Brent rallied above $10/bbl early this year and has since stayed mainly at $10-11. At closing in London Jan. 27, March-delivery Brent stood at $10.88.
"The recent, fleeting backwardation of the Brent market, however, should not be taken as evidence of a sustained tightening of the market," said CGES. "Such is the global stock overhang-at about 500 million bbl-that any respite can only be temporary."
Left to its own devices, the industry will gradually chip away at the 8-day inventory overhang accumulated since mid-1997, but it will take a long time, says CGES. The analyst said non-OPEC producers have finally responded to the price collapse, with, for example, U.S oil production down by 300,000 b/d on average for 1998 and Norway's output down by about 120,000 b/d.
If OPEC does not reduce its output, Brent futures prices will remain flat at about $11/bbl this year, rising by $1/bbl in the fourth quarter, assuming normal winter weather. If OPEC cuts 1 million b/d, however, dated Brent would average $11.50/bbl in the second quarter and $13.20 in the third, said CGES.
"It is likely that compliance with output cuts would weaken as prices begin to rise, but even with 500,000 b/d of leakage in the fourth quarter, the price of dated Brent would still average $15.30/bbl." However, if Brazil's economic problems spread throughout South America and perhaps spread to Asia, CGES reckons global oil demand could fall by 300,000 b/d, which could lead to dated prices dwindling to an average $8.90/bbl in the fourth quarter.
U.K. Energy Minister John Battle was expected to meet with U.K. offshore operators Jan. 27 to discuss easing of oil taxes. In September 1997, when Brent crude was worth $21/bbl, the U.K. was considering raising taxes on producing oil fields; now it is thinking of easing the burden to keep marginal fields on stream. Battle is chairman of a task force looking at ways to trim the offshore industry cost base. He said, "Nothing is ruled in and nothing is ruled out."
The Asian economic blight and industry downturn appear to have spread to China, where Beijing reportedly is postponing petrochemical expansion plans. Chinese officials were quoted as saying chronic oversupply in Asia's petrochemical markets, plus low product prices and financial problems in some state-owned companies, make a number of planned projects less alluring.
Among projects expected to be delayed are Royal Dutch/Shell's planned $4.5 billion petrochemical complex in Guangdong province, BP Amoco's planned $2.5 billion JV complex at Jinshan near Shanghai, and BASF's planned $3.6 billion ethylene cracker at Nanjing in southeast China.
Unlike previous industry recessions, the downstream sector seems to be faring no better than the upstream during the current business cycle.
Chem Systems Managing Director Kenneth Stern told the firm's annual conference last week that current cash margins, on a constant dollar basis, for the U.S. chemical industry "are near those experienced in 1992 and 1993, representing the lowest levels of the decade. Things have pretty much bottomed out on a monthly basis," he said, "although, on a yearly average, 1999 will be worse than 1998." Stern cites overcapacity as the root of the problem.
Things are equally bad one step up the production chain. Chem Systems Vice-Pres. and Director Bruce Burke said, "On a simple return-on-replacement-capital basis, the (U.S. refining) industry has achieved dismal results, estimated at only 2.4% over the past 10 years." Burke sees Asia, because of its reduced asset values, as the next area of focus for U.S. refiners, in terms of acquisitions and joint ventures, following similar moves into Europe and Latin America.
Mobil's decision to call off a planned downstream merger with Shell in Australia may have been driven more by Mobil's global merger partner, Exxon, than by the extended regulatory review process that Mobil blamed for the move (OGJ, Jan. 25, 1999, Newsletter). There is talk that the decision was based on Exxon's study of all the underperforming assets in Mobil's worldwide portfolio and the conclusion that the profitability of its Australian refining unit is highly dependent on what happens in the large refineries of Asia. A 1998 Australian Institute of Petroleum study found that Australia's refining companies (Mobil, Shell, Caltex, and BP) made profits totaling just $81 million (Australian) in 1997-a return of a mere 2%. Since then, markets have worsened, as Australian refiners struggle to meet competition from product imports from Asia.
This year is likely to provide significant opportunities for E&P companies with enough cash and corporate vision to strike strategic deals, says Wood Mackenzie (see related story, p. 26). There will also be significant opportunities for asset swaps and farm-outs. The firm reckons equity markets are now closed for raising capital in the E&P sector, as the investment community looks to reduce its exposure. "Cash will be king in 1999," said the analyst.
"We are aware of a small number of competitors in the market with the desire and cash to effect sizable asset acquisitions in 1999. However, if oil price and equity market conditions prevail, the overall scarcity of cashellipseis likely to act as a brake on the number of such transactions early in the year."
Wood Mackenzie forecasts that the E&P sector will switch from being a strong asset sellers' market to a strong buyers' market around midyear. Therefore, the timing of offers and bids will be critical. "It will be much harder to sell lower-quality assets in 1999 than in recent years," said Wood Mackenzie. "Companies looking to buy assets are not likely to be opportunity-constrained; the challenge will be to remain focused and target opportunities that fit within a clearly defined strategy."
Vastar Resources is apparently one of the firms poised to take advantage of low asset and service prices. Its 1999 capital budget is $695 million, only $1 million less than 1998's. Of the total, 55% will be allocated to development, 35% to exploration, and 10% to "other opportunities," including acquisitions of producing properties. "We are fortunate to have an attractive opportunity portfolio on hand that is worthy of this level of investment," said CEO Charles Davidson. "Considering recent declines in drilling and service costs, we expect this budget to support a very active programellipseWhile we are sensitive to the current industry environment, we believe 1999 is an opportune time to invest in our business."
Rumors are running rampant regarding a possible merger among Russia's state-controlled oil firms. Local press reports indicate that Rosneft, Slavneft, and Onako plan to form a holding company in which the government would own a 75% stake. Tyumen Oil Co., which has minority government ownership, may join if its shareholders approve.
Deputy Prime Minister Vladimir Bulgak, who revealed the plan, said the move was not aimed at nationalizing Russia's oil sector but rather at cutting costs and improving earnings. If the plan goes forward, the new firm would have more reserves than Lukoil, Russia's largest oil company (see related story, p. 20).
India's Oil & Natural Gas Corp. (ONGC) and Indian Oil Corp. (IOC) have agreed to form a joint-venture "national oil entity"-a vertically integrated oil major to attain the characteristics of global players. The firms' chiefs, ONGC's B.C. Bora and IOC's M.A. Pathan, said the pooling of resources would enhance national oil security. A complete merger has been ruled out, however.
The alliance would provide a balanced portfolio of ONGC's high-risk, high-margin E&P projects and IOC's low-risk, low-margin refining-marketing ventures. Bora said the firms have identified several upstream opportunities, in India and abroad, on which they could work together. They could also participate in joint bidding on exploration blocks under India's New Exploration Licensing Policy (NELP), including exploration in frontier areas (OGJ, Nov. 23, 1998, Newsletter).
India published a notice invitation offer for 48 blocks under NELP on Jan. 8. Road shows promoting the bidding round have begun.
Petrobras has disclosed first oil from giant Roncador field and another deepwater production record. The Campos basin field development is in 6,079 ft of water. Its fast-track development began in October 1996. The field is produced via an FPSO with capacity to produce 20,000 b/d and store 306,000 bbl.
Roncador reserves are put at 2.7 billion bbl.
The U.S. Supreme Court has agreed to hear a case in which the Southern Ute tribe challenged oil companies' ownership of coalbed methane leases in southwestern Colorado. The case may affect other federal coalbed methane leases in the U.S. (OGJ, Jan. 25, 1999, p. 34). The court scheduled arguments for April and is expected to issue an opinion by late June.
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