Venezuela is one of the oldest oil producing countries in the world, accounting for 4% of global crude oil production. The country has oil reserves of almost 78 billion barrels and gas reserves of 148 trillion cubic feet, accounting for approximately 8% and 4% respectively of world supplies.
More than half of Venezuela’s oil reserves are extra-heavy crude that is not as valuable as conventional light, medium and even heavy crudes that account for 42 billion barrels. What’s more, much of the 78 billion barrels of reserves cannot be brought into production quickly. Only 17.3 billion barrels are proven in-production reserves, with just under a third of these as extra-heavy crudes.
Venezuela nationalized its oil industry in 1976 which has since been run by Petróleos de Venezuela S.A. (PDVSA), the national state oil company, with important refining and marketing assets in the US and Europe. In 2001 PDVSA reported net income of $4.3 billion compared to $7.4 billion the previous year. In the same year PDVSA paid $11.8 billion to the government in royalties, dividends and taxes, and invested $3.8 billion boosting production capacity to 4 million barrels per day (bpd) from 3.85 million bpd in 2000. In 2000, operational cash flow was just under $9.6 billion, the highest level between 1995 and 2000.
Operating expenses for PDVSA have been creeping up from $5.41 per barrel in 1998 to $7.65 per barrel in 2000. Direct production costs have also risen from $2.89 per barrel in 1999 to $3.93 per barrel in 2000, and other costs have risen as well.
PDVSA finances its normal investment program from its own resources. Until 1990, most of PDVSA’s investments were met from cashflow with a minimum of debt taken on mainly to fund certain overseas acquisitions. In 1990, the government opened the industry to a limited amount of private capital to help achieve production targets and develop new refining capacity with all joint ventures majority-owned by overseas private companies and PDVSA holding typically a 35% stake.
The strategic associations agreements, structured to develop the Orinoco Oil Belt, are subject to a flexible royalty payment fee and income tax of 34%. Four developments so far – Petrozuata, Sincor, Hamaca and Cerro Negro – have been entered into under this agreement, with limited success. Few of the companies that entered into the various agreements have made money or achieved the expected production rates. The British oil company LASMO, which was taken over by the Italian giant ENI last year, paid approximately $454 million for its contract and has struggled to achieve acceptable rates of return and production figures. Similarly, BP acquired the Pedernales marginal field development contract expecting to reach production of 1000,000 bpd but only managed to achieve 20,000 bpd.
Prior to the enactment of a new hydrocarbon law in November 2001, PDVSA drew up a business plan in 2000 that estimated that capital expenditure of between $50 billion and $55 billion was needed for the Venezuelan oil industry during the first decade of the millennium, with PDVSA contributing $22.3 billion.
Under the plan, PDVSA wanted the country’s productive capacity to rise to 5.8 million bpd in 2009 from 3.6 million bpd in 2000, with most of the increase coming from the private sector. PDVSA’s own production was expected to increase to 3.9 million bpd from 2.8 bdp, while private sector production was expected to rise to 1.9 million bpd from 0.8 million bpd, with the Orinoco Oil belt contributing 700,000 bpd. Total capital expenditure for such a large increase in productive capacity would be in the order of $40 billion, with the private sector contributing $20 billion.
One of the major issues for the 2000-2009 plan was the development of the gas business based on private participation. Gas transmission was to receive a major expansion estimated at $1.6 billion, and there was also encouragement to distribute gas to households at a cost of $2 billion. The biggest investment however was earmarked for gas exports at a cost of $4.6 billion. In the refining and marketing divisions, a total of $2.7 billion was expected to be invested for the period.
New Oil Law
In November 2001 the government passed a hydrocarbons law to accelerate further transfers of oil revenues to the government and also as a nationalist gesture to increase control of its natural resources. The new law increased royalty rates on oil production from 16.7% to between 20% and 30%, compared with a global average of 7.1%. It prohibited private companies from having a majority share in any joint venture and reduced income tax to 34% from 67%. In order to attract foreign investment, most current projects under development have a lower income tax of 34%. In addition, many of the current heavy oil projects have royalties of only 1%. The state expects something like $65 billion of foreign investment to develop the country’s oil and gas reserves but this is a forlorn hope.
To maintain its current production Venezuela needs to replace around 520,000 bpd every year at a cost of between $5 billion and $6 billion because of its overall depletion rate of around 20%. It is however getting more expensive to replace these barrels as productivity per well is declining from 229.5 barrels per well in 1998 to 183.4 barrels per well in 2000. As a mature oil province, Venezuela needs to drill more wells for a given amount of oil production.
In order to redress this problem, exploration activity has increased, with 21 exploratory wells drilled in 2000 compared to five in 1996. However, the overall number of wells drilled has fallen from a peak of 1,058 in 1997 to 474 wells in 2000.
As part of its exploration program, PDVSA in February 2002 started the $375 million Deltana Platform Project, located near the offshore border with Trinidad. Over the next two-and-half years it will drill between 10 and 14 wells off the country’s eastern coasts. The area could hold additional reserves of 38 trillion cubic feet (tcf). If commercial quantities of gas are found, production could start in 2007 at one billion cubic feet per day for domestic and international consumption at a cost of $4 billion.
In recent years there have been some notable exploration successes such as the SINCOR heavy-oil project, where TotalFinaElf is the lead investor with a 48% stake. This came on stream in December 2001 and is on course to produce 80,000 bpd. Another heavy-oil success has been Petrozuata, a joint-venture between PDVSA and Conoco, which came on stream in 2000 producing 1,500 bpd. Conoco also has the possibility of developing a 500 million barrel crude oil field offshore the Paria peninsula. The concession was awarded in 1996 before the new hydrocarbons law, and the company expects its contract to continue under the previous fiscal regime and thus pay lower royalties. At the moment it is deciding whether to go ahead with the project.
In mid-June, Venezuela selected Royal Dutch/Shell, Mitsubishi Corp and Qatar’s state oil company, Qatar Petroleum, to partner with PDVSA in a $2.2 billion LNG plant in the Paria peninsula. In a further development under the new hydrocarbons law TotalFinaElf (69.5 %), Repsol (15%) and Venezuela’s Otepi SA (5.3 %) and Inelectra SACA (10.2%) were awarded in January 2001 the right to explore and produce the Yucal Placer North field, a natural gas field adjoining the Yucal-Placer South field. The field is thought to contain 20 trillion cubic feet of gas and the concession is for 35 years with an option to extend for a further 20 years. The group is paying 2.51% above the country’s 20% royalty.
Waiting for Clarity
The Conoco deal and any others however will remain on hold until the situation becomes clearer. For example, can PDVSA under the new oil law come up with $1 billion investment needed for the LNG Paria Gulf project? In addition, can any foreign company take the risk of entering into an agreement with such an unstable government that has an ideological distrust of foreign companies?
PDVSA has insufficient cash flow to meet the investment needed to maintain production let alone increase it. In 2000, according to the latest detailed figures available, PDVSA had operating cash flow of $9.6 billion. The figures were flattered by a large provision for employee termination and pension benefits of $2.1 billion. In 2000, PDVSA spent $2.5 billion in fixed investments and paid $2.2 billion into a fund set up in 1999 to minimize adverse effects of volatile oil prices, a debt repayment of $1.3 billion and dividends of $1.7 billion.
This leaves a net cash flow of $2.2 billion, which is insufficient to cover the company’s additional capital expenditure needed to grow. Its overall investment in fixed assets of $2.5 billion is around $1.5 billion short needed to replace its natural depletion of crude oil production, and does not include capital expenditure in other areas such as refining and marketing. PDVSA’s investment program has been declining steadily since 1998 when it was $3.7 billion.
The large amount of money owed to PDVSA by various government agencies weakens the company’s position. The government owes PDVSA hundreds of millions of dollars in late payments for products and services. The National Tax Institute also owes the company $2.1 billion in deferred tax payments, known as drawbacks. Finally, the state power utility also owes PDVSA about $120 million for heating oil used to generate electricity. In addition, PDVSA also faces a shortfall due to government subsidies on its domestic sales of gasoline at a cost of $800 million in lost revenues in 2001.
All this points to the inevitable conclusion reached many years ago by PDVSA that in order to maintain the country’s production or increase it to just under 6 million barrels per day by 2009, it will have to rely on foreign investment. Still, foreign companies must cope with the new hydrocarbon law, perceived leftist policies pursued by Chávez, his vigorous defense of OPEC quotas, and his government’s growing instability. But without foreign investment, the country’s productive capacity will suffer.w