OGJ Newsletter

March 25, 2002
Despite recent news and statistics indicating recovery of the US economy, IEA has slightly lowered its forecast of worldwide oil demand for 2002.

Market Movement

IEA lowers forecast

Despite recent news and statistics indicating recovery of the US economy, IEA has slightly lowered its forecast of worldwide oil demand for 2002. In its latest report-released 3 days prior to the Organization of Petroleum Exporting Countries' meeting in which the organization agreed to maintain existing oil production quotas-IEA warned that producers need to anticipate developments in the market to avoid excessively tightening output and thereby feeding cyclical instability.

Addressing improving economic conditions, IEA said that the focus is now on the pace of a US-led recovery and that perceptions about the health of the broader economy are becoming more favorable. Recovery in gross domestic product growth combined with continued production restraint will cause the crude oil market to eventually rebalance.

Timing is the key. Should the tight market plus political uncertainty and a heightened risk of supply disruptions continue to firm prices, demand for oil products will fall in fragile economies outside the Organization for Economic Cooperation and Development, hampering the pace of a global economic recovery.

"Many of these economies are also struggling with the deteriorating terms of trade due to currency devaluation, making it more expensive to purchase even the same quantity of dollar-denominated crude," the agency said.

Flat demand outlook

While many economists are increasing their economic growth forecasts in OECD countries, IEA finds it too early to adjust upwards its estimate of oil demand growth. In addition to unseasonably warm weather this winter and unusually high US natural gas inventories, growth in the more oil-intensive sectors appears to be lagging behind the broader US economy.

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IEA expects global oil demand to grow 420,000 b/d this year, a decline of 80,000 b/d from the agency's previous report. Demand growth was only 90,000 b/d last year. Estimates for second and third quarter 2002 demand have been raised in line with broad indicators that the US economy bottomed out sooner than expected; if the economic recovery is shallow, IEA expects that lower demand growth in the fourth quarter will offset these increases.

Although upward revisions to fourth quarter 2001 US economic indicators may heighten optimism about the health of the global economy, IEA noted, the implications for oil demand are less bullish. "While the assessment of US GDP growth for the fourth quarter was adjusted sharply upwards, estimates of US oil demand were revised down even more sharply, with December deliveries showing the steepest monthly decline in 12 years." This phenomenon continued in January, as preliminary data showed that oil demand contracted sharply in key US, Japanese, and German markets.

Stock levels mixed

Early estimates indicate that total oil stocks in OECD countries declined 300,000 b/d in January following a mild 400,000 b/d stock draw in the fourth quarter. Most of the January draw came from the Pacific region, which saw a strong 380,000 b/d decline in crude stocks and a modest decline in product inventories. In North America, crude oil stocks increased 140,000 b/d, while product stocks declined. In Europe, the reverse was true as crude stocks were down 160,000 b/d, and product stocks increased 190,000 b/d.

Although OECD oil stocks declined in January, the surplus over the previous year widened to 113 million bbl. Demand cover, at 55 days, was 3 days higher than a year earlier.

Industry Scoreboard

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Industry Trends

UBS Warburg LLC launched earlier this month the first version of a new research product that is designed to gauge near-term expectations and trends for commodity prices, oil field activity, and oil field service and product pricing. Data for the survey-called UBS Warburg PatchWork Survey-will come from oil company operating personnel, who will be polled monthly.

"We believe the information gleaned from this survey will provide investors with more in-depth and real-time insight into these key areas of interest vs. semiannual or annual surveys of senior oil company management, which just focus on capital spending,"

The initial survey was compiled from fewer than 100 respondents, although Warburg hopes to build on that figure and get to the level of a few hundred responses every month, said James Stone, managing director, oil field services research.

Based on responses from the initial group, Warburg calculated that 32% of US and Canadian operators plan to reduce capital spending in the next 60 days, while 54% plan no change and 14% plan to increase spending.

Meanwhile, for operations outside the US and Canada, 29% of oil companies are planning to boost outlays, while 13% plan a decrease and 58% plan no change.

Although Warburg cautioned industry not to read too much into the initial survey, it assured that greater insight would emerge as many more months' worth of responses are collected. "…[T]he results are a good indication of the short-term direction of the oil service industry and based on the initial results, we believe that industry conditions are still worsening in North America but getting closer to a bottom."

INDUSTRY'S PROSPECTS for recovery also hinge on a rebounding economy. A report from Standard & Poor's indicates that an economic rebound in the US economy has been "quicker and stronger than expected."

S&P's Chief Economist David Wyss said, "A surprisingly quick and strong rebound in the US economy that followed the Sept. 11 terrorist attacks should lead to growth of near 4% in the first quarter and the full year, which would surpass earlier estimates and recent Federal Reserve forecasts."

Wyss said that the economy expanded at an upward-revised 1.4% annual rate in the fourth quarter of 2001 and "continued to accelerate" this year.

Wyss admits that although "a dip back into recession is possible," it is not likely-unless set off by an outside event: "Unfortunately, the probability of another terror attack or an oil price surge caused by Middle East violence remains very high. Oil prices have firmed, but this reflects expectations of economic recovery and the start of the summer driving season more than worries about embargoes or revolutions," he said.

Government Developments

APPARENT HIGH BIDS totaling $363.2 million were offered for 506 offshore tracts at Lease Sale 182 for the central Gulf of Mexico, the US Minerals Management Service reported Mar. 19. A detailed sale analysis will appear in next week's issue.

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MMS officials received 697 bids totaling $442.4 million from 69 companies the sale. That was down from 780 bids totaling $663.4 million submitted by 90 companies for 547 tracts during the last central gulf lease sale nearly a year ago. High bids in that previous sale totaled $505.5 million.

There was a more even mix of major integrated companies and independents participating in the sale, however, analysts reported. Independents seemed to dominate lease sales last year for both the central and western gulf.

MMS Mar. 18 proposed a 2002-07 offshore lease sale schedule that closely resembles a preliminary plan the agency announced last October.

The schedule does not propose a sale in any area currently under congressional spending moratoriums or presidential withdrawals. Those areas are off the East and West coasts and in parts of the eastern Gulf of Mexico (OGJ Online, Oct. 26, 2001).

The proposed final program schedules a total of 20 lease sales in eight Outer Continental Shelf planning areas located off the Gulf Coast states and Alaska, carrying forward the provisions of the previous proposals with one adjustment.

MMS revised its proposal for two lease sales in the Chukchi Sea-Hope basin area off Alaska. That area has been adjusted to convert those sales to the "special" category that originally was devised for the Norton Basin Planning Area, MMS said. MMS now plans to issue a request for interest in May, and if industry interest is not expressed, the sale process ends. If there is sufficient interest, MMS plans to proceed with the remaining steps leading to holding the sale.

The same procedures will be followed the next year and annually until one or both proposed sales are held or the 2002-07 program ends.

About 84% of federal oil and gas revenues are produced from OCS leases, according to MMS. US officials estimate MMS will collect about $4.2 billion in revenues next year from minerals, mostly oil and gas, produced from offshore and onshore federal and Indian lands.

As required by law, MMS's 5-year proposal will be submitted to Congress for review.

Speaking before the National Ocean Industries Association, Interior Sec. Gale Norton said oil and gas produced from the OCS represents one fourth of US production. She said the leases under the new sale schedule will make available postulated resources totaling 10.2-21.5 billion bbl of oil and 40-60.6 tcf of natural gas.

Quick Takes

TOTALFINAELF SA leads production news with production start ups in Venezuela and off Iran.

First production of "Zuata Sweet" syncrude has been reached from the $4.2 billion Sincor project in Venezuela. TotalFinaElf holds 47% interest in Sincor; other partners are Venezuela's Petroleos de Venezuela SA 38% and Norway's Statoil 15%.

Sincor-formerly known as Sincrudos de Oriente Sincor CA-operates the project, which produces 8.5° gravity crude, transporting it by a 200 km pipeline to Jose on the Carribbean coast, and there upgrading it to a 32° gravity crude for export (OGJ, Oct. 29, 2001, p. 47). Sincor is one of the four world-class integrated heavy oil projects in Venezuela's Orinoco oil belt.

At peak production, the project is expected to produce 200,000 b/d of heavy crude, which in turn will be upgraded into 180,000 b/d of syncrude.

First shipments of Zuata Sweet are slated for the end of March from Jose terminal to TotalFinaElf's Port Arthur, Tex., refinery. More regular deliveries, said TotalFinaElf, will begin in April and will increase over time.

Meanwhile off Iran, TotalFinaElf has brought on stream Phases 2 and 3 of the South Pars natural gas development project in the Persian Gulf. Development costs for the field, which lies in 70 m of water, reached a total of $2 billion.

Production from Phases 2 and 3 is expected to plateau at 2 bcfd of gas and 80,000 b/d of condensate from 20 wells, which are tied into two unmanned platforms, TotalFinaElf said. Gas and condensate from the field will be transported via two 32-in., 105 km pipelines to be treated onshore at the Assaluyeh gas processing facility.

Gas produced from the South Pars project will be used in Iran, while condensate will be sent to an offshore buoy for export. However, BP PLC, National Iranian Oil Co., and India's Reliance Industries Ltd. last year agreed to begin a $10 million feasibility study of an LNG project in southern Iran based on South Pars gas. The study will evaluate a proposed two-train, 8 million tonne/year plant.

Phases 2 and 3 operator TotalFinaElf holds 40% interest in both latter phases of the South Pars field development project. Partners are Russia's OAO Gazprom 30% and Malaysia's Petronas 30%. Phase 1 of the South Pars development project is being undertaken by Iran's state-owned Petro Pars.

In Norwegian production news, Statoil ASA awarded contracts totaling 12 billion kroner ($1.36 billion), including options, to three companies for maintenance and modifications of installations on the Norwegian continental shelf and at the Kollsnes gas treatment complex near Bergen. Aker Offshore Partner AS was awarded a contract for the Tampen complex in the North Sea, while ABB Offshore Systems AS was given the contracts covering the Troll-Sleipner complex in the North Sea and the Kollsnes gas plant. The contract for the Halten-Nordland complex in the Norwegian Sea went to Aker Reinertsen, a joint venture of Aker Maritime ASA and Reinertsen AS. Plans call for the contracts to be signed in March. They run for 5 years initially, with three consecutive options to extend by 2 years. Tampen alone represents half the contract amount, while the remainder is shared equally between Troll-Sleipner and Halten-Nordland. With that round of tenders, Statoil is reducing the number of maintenance and modifications contracts to three in its Norwegian exploration and production unit from eight initially.

THE SAKHALIN I CONSORTIUM plans to build an advanced, special-purpose rig to drill extended-reach wells to offshore targets from a land-based site on Sakhalin Island, Russia.

Consortium leader ExxonMobil has two contracts with Parker Drilling Co., Houston, to build and operate the rig. A Parker subsidiary will design and build the rig and transport it to Russia. A second Parker subsidiary will operate the rig on Sakhalin Island. Rig construction is expected to be completed by midyear.

Parker Drilling Pres. and CEO Robert L. Parker Jr. said the Sakhalin rig will be engineered exclusively for this project and will be "the most sophisticated land drilling rig in the world, designed to withstand earthquakes and operate in the frigid winters where ice covers the Sea of Okhotsk for 6 months of the year."

The Sakhalin I, Phase 1 project will be an oil-only development with a peak production target of 250,000 b/d. (OGJ, Aug. 13, 2001, p. 35).

Parker Drilling Co. will build a rig to drill extended-reach wells off Sakhalin Island. Illustration from Parker Drilling.
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Although Phase 1 is an oil-only project, marketing of future gas production from the Sakhalin I blocks continues. Japan, China, and Russia have expressed interest in purchasing the gas.

Development planning activities are progressing, and startup is likely by yearend 2005. Exxon Mobil has 30% interest in the project through its subsidiary, Exxon Neftegas Ltd., operator for the consortium, and estimates the total Phase 1 project investment to be $3.7 billion.

The Japanese company Sakhalin Oil & Gas Development Co. Ltd. has a 30% interest, and Russian companies Sakhalinmorneftegas-Shelft and Rosneft-Sakhalin have a 23% and 17% interest in the project, respectively.

NORTHWEST CHINA geological studies are progressing.
China Petroleum & Chemical Corp. (Sinopec) and Royal Dutch/Shell Group plan to complete in April a geological study of five blocks that are prospective for oil and gas in northwestern China's Tarim and Ordos basins.

The study, which started last year, is part of the strategic partnership between the two companies that was formed when Shell invested in Sinopec's initial public offerings last October.

Two of the blocks in the Ordos basin, bordering the Inner Mongolia Autonomous Region and Shaanxi province, have potential for medium-sized gas fields.

In the northern Tarim basin, the companies are studying geological data on three blocks, one of which is thought to contain gas and condensate. Of the other two Tarim blocks, chances are high for confirming significant crude reserves, government sources said.

After completion of the study, the two companies will decide whether to enter into production-sharing contracts to further explore and develop hydrocarbons on the five blocks. Sinopec's possible joint venture with Shell is subject to government approval.

Currently, Sinopec unit Sinopec Star Petroleum Co. Ltd. is producing oil and gas in the Tarim basin. In January, Sinopec Star produced 220,400 tonnes of crude, up 44% on the year. The bulk of Sinopec Star's Tarim basin crude production is from Tahe field.

In other exploration news, the Oman Ministry of Petroleum granted TotalFinaElf an exploration and production-sharing agreement in which TotalFinaElf will take 100% interest and become the operator of Block 34. The block is in southeastern Oman and covers 11,500 sq km. The exploration agreement calls for successive phases, with the first 2 years dedicated to geological studies and to the acquisition and interpretation of seismic data. TotalFinaElf said the block strengthens its presence in Oman, where it is a partner on other projects with state owned Petroleum Development of Oman and Oman Liquefied Natural Gas.

A GTL commercialization study in Japan leads gas processing news.
Ivanhoe Energy Inc., Whitehorse, Yukon, has initiated a commercialization study in Japan to investigate opportunities for utilization of gas-to-liquids and NGL products that would be produced in Ivanhoe's proposed Qatar project.

The Qatar GTL project involves the development of gas reserves in an area of supergiant North field off Qatar and the transportation of produced gas to NGL and GTL plants having the capacity to convert the gas into 155,000 boe/d of NGL products and 185,000 b/d of GTL fuels.

The commercialization study will investigate the marketing and financial opportunities in Japan for the project. Ivanhoe initiated the study by signing a memorandum of understanding with Japan's Inpex Corp. and Mitsui & Co. Ltd.

LADYFERN SALES natural gas pipeline has been brought on stream.
Calgary-based Canadian Natural Resources Ltd. has completed construction and commissioning of the 20-in., 7.5 mile Ladyfern Sales pipeline, which will transport gas from the Ladyfern region of British Columbia to TransCanada PipeLines Ltd.'s Owl Lake South meter station in Alberta. The pipeline, which came on stream Mar. 8, has the capacity to deliver 600 MMcfd of gas.

The Ladyfern region, which contains one of the hottest natural gas plays in North America, is currently producing more than 500 MMcfd of gas and is thought to contain as much as 1 tcf of gas reserves (OGJ Online, Oct. 23, 2001).

Canadian Natural said that the pipeline's commissioning will enable the company to increase production of natural gas from the Ladyfern area to 215 MMcfd from 175 MMcfd.

Canadian Natural operates the Ladyfern Sales pipeline; other pipeline partners are Canadian Natural 39.4486%, Murphy Oil Co. Ltd. 14.4578%, Kaiser Energy Ltd. 11.6883%, Devon Canada Corp. 9.3233%, Talisman Energy Inc. 8.3333%, Alberta Energy Co. Ltd. 7.2289%, Apache Canada Ltd. 6.7420%, and Grey Wolf Exploration Inc. 2.7778%.

In other Canadian pipeline news, Pan Canadian Energy Corp., Calgary, has submitted to Canada's National Energy Board an application to build its Deep Panuke natural gas pipeline off Nova Scotia. The pipeline is part of a development project for the field, which is estimated to hold 1 tcf of gas about 250 km east of Halifax, NS, on the Scotian shelf. (OGJ, Mar. 18, 2002, Newsletter, p. 8). Deep Panuke, which underlies Panuke-Cohasset oil field, is the second major gas development on the Scotian shelf, following the Sable Island area gas fields development that went on stream in late 1999. NEB has yet to announce the procedures for dealing with the application, although PanCanadian has said regulatory hearings are expected to start in the fall. PanCanadian also filed with the Canada-Nova Scotia Offshore Petroleum Board. Both filings cover the technical aspects of the project, its economic benefits, the potential environmental and socioeconomic impacts, and public consultation. PanCanadian anticipates spending $1.1 billion (Can.) on the project, with operating expenses pegged at $60 million. The project involves the construction of platform-based gas processing facilities offshore as well as a subsea pipeline network to transport the gas to shore. Offshore, components will include three new bridge-linked platforms installed near the existing Panuke platform. About 179 km of 24-in. pipeline will carry gas from the platform complex to landfall at Goldboro, NS, where the system will tie in with the existing Maritimes & Northeast Pipeline system. Panuke will have a production design capacity of 400 MMcfd, expandable to 650 MMcfd. First gas is expected in 2005.

Valero Energy Corp. made an early start of the scheduled April turnaround of its 160,000 b/d Texas City, Tex., refinery after a problem with a utility company's electric power transformer forced an emergency shutdown earlier this month.

That unit was forced to shut down Mar. 6 when a Texas New Mexico Power Co. transformer lost power. But when refinery workers subsequently attempted to bring it back online, they experienced problems with the plant's electrostatic recipitator (ESP).]

An emergency order from the Texas Natural Resource Conservation Commission authorized Valero to operate the refinery without the ESP, but then the company realized it had experienced greater damage to the fluid catalytic cracker unit than had been originally estimated so it was not be possible to bring the FCCU up before the turnaround, a spokeswoman said.

The 55,000 b/d FCCU originally was scheduled for a 44-day turnaround, but the turnaround may be extended by 10 days or more for repairs, she said. The 30-day turnaround of the refinery's 7,000 b/d alkylation unit and the 22-day turnaround of its 90,000 b/d residfiner will also take place during the same period.

Correction

Bechtel Group was incorrectly reported as being the deepwater managing contractor on the Scarab-Saffron West Delta Deep Marine Concession (OGJ, Feb. 11, 2002, Newsletter, p. 9). A consortium of Bechtel and INTEC Engineering is the deepwater managing contractor for the project.