
Losses can be carried forward indefinitely but are limited to 30% of annual taxable basis.
Under Brazil's GAAP, there are no separate accounting rules for oil and gas companies. When a dispute arises, parties are to refer first to the conceptual framework of Brazil's general account rules and secondly to any specific guidelines for the issue in question. For issues not treated under Brazil's GAAP, parties are to turn to International Accounting Standards and US GAAP for guidance.
Applicable taxes
Capital expenditures on imported intangible services are subject to a 15% withholding tax; an Imposto Sobre Serviços city service tax of 2-5% on gross billings before withholding tax, and Brazil's Contribuição Para Fin Social (COFINS) tax of 7.6% and its PIS (value-added tax) of 1.65%—both of which are recoverable.
There also is a CIDE tax of 10% for those imported services involving technology transfer, technical assistance and specialized technical services, technical services and administrative support services, and assignment of trademark usage rights. That tax is not recoverable, the experts said. "Sometimes it is less expensive to buy local than to import foreign because of the tax," they said.
The Imposto Sobre Circulação de Mercadorias e Serviços (ICMS), Brazil's excise tax on domestic intangible services, is recoverable, along with COFINS and PIS taxes on those services.
Brazil's federal import duty on tangibles to be consumed has an average rate of 15%, said the tax experts. The REPETRO customs special regime includes taxes on imported equipment paid proportionately to the time it is in Brazil. But some E&P assets are give special treatment under that regime. Brazil's list of equipment designated as "qualified" under the REPETRO tax regime include exploration vessels and equipment used in the survey and acquisition of geodetic and geophysical data, support vessels for the survey, exploration, drilling, production, and storage of oil and gas, tugboats, auxiliary equipment for drilling and development of wells, cranes used in offshore rig facilities, machinery qualifying as "fixed assets" for exploration, drilling, and production, semisubmersible platforms, wellheads, risers, remotely operated submarine vehicles, and floating production, storage, and offloading (FPSO) vessels. Other equipment may be qualified by customs authorities on a case-by-case basis, officials said.
Special participation tax
Brazil also imposes a special participation tax (SPT) as a special tax on oil and gas production, "which seeks to tax a high proportion of the economic rent (windfall profits)," the experts said. It applies only to onshore fields that produce more than 10,500 boe/d; offshore fields in less than 1,300 ft of water that produce more than 21,000 boe/d; and fields in more than 1,300 ft of water that produce 31,500 boe/d.
SPT is a field-based tax, with each field treated as a separate taxable unit. Its sliding scale rate is based on volumes, production year, and location and is self-assessed for each chargeable quarter. The primary deductions allowed in calculating the "positive net revenues" subject to this tax include royalties, exploration costs, depreciation of development costs, operating costs, and cost provisions for future abandonment.
"Exploration costs are depreciated over 5-10 years. Depreciation of development costs begins when the asset—wells, pipelines, etc.—becomes operative and follows a linear book depreciation, based on terms listed in the normative Ruling 162 of 1998, with pipelines and fixed platforms being depreciated over 10 years and an FPSO over 20 years. Interest on loans is expensed or amortized over 5-10 years," Barbosa said
However, no losses incurred outside the ring-fenced field area may be offset against field income subject to SPT. That includes the costs of dry holes drilled in other concessions, regional seismic surveys outside that field, or transferred development costs within the concession. Although lease payments are deductible, interest costs are not, nor are foreign exchange losses. Except for the bonus paid to the government, other costs of acquiring land interests are not deductible. Allocated headquarters overhead also is not deductible "unless documented and based on the arm's-length principle," officials said.
Payments to landowners are not for mineral rights, which belong to the government, but to compensate landowners for limiting their use of their property. Such payments are levied at 1% of the value of oil and gas production, the same valuation criterion used for the SPT and royalties. Such payments are deductible from both the SPT and the corporate income tax.
The concession agreement also requires that, on those fields subject to special participation tax, 1% of gross revenues should be invested in research and development, which is deductible from both SPT and corporate income tax.
Although there is no tax treaty between the US and Brazil to avoid double taxation of company profits by the two countries, the experts said, Brazilian companies can be affiliated through firms in France, Canada, or the Netherlands that have such treaties. As a rule, they said, "It is better to acquire an interest in a Brazilian company that to acquire the whole company."
The so-called Valentim (anti-REPETRO) law passed in 2002 by Rio de Janeiro's state legislature that imposed additional costs of 19% in the form of a Brazilian excise tax on platforms built abroad to work off Rio de Janeiro (OGJ Online, May 5, 2003) has been challenged as unconstitutional by Brazil's attorney general, said the tax authorities. A similar wellhead tax on oil production "is suspended and being challenged now," they said.
Meanwhile, they said, oil exports from Brazil are "either exempt from taxes or taxes are zero rated, so there is no export taxation."
