Bidding for a Venezuelan Oil Field:
The Third Round of “La Apertura”
The last week of April 1997 was very hectic for many people at British Petroleum Venezuela (BP). The third round of bidding for the extremely large and potentially lucrative oil fields in Venezuela (a process known in Venezuela as “La Apertura”) was scheduled for the first week of June, and an analyst team was assembling to begin work on BP’s bidding proposal. The team had experience building bid proposals for the first and second round of La Apertura, but this round had much more at stake than the prior ones. The 20 fields offered contained over 3 billion barrels of proven oil reserves, which made this the most significant round to date.
After reviewing the oil field quality assessments, the team had identified a couple of very attractive fields, but they were keenly interested in Boqueron, a field located in the eastern part of the country. Boqueron’s location and the technology needed to explore it aligned with BP’s strategy and expertise, but the analyst team wanted to further analyze its potential economic value before making any final bid recommendations to upper management.
Venezuela
Politics
Venezuela had enjoyed the longest uninterrupted period of democratic political leadership (39 years by 1997) of any country in Latin America. There were several failed military coups (most recently in 1992), and the country’s economic crisis had strained its democratic process, but none of these things had ever materially changed the country’s determination to stay its current democratic course. The national election of President Caldera in 1993 and his support of the social reform program called Agenda Venezuela, were key factors in its recent economic recovery. Agenda Venezuela included many far reaching economic policies including the elimination of price and exchange-rate controls, deregulated interest rates, a more restrictive monetary policy, increased taxes, encouraged privatization, and the restructuring of much of Venezuela’s outstanding debt. See Exhibits 1, 2, and 3 for a graphical view of Venezuela’s recent economic indicators. Now, with the 1998 presidential elections on the horizon, a number of uncertainties were beginning to concern those with vested economic interests in the country. Would a change in political leadership overturn much of what had been done to pull Venezuela’s economy back together?
An Oil Economy
The oil sector has been the primary basis of the Venezuelan economy since major exploration of its vast hydrocarbon resources began in the 1920s. In 1994, its direct contribution to the country’s Gross Domestic Product was 24% and estimates of its indirect contribution to GDP represented an additional 33%. While oil, as an abundant natural resource in Venezuela, represented one of the country’s most significant strengths, even minor fluctuations in the global hydrocarbon market were highly correlated with the stability of the Venezuelan economy. Global oil prices have historically been fairly unstable and therefore, Venezuela’s domestic economy has also.
In 1995, Venezuela was among the top four oil-producing countries in the world, with an average daily production exceeding 2,800,000 barrels. Furthermore, outside of the Middle East, it boasts the world’s largest proven oil reserves estimated at approximately 66.3 billion barrels – more than twice that of the United States (see Exhibit 4). Its sophisticated infrastructure of pipelines, refineries, oil service companies, and highly trained workers as well as its favorable climate and proximity to the US make it one of the most attractive places in the world for a multi-national oil producer to invest. However, the threat of political and the potential for economic instability in Venezuela raise significant concerns for the prospective international investor.
Petróleos de Venezuela S.A. (PDVSA)
International investment in the exploitation of Venezuela’s oil reserves had been a significant part of the country’s history since oil was discovered seeping out of Lake Maracaibo in the western part of the country in 1920. However, on January 1,1976, the government completed the expropriation of foreign owned assets into government controlled assets by paying Royal Dutch Shell, Exxon, Conoco, Gulf, Mobil, and others, a total of $1 billion and creating Petroleos de Venezuela S.A. (PDVSA). PDVSA (pronounced Pedevesa) was a state-owned enterprise with commercial and financial autonomy formed to “efficiently develop and manage the country’s hydrocarbon resources and promote economic development.”
As of 1996, PDVSA managed the entirety of Venezuela’s oil and gas reserves and operated refineries throughout the world in locations such as the US, Europe and the Caribbean. In fact, it maintained the 3rd largest refining capacity and the largest retail gasoline operation in the United States through several of its wholly owned US subsidiaries. It was the world’s 2nd largest oil and gas company and the 10th most profitable company in the entire world. It comprised so much of the domestic economy in Venezuela (78% of export revenues, 59% of the government’s fiscal revenues, and 26% of the nation’s GDP) that it wielded a considerable amount of bargaining power with the Venezuelan federal government which was beneficial during taxation and debt covenant negotiations.
“La Apertura” (The Opening)
After the nationalization was complete in 1976, PDVSA was able to exploit the country’s existing oil fields and was generating revenues of $26 billion by 1995. However, in 1990, PDVSA, in conjunction with OPEC and the national government, decided it would embark upon plans to increase the country’s production capacity from 2.8 billion barrels to 5.5 billion barrels per day – effectively doubling total capacity! Given these aggressive plans and the lack of capital available on hand to both PDVSA and the Venezuelan government, the situation dictated they attempt to raise money, estimated to be between $55 and $65 billion, by seeking investments from international oil conglomerates. Therefore, Venezuela had to “re-open” its oil industry through the establishment of operating contracts, profit sharing agreements, and strategic joint ventures to the very same outside investors they had shut out only 14 years earlier. This process was called: “La Apertura”.
Beginning in 1992, Venezuela held two successful bidding rounds with foreign investors. This process intended to reactivate 15 marginal fields with active reserves that were already producing, but had further exploitation possibilities. These bidding rounds carried little to no reserve or exploration risk since they were already producing. Further rounds, described below, contained substantial risk in not finding oil, or not finding a substantial amount of oil to recover the expense of exploring of the area.
The Third Round
The third round of bidding in La Apertura was announced in November 1996 and was to be conducted between June 2nd and June 6th of 1997. This round was expected to be much more competitive than the previous two because of its size and attractiveness to the cash rich and the resource hungry players in the industry. This was the most significant round to date involving 20 reactivation fields and up to 3 billion barrels of proven reserves. The 20 fields on offer included 9 in Eastern Venezuela, 10 in and around Lake Maracaibo in Western Venezuela and 1 on the Northwest coast. See Exhibit 5 for a map of Venezuela and the location of the oil fields being offered.
The Bidders
Several major industry players were shut out of the first two rounds of bidding because they were either disqualified from the bidding or because their bids were not high enough to win. This time the fields were to be awarded solely on the basis of a closed, cash bid and these players were sure to bid high. Among those expected to bid were winners, such as Amoco, BP, ARCO, Agip, Pennzoil, and Total, from the first two rounds as well as companies seeking entry into the market in Venezuela, a country with a substantial proportion of the world’s known oil reserves. These companies, such as Mobil, YPF, Benton, Texaco, Elf, Marathon, Conoco, Chinese National Petroleum Corporation (CNPC), Union Texas Petroleum, Phillips, Chevron and Statoil, were expected to be among the more aggressive of the bidders in the 3rd round.
British Petroleum Company
Corporate Strategy
In the first two rounds of La Apertura, BP had established a strong foundation in the upstream oil sector by acquiring an inventory of more than a billion barrels of net oil reserves in Eastern Venezuela. By 1996 their production was equivalent to 19 million barrels per day and was projected to grow to 60 million barrels per day by the first quarter of 1998. BP’s international strategy was to focus their growth in regions of the world where political and economic instability and a lack of technical sophistication had created an environment of unexploited oil and gas reserves. Venezuela was a perfect example of this situation and seemed to be an amazing opportunity for BP to expand their operations in an area of their primary core competency
The third round of La Apertura offered BP an opportunity to further establish its operations in Venezuela and secure a significant portion of oil sources for its future growth. The political, economic and competitive environment was maturing, and access to the upstream sector was arguably entering a middle stage. BP was looking to consolidate around their existing operation in the east, and expand by entering some of the western sectors around Lake Maracaibo. BP wanted to duplicate existing production in Venezuela by 2010, and this round offered them the opportunity achieve that goal by both deepening and broadening their Venezuelan portfolio.
Financial Strength
By 1997, BP’s financial strength provided it with many options for financing this project’s bid and ongoing operations. See Exhibit’s 6, 7, 8, and 9 for BP’s Income Statements, Balance Sheets, Cash Flow Statements, and Ratios from 1996 to 1998. Also Exhibit 10 shows the oil and gas industry’s, project’s, and company’s debt ratings. The analyst team at BP was inclined to use primarily equity to fund the project and was considering several key ratio trends the company was expecting to see over the next few years. Debt to Equity was currently about 30% and was expected to rise over time. Furthermore, the company’s Return on Average Capital Employed was almost 13%, but it was expected to drop over time. Finally, the company’s shareholders were experiencing an average return on their investment of roughly 14.6%, but that was also expected to drop over the next couple of years.
Field Selection
BP screened the fields being offered by evaluating, size, quality, and location, where size was defined as remaining reserves and quality as a mix of parameters such as business fit, re-development potential, and exploration potential. These studies indicated that approximately two-thirds of the total reserves on offer were located in Western Venezuela, but BP’s strength and presence in the Eastern part of the country made it partial to fields located there.
Quality assessment of the offered fields indicated that the best in the East were Boqueron, Dacion, and Caracoles, and in the West were LL-652, B2-X.68/79 and B2-X.70/80. The analysts at BP believed Boqueron was one of the highest quality fields up for bid and focused much of their effort on this particular field. Discovered in 1989, it was located about 13 kilometers Northeast of Marturin, a city in eastern Venezuela, and had an estimated reserve of about 105 MMBO. Although this was a small amount of estimated reserves, BP believed there might be further opportunity for exploitation if they were successful in exploring the field for more reserves. See Exhibit 11 for a comparative assessment of the fields being offered in the 3rd round.
The Competition
The BP analysts were not sure which companies were going to show a strong interest in bidding for the Boqueron field, but analyzing the potential competition’s technical expertise and financial backing, they compiled a list of potential bidders which included Agip, TOTAL, Union Texas Petroleum, and YPF.
Agip and TOTAL were similar in a sense that they were large multinational energy companies with a strong base in all parts of the world. Although both already had operations in Venezuela, Agip was potentially a stronger competitor for the fields because it had operations only in the lubricant sector of the industry, and was willing to expand into other sectors. Union Texas Petroleum and YPF, on the other hand were relatively smaller companies, with exploration and operations in countries like Indonesia, the North Sea, Pakistan and Argentina. YPF was known to be pursuing an aggressive Latin American growth strategy.
The Valuation
Revenues
The contract for this round was for 80 quarters or 20 years. For the purpose of this case, the input and output variables of this model are assumed to be in years. The Operating Service Contracts being awarded were effectively joint venture agreements with a PDVSA affiliate. The winning bidder agreed to perform work on behalf of the PDVSA affiliate. However, at the risk and cost of the contractor were certain “rehabilitation, reactivation, development, production, exploration and other activities” as may be required to achieve commercial development of the area. The affiliate retained ownership of all related goods and assets, and the contractor was remunerated by means of a service fee. The service fee, or income generated by the contractor, was a series of complex formulas that are omitted for the purpose of this case. Instead it can be assumed that the contractor received 31% of the pre-tax revenues from the sale of oil on the open market. Based on historical oil prices, analysts estimated the price of oil to be $14 per barrel over the life of the contract.
Taxes and Royalty Payments
The federal tax rate applicable for these projects was established at 34%. In addition, a municipal tax rate was applicable depending on the location of the field. The Municipal Tax rate was 0% for fields located around Lake Maracaibo, and 4% elsewhere. Furthermore, a royalty fee of 16.7% on income after operating expenses and depreciation calculations was established as another obligation for the contractor.
Costs
To date, eleven wells had been drilled in Boqueron and five still remained productive. Fluid properties in the field varied with depth. At the top of the reservoir was a gas-condensate, and as one moves deeper into the ground, the fluid transformed from volatile oil to black oil. Poor drilling practices seem not to have yet exploited the full productivity of the field. Taking these factors into consideration, the analyst team met to estimate the adequate production rate needed to extract the oil in the next 20 years. These assumptions led them to estimates of the overall operating expenses and capital expenditures the project would require. See Exhibit 12 for the analyst team’s detailed estimates of Production, OPEX, CAPEX, and other key project data sets.
Conclusion
With this data the analysts were ready to model the value of the field as their first step in establishing the size of BP’s bid. Furthermore, they had to consider the benefit that BP might obtain beyond the operation of this field, a factor not easy to determine given the unknown “future options” this field might provide for the company. How much should they add on to the bid above and beyond their calculated NPV? What risk factors should they include in their estimate of the cost of capital? How much would game theory play in understanding the competitive bids? Should they be prepared to match the competitive bids? Was this field strategic enough to BP for them to overbid? In the end, the analyst’s had to decide how much should BP bid for the field and what their maximum bid might be.
Exhibit 1: Inflation Rate (%)
Exhibit 2: Interest Rate (%)
Exhibit 3: Bolivar/$ Exchange Rate
Exhibit 4: Proved Crude Oil & Condensate Reserves
Exhibit 5: Venezuelan Oil Reserves
Exhibit 6: BP Group Income Statement
Turnover / 102,064 / 108,564
Less: Joint ventures / - / (16,804)
Group turnover / 102,064 / 91,760
Replacement cost of sales / (81,922) / (73,928)
Production taxes / (1,611) / (1,307)
Gross profit / 18,531 / 16,525
Distribution and administration expenses a / (8,367) / (6,742)
Exploration expense / (997) / (962)
9,167 / 8,821
Other income / 714 / 662
Group replacement cost operating profit / 9,881 / 9,483
Share of profits of joint ventures / - / 544
Share of profits of associated undertakings / 663 / 556
Total replacement cost operating profit / 10,544 / 10,583
Profit (loss) on sale of businesses / 127 / 127
(Loss) profit on sale of fixed assets / (298) / 313
European refining and marketing joint venture implementation / (532) / -
Refinery network rationalization / - / 71
Merger expenses / - / -
Replacement cost profit before interest and tax / 9,841 / 11,094
Stock holding gains (losses) / 1,172 / (939)
Historical cost profit before interest and tax / 11,013 / 10,155
Interest expense / (1,004) / (908)
Profit before taxation / 10,009 / 9,247
Taxation / (2,755) / (3,066)
Profit after taxation / 7,254 / 6,181
Minority shareholders' interest / (13) / (151)
Profit for the year / 7,241 / 6,030
Distribution to shareholders / (3,006) / (3,452)
Retained profit (deficit) for the year / 4,235 / 2,578
Replacement cost resultsb
Historical cost profit for the year / 7,241 / 6,030
Stock holding (gains) losses net of minority interests / (1,172) / 939
Replacement cost profit for the year / 6,069 / 6,969
Exceptional items, net of tax and minority interests / 627 / (320)
Replacement cost profit before exceptional items / 6,696 / 6,649
aResearch and development expenditure amounted to: / 369 / 382
Source: BP Annual Reports 1996-1998
Exhibit 7: BP Group Balance Sheet