OPEC excess in 'strong hands'
The Saudis' proposed further production increase of more than 500,000 b/d will likely do more than ease world oil prices. It should also lift the veil to reveal just which nations within OPEC actually have any excess capacity to spare.
So says Merrill Lynch in a recent report, claiming that only two OPEC member nations, Saudia Arabia and the UAE, have any capacity to spare and thus will serve as the "key to stabilizing oil prices above $20/ bbl.
"With the rest of OPEC at or near capacity limits, Saudi Arabia and the UAE will be in a strong position to manage oil prices," Merrill Lynch said. "The Saudis are in the best position since 1983 to manage the oil supply-demand balance."
However, the analyst notes, the latest production hike would be quickly reversed if oil prices again approach $22/bbl.
Gasoline prices ease
The prospect of increasing oil production has had an effect on the US gasoline market, despite the fact that the added crude volumes have not actually arrived yet.
US Energy Sec. Bill Richardson noted that fact last week as US gasoline prices fell for the fifth week in a row, particularly in the Midwest.
"Crude oil prices have also dipped, but more importantly, stocks are beginning to rebuild," he said. "There is 3.5 million bbl [more] of oil on the market since this time last year. All of these factors will restore the balance between supply and demand and help sustain economic growth."
Richardson urged Congress to pass tax incentives to increase domestic oil and gas production, alternative energy sources, and energy efficiency.
"It needs to pass the Energy Policy and Conservation Act to give us a workable trigger for a regional home heating oil reserve, reauthorize the strategic petroleum reserves, pass these tax incentives, and fully fund our energy programs."
FTC: Gasoline price report not definitive
As OGJ went to press last week, the US Federal Trade Commission had announced that it would issue to Congress within days a preliminary report that examines the gasoline price spikes that occurred last month in the Chicago and Milwaukee areas.
Richard Parker, head of the FTC's price-fixing investigation, briefed the Senate energy and natural resources committee about the inquiry during a recent hearing. He warned the senators that the interim report would not be definitive, saying, "I don't want to hold out too much expectation as to conclusions." The investigation won't be completed for another 6 months.
Parker said, "Chicago, Milwaukee, and other places, principally in the Midwest, have suffered particularly severe recent price increases that cannot be explained solely" by crude oil price increases.
He said, "We do not regulate or attempt to determine the reasonableness of energy prices. Instead, we investigate whether or not specific anticompetitive and unlawful conduct has occurred that interferes with the operation of the free market.
"Thus, our investigation will not determine whether prices are too high or too low but only whether there is reason to believe that the antitrust laws have been broken."
The FTC issued subpoenas to operators of refineries, pipelines, terminals, and blending plants in the Midwest.
"Our staff also has begun conducting interviews with market participants, consumers, corporate users of gasoline, and others with potential knowledge of relevant facts. The objective is to determine who raised prices and whether there was any illegal contact, communication, or signaling among competitors before or during the time of the price increases."
Oil and gas E&D spending should improve through the second half into 2001, after plummeting 22% to $62 billion worldwide in 1999-including a 29% drop in US upstream spending to $25 billion-says Arthur Andersen, citing its survey.
Operators have been loath to boost outlays despite rising revenues, profits, and cash flow.
Worldwide upstream capital spending declined 5% to $92 billion in 1999, with decreases recorded in virtually all categories. The biggest was drop shown in global exploration spending, down 34% to $13.4 billion, according to the survey.
US producers are responding to higher natural gas prices with increased drilling, according to the Natural Gas Supply Association.
So says NGSA Pres. Skip Horvath, adding, in Senate testimony, "We are confident that natural gas [supplies] will meet winter market demand (see related story, p. 20)."
US gas demand has grown in recent years, he said, while consumers' gas service costs have declined, in real terms, from $4.10/ MMbtu in 1983 (under government-regulated prices) to $3.05/MMbtu in 2000 (1998 dollars) under competition.
Tight supplies today are due in part to E&P budget cuts spawned by the collapse in oil and gas prices in 1998-99, he noted.
"Today, producers are individually responding to the market. The number of active natural gas drilling rigs is up 90% from April 1999, and 75% of the active US drilling rig fleet is engaged in drilling for natural gas. Thus, the supply of natural gas is expected to slowly increase."
Horvath warns that, if the government reimposes price controls, it could create a gas shortage: "Free markets have not always been allowed to work for natural gas, and consumers have suffered the consequences."
Mobile rig Utilization has hit a 2-year high in the Gulf of Mexico, Offshore Data Services reports.
Meanwhile, MMS reports a record 34 rigs working in the deepwater gulf, vs. 26 a year ago, and that record is likely to fall this year. Independents are drilling 13 of those deepwater wells.
Of the 204 total rigs available for work in the gulf, 175 are now under contract-4 more than the previous week-for a utilization level of 85.9%, says ODS. Rig utilization in European waters remains at 87.3%, with 89 rigs contracted.
Worldwide, 5 more offshore rigs were working, boosting total utilization to 83.3%, with 535 mobile offshore rigs under contract.
THE PICKUP IN NORTH SEA DRILLING is luring back drilling contractors previously put off by high costs.
Rowan is planning to return there and is building a new office and warehouse in Aberdeen, even though it probably won't have a rig working there for a year, says Chairman and CEO Bob Palmer.
"The North Sea is a real problem and a real enigma," he said. "It's a high-cost place to operate. It's got all kinds of regulatory barriers that cause things to slow down, which translates again into higher costs.
"The North Sea is dominated by the majors and supermajors. They have a much longer budgetary process. Well approvals sometimes take 2-4 years to work their way through the system." Currently, Palmer says, there are six jack ups in the North Sea without contracts, many with contracts that face renewal before yearend.
MEXICAN ENERGY SECTOR REFORM is high on the agenda of Vicente Fox, the country's new president-elect.
His transition team has signaled plans to seek a further opening to private investment in Mexico's energy sector (OGJ, July 24, 2000, Newsletter, p. 7).
Top economic adviser Luis Ernesto Derbez says Fox's first priority would be to push for reforms in Mexico's woefully undercapitalized electricity and petrochemical sectors: "We are reviewing all the legislation both in the electricity and petrochemical sector to later take proposals to Congress for their approval," he said.
Although few details are available, the incoming administration's plans on the electricity sector appear similar to Pres. Ernesto Zedillo's 1999 congressional initiative, which withered for lack of support. Both the CFE and LFC would remain in state hands, but new generation capacity would come from private investment.
Derbez said the Fox proposal would allow investors complete access to sell energy to the national network through an "autonomous and automatic" pricing scheme.
As for getting the proposals through the new Congress, in which Fox's PAN will need the support of the PRI or PRD parties, Derbez said, "We hope that, by clearly stating that this is not a sell-off of assets, Congress will be disposed to find a way for Mexico to obtain the necessary energy at adequate prices for the population."
However, it's an open question whether Fox will have the political clout to undertake further reforms in Pemex. Michelle Michot Foss, director of the Energy Institute at University of Houston's College of Business Administration, says the political scenario precludes any major changes in Pemex.
"Changing the ownership structure of Pemex, its role as a state company, that's off the table," said Foss. "But how Pemex is managed and the way they do things, certain aspects of their capital budgeting, the types of contractual relationships they're allowed to make, that might be fair game."
Foss also pointed out that the trend toward decentralizing government decisions in Mexico, which Fox and the PAN support, could lead to more influence by state and municipal governments in energy projects: "You could see some of these northern states in particular wanting to have some say in how projects in their states, like pipelines and gas distribution systems, are set up for bidding, how bids are handled, and how the projects are managed."
Juan Quintanilla, an energy specialist at the Universidad Nacional Autónoma de México, thinks Fox will almost certainly aim to reduce Pemex's tax structure as part of an overall national tax reform. The government depends on Pemex for over 30% of its annual budget, leaving the company with precious little investment capital.
Fox's first major energy decision will be to pick a new energy secretary, to be named along with the rest of the cabinet before September. Current Energy Sec. Luis Téllez is a strong candidate to retain his post under Fox. F
StatOIL's development plans are firming up for Kristin gas-condensate field off Norway.
Statoil has chosen a semisubmersible production platform as its "principal option" to develop Kristin, located in the Haltenbanken area of the Nor- wegian Sea (see map).
But Kristin's partners plan to continue evaluating alternative approaches for their discovery, part of the four-field South Halten- banken complex. A final plan will be submitted to authorities in May 2001, and first contracts could be awarded at yearend 2001, with an eye to start-up in fall 2005.
Under the currently preferred plan, Kristin gas would be partially processed on the platform before being piped to the group's Kårstø treatment complex north of Stavanger. Unstabilized condensate would be transferred to Statoil's nearby Åsgard A FPSO for processing and transport. Kristin contains about 40 billion cu m of gas and 250 million bbl of condensate, and Statoil pegs the cost of developing Kristin at 12-14 billion kroner.
In other development action, Phillips will proceed with first-phase development of Peng Lai 19-3 field on Block 11/05 in China's Bohai Bay. Phillips has two new oil discoveries on the block, bringing its total discoveries there to six-plus several large additional prospects. Phillips plans to begin production in first quarter 2002 at an estimated gross rate of 35,000-40,000 b/d of oil. To fully integrate the knowledge gained from the reservoir performance in Phase I, Phillips plans to start production from Phase II in late 2004 or in 2005.
Burlington Resources and Talisman have submitted a development plan for MLN field on the Menzel Lejmat Block 405a in Algeria's Berkine basin. The companies, along with state oil firm Sonatrach, have applied for an exploitation permit for the block. Phase I development will concentrate on construction of a central production facility and an oil export pipeline. This phase is to produce an initial 16,000 b/d of oil by mid-2002 from the Triassic and underlying Devonian reservoirs. Phase I development is expected to cost about $150 million.
DEEPWATER WEST AFRICA EXPLORATION continues to yield successes.
Triton's Ceiba-5 appraisal well on Block G off Equatorial Guinea not only confirmed the primary oil pool found in the first four Ceiba wells but also encountered a deeper pool with an additional high-quality reservoir not seen in any of the previous Ceiba wells (OGJ, July 10, 2000, Newsletter, p. 8).
Ceiba-5 cut 243 ft of net oil-bearing pay in three zones. The new oil pool has an oil-water contact 328 ft below the oil-water contact of the primary Ceiba pool.
The well, drilled to 9,187 ft TD in 2,622 ft of water and about 1.75 miles northwest and 50 ft downdip of the Ceiba-3 well, has been temporarily suspended and will be brought on production after the first four Ceiba wells provide early oil.
Operator Triton holds an 85% working interest in Blocks F and G, while Energy Africa holds the remaining 15%.
Topping other exploration news, US MMS issued the final notice of sale for Western Gulf of Mexico Sale 177, planned for Aug. 23 in New Orleans. The sale will offer 3,789 blocks totaling about 20.61 million acres off Texas and Louisiana. The tracts are 9-200 miles offshore in water depths of 8 m to more than 3,000 m. Of the blocks, 1,814 are in less than 400 m of water and will carry 16 2/3% royalty rates. Another 315 blocks in 400-800 m and 1,660 blocks in over 800 m of water will have 12½% royalty rates. A total of 2,152 blocks in more than 200 m of water will be eligible for deepwater royalty relief. Perth's Norwest Energy acquired a farmout on Exploration Permit 364 in Australia's Carnarvon basin, inshore from Chervil and Saladin oil fields. Norwest will earn a 10% interest from operator Tap Oil and Australian Worldwide Exploration in exchange for funding a wildcat, Lindsay-1, in the fourth quarter. The prospect is a basal Cretaceous stratigraphic-structural play on the eastern shelf margin of the Barrow sub-basin identified by a large seismic amplitude anomaly. It is a shallow-depth (510 m), shallow-water (14 m) prospect. Tap currently owns a 55% stake in EP-364 and AWE, 45%.
Texaco began commercial production of oil and gas from the Petronius project in 1,754 ft of water on Viosca Knoll Block 786 in the Gulf of Mexico.
Installation of the Petronius platform, 130 miles southeast of New Orleans, was completed in early May for operator Texaco and 50-50 partner Marathon (OGJ Online, May 5, 2000).
The project was once expected to be on stream in early 1999, but a module was lost overboard in late 1998 and had to be rebuilt. Current production from two wells is 8,700 b/d and 6 MMcfd. Another three predrilled wells will be brought on production over the next 3 months, leading to output of 40,000 b/d and 35 MMcfd by October.
Additional wells will be drilled and brought on line during 2000-01, says Texaco. Output is expected to peak at 50,000 b/d of oil and 70 MMcfd of gas. Operator Texaco and its partner, Marathon Oil, each hold a 50% working interest in the project.
In other production news, operator Elf Qatar let a multimillion-dollar contract to National Petroleum Construction Co. of Abu Dhabi for engineering, procurement, installation, and commissioning the second phase of expanding crude oil production capacity at Al Khalij Block 6 field off Qatar to 60,000 b/d. The contract covers three platforms and about 31 miles of 10, 16, and 20-in. pipelines linking the platforms to the Halul processing and loading terminal; a subsea power cable; and modifications to existing facilities. MMS and Wyoming offered to sell about 6,600 b/d of royalty crude from federal and state leases in the Bighorn and Powder River basins; it is the fifth federal-state royalty in-kind (RIK) test sale program. The most recent sale offered 4,900 b/d for production from April through September. Bids will be accepted on specific pipeline subgroups and entire packages of Wyoming sweet, sour, and asphaltic-sour crude. Delivery will begin Oct. 1 and continue for 6 months. In another RIK test program, MMS earlier said it would begin taking its royalty share of gas production from leases connected to the Matagorda Offshore Pipeline System in the Gulf of Mexico. The MMS will offer about 25 MMcfd of gas for 3 months beginning Aug. 1.
Gaz de France is to open up its transport and distribution network to eligible customers Aug. 10, when the EU directive on gas deregulation takes effect.
GdF will not await parliamentary approval of the French draft law transposing the directive into national legislation, a process delayed because of other pressing parliamentary business.
Eligible customers will be able to choose their own supplier for natural gas shipped via GdF's transport network. In this first phase, those eligible account for about 20% of France's gas market: all electricity producers except cogeneration, whatever the consumption level; and all clients that consume more than 25,000 cu m/year/site.
In other happenings on the pipeline front, Russia's state oil pipeline operator Transneft is prepared to offer financial incentives to companies that pledge to export Caspian area oil production through the Baku-Novorossiisk pipeline. A number of foreign oil firms working in the Azeri sector of the Caspian Sea, including BP and ExxonMobil, refuse to send their oil to Novorossiisk, claiming Transneft's tariffs are too high. But the Russian pipeline operator says it would be willing to reduce its fees in exchange for a commitment to export at least 7 million tonnes/year of oil through the line. Transneft currently charges $15.67/tonne of oil shipped from Baku to Novorossiisk, which now includes a 194-mile bypass line through Dagestan. The bypass was built to replace the old middle section of the pipe, which passed through Chechnya. Meanwhile, Russia's Federal Energy Commission has granted Transneft permission to raise its tariffs by 12.2%, on average, in order to cover the $140 million cost of building the bypass. Cross Bay Pipeline, owned by Williams, Duke Energy, and KeySpan, filed with FERC to increase natural gas deliveries into New York City by 125 MMcfd. At a cost of $59.5 million, the project will include transfer of about 37 miles of Williams's existing Transco lower New York Bay extension to Cross Bay; construction of a 16,000-hp compressor station in Middlesex County, NJ; pipe replacement; and system modifications. The Cross Bay facilities will form a new interstate pipeline system that extends from Middlesex County across lower New York Bay to Nassau County, NY, and has a total capacity of more than 600 MMcfd. Construction is to begin in July 2001, with an in-service date of Dec. 1, 2002.
TransCanada sold its 49% interest in the Tuscarora transmission pipeline to TC PipeLines. The line ships up to 111 MMcfd of natural gas from Malin, Ore., to Reno, Nev. TC is a limited partnership one-third owned by TransCanada, which will retain a 1% interest in the line; Sierra Pacific Resources controls the remaining interest. Chemical firm Orica sold its 1,375-km Moomba-Botany ethane pipeline for $124 million as part of its move to quit the noncore plastics industry. The proceeds will be used to repay debt. The line was bought by a group of Uni-Super, National Australia Asset Management, and John Lang Investments. It will continue to transport ethane under a long-term contract to the Qenos plant in Botany to make polyethylene. Qenos is an equal joint venture of Orica and ExxonMobil.
DIESEL DESULFURIZATION commands center stage in this week's look at refining.
Starting Aug. 1, Russia's Tyumen Oil (TNK) will begin manufacturing diesel fuel with a sulfur content below US, Russian, or EU limits.
The move, says TNK, makes it the first Russian firm to provide low-sulfur diesel to its Russian customers.
TNK has been working with ABB Lummus Global to handle a revamp of its Ryazan refinery (OGJ, Feb. 28, 2000, p. 28). This year alone, the company is spending $90 million on the project, in which hydrotreating equipment was installed to reduce diesel sulfur.
TNK expects to begin supplying the fuel, with a sulfur limit of 340 ppm, to about 100 stations in the Moscow region and at Ryazan.
Meanwhile, Ruhr Oel awarded a contract for its Auto Oil Program II clean-fuels project at its Gelsenkirchen refinery to Fluor Daniel. Work scope covers the revamp and upgrade of two diesel desulfurizers and construction of a new IFP process gasoline desulfurizer, as well as modifications to utilities and infrastructure. Fluor Daniel says the facility will be able to produce, by 2001, motor fuels with sulfur content of 50 ppmthe European standard required by 2005. It also notes the project prepares the refinery for more advanced specifications. The engineering, procurement, and construction phase started in January, and project start-up is scheduled for third quarter 2001.
Topping gas processing news, Duke Energy will more than double processing capacity at its Roggen plant northeast of Denver to 55 MMcfd from 25 MMcfd.
The upgrade will ease processing constraints in Colorado's Denver-Julesburg basin, where increased drilling activity and advances in recovery techniques have sharply boosted prospective gas supplies.
Throughput at Roggen is expected to reach nearly 55 MMcfd within the next year, while NGL output jumps to more than 4,300 b/d from 2,100 b/d. Incremental NGL produced at Roggen will be delivered into Phillips Pipe Line Co.'s NGL line that extends from the Powder River basin of Wyoming to the Texas Panhandle.