OGJ Newsletter

Oct. 18, 2004
Benchmark US crude futures prices fell Oct. 12 as traders took profits after six consecutive sessions of record highs but bounced back to near-record levels in the next trading session, following an explosion of a Mexican oil pipeline, a fire on a Nigerian pipeline, and prospects of labor problems that could disrupt Nigerian production.

Market Movement

Crude futures prices remain high

Benchmark US crude futures prices fell Oct. 12 as traders took profits after six consecutive sessions of record highs but bounced back to near-record levels in the next trading session, following an explosion of a Mexican oil pipeline, a fire on a Nigerian pipeline, and prospects of labor problems that could disrupt Nigerian production.

The November contract for benchmark US crudes finished Oct. 11 at $53.64/bbl, up 33¢ for the day on the New York Mercantile Exchange after hitting a new peak of $53.80/bbl in that session. That contract continued to climb to a new high of $54.45/bbl Oct. 12 before closing at $52.51/bbl, down $1.13 for the day on NYMEX. It bounced back Oct. 13 to close at $53.64/bbl, after trading at $52.60-53.95/bbl.

Energy prices were driven up by an Oct. 11 labor strike in Nigeria that threatened to curtail that country's oil production; escalation of an ongoing strike by Norwegian offshore workers; and continued delays in bringing oil and gas production back online in the Gulf of Mexico after last month's hurricane.

The already jittery market was shaken again Oct. 13 by reports that a 30-in. oil pipeline exploded in eastern Mexico. Workers from Petroleos Mexicanos closed off the line and were working to contain the spilled oil.

GOM production disrupted

The US Minerals Management Service reported Oct. 12 that 471,328 b/d of oil production and 1.7 bcf of natural gas production in the Gulf of Mexico were still shut in because of damage from Hurricane Ivan, which made landfall Sept. 16 in Alabama.

That amounted to 27.73% of normal daily crude production and 13.87% of normal daily gas production in the gulf. And that's not counting production lost from five of the seven offshore platforms that were destroyed by Hurricane Ivan, MMS said.

"A substantial amount of the deferred production is directly attributable to damage that has occurred along pipeline routes, rather than actual structural damage to the producing platforms," MMS reported Oct. 8. They said 12 large-diameter pipelines, 10–in. or larger, were damaged in federal waters.

"Pipelines in mudslide areas off the mouth of the Mississippi River experienced failures and will take a significant effort to locate and repair because the pipelines are buried by as much as 20-30 ft of mud," MMS said. The industry is still assessing underwater damage through the use of divers and remotely operated vehicles, MMS said.

MMS earlier predicted that 96% of normal gulf production—1.7 million b/d of oil and 12.3 bcfd of natural gas—should be back online within 6 months.

Natural gas price fluctuates

The November natural gas contract plunged Oct. 12 by 35.7¢ to $6.64/Mcf on NYMEX, before rebounding the next day to $6.85/Mcf. The drop in natural gas futures price was the result of a market "pressured by a steady flow of technical selling fueled by weak fundamentals and exacerbated by a big drop in crude oil futures," said analysts at Enerfax Daily.

"Also, the impact on market sentiment of continued production outages in the Gulf of Mexico being reported by [MMS] has faded somewhat as traders realize that the overall supply-demand picture remains bearish," they said.

"A number of pipelines in the Gulf Coast, Midwest, and West cautioned shippers last week to stay close to nominated volumes or incur financial penalties because pipeline pressures are up from too much gas backing-up in their systems."

Enerfax added that, the most recent weekly storage report from the US Energy Information Administration showed an 81 bcf weekly storage build, which "was bearish, especially since the gain came despite the nearly 19 bcf of Gulf of Mexico volumes still shut-in because of damage to offshore facilities."

Refining capacity limited

US refining capacity expanded by some 1.9 million b/d over the last 10 years, but that growth rate is likely to slow, with only "a remote possibility" for construction of a new US refinery or the restart of shutdown facilities, according to data presented by EIA at a recent conference sponsored by Oil Price Information Service, Lakewood, NJ.

As a result, "total refined products demand should continue to outpace supply over the next several years," said analysts at Friedman, Billings, Ramsey & Co. Inc., Arlington, Va.

Based on data from the April OGJ Worldwide Refinery Construction Report, FBR analysts project that US refining capacity should increase by only 0.5%/year in 2004-06, compared with a 1.1%/year increase in 1998-2003.

The last refinery built in the US was Marathon Ashland Petroleum's Garyville, La., 232,000 b/d plant in 1976. But record refining margins so far this year have sparked "a new round of optimism" for future refinery construction, said the analysts.

FBR analysts reported that at the OPIS conference, Malcolm Turner of Turner, Mason & Co., Dallas, cited high construction costs; below-acceptable investment returns from such projects; and the number of regulatory and permitting issues as major deterrents to new construction.

It would cost some $1.5 billion to build a new 150,000 b/d US refinery for processing sweet crude. A similar-sized, more complex refinery capable of processing heavy sour crude would run $2.4 billion, said Turner.

"Such construction would therefore be uneconomical, as refinery sales prices have averaged only 25% of their replacement costs over the past 10 years, with the three most recent transactions during 2004 equating to even more attractive 16%, according to our estimates," the FBR analysts said.

Moreover, Turner said a new refinery would have to have consistent Gulf Coast-equivalent refining margins "in the low teens ($/bbl)" to generate a 15% internal rate of return.

Even if a refinery construction could be justified on economic grounds, Turner said, permitting, regulatory, and "Not-in-my-backyard" issues would delay the process and jack up costs.

He said current plans by Arizona Clean Fuels to build a grassroots refinery in Arizona have less than 50% chance for success.

Turner estimated 46 US refineries have been closed since 1981 and that none of those facilities is likely to be restarted because of the high level of capital expenditures required and their relatively small size, with refining capacities "well below 100,000 b/d."

If in line with historical levels, demand for petroleum products should rise by 1.5%/year over the next 5-10 years, EIA said, meaning that the US will require 250,000 b/d of either new refining capacity or imports each year to meet demand.

"The ongoing movement towards low-sulfur gasoline (2004) and diesel (2006) specifications in the US is expected to be closely followed by similar actions in Canada, the Virgin Islands, and Western Europe, thus implying that these regions not only will remain as dedicated sources of US refined products imports but are likely to grow in importance over the short term as they partially replace lower expected volumes from South America and Asia, which are moving more slowly towards low-sulfur standards," FBR reported.

Scoreboard Due to a holiday in the US, data for this week's Industry Scoreboard are not available.

Industry Trends

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OIL AND GAS COMPANIES could improve the efficiency of their dealings with engineering and construction contractors, which would create cost savings for both project owners and contractors.

That word came Oct. 12 from speakers during a Global Engineering & Construction Forum at Rice University in Houston.

"What is needed at this time is a positive attitude by the majors and supermajors in order to restore some common sense in their dealings with contractors," said Daniel Valot, chairman and CEO of Technip SA.

For instance, contracting strategy could use clarification and stabilization of common procedures, he said. In addition, oil companies might consider how the risks and costs associated with a project are being allocated, he said. "Some contractor associations are currently trying to redefine what could be the best practices in oil and gas contracting."

Valot called for "more common sense toward a new behavior" in contracting terms. For instance, a project owner should provide a neutral, if not positive cash flow to the contractor. The project owners typically are major oil companies having better access to capital than do the contractors, he noted.

"Providing to contractors negative cash flows on projects, limited insurance coverage, and single currency contracts is economic nonsense," Valot said. "Oil companies should realize that additional burdens on contractors mean—one way or another—additional costs and risks on projects."

In addition, contractors would rather deal with people working directly for the oil company involved in the project rather than with outside consultants and lawyers serving as project representatives for that company, Valot said.

Oil companies should "forget short termism and focus on long-term partnerships" with contractors, Valot said.

Maria Antonietta Solinas of ENI SPA acknowledged "the deteriorating owner-contractor relationships," saying that better communication is needed between oil companies and their contractors. She is ENI's manager of strategic planning, petrochemicals and shared services.

Previously, a wave of mergers and acquisitions changed the number and size of oil companies, which have since used bargaining superiority to force down prices and introduce difficult contractual terms, Solinas said.

"Consequently, in recent years, many contractors have disappeared or are financially sick," Solinas said. Contractors have experienced falling operating margins, falling profit margins, falling returns on capital, and bankruptcies, she said.

"The current status of relationships between [project] owners and contractors is unsustainable in the long term," she said.

Meanwhile, some oil companies have developed a framework for standardized contracts with their preferred engineering contractors, Solinas noted.

THIS WINTER could bring above-normal volatility for US heating oil supplies.

"While the current outlook indicates that the expected normal winter-weather pattern can be managed, the risks of significant volatility are unusually high," ICF Consulting Inc., Washington, DC, said in a report.

Crucial to US heating oil supply will be refinery production and imports from Europe, which will determine inventory levels when consumption is highest.

"Potential could exist for some severe price spikes if unanticipated shortages occur during peak-demand periods," said Zeta Rosenberg, ICF Consulting fuels vice-president.

Government Developments

RUSSIA'S SLOW PROGRESS on corporate governance issues and the government's crackdown on OAO Yukos have shaken investor confidence, concludes a study by a global association of financial institutions.

The Institute of International Finance's Equity Advisory Group (EAG) released the study results in Washington, DC, on Oct. 2. Despite noting some progress over a similar assessment 2 years ago, EAG still rated corporate governance in Russia overall "weak."

IIF, with 330 members in 60 countries, assessed Russia in relation to the investment environment that EAG members hope to see develop in so-called emerging-market countries.

The new study says investors have been disturbed by the Russian government's seizure of the core oil and gas assets of Yukos and possible efforts to reassert control over the energy business. These developments, it says, "have underscored the weakness and fragility of Russia's institutional framework that underscores corporate governance practices."

Assurances by Russian President Vladimir Putin about the government's commitment to property rights "have not been confirmed by realities in the marketplace," it said.

The consequence: "Investor confidence has been shaken on a scale not seen since the Russian 1998 financial crisis."

Progress in Russian corporate governance since 2002 includes the increased use of cumulative voting and improvement in board composition and management expertise. Also, the study salutes new requirements for shareholder approval of major asset sales and standardization for calculating dividend payments.

But, the study makes these recommendations:

Toughen enforcement of rules on disclosure of ownership, control, and related-party transactions.

Adopt international financial reporting standards promptly.

Require equal treatment in buy-out offers for shareholders in corporate takeovers.

Take further steps to prevent forcible takeovers or minority squeeze-outs.

"Although some progress has been made in improving the infrastructure of corporate governance, Russia still has a relatively weak equity culture that tends to undervalue minority shareholders' rights," the study says.

PHILIPPINE REGULATORS are re-evaluating tariff levels on imported petrochemicals.

The Tariff Commission is considering an industry request to extend temporary tariff protections on petrochemical imports from members of the Association of Southeast Asian Nations.

The Association of Petrochemical Manufacturers of the Philippines filed a petition seeking the extension because existing tariff protections are slated to end Dec. 31.

Quick Takes

PETRO-CANADA, Calgary, and OAO Gazprom signed a memorandum of understanding (MOU) to investigate a joint project to ship Russian LNG to North America by 2009. The MOU covers options for a joint liquefaction plant development near St. Petersburg, gas supplies for the plant, and regasification in North America. The companies would study exploration and production, liquefaction, regasification, and supply-demand fundamentals and the potential for further cooperation both in Russia and North America. Petro-Canada recently announced its intention to develop the Cacouna Energy regasification facility in Quebec to provide 500 MMcfd of natural gas to Canada and the US (OGJ Online, Sept. 28, 2004).

BP PLC and its Tangguh LNG project partners have signed a long-term sales and purchase agreement to supply LNG from Papua, Indonesia, to Sempra Energy LNG for markets in Mexico and the US. As much as 3.7 million tonnes/year of LNG will be delivered over 20 years beginning in 2008 to Sempra Energy's proposed LNG receiving terminal near Ensenada in Baja California, Mexico. The terminal's design capacity is 7.5 million tonnes/year of LNG processed to 1 bcfd of natural gas. The flexible agreement also allows the BP partners to continue offering Tangguh gas to Japan and the Asia-Pacific area. Ras Laffan LNG Co. Ltd. II (RasGas II) has signed time charter agreements with newly formed Maran Gas Maritime for the 20-year charter of four LNG vessels to deliver LNG from Ras Laffan Industrial City to various markets, particularly in Europe. The 145,700 cu m capacity carriers, which will be delivered between November 2005 and June 2008, will be built at Daewoo Shipbuilding & Marine Engineering Co. Ltd. in South Korea. Qatar Gas Transport Co. Ltd. and Maran Gas also signed a letter of intent allowing Maran to assume as much as 30% equity ownership in each carrier. Maran Gas is a member of the Angelicousis group of companies in Qatar. RasGas II and Ras Laffan LNG Co. Ltd. are joint ventures of Qatar Petroleum Co. and Mobil QM Gas Inc.

A JOINT VENTURE of Suncor Energy Inc., Enbridge Inc., and EHN Wind Power Canada Inc.—a unit of Corporacion Energia Hidroeléctrica de Navarra SA of Spain—has submitted to the Ontario government a proposal to build a 75 Mw wind-power project near Ripley, Ont. The JV would install wind turbines east of Lake Huron in Huron-Kinloss Township and connect them to the provincial power grid. The JV submitted the proposal in response to Ontario's request for projects to help the province produce 5% of Ontario's electric power from renewable sources by 2007.

CHEVRON OVERSEAS CONGO LTD. and its eight partners reported a significant oil discovery with the Lianzi-1 exploration well within the 696-sq-km deepwater unitization zone, 14K/A-IMI, shared 50:50 between Angola and Congo. The shared unit covers the combined portions of 14K, Angola's deepwater prospect within Block 14, and the A-IMI prospect within the Congo's Haute Mer permit (OGJ Online, Dec. 27, 2002). The Lianzi-1 exploration well was drilled in 909 m of water, encountering two oil-bearing reservoirs. A drill stem test of one interval flowed more than 5,000 b/d of 40° gravity oil through a 40/64-in. choke. ChevronTexaco next will complete geologic and engineering studies to assess the field's size, reserves potential, and development options.

ChevronTexaco Latin America Upstream said its offshore Plataforma Deltana Loran 2X exploration well on Block 2 off Venezuela has encountered a significant amount of natural gas. Block 2 is adjacent Petroleos de Venezuela SA's Loran 1X discovery well. Loran 2X encountered five gas sand intervals totaling 494 ft of gross thickness. The well flowed on test more than 32 MMcfd of gas from two sand intervals; both tests were equipment-restricted. Drilling began Aug. 11 in 360 ft of water and has now reached TD. ChevronTexaco said it would drill two more wells by yearend. ChevronTexaco, holding 60%, operates Block 2 in partnership with ConocoPhillips 40%. The Venezuelan Ministry of Energy and Mines recently awarded ChevronTexaco and PDVSA an exploration license for Plataforma Deltana Block 3, which is on trend with Block 2.

Newfield Exploration Co. has agreed to explore and develop prospects in the BP Exploration Operating Co. Ltd.-operated West Sole field area in the North Sea's southern gas basin. Houston-based Newfield identified several prospects on the 125,000-acre exploration area and plans to spud an exploration well in early 2005 on Block 47/10. The independent also has an option to drill two additional wells. In exchange for a 65% working interest, Newfield agreed to pay 100% of the drilling and development costs. The agreement covers segments of Blocks 47/10, 48/1c, 48/6, 48/7a, and 47/7b, excluding the existing West Sole-area fields that produce 100 MMcfed. Shell Pakistan Ltd. (SPL) affiliate Shell Development & Offshore Pakistan BV has completed a 3D seismic survey of Block 2365-1 in the deepwater Indus E basin, 150 km south of Karachi in the Persian Gulf. SPL, which has already invested $12-15 million in the block, plans to allocate $25 million more to drill an exploratory well if the survey indicates promise. A decision will be made by yearend, said SPL Managing Director Farooq Rehmatullah. Shell's partners are Kufpec Pakistan BV, Kuwait Petroleum Corp., and Premier Oil PLC.

PRODUCTION BEGAN OCT. 11 from the Alpha North gas-condensate structure on Statoil ASA's Sleipner West field in the North Sea, 18 km northwest of the Sleipner platforms. The 2.3 billion kroner development was brought on stream with one subsea template and four wells. A 16-in. pipeline transfers the wellstream to the Sleipner T gas treatment installation on Sleipner East for processing. Reserves in the satellite structure are estimated at 13 billion cu m of gas and 32 million bbl of condensate. Licensees on Sleipner West are operator Statoil, with a 49.5% holding, ExxonMobil Corp. 32.34%, Total SA 9.41%, and Norsk Hydro AS 8.85%. Gross oil production from Etame oil field off Gabon in West Africa has increased to more than 22,000 b/d, from 15,000 b/d, after completion of the field's fourth producing well, Etame 5H, which has a substantial horizontal section, said field consortium partner Sasol Petroleum West Africa Ltd. (OGJ Online, Aug. 24, 2004). Vaalco Energy Inc. is Etame's operator with 28.07% interest; Sasol Petroleum holds 27.75%. Other partners are PanAfrican Energy Gabon Corp. 31.36%, Energy Africa Gabon 7.5%, Sojitz Etame Ltd. 2.98%, and PetroEnergy Resources Corp. 2.34%.

THE UK AND NORWAY, as part of a 3-year-old cooperation initiative, have agreed on the regulation of two small cross-boundary fields in the North Sea, enabling Boa and Playfair fields to be developed more quickly. Each field extends slightly across the boundary between the two countries. The pact allows the fields to be regulated by the country with the majority field interest. The UK, therefore, will regulate Playfair, and Norway will regulate Boa. Special provisions were included to reconsider the agreement if reserves are found to be larger than anticipated. CNR International (UK) Ltd., operator of Playfair, is drilling a well from its Murchison platform and expects to begin production this autumn. Boa is part of the Alvheim development operated by Marathon Petroleum Norge ASF Norway then approved Marathon's development and operating plan for Kneler, Boa, and Kameleon fields in the Alvheim area on the Heimdal formation. Production is slated for early 2007. Marathon holds a 65% interest; ConocoPhillips holds 20%; and Lundin Norway AS has 15%. Development calls for a floating production, storage, and offloading vessel (FPSO), converted from a multipurpose shuttle tanker, with subsea infrastructure involving five drill centers and associated flow lines (OGJ Online, Feb. 23, 2004).

Ivanhoe Energy (Middle East) Inc., a unit of Ivanhoe Energy Inc., Vancouver, BC, has signed an MOU with Iraq's Ministry of Oil to study the use of enhanced oil recovery techniques in the shallow Qaiyarah unrefinable-heavy-oil field in northern Iraq. The field's reservoirs contain a large proven accumulation of 17.1° oil at about 1,000 ft, but this oil is not commercially refinable and is used only for limited production for asphalt for national use. Ivanhoe's work includes assessing the reservoirs' oil-in-place and optimum EOR methods, including possible use of Ensyn Petroleum International Ltd.'s heavy-to-light oil RTP conversion technology. Ivanhoe expects to complete the study within a few months after receiving requiree field data. If results indicate an economically viable development, Ivanhoe will propose a commercial EOR program.

CITGO PETROLEUM CORP., Houston, agreed to install $320 million worth of pollution controls at six refineries that represent nearly 5% of total US refining capacity, the US Department of Justice said. Citgo also will pay a $3.6 million civil penalty. Citgo must reduce nitrogen oxides emissions by 7,184 tons/year and sulfur dioxide emissions by 23,250 tons/year and reduce other air pollutants at all Citgo refineries. Citgo also must pay more than $5 million to reduce NOx and carbon monoxide emissions at its Corpus Christi, Tex., refinery. The proposed consent decree is subject to final federal court approval. The BOC Group PLC, Murray Hill, NJ, plans to build a $100-million hydrogen and utilities complex to supply as much as 120 MMscfd of hydrogen to BP PLC and Sunoco Inc. oil refineries in Toledo, Ohio and other potential customers in the area. The facility will be located at the Sunoco refinery, which also will receive steam from the complex. LindeBOC Process Plants, Tulsa, will provide engineering and construction services. Construction is scheduled to start in November and complete in fourth quarter 2005. The complex will enable the refineries to meet requirements for ultra-low sulfur gasoline and diesel fuels, meeting the US Environmental Protection Agency's Tier 2 clean fuels regulation.

KINDER MORGAN INC., Houston, plans $52 million capacity-expansion initiatives for its Natural Gas Pipeline Co. of America (NGPL) unit's system. KMI purchased Black Marlin Pipeline system from Northern Natural Gas Co. Sept. 1, adding 38 MMcfd of incremental capacity. Service on Black Marlin, which extends from Bryan County, Okla., to Lamar County, Tex., is expected to begin later this month, pending completion of tie-ins. KMI also will expand existing NGPL assets in northeast Texas and southern Oklahoma, adding 51 MMcfd of capacity on its Amarillo-Gulf Coast line and 20 MMcfd of incremental capacity on its Oklahoma Extension. NGPL also will install horsepower at compressor stations 801 and 155 and modify existing equipment at CS 154 and CS 802. Service will begin in second quarter 2006. NGPL will drill additional wells, install more compression and dehydration equipment, and expand the gathering system at its Sayre Storage facility in Beckham County, Okla., to expand storage capacity by 10 bcf during first quarter 2006.

P.T. McDERMOTT INDONESIA (PTMI) has completed fabrication, integration, and onshore mechanical completion on the FPSO Belanak Natuna. The vessel will be used by ConocoPhillips Indonesia for production operations in Belanak field off Indonesia (OGJ, Dec. 8, 2003, p. 50). P.T. Brown & Root Indonesia awarded PTMI the contract in July 2001 to fabricate more than 25,000 tonnes of topside modules and integrate the facilities on to the FPSO's hull. PTMI simultaneously invested $5.25 million to upgrade its FPSO berthing facility to handle vessels as large as 300,000 dwt. PTMI engineers will continue to provide commissioning assistance to the vessel offshore. The FPSO set sail Oct. 10 en route to the South Natuna Sea.

Belanak Natuna sets sail for South Natuna Sea from McDermott marine base in Batam Island. Photo courtesy of J. Ray McDermott.
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WÄRTSILÄ CORP., Helsinki, received contracts from two separate manufacturing companies in Mexico to build combined steam and power projects to generate heat and electricity for their operations. Wärtsilä North America Inc. will provide engineering, procurement, and construction services for cardboard manufacturer Cartones Ponderosa and paper manufacturer Productora Nacional de Papel (Pronal). Cartones Ponderosa ordered a 19 Mw system, and Pronal is upgrading its existing facilities with a 13 Mw system. Wärtsilä manufactures gas- and oil-fired engine-based power plants.