OGJ Newsletter

Sept. 27, 2004
Benchmark US crude for November delivery jumped by $1.59 to $48.35/bbl—the second highest settlement price ever—Sept. 22 on the New York Mercantile Exchange after the US Energy Information Administration reported a large drop in US inventories of crude and petroleum products in the wake of Hurricane Ivan.

Market Movement

Hurricane Ivan raises energy prices

Benchmark US crude for November delivery jumped by $1.59 to $48.35/bbl—the second highest settlement price ever—Sept. 22 on the New York Mercantile Exchange after the US Energy Information Administration reported a large drop in US inventories of crude and petroleum products in the wake of Hurricane Ivan.

Commercial US crude inventories plunged by 9.1 million bbl to 269.5 million bbl in the week ended Sept. 17, "well below the lower end of the average range for this time of year," EIA said. It marked the eighth consecutive week that EIA reported declines in crude inventories, including a 7.1 million bbl drop the previous week.

Ivan, which made landfall Sept. 16 in Alabama, triggered a drop in US crude imports of nearly 1.5 million b/d that week. Imports were down by 800,000 b/d the previous week as Hurricanes Frances and Ivan interrupted crude shipments through the Caribbean. Although Gulf Coast ports reopened after the hurricane, heavy seas still delayed or slowed imports of crude and petroleum products. September is the peak of the US hurricane season, and other storms in the Atlantic and Caribbean could interfere with imports.

Refineries impacted

Ivan also forced a number of refineries to shut in or reduce operations by 1.9 million b/d, or 11% of total US refining capacity. As a result, input of crude into US refineries plummeted by nearly 1.3 million b/d to 14.7 million b/d during the week ended Sept. 17. US gasoline production fell to 8.4 million b/d, with distillate production down to 3.7 million b/d.

US gasoline stocks fell by 2.8 million bbl to 199.7 million bbl that same week, and distillate inventories dropped by 1.5 million bbl to 126.8 million bbl, with heating oil accounting for most of the decrease. Concerns of possible shortages of heating oil during the peak winter season caused the October heating oil contact to hit a record high of $1.35/gal Sept. 22 on NYMEX before dipping to $1.34/gal at the close of that session.

"The falls in oil product inventories are more significant than the fall in crude inventories," said Paul Horsnell, Barclays Capital Inc., London. "Crude imports will rebound, while restoring balance in oil products will take far longer."

Production still disrupted

Energy prices escalated Sept. 20-21 as traders realized that the Gulf of Mexico oil and gas production shut in by Ivan would be slower in returning onstream than they first thought. On Sept. 22, the US Minerals Management Service reported 578,411 b/d of oil and 2.4 bcfd of natural gas production were still shut in nearly a week after the hurricane made landfall. That was equivalent to 34% of the oil and 20% of the natural gas normally produced in the gulf, and did not include production lost as a result of destroyed platforms, said MMS. It said the cumulative amount of production lost to shut-ins Sept. 13-22 totaled 9 million bbl of oil and 38.6 bcf of natural gas.

Moreover, Murphy Oil Corp., El Dorado, Ark., said its Medusa field in more than 2,200 ft of water on Mississippi Canyon Block 582 could be shut in as long as 5 weeks, while Dominion Exploration & Production Inc., a subsidiary of Dominion, Clarksburg, WV, said its Devil's Tower field in 5,610 ft of water on Mississippi Canyon Block 773 may be shut in at least 3 weeks, pending inspections and repairs. Medusa was producing 34,000 b/d of oil and 34 MMcfd of natural gas prior to the storm. Devil's Tower was producing 20,000 b/d of oil and 16 MMcfd of gas.

"The full impact of these [gulf production] shut-ins should be partially offset by 'lost' demand from refining and chemical operations along the Gulf Coast that temporarily shut down due to the storm," said Robert S. Morris, Banc of America Securities LLC, New York.

In its initial sweep though US gulf waters, Ivan set adrift five mobile offshore rigs, all of which were later located although one was listing 3º. It destroyed 7 fixed platforms and damaged 4 others, along with 1 mobile drilling rig and 2 spar units. One platform rig was missing and another damaged. There were 13 pipeline leaks in the wake of the storm, but MMS reported no resulting pollution.

On Sept. 23, a weakened Ivan was again threatening oil and gas operations off Texas and Louisiana. After making landfall the previous week, Ivan broke apart as it traveled north, drenching southern and mid-Atlantic states before returning to sea where it strengthened into a tropical storm that again forced evacuations of some offshore oil and gas facilities.

Industry Scoreboard

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Industry Trends

EUROPEAN REFINING MARGINS have rebounded but remain at or below breakeven levels while Singapore refining margins also are rising, reported A.G. Edwards Inc., St. Louis.

"Refining margins had spiked in response to a shortage of gasoline due to strong demand from the summer driving season being experienced both in Europe and the US, but rebuilding gasoline inventories on both sides of the Atlantic and high oil prices have more than offset unscheduled refinery maintenance," said L. Bruce Lanni, senior analyst for A.G. Edwards.

Companies with the most leverage to European refining include BP PLC, ConocoPhillips, ExxonMobil Corp., and Royal Dutch/Shell Group, Lanni said.

September's refinery maintenance season in Europe was estimated at 1.2 million b/d, which Lanni called "relatively heavyUmost affected are those that operate in countries that use sulfur above 50 ppm as they complete upgrades to meet lower European sulfur regulations that begin in 2005. The large concentration of maintenance in 1 month could possibly contribute to a spike in refining margins as any excess refining capacity should be greatly reduced."

Meanwhile, strong Asian demand—led by China—has helped create a current tight regional supply-demand situation, he said.

The recent surge in demand for crude products in Asia has helped to alleviate a capacity overhang issue, he said.

Lanni noted that new capacity coming on stream during 2005-06 in China and India probably means that current margin levels are not sustainable, even if upside demand continues.

NUCLEAR POWER PROTECTS Japan's economy from volatile crude oil price spikes, but too heavy a reliance on nuclear power would raise electric costs to the point of diminishing returns, Rice University's Institute for Public Policy said.

"Although nuclear power can reduce a nation's exposure to international oil market fluctuations, diversity of fuel choice in the electricity sector is important to a nation's energy security," said a new study's principal author, Kenneth Medlock III, senior research fellow in energy studies at the Baker Institute and a visiting economics professor. Peter Hartley, chair of Rice's economics department, was co-author.

The study examined the possible economic impact of an oil price shock. In the absence of nuclear power, the cumulative impact of a 25% increase in oil prices could result in a loss of up to $18.2 billion in gross domestic product.

Statistics do not account for nuclear power's controversial operating issues, such as the problem of waste disposal or potential costs of nuclear accidents, the study noted.

Fuel diversity is important to keeping electricity prices low and maintaining system stability, the study concluded. If all electricity in Japan were to be shifted to nuclear power, then electric prices would increase above current levels because of the costs of managing peak loads without peaking facilities, which typically are fired by natural gas or fuel oil.

Government Developments

GERMANY IS SEEING the construction of more solar power plants in its national push for renewable energy.

German Environment Minister Jürgen Trittin recently inaugurated a large solar plant in the eastern city of Espenhain, noting that Germany is the leading European country to install solar energy facilities.

Major oil companies are helping build Germany's solar plants. Shell Solar GMBH, the Society for Solar Energy (Geosol), and German-based WestFonds Real Estate Co. worked together to construct the $27 million plant near Leipzig, formerly one of Germany's most polluted areas.

Geosol developed the project while Shell Solar supplied the solar technology and was the prime construction contractor. WestFonds acquired interest in the plant through its investment fund for renewable energy projects, WestFonds Solar 1.

Hans Willemsen, Shell Solar executive vice-president, said his company "has strategically been involved in the development of large-scale solar projects in Germany."

The plant features 33,500 photovoltaic panels capable of generating 5 Mw, enough to provide electricity for 1,800 households. The plant is part of a series of solar generators constructed in Germany. BP Solar International LLC also is building plants in Germany.

Trittin actively promotes the development of large-scale solar projects, saying that solar power and wind power are key to the government's energy policy. On Aug. 1, an amendment to the Renewable Energy Sources Act became effective.

"It is an engine for innovation and increases export opportunities for German technology," he said of the act, which was created to provide a reliable legal framework for investments in solar, wind, hydropower, bioenergy, and geothermal energy.

The amendment calls for Germany to increase its share of renewable power to 12.5% of the country's total power generation by 2010 and to 20% by 2020. Currently, renewable energy from water, wind, and solar power represents 10% of the total.

"Supporting renewable energies will still cost an average household just 1 euro a month—the price of an ice cream cone," Trittin said.

US MINERAL MANAGEMENT SERVICE issued a new regulation aimed at reducing administrative costs and reporting duties for marginal oil and natural gas well owners.

The rule outlines how leaseholders can obtain accounting and auditing relief for production from federal oil and gas leases that qualify as marginal properties.

A marginal property is defined as having average production of fewer than 15 boe/d for each well, or 1,000 boe/year for the entire property, MMS said.

"This new rule encourages leaseholders to continue production from marginal properties," said Lucy Querques Denett, MMS associate director in Washington, DC.

The rule provides that leaseholders of marginal properties can report and make royalty payments on an annual basis rather than on a monthly basis.

MMS noted that if the marginal property involves onshore wells, then the state government where the production occurs also must concur before the relief will be granted. If the marginal property is in federal waters, MMS alone can approve the reporting relief.

Quick Takes

BRAZILIAN OFFICIALS and China's state-owned Petroleum & Chemical Corp. (Sinopec) signed an agreement giving Sinopec the option to participate in Brazil's 1,225 km Gasene natural gas pipeline from Cabiuna's gas processing plant in Rio de Janeiro state to Bahia state. Construction on the $1.3 billion pipeline would begin in July 2005 and finish in January 2007. Brazil's state-owned Petroleo Brasileiro SA (Petrobras) and Sinopec also inked partnership agreements for oil exploration, production, refining, oil products sales, petrochemicals, pipeline engineering services, and technical cooperation (OGJ Online, May 27, 2004). In addition, they also might partner in developing Santos basin gas off São Paulo and a planned plant to liquefy the gas.

WOODSIDE PETROLEUM LTD. has a new natural gas discovery near its Blacktip gas field in the Bonaparte Gulf off northern Australia. The Polkadot-1 wildcat on permit WA-313-P intersected three gas zones having a cumulative gross thickness of 50 m. Polkadot-1 is 30 km west of Blacktip and 300 km southwest of Darwin. The gas indications occurred during wireline logging at 3,791 m TD. Blacktip field development testing will more fully evaluate the reservoir. Plans include a $450 million (Aus.) offshore field development plus a $550 million pipeline across northern Australia to a connection with an existing pipeline from central Australian gas fields to Darwin and a spur line to the Gove alumina refinery in northeastern Arnhem Land in Northern Territory. Total E&P Congo reported an oil discovery in water 2,000 m deep on its ultradeepwater Mer Très Profonde Sud (MTPS) permit, 200 km southwest of Pointe Noire, Republic of Congo. The discovery well Pégase Nord Marine 1 was drilled to 3,622 m TD and flowed on test at 14,360 b/d of oil. The 5,000 sq km MTPS permit lies in water 1,300-3,000 m deep. Total is the operator, holding a 40% interest. Partners are ENI Congo 30% and Esso Exploration & Production Congo (MTP Sud) Ltd. 30%. Noble Energy Inc. subsidiary Noble Energy EG Ltd., Houston, has acquired a 40% working interest in a production-sharing contract covering Block I off Bioko Island, Equatorial Guinea, adjacent to Noble Energy's Block O. Block I covers 806 sq km in more than 500 m of water. Noble Energy will be technical operator, and the Atlas Group, holding 60%, will be administrative operator. Equatorial Guinea's national oil company GEPetrol will have a 5% carried interest once commerciality is determined. Noble said several substantial leads have been identified on Block I, and it expects prospectivity to be enhanced after processing recently acquired 3D seismic later this year. Mosaic Oil NL, Sydney, reported its Rockhampton-1 well in permit ATP709P in southeastern Queensland found gas and oil. Electric logs indicated an 11.5 m interval of wet gas in the Permian Tinowon sandstone over a 2,394-2,405.5 m interval and the possibility of a 12 m thick section of oil reservoir in the overlying Triassic Rewan formation at 2,316-2,328 m. Unstable formation conditions preclude open-hole testing, Mosaic said, so a workover rig will be brought in to run drillstem tests through casing to confirm the find. The well reached 2,527.5 m TD. The Rockhampton-1 wildcat is 20 km northwest of Mosaic's Waggamba oil and gas field and 45 km south of Churchie field. Heritage Oil Corp., Calgary, said Uganda agreed to relicense Block 3 in that country for another 6 years. Heritage licensed Block 3 in the Albert graben in 1997 and drilled the Turaco-1 and Turaco-2 wells (OGJ Online, June 15, 2004). Turaco-2 encountered two potential hydrocarbon zones with an estimated gross pay of 300 m. Heritage has a 50% interest and operates Block 3. Its 56% joint venture partner is Energy Africa Ltd., Cape Town. Heritage plans to drill and test the Turaco-3 well this year. A 3D seismic survey is being shot in the area surrounding the Turaco-2 well. Total SA, operator of Laggan gas field 120 km west of the Shetland Islands in the UK North Sea, reported a positive field appraisal. Two appraisal wells were drilled in 600 m of water.

The 2006/1a-4AZ well was tested at 37.8 MMcfd of gas, Total said, and data are being analyzed toward a development decision. Total holds a 50% interest in Laggan. Partners are Dong Norge AS, ENI UKCS Ltd., and Texaco Britain Ltd. Separately, during the UK's recent 22nd round of licensing offshore, Total won three frontier licenses adjacent to Laggan—Blocks 214/23, 24, 28, and 29; 205/5; and 214/25. Shell Malaysia unit Sabah Shell Petroleum Co. Ltd., operator of Block G in deep water northwest of Sabah, has made another oil discovery—with the Malikai-1 exploration well—off Sabah. Shell's joint venture partners in the well are Malaysia's Petronas Carigali Sdn. Bhd. and ConocoPhillips. "The Malikai-1 exploration well encountered a long oil column in very good quality reservoirs," said Shell Malaysia Chairman Jon Chadwick. "Initial indications are that Malikai crude oil is of a high quality." Specifics of the discovery were not disclosed. The vertical well, spudded Aug. 4, was drilled in 565 m of water. It is 110 km from Gumusut field on Block J.

STATE-OWNED Pakistan Petroleum Ltd. (PPL) awarded a $21 million contract to Malaysian engineering firm Ranhill Bhd for expanding existing LPG-NGL facilities at Adhi field in northern Punjab province. Contract terms call for Ranhill Berhad to double the capacity of the existing facilities by yearend 2005. The expansion was prompted by increased estimates of recoverable reserves. PPL operates and has expedited activities at Adhi field. Currently, 16 wells are being drilled, and PPL plans to spud another four wells. AltaCanada Energy Corp. unit Montana Land & Exploration Inc. (ML&E), Calgary, is developing its Cherry Patch play in Montana. The $2.4 million development includes an 18 mile, 6-in. natural gas gathering system and the drilling of 15-25 wells by yearend. ML&E also will participate in 5-10 wells on adjacent areas, and will drill 5 wells in Canada during the third quarter. The pipelines will connect to an existing 10 mile lateral that ties in, at Battle Creek, Mont., to the Chinook export pipeline. During ML&E's 16-well spring drilling program, 15 wells encountered Eagle formation gas in commercial quantities at 1,200-1,780 ft.

US DRILLING ACTIVITY declined slightly the week of Sept. 17, down by 8, units with 1,232 rotary rigs working in the US, Baker Hughes Inc. reported. That compares with 1,092 rigs drilling during the same period last year. Land operations accounted for the drop in the rig survey that was made prior to Hurricane Ivan's making landfall Sept.16 in Alabama. US land drilling was down by 9 rigs with 1,121 working. On the other hand, offshore drilling was unchanged at 87 rigs in the Gulf of Mexico, but increased by 1 rig to 93 in US waters as a whole. In Canada, the rig count dropped by 15 to 246 units working, down from 338 a year ago.

KUWAIT FINANCE HOUSE BAHRAIN announced the launch of a $1.3 billion petrochemical, water, and electric power generation complex to be built in Bahrain, reported OPEC News Agency. Successful feasibility studies on the project were carried out by a consortium consisting of partners General Electric (GE) Energy, Weir International, and Shaw Group subsidiary Stone & Webster in cooperation with ThyssenKrupp Group's Germany-based engineering firm Uhde GMBH and Chicago Bridge & Iron Co. The complex would produce ethylene dichloride, caustic soda, LPG, and gasoline, along with some hydrogen and sulfur, and would provide electric power generation and water. At full capacity, the complex would require about 255 MMscfd of fuel gas. Pending receipt of a Ministry of Industry license, construction could begin in June 2005, and start up by first quarter 2008, OPECNA reported.

Brazil's state-owned oil company Petróleo Brasileiro SA (Petrobras) and Brazilian private petrochemical group Ultrapar Participações SA (Ultra) are negotiating the construction of what, if built, would be a $3 billion petrochemical complex, possibly at Itaguai, 80 km south of Rio de Janeiro. "The project is still at an embryonic state and the location under evaluation," said Paulo Roberto Costa, Petrobras's director for supply, refining, and sales. The complex, which would produce 1.2 million tonnes/year of ethylene, polypropylene, and polystyrene, would also include a 150,000 b/d refinery with technology developed by Petrobras to process heavy oil from the Campos basin. The refinery would process mainly diesel and LPG plus raw materials such as propane and aromatic derivatives for the petrochemical chain. Petrobras, which would not have a majority stake in the project but might reach a 50% interest in some units, is mulling whether to accept Ultra's partnership proposal, said Costa. Foreign groups also are welcome to join the project, said Petrobras chemical engineer Carmen de Sá Barreto, as some foreign know-how for enhancing the production of petrochemicals raw materials will be required.

Borealis AS, Copenhagen, awarded two contracts to a subsidiary of Jacobs Engineering Group Inc., Pasadena, Calif., for services related to the expansion of polypropylene production capacity at Borealis facilities in Schwechat, Austria, and Ronningen, Norway. The Schwechat project, to expand production capacity to 300,000 tonnes/year, is scheduled for completion by yearend 2005. Jacobs performed basic design with Neste Engineering of Porvoo, Finland, and Tecon Engineering GMBH, Leobersdorf, Austria. The same team will cooperate during the implementation phase. For the Ronningen site, Jacobs is providing engineering, procurement, and construction management services to increase production capacity to 175,000 tonnes/year by autumn 2005.

Ras Laffan Liquefied Natural Gas Co. Ltd. (II) (Ras Gas II) has awarded a contract to a joint venture of ENI SPA unit Snamprogetti SPA and Yokohama-based Chiyoda Corp. to perform engineering, procurement, and construction for the fifth LNG train and related facilities at Ras Laffan, Qatar. RasGas II Train 5 will be sited near existing Trains 3 and 4, which were executed by the same JV. The project is scheduled for completion in fourth quarter 2006. Train 5, like Trains 3 and 4, is expected to produce 4.7 million tonnes/year of LNG. Qatar's 900 tcf North field will supply gas for the unit. Production is scheduled to commence in January 2007.

TOTAL SA reported the start-up of the third phase of development at Al Khalij oil field off Qatar. Also, Total has brought on stream a water separation and treatment platform. Production from the field will be increased to 20,000 b/d of oil with the finalization of the drilling phase in January 2005. New peak production from Al Khalij will reach 50,000 b/d of oil. Additional output will be provided by 10 new production and injection wells with the separation, treatment, and reinjection of water to be handled by a new unmanned, remotely operated platform. Total holds 100% interest in Al Khalij field.

Shell Canada Ltd. plans to increase bitumen production at the Athabasca oil sands project (AOSP) in Alberta to 270,000-290,000 b/d by 2010. Its long-term target is 500,000 b/d. During the next 3 years, debottlenecking at Muskeg River Mine north of Fort McMurray and the Scotford Upgrader near Edmonton should increase production to 180,000-200,000 b/d. The upgrader could be modified to process the heaviest product streams into lighter crude blends, Shell said. Plans also include mining on newly acquired leases. Expansion costs are estimated at $4 billion. AOSP is a joint venture of Shell 60%, Chevron Canada Ltd. 20%, and Western Oil Sands LP 20%.

Petroleum Development Oman has completed studies for waterflooding projects at 10 field clusters, including the 23-field Rahab-Thuleilat-Qaharir group in Oman. Plans call for first enhanced-recovery oil from Mukhaizna field in 2007 in a project requiring 1,800-2,200 new wells. Front-end engineering and design are under way for EOR at the Harweel field clusters in southern Oman, 80 km southwest of Marmul, and a Qarn Alam EOR project is to be developed from a steam injection pilot, also under way. PDO added a compressor at the Yibal gas plant, boosting capacity to 23 million cu m/day. Early construction began on the Saih Nihayda gas plant, and pipe was ordered for a 48-in. loop from the plant to a point near Al Kamil. Production began in March from Zalzala field in the Harweel cluster where production is expected to rise to 18,000 b/d of oil and 30 MMcfd of gas by yearend. In Phase II, Harweel gas will be injected into nearby fields. PDO members include the Omani government 60%, and affiliates of Royal Dutch/Shell Group, Total SA, and Partex (Oman) Corp.

CALTEX OIL SOUTH AFRICA (PTY) LTD., a ChevronTexaco group member, awarded an engineering, procurement, and construction contract to Foster Wheeler South Africa (Pty.) Ltd. for the third stage of a $32 million low-sulfur diesel project in Cape Town. The project involves revamping a diesel hydrotreating unit and adding a hydrogen purification unit to produce low-sulfur diesel that will meet South Africa's diesel fuel specification of 500 ppm wt sulfur by Jan. 1, 2006. Commissioning is expected in November 2005. During the first and second stages, Foster Wheeler produced the conceptual engineering package.

CORRECTION

Equitable Supply's gas reserves in the OGJ200 report (OGJ, Sept. 13, 2004, p. 28) should have been 2,064 bcf. This would rank Equitable at No. 13 for gas reserves in the US and No. 19 for worldwide gas reserves.