OGJ Newsletter

May 21, 2001
The latest IEA figures released show another drop in projected 2001 oil demand.

Market Movement

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IEA lowers global oil demand forecast, again
The latest IEA figures released show another drop in projected 2001 oil demand.

First quarter demand is estimated to have been well short of expectations, with nearly all of the shortfall in OECD countries. Just a month earlier, the Paris-based agency reported its estimate of first quarter worldwide demand at 77.3 million b/d; the figure has now been revised to 76.7 million b/d. The new estimates put demand growth for the year at 1 million b/d, down from 1.3 million b/d as IEA projected last month.

The drop in demand eased the call on OPEC for crude and allowed for an OECD stockbuild in the first quarter. This crude stock buildup was offset by a draw on product stocks, though, and IEA expects that crude inventories will dip as refiners increase runs following maintenance turnarounds and while both crack spreads and margins are strong by historical standards.

Supply reduction
IEA estimates show that first quarter 2001 OECD supply trailed output for the same period a year earlier by 500,000 b/d (see table). The bulk of the supply reduction was in Europe.

Non-OECD supply moved up vs. first quarter 2000 on the strength of production gains in the former Soviet Union. For the period, OPEC production climbed 2 million b/d from a year ago.

Preliminary estimates indicate that worldwide oil production dropped an average 900,000 b/d in April compared with March.

New, lower OPEC production quotas went into effect Apr. 1, calling for average output of 24.2 million b/d (excluding Iraq). IEA expects second quarter demand to drop sharply, so such a quota cut would appear well-timed, but for the month of April, actual OPEC production excluding Iraq is estimated at 24.9 million b/d.

Output by Iraq last month is pegged at 2.95 million b/d. Based on UN data, 2.25 million b/d of this was exported under the oil-for-aid program. The remainder was used for domestic consumption and border trade.

The current phase of the oil-for-aid program is set to expire June 3. The UN is expected to extend the program for another 6 months by the end of May, but export disruptions would not come as a surprise, if Iraq once again capitalizes on the occasion to renegotiate terms.

Venezuela's production moved 100,000 b/d lower last month as companies operating there were ordered to reduce output in line with OPEC's quota cut. In the Orinoco heavy oil belt, Venezuela has a resource postulated at 270 billion bbl of extra-heavy oil. Three joint ventures are already producing or upgrading this oil, and another is expected to start up late this year. In 2005, IEA reports, production from these four projects is expected to reach 700,000 b/d. This has called into question whether Venezuela's extra-heavy oil will be counted as crude and subject to OPEC quotas or else treated as bitumen and exempt from OPEC's output ceilings. Although Venezuela has lowered its production of extra-heavy oil in line with the Apr. 1 cut, it also reportedly has stated that the Orinoco crude is technically exempt from OPEC quotas.

Brazil's output is reported to have fallen to 1.3 million b/d in April from 1.35 million b/d just 2 months earlier, due to loss of the P-36 platform. To offset the production decline, Petrobras announced a plan to increase output at Marlim Sul field (OGJ, May 7, 2001, p. 22). IEA estimates Brazil's production will average 1.34 million b/d this year.

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Industry Trends

DESPITE A 150% INCREASE IN CAPITAL SPENDING TO $50.7 BILLION, RESERVE REPLACEMENT COSTS DROPPED 8% RO $4.73 BOE IN 2000 FOR THE TOP 50 E&P COMPANIES, according to John S. Herold.

The firm's annual survey said reserve replacement rates set records, with E&P companies replacing 272% of oil and 251% of gas production.

It said that was "an extraordinary achievement," demonstrating that the companies "spent lavishly yet wisely."

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It said the $30 billion jump in capital spending was fueled by a $20 billion increase in proved acquisitions and a $10 billion spurt in finding and development expenditures. BP was the biggest US spender at $12.7 billion, followed by Phillips Petroleum at $6.7 billion and Anadarko Petroleum at $6 billion. Despite the torrent of spending, US reserve replacement costs fell to a 5-year low. Finding and development costs dropped to $5.17/boe, while proved acquisition costs slipped to $4.38/boe (see chart).

REFINING MARGINS IN FRANCE NEARLY DOUBLED THE HISTORICAL AVERAGE LAST YEAR, leading to a "good but atypical" post-tax result of 6.7 billion francs for the country's refining-distribution sector, the president of the Union Française des Industries Pétrolières, Philippe Trépant, said.

Consumption of oil products, however, fell for the first time since 1993, by 1.8%, reaching 88 million tonnes, a drop explained by Trépant as the result of high oil prices.

"Refining margins, which reached the exceptionally high level of 191 francs/tonne-that is nearly double the average 100 francs/tonne margin observed over the 1996-99 period-essentially explain the industry's good 2000 results," he said. But he noted that, despite the easing of taxes on oil products introduced in October, consumption of oil products had been negatively affected by a crude price that had "trebled in dollars but quadrupled in francs." Only consumption of jet fuel escaped the effect of high oil prices.

Trépant said he was unwilling to forecast an outlook for the rest of the year "because of the market's too-high volatility."

One certainty facing the industry in the coming year, he noted, was the "long and costly process" of introducing the euro into France's 16,000 service stations and posting the new rates on 80,000 fuel pumps before Jan. 1, 2002.

The conversion is expected to cost industry 150 million francs, a figure that does not include training the work force and handling two currencies during the 9-month transition period.

Government Developments

US VICE-PRES. DICK CHENEY'S ENERGY TASK FORCE REPORT, UNVEIDED MAY 17, SEEKS TO CORRECT WHAT THE WHITE HOUSE CALLS "THE MOST SERIOUS ENERGY SHORTAGE SINCE THE OIL EMBARGOES OF THE 1970S."

Senior White House officials said the document is a broad blueprint that Congress and policymakers will build on in the coming weeks, although no specific timetables have been set.

Senate Committee on Energy and Natural Resources Chairman Frank Murkowski (R-Alas.) pledged he will push the Senate to pass bipartisan energy legislation this summer that will include many, if not all, of the report recommendations.

Report proposals that need congressional action include gaining access to the coastal plain of the Arctic National Wildlife Refuge, passing comprehensive electricity restructuring legislation, crafting "multipollutant" legislation to establish a market-based program to reduce power plant emissions, and expanding tax credits for hybrid electric cars.

As expected, the report does not call for expanded tax incentives for marginal wells. However, pending Senate Republican and Democratic energy bills seek to encourage domestic production through more-favorable tax treatment. Democrats, however do not support ANWR drilling, and some are calling for more active use of the Strategic Petroleum Reserve when oil prices are high.

The White House does not advocate drawing down the SPR absent a sudden supply shock.

Also absent from the report is a call to reduce or suspend the 18.4¢/gal federal excise tax on gasoline. Some lawmakers support reducing the tax as a fast way to reduce record high retail gasoline prices. But congressional leaders have so far resisted the idea.

Actions the administration will execute right now include two executive orders: the first will direct all federal agencies to consider what impact a major regulation may have on energy supplies; the second will direct federal agencies to expedite permits and coordinate federal, state, and local actions necessary for energy-related project approvals nationwide.

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Other items President George W. Bush is advocating include encouraging agencies to speed up a USGS inventory of possible oil and gas reserves on federal lands, directing US EPA to consider ways to regionalize reformulated gasoline programs, and asking IEA to encourage countries to supply more-accurate energy data. The White House also endorsed ongoing Interior plans to hold a lease sale in the eastern Gulf of Mexico this December and to expand leases in the National Petroleum Reserve-Alaska.

With regard to foreign policy, the report seeks better communication with Congress on what role trade sanctions play in US foreign policy. The White House does not address under what conditions it would be willing to retool or eliminate existing sanctions against Iraq, Iran, and Libya, although the state department is expected to move forward with a "smart" sanctions policy next month.

The White House report also does not offer any specific recommendations on how to convince OPEC to "increase the spigot," as characterized by Bush when he was running for president last year.

Rather than campaign publicly for production increases, the White House prefers "quiet diplomacy," a senior administration official said.

Quick Takes

SOME NEWLY PROPOSED NATURAL GAS PIPELINE PROJECTS COULD EASE THE GROWING DEMAND FOR GAS-FIRED ELECTRIC POWER GENERATION IN THE US WEST.

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Most recently, Kinder Morgan Energy Partners and independent power producer Calpine announced plans to jointly develop a 1,160-mile, $1.7 billion high-pressure pipeline that would deliver gas to California from the San Juan basin in New Mexico (see map).

The proposed Sonoran interstate natural gas pipeline project will have a maximum capacity of 2.5 bcfd and will be evaluated and developed in two phases, both subject to FERC jurisdiction. Sonoran plans to use existing right-of-way corridors as much as possible to minimize potential environmental impact, the companies said.

Phase 1 of the project will consist of 460 miles of 36-in. pipeline originating from interconnects with TransColorado Gas Transmission, Transwestern Pipeline, and various points at the Blanco Hub in San Juan County, NM, near the Colorado-New Mexico state line. The pipeline will continue westward with delivery points on the California-Arizona border near Needles with a 20-mile, 24-in. lateral to Topock. The line will initially transport up to 750 MMcfd and can be expanded with compression to transport up to 1 bcfd. The first phase of the pipeline is expected to be completed in the summer of 2003.

Phase two will consist of 590 miles of 36-in. and 42-in. line continuing from Needles on the California border to points within California, terminating near Antioch in Contra Costa County. Depending on shipper interest, Phase 2 will transport 1-1.5 bcfd.

Meanwhile, federal regulators earlier this month issued El Paso Corp. unit El Paso Natural Gas a certificate to operate a pipeline that will provide 230 MMcfd of gas capacity to serve California and the southwestern US.

The California project involves a $154 million conversion of 785 miles of an existing crude oil transmission pipeline to gas. The extra pipeline capacity will serve existing customers when other parts of the El Paso system are down for maintenance, El Paso said.

The converted pipeline would begin near the California border at Ehrenberg, Ariz., and extend to McCamey, Tex. The project is scheduled to be operational in the fall.

In addition, El Paso Corp. is considering building a new intrastate gas pipeline in California that will run from Bakersfield north towards Antioch and Sacramento. The company also is gauging customer interest in an expansion of the existing Mojave Pipeline that runs from Topock to Bakersfield.

El Paso is holding open seasons for both projects until May 31. The Mojave Pipeline expansion and extension could interconnect with El Paso Natural Gas, Transwestern Pipeline, Kern River Pipeline, Lodi Gas Storage, and California gas producers, the company said. Depending on the result of the open season, El Paso will file applications with FERC to build the proposed new pipeline and pipeline expansion, it said. The projects will also require environmental assessments and other local and state California permits.

Also in the west, Southern California Gas plans to boost its California pipeline capacity by another 200 MMcfd of gas with the planned construction of a 32-mile pipeline link to the Kern-Mojave pipeline. Completion of the project-referred to as the Kramer Junction Interconnect-is expected by yearend.

Combined with a previously proposed expansion, SoCalGas said it will boost system capacity by a total of 11%. Earlier, the company said it would modify parts of its transportation system to add 175 MMcfd, a 5% increase, by winter. Those efforts are now under way. The project will be installed adjacent to the existing utility corridor, the company said. Supply on the Kramer expansion at Adelanto will be transported both south and west through SoCalGas's existing transmission facilities.

DEVELOPMENTS IN GAS-TO-LIQUIDS TECHNOLOGY HAVE HEATED UP IN RECENT WEEKS.

Conoco announced plans to build a $75 million demonstration plant in Ponca City, Okla., to commercialize the company's proprietary GTL technology.

Converting natural gas into liquids could enable economic development of stranded gas reserves estimated at more than 4,000 tcf worldwide, the company said.

Jim Rockwell, Conoco GTL manager, said his company's technology is at the point where a full-scale plant is economical: "Building the demonstration plant will enable us to gather the engineering data required to design a much larger commercial plant," he said.

A team of 80 scientists and engineers, who have been researching gas-conversion technologies since 1997, has designed, manufactured, and tested various reactor configurations and more than 4,500 catalysts.

GTL technology has the potential for widespread environmental benefit because it produces fuels such as methanol and sulfur-free diesel that could displace less-efficient, higher-emission fuels, Conoco claimed. Slated for completion in September 2002, the demonstration plant will convert gas into 400 b/d of sulfur-free diesel, jet fuel, and other products. After proving its low-cost GTL technology, the demonstration plant will test new gas-conversion and petrochemical technologies. Conoco expects to begin construction of its first commercial GTL plant by 2004.

Meanwhile, Syntroleum and Norway's Petroleum Geo-Services agreed to form a joint venture to develop, market, and operate mobile marine production facilities based on Syntroleum's proprietary GTL technology.

The proposed JV, to be based in Aberdeen, will offer contract GTL services to convert otherwise stranded natural gas from offshore fields into marketable hydrocarbon products.

Syntroleum, in association with UK-based AMEC, has been conducting engineering and design work for the floating systems for a number of months. "The mobility of floating facilities will permit their use at multiple locations, thereby providing access to fields that are otherwise too small to justify permanent GTL facilities," Syntroleum said. The company said those proposed GTL facilities will be useful for small associated gas fields, monetization of gas caps, short-term use as an early production system, and as a long-term solution for offshore gas in a range of water depths.

Statoil will spend 3 billion kroner ($330 million) on a plan to boost compressor capacity on its workhorse Troll field in the Norwegian North Sea by using more electric power from the mainland, it said.

The scheme-which will ultimately employ four compressors to offset declining reservoir pressure at Troll-is scheduled to start in 2005-06 at the field. Troll is responsible for around 35% of gas delivered from the Norwegian Continental Shelf to Europe.

Along with its field partners, operator Statoil decided that, of the two options studied-electric power transmitted from land to the Troll A platform or power generated by the field's own gas production-the first option was the best solution "based on financial and environmental considerations." Statoil noted that the fieldwide solution opted for is an expansion of current operations at Troll A-the only platform on the NCS powered by mainland electricity.

The electricity-based scheme, to be submitted to the Ministry of Petroleum and Energy at yearend, calls for the addition of new power cables running from the mainland to field's A platform, along with the added compressors.

TWO US INDEPENDENTS HAVE STRUCK AN EXPLORATION AGREEMENT IN THE GULF OF MEXICO.

Kerr-McGee and Ocean Energy agreed to jointly explore 181 undeveloped leases that Kerr-McGee holds in the deepwater Gulf of Mexico. Under the deal, Ocean will acquire working interests in the leases of 16.67-50%, while Kerr-McGee will retain working interests of 33.33-50%. The leases are in several proven trend plays in water depths up to 8,000 ft.

The two companies expect to drill 15 wildcats in the next 3-4 years on the leases, with Ocean paying a disproportionate share of drilling costs. Kerr-McGee will remain the operator for 75% of the prospects it currently operates, and Ocean will operate the rest. Kerr-McGee said the agreement is an integral part of its exploration program that includes drilling 8-10 deepwater gulf exploratory wells/year.

Kerr-McGee holds interests in more than 140 additional deepwater leases in the gulf not covered by the agreement. The first wildcat under the agreement is expected to spud by the end of the second quarter at the Red Hawk prospect on Garden Banks Block 877.

In other exploration news, BP Trinidad & Tobago said its Cashima-1 well off the east coast of Trinidad has found more than 1 tcf of gas. The well, 2.5 miles east of Flamboyant field, is the first of four planned this year. Cashima, in 263 ft of water, was drilled to 13,160 ft MD. It found 520 ft of gas-bearing sand in four pay horizons, said BP. This year, BP plans to drill two more exploration wells on the shelf and one in deep water, on Block 27. It will also drill an appraisal well in Red Mango field.

Petrobras discovered 22° gravity oil on Santos basin Block BS-500 in 1,498 m of water. The discovery was off Rio de Janeiro state, 170 km from the city of Rio de Janeiro. The well was drilled to 4,528 m, with oil shows in several zones at 2,524-4,210 m. Oil was discovered on Block BS-500 in 1999 with the 1-RJS-539 well, but commercial quantities were not proved at that time, despite additional seismic work and the drilling of two wells. Petrobras plans to intensify its exploration activities in the region with a drilling platform available to operate exclusively on Block BS-500.

OIL COMPANIES HAVE MARKED MILESTONES IN ALTERNATE FUELS DEVELOPMENT.

Southern Pacific Petroleum and Central Pacific Minerals have made their first shipment of shale oil products from the Stuart Project near Gladstone, Queensland.

More than 40,000 bbl of medium shale oil was exported May 9 from Australia bound for the Southeast Asia fuel oil market.

The shipment marked the first revenue from the project and followed a successful run of production in April when more than 35,000 bbl of oil was produced.

SPP and CPM assumed operatorship of the Stuart plant from Canada's Suncor Energy earlier this year.

The operators plan to produce 200,000 b/d of shale oil by 2012. That would include 85,000 b/d of production from the fully developed Stuart Project Stage 3 by 2009 (OGJ Online, Apr. 30, 2001).

Both companies expect to reach a financial break-even point from Stage 1 production by moving to continuous production at the demonstration plant during the second half of the year and moving into the commercial Stage 2 in 2002.

Elsewhere in the realm of alternate energy, TotalFinaElf signed a codevelopment agreement with Delphi Automotive Systems to research and test fuel cell technologies and fuel reformation. Delphi, a mobile electronics and transportation systems technology specialist, said the partnership will study the effect of fuel composition and additives on the performance of fuel-reforming devices. Initial studies will focus on the use fuel cells for gasoline, then diesel, heating oil, and LPG. Research and testing will take place at Delphi's Rochester, NY, technical center and at TotalFinaElf's European facilities.

AN ULTRADEEPWATER DRILLING RECORD HAS BEEN CLAIMED IN THE GULF OF MEXICO.

Transocean Sedco Forex Inc.'s Discoverer Spirit drillship. Photo from Transocean.
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Transocean Sedco Forex, while drilling for Unocal in the gulf, said its Discoverer Spirit drillship set a world record for ultradeepwater drilling by spudding an exploration well in 9,687 ft of water. Blowout prevention equipment was installed and tested after the May 2 spud, and drilling operations are under way. The exploration well, on Unocal's Trident prospect on Alaminos Canyon Block 903, beat a record of 9,157 ft of water off Gabon set earlier this year (OGJ On- line, Apr. 26, 2001). The Discoverer Spirit uses Transocean's proprietary dual-activity drilling process. Transocean has drilled three deepwater exploration wells in the Gulf of Mexico for Unocal, in which the two companies used internal benchmarking to develop a detailed plan for each well.

This special analysis of the IEA's Oil Market Report and its effects on the international oil market was provided by Marilyn Radler, Economics Editor.