Market Movement
Natural gas market sags
Natural gas futures prices declined through most of last week, dipping to $3.85/Mcf at midweek. "The market is well underneath technical support levels, and that could trigger a reaction upward and a short-covering rally later this week," said analysts at Enerfax Daily. "However, it is likely we haven't seen the lows yet."
Still, "the winter natural gas market is much better looking than the bears would have believed a year ago. In fact, prices are almost double," said John P. Herrlin Jr., first vice-president of Merrill Lynch Global Securities Research & Economics Group. "That's not to say that natural gas prices will be static, given the at-the-margin nature of the business," he observed. "But, hurricanes or no hurricanes, companies with US natural gas production haven't exactly knocked the leather off the ball."
With 28 of the 40 largest public producers of US gas reporting, indications are that third quarter production declined 1.5% from second quarter levels and are down 5.1% from the same period a year ago, said analyst Robert Morris with Salomon Smith Barney Inc. in New York.
Herrlin estimated even higher decline rates of 1.6% and 6.1%, respectively. "We believe that the market has already digested the information," he said.
Meanwhile, meteorologists at Salomon Smith Barney forecast "a steady flow of arctic air southward into the mid-latitudes" through the first half of November, with temperatures below normal for most of the country and near record-low temperatures in the central US.
"For the first time since May, natural gas prices have risen above residual fuel oil prices on an energy equivalent basis," said Morris, who also pointed out, "many conventional gas-fired steam turbines can also burn residual fuel oil while combined-cycle plants can typically switch from natural gas to lighter distillates."
He said, "Power generators in the Northeast have indicated that they began to switch to residual oil from natural gas..., where they have the capability and were not limited by contractual obligations." Such a decision "is based almost exclusively on relative prices," Morris said. "However, (the latest) injection figure does not indicate a significant level of fuel switching at this juncture."
Morris estimated fuel switching could reduce US demand for natural gas "by as much as 4 bcfd, or about 7% of annual demand," if gas prices spike, relative to residual and distillate prices, for an extended period this winter.
"Also, the difference between natural gas and ethane prices has narrowed, and in certain regions it is now more economic to reject ethane rather than extract it as NGL," he said. "Based on conversations with several operators, we estimate that less than 10% of the natural gas processed is presently operating in a 'rejection' mode."
The decision to extract ethane or to leave it in the natural gas stream "is based solely on price differentials on an energy equivalent basis as incremental operating costs are minor," said Morris. "Importantly, ethane rejection increases the energy content of the natural gas stream and thus reduces demand on a volumetric basis. We estimate full-scale ethane rejection could result in a roughly 0.5% reduction in natural gas demand on a volumetric basis."
OPEC production above quota
Tanker tracking data for October indicated continued over-production by the 10 active OPEC members, minus Iraq, above their combined quota of 21.7 million b/d, said Matthew Warbur- ton with UBS Warburg LLC, New York. "Revised estimates for October have production at 24.19 million b/d vs. 24.12 million b/d for September, with only Indonesia not producing above its quota," he said. "This level of OPEC-10 production would indicate that inventories are no longer being drawn down."
The American Petroleum Institute last week reported US oil stocks gained 2.3 million bbl to 291.6 million bbl during the week ended Nov. 1, while distillate inventories, including heating oil and jet fuel, were up 1.5 million bbl to 124.5 million bbl.
"Driven by higher (oil) imports," up 515,000 b/d to 9.4 million b/d, US crude inventories "reached their highest level in 7 weeks," Warburton said. He noted that US Gulf Coast refineries registered "their highest input level in 9 weeks."
US stocks of unleaded gasoline fell by 638,000 bbl to 195 million bbl, despite a rise in refinery operations to 90.1% from 87.5% the previous week and an increase of 35,000 b/d in US gasoline production to 8.5 million b/d.
Still, Warburton said, "Gasoline inventories were essentially unchanged (week-to-week) with resurgent imports and robust domestic production offsetting increased implied demand."
Industry Scoreboard
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Industry Trends
US DOWNSTREAM fundamentals gradually have strengthened since midsummer, and overall annual product demand is expected to improve to 1.7% next year from close to flat this year.
Merrill Lynch analyst Andrew C. Fairbanks said factors point toward an improved 2003. "These include improving heavy sour crude oil discounts, strong US gasoline demand, improving distillate demand, and a gradual tightening in US product inventories," he said in a research note.
The 2003 forecast assumes a normal winter and a stronger economic recovery in the fourth quarter and next year.
"Once in a better total demand environment, we believe the industry will once again run at full capacity under very tight conditions," Fairbanks said. "Gasoline imports, though high this year, should be fully absorbed in similar quantities next year with only modest demand growth."
US imports are running higher this year than in the high margin years of 2000-01 despite the steep drop in 2002 US refining margins, he said.
"While gasoline demand growth has been strong this year, the market has failed to retighten quickly because rising import levels have effectively offset all the demand growth," Fairbanks said.
Of the 51 countries that exported gasoline products to the US this year, 14 accounted for significant volumes, with the biggest share coming from Canada (see chart).
"The primary growth in incremental imports during the 1999-2002 period has been driven by Western Europe, Canada, and to a smaller extent Russia. These countries have increased exports to the US by 294,000 b/d over the period," Fairbanks said.
Structural changes prompted growing imports from Europe, especially post-2000, he said. "We estimate that the incremental cost to make Eurograde gasoline material into US reformulated gasoline spec material is only about 0.5¢/galU," he said.
This year's rise in Russian exports to the US stemmed from Russia's agreement with the Organization of Petroleum Exporting Countries to withhold crude oil exports from the market, he said.
"Though we are estimating another record year for gasoline imports into 2003, we think the US market will be able to accommodate realistic import levels going forward," Fairbanks said. "Incre- mental imports are coming from everywhere, including some unusual places where it should not be economic to export barrels to the US." Some imported gasoline is expected to drop off the market in 2003, especially if certain countries' home markets become more attractive with better local demand.
"Going forward, we believe the US supply demand balance will again return to the conditions of 2000-01 when strong demand and margins in the US pulled in higher imports to balance tight marketsU," Fairbanks concluded.
Government Developments
REFINERS' CONCERNS about the US Environmental Protection Agency's pending 2006 highway low-sulfur diesel regulations will be addressed during a Nov. 20-21 workshop in Houston.
Ed Murphy, the American Petroleum Institute's downstream general manager, said industry wants to avoid possible retail diesel fuel supply problems when the program begins in mid-2006.
Late last month, EPA formally presented a clean diesel review panel report updating information on the technical advances being made to comply with the rule. Previously, API and the National Petroleum & Refiners Association endorsed the independent panel's work.
The panel found technology issues would not prevent regulators from proceeding with the rule. The panel acknowledged some refiners' concerns about the impact that the rule might have on distribution, but most panel members agreed those issues were beyond the panel's charter (OGJ Online, Sept. 26, 2002).
"Now, we look forward to working with EPA and all stakeholders," Murphy added of the upcoming meeting. "We do not seek to change the rule or the schedule for its implementation, but potentially significant implementation problems need to be addressed to help ensure that adequate ultra-low sulfur and low sulfur highway diesel fuel supplies are available to consumers in mid 2006." The NPRA also said its members have concerns about diesel supply and distribution issues regarding the 2006 highway diesel rule.
"As the manufacturers of highway diesel, the nation's premier commercial transportation fuel, we have a keen interest in working to understand and address any potential difficulties in implementing the ambitious rule," said Bob Slaughter, NPRA president.
Noting that the downstream sector is experiencing difficult economic times, Slaughter said, "It is important that (the refining industry's) limited investment capital is efficiently spent to maintain both a secure national energy supply while sustaining environmental progress."
Six industry trade organizations, including the NPRA and API, are hosting the Houston meeting along with the EPA.
SPANISH OIL COMPANIES Repsol-YPF SA and Cepsa are negotiating contracts with Iran covering oil exploration and development, and Repsol also is discussing LNG contracts, said Iranian Economy Minister Tahmasb Mazaheri. Speaking in Brussels to OPECNA, the Organization of Petroleum Exporting Countries' news service, Mazaheri said negotiations were close to completion "and we hope to be able to sign very soon."
The talks with Repsol focus on LNG projects and oil exploration. No details were available on the discussions between Iran and Cepsa, but a company spokesman said discussions involved the company's participation in an oil field development.
Repsol is considering a $1 billion investment, while Cepsa is targeting spending of $350 million. The negotiations follow Mazaheri's and Iranian President Mohammad Khatami's visit to Spain last week. Khatami appealed to Spanish companies to step up their operations in Iran to take advantage of a climate that he said was receptive to international cooperation.
Quick Takes
STATOIL ASA and PetroPars Ltd., Tehran, have signed a participation agreement designating Statoil as the operator of offshore development in Phases 6, 7, and 8 of the giant South Pars natural gas development project in the Persian Gulf. It also gives Statoil a 40% ownership interest in these phases of the project.
Offshore work will proceed over the next 4 years, during which Statoil's capital commitment will be $300 million. The company's capital commitment and return will be covered from "sales revenues generated by condensate and LPG produced over a 4-year period from the start of production (in late 2004)," Statoil reported.
"Production capacity will be 100 million cu m/day, with 80 million cu m/day being exported to other Iranian oil fields for injection as pressure support. The remaining condensate and LPG will be sold," Statoil added.
Phases 6-8 will be developed with three offshore wellhead platforms linked by three pipelines to an onshore gas treatment plant.
PetroPars is undertaking Phase 1 development, expected to hold 5.8 billion boe, and will handle development of the land-based gas treatment facilities at Assaluyeh.
Iran is investing $15-20 billion during a 5-7 year period in the treatment complex, which will include liquids separation facilities, petrochemical projects, pipelines, and upstream planning and execution (OGJ Online, May 20, 2002).
PetroPars is owned 60% by the National Iranian Oil Co., and 40% by Iran's Ministry of Industry agency, Industrial Development & Renovation Organization.
TotalFinaElf SA subsidiary Total South Pars, operator and a 40% interest holder in Phases 2 and 3 of the South Pars project, brought those phases on stream earlier this year (OGJ Online, Mar. 19, 2002). Its partners are Russia's OAO Gazprom 30% and Malaysia's Petronas 30%. Phases 2-3 field development costs reached $2 billion. Production is expected to plateau at 2 bcfd of gas and 80,000 b/d of condensate from 20 wells tied into two unmanned platforms. Gas and condensate will be transported via two 32-in., 105 km pipelines to be treated onshore at Assaluyeh.
Phases 4 and 5 are being undertaken by Agip Iran, a unit of Italy's ENI SPA, which has called tenders for subcontract work. This phase is expected to have an output of 80,000 b/d of condensate, 1 million tonnes/year of LPG, and more than 1 million tonnes/ year of ethane.
South Korea's LG Group unit LG Construction Co. and Iran's Oil Industries Engineering & Construction signed a $1.6 billion contract in September for gas processing facilities in Phases 9 and 10. LG reportedly will have a 40% stake in these phases.
Although South Pars gas will be used in Iran and the condensate exported, BP PLC, National Iranian Oil Co., and India's Reliance Industries Ltd. last year agreed to begin a $10 million feasibility study of an LNG project in southern Iran (Phases 11-12) based on South Pars gas (OGJ Online, Feb. 23, 2001). LNG exports would go to India and other markets in Asia and Europe.
Total production from South Pars field may reach 25 billion boe at full development over 20 years (OGJ, Aug. 19, 2002, p. 22).
In other development news, BP and Algerian state-owned oil and gas firm Sonatrach have awarded a $745 million contract to JGC-KBR for the engineering, procurement, and construction of In Amenas natural gas development project facilities, infrastructure, and pipeline systems in southern Algeria. Under terms of a 20-year agreement signed in 1998, Sonatrach and Amoco Algeria Petroleum Co. (now part of BP) agreed to develop In Amenas jointly (OGJ, July 6, 1998, p. 42). Amoco agreed to invest $900 million over the life of the project, to drill 80 wells and construct a 100 km pipeline and a 700 MMcfd gas treatment plant. First gas is expected in 2005. The project includes development of four production fields. The first phase is the development of Tiguentourine gas field 40 km southwest of In Amenas. The EPC contract will involve gas processing facilities, product pipelines, and basic infrastructure. Pipeline-grade gas, LPG, and condensate products will be piped 110 km for delivery to Sonatrach's pipeline grid at Ohanet. Expected project duration, from beginning to performance testing, is about 3 years, KBR said. F Elsewhere, Norsk Hydro AS, operator of Vigdis field in the North Sea, also awarded an EPC contract, this one worth 370 million kroner to FMC Kongsberg Subsea AS, a unit of FMC Technologies Inc., Houston, to supply subsea systems for the field's extension program. The EPC contract includes six subsea trees and associated structures, manifolds, production control systems, and tie-in and connection systems for flowlines and umbilicals. Vigdis extension will contain two, four-well subsea frames and two satellites.
A COOPERATIVE of rural municipalities signed a letter of intent with a subsidiary of Outlook Resources Inc., Toronto, to jointly develop and build an ethanol plant in the Dauphin and Roblin region of Manitoba.
Outlook's Atlantol Industries Inc. said the proposed $50 million (Can.) plant would be capable of producing 80 million l./year of fuel grade ethanol.
The Parkland Agricultural Resource Cooperative (PARC) represents 5,200 farms consisting of 2.5 million acres of producing farmland. The agreement gives PARC members the option to acquire as much as 25% interest in Atlantol.
PARC agreed to pay $50,000 for an engineering feasibility study to be prepared by Dillon Consulting Ltd.
When the study is completed, PARC can obtain its stakeholder's position by providing an additional $2.45 million for plant development and construction.
The agreement hinges upon Atlantol arranging financing to cover 25% of the project costs and obtaining a binding commitment for project financing equal to 70% of the project costs.
OSINERG, the supervisory organization for Peru's energy industry, has fined Transportadora de Gas del Peru (TGP) 3.4 million soles, equivalent to $944,000, for environmental violations during construction of natural gas pipelines for the Camisea project.
The regulatory agency claims TGP failed to comply with all of its commitments under an environmental impact study for that project. Failures include excessive deforestation along the pipeline right-of-way, causing landslides, and endangering the watershed with the risk of erosion, regulators said.
Osinerg will reduce the fine by 25% if TGP foregoes its right of appeal and pays within 15 days. TGP also must repair the damage it caused.
NAPHTACHIMIE, the 50:50 joint venture of BP Chemicals SNC and TotalFinaElf SA's petrochemical branch Atofina Petrochemicals Inc., plans to invest 250 million euros over the decade to turn its Lavéra site on the French Riviera into a "star site" for further integrated development of refining and petrochemicals.
Modernization of the Lavéra steamcracker is a prelude to debottlenecking production at the site, which will be elevated "to 1.1 million tonnes/year from the current 720,000 tonnes/year during 2006-11," BP Chemicals CEO Jean-François Rogeau told OGJ.
BP already is investing more than 120 million euros this year on Lavéra to integrate the refining and petrochemical businesses after having upgraded the capacity of numerous production plants there in 2001.
BP has assumed administration and management responsibilities for the steamcracker's manufacturing operations.
Naphtachimie also plans a new column to improve ethylene production, a single control room for the entire site, and replacement of 20 furnaces having a total capacity of 25,000 tonnes with four or five 120,000-tonne units by 2007.
China National Offshore Oil Corp. (CNOOC) and Shell Petrochemicals Co. Ltd. units have agreed to proceed with the joint venture construction of a $4.3 billion world-scale petrochemical complex in southern China. The agreement follows a 20-month definition phase during which the JV finalized basic design engineering packages, updated an environmental and social impact assessment, prepared bid packages for the engineering, procurement, and construction phase of the project, and arranged financing. The JV expects to award before yearend major contracts worth more than $1 billion for the process plants, plant automation, and project management services. Major construction work is expected to start early next year on the 430 hectare site at the Daya Bay Economic and Technical Development Zone in Guangdong Province, with start-up slated for late 2005. Shell Nanhai BV and CNOOC Petrochemicals Investment Ltd. (CPIL), each with a 50% shareholder interest, signed a JV contract in October 2000. CPIL is 90% owned by CNOOC and 10% by the Guangdong Investment & Development Co.
Major features of the project are an 800,000 tonne/year (t/y) ethylene cracker, a 560,000 t/y styrene monomer and 250,000 t/y propylene oxide plant, a 320,000 t/y ethylene glycol plant, and a 240,000 t/y polypropylene plant. The complex also will contain a high-density, 200,000 t/y polyethylene plant with capability to produce linear low-density polyethylene and a low-density, 250,000 t/y polyethylene plant with integrated support facilities and utilities. The entire complex has been designed to international standards to protect the environment and use energy and material efficiently. A consortium serving as project manager will help manage the project until the plant starts up. It is composed of Bechtel Group Inc., Sinopec Engineering Institute, and Foster Wheeler Corp. (OGJ Online, Mar. 15, 2001). When the complex is completed, the JV will produce about 2.3 million t/y of products, generating as much as $1.7 billion in products sales, primarily suppling customers in Guangdong and the high consumption areas of China's coastal economic zones.
THE TRANS-ALASKA PIPELINE returned to service Nov. 6 following a 3-day shutdown in the wake of an earthquake of 7.9 magnitude that rocked central Alaska Nov. 3, slicing roads and damaging some pipeline supports in six locations.
BP PLC and other producers on Alaska's North Slope temporarily shut in all but 5% of their 1 million b/d of oil production there "just as a precaution," a BP spokeswoman said. No damage to BP facilities or operations was reported, she said, but Aleyska Pipeline Service Co. said it made "a myriad of repairs and conducted dozens of tests on the pipeline." No leaks were detected, although oil spill response crews were on stand-by notice during the pipeline's restart process.
After the earthquake, Aleyska immediately placed temporary supports under areas of the pipeline affected by the earthquake, and it pressure-tested two sections of the pipeline before beginning the restart.
Oil reserves stored at the shipping terminal in Valdez enabled the oil flow to be stopped without immediately affecting oil deliveries. Alyeska said it used oil stored in tanks at Pump Station One to fill a portion of the pipeline during the restart.
Between the time of the earthquake and the morning of Nov. 6, one oil tanker was loaded out of Valdez, depleting the already-low oil inventory there, but tanker loading was expected to resume on Nov. 7.
Tesoro Petroleum Corp., San Antonio, said its 72,000 b/d Kenai refinery did not incur any damage or shutdowns, and its crude and product pipeline system and network of retail outlets were unaffected.
Farwah FPSO launched at Fene yard
The 900,000 bbl Farwah floating production, storage, and offloading vessel, which will operate on Block C137 in Aquitaine field off Libya, was launched on schedule in early October from Izar Carenas's Fene shipyard. Field operator TotalFinaElf SA affiliate Cie. des Petroles Total Libya contracted Antwerp-based Exmar Offshore Co. to supply the FPSO on a leased basis.
Construction began 1 year ago on the vessel, which is 210 m in length, 44 m in breadth, and has a depth of 23 m and a design draft of 16.5 m. Bilge keels 60 m long are being fitted along the vessel's sides to strengthen support structures and aid stability. When fully laden, it will have a dead weight of 147,700 tons. The vessel will be fully outfitted before being delivered to the field in January. Photo courtesy of Izar Carenas.
