OGJ Newsletter

April 8, 2002
The Organization of Petroleum Exporting Countries' market share will likely rebound to 40%, according to Merrill Lynch & Co., and it will do so without an oil price war.

Market Movement

OPEC's market share likely to increase in long term

The Organization of Petroleum Exporting Countries' market share will likely rebound to 40%, according to Merrill Lynch & Co., and it will do so without an oil price war.

"Many bearish calls relating to oil prices and energy shares center around the notion that ultimately OPEC will be forced to 'crash prices' to increase market share relative to non-OPEC producers," Merrill Lynch said in a research note. "These arguments generally focus on OPEC's short-term reduction in market share as the organization reduced output to compensate for slowing demand.

OPEC's outlook, however, is over the longer term, and longer term, the secular slowing in the rate of non-OPEC supply growth leaves OPEC in the strongest position since the 1970s," it said.

Generally, OPEC's market share has been 39-40% since 1992, Merrill Lynch noted. "While OPEC's market share did briefly decline to 38% in the first half of 2002, the need for 2 million b/d of incremental OPEC oil during the second half of 2002 will rapidly bring OPEC's market share back to 40%," it said.

Several forces behind rise in natural gas prices

Meanwhile, several variables have resulted in natural gas prices rising by more than 50% on the New York Mercantile Exchange since mid-February. Chief among them are a 30% spike in crude oil prices, tensions in the Middle East, concerns over US nuclear power capacity, and positive gas storage trends.

NYMEX gas for May delivery closed Apr. 1 at $3.53/MMbtu, putting the near-month futures gas contract up more than $1.25/MMbtu since mid-February's daily closings of $2.18-2.25/MMbtu.

Natural gas markets clearly faced upward price pressure after some significant corrosion problems were found at the Davis-Besse nuclear reactor in Oak Harbor, Ohio. The Nuclear Regulatory Commission has said it might impose mandatory inspections and possibly shutdowns on similar nuclear plants (OGJ, Apr. 1, 2002, Newsletter, p. 5).

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"A worst case estimate suggests that over 5 bcfd of gas demand could be added if 40,000 Mw (two-thirds of the nuclear plant power capacity potentially impacted, out of a total of 65,000 Mw) is taken offline," said David A. Pursell of Simmons & Company Inc. in a research note (see table).

Even if only 8,000 Mw of nuclear power capacity is impacted, it would increase natural gas demand by 1 bcfd until the problems are resolved, he said.

The US has 69 plants with reactor designs similar to the Davis-Besse unit. This represents 71% of the nation's nuclear power capacity. Meanwhile, 20,000 Mw of the 65,000 Mw potentially affected already is scheduled for refueling outages by June.

Crude oil prices

Natural gas prices also have been pulled along with spiking crude oil prices, which could go higher given circumstances such as military action against Iraq, Pursell said, noting President George W. Bush's "axis of evil" remark in his State of the Union address. Bush lumped Iran, Iraq, and North Korea together as culprits in the fight against terrorism.

Oil prices also have been driven by successful efforts to curb oil production coordinated by OPEC in concert with some key non-OPEC oil exporters.

Another factor in oil price strength has been a string of bullish weekly US oil inventory reports suggesting a rebound in demand fueled by economic recovery. "The historical relationship between natural gas and fuel oil pricesellipsesuggests that the concurrent increase in crude oil and natural gas prices is not coincidental," Pursell said.

Positive gas trends

Weekly gas storage numbers, meanwhile, began to improve in February when adjusted for weather and compared with both the 7-year average withdrawals and withdrawals earlier this year.

"This was clearly a catalyst for natural gas prices to increase. However, we believe there is a chance that the outperformance seen in the February and early March withdrawals was based on increased gas-fired power demand due to unusually high maintenance of nuclearellipseand coal power plants," Pursell said.

He said he plans to watch inventory data in coming weeks to prove or disprove this thesis.

Industry Scoreboard

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Industry Trends

CANADIAN NATURAL GAS production has gained momentum despite a slow start in January, thanks in part to the recently completed pipeline expansion at Ladyfern field in northeastern British Columbia.

That word comes in a recent research note from Lehman Bros. Inc. analyst Thomas Driscoll of New York. He believes Canadian gas production could possibly exceed investor expectations. Natural gas well completions during the winter drilling season are up 13% compared with last year despite rig utilization being down.

Total Canadian natural gas production grew 113 MMcfd, or nearly 5%, vs. prior-year levels, to 14.8 bcfd in January 2002. Meanwhile, month-to-month Western Canadian production was up 3.3% as of Mar. 20, when it averaged an estimated 14.4 bcfd. This marked a 1% increase from January 2002 levels but still fell 0.4% below February levels.

"Production should begin to benefit from the increased pipeline capacity at Ladyfern," Driscoll said. He expects volumes soon will reach 785 MMcfd compared with an estimated February average rate of 500 MMcfd (OGJ, Mar. 25, 2002, p. 9).

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"The ultimate 235 MMcfd of excess pipeline capacity left over after peak production is reached could allow for fast-track development of any potential look-alike discoveries," Driscoll said.

Total capacity for Ladyfern is capped at 785 MMcfd by a recent partnership agreement among Alberta Energy Co. Ltd., Calgary, Apache Corp., Houston, Canadian Natural Resources Ltd., Calgary, and Murphy Oil Corp., El Dorado, Ark.

US NATURAL GAS production is on the decline, and the decline is accelerating rapidly, according to preliminary results of a Raymond James & Associates Inc. first quarter survey of 30 of the largest US natural gas producers.

On a year-over-year basis, US gas production is projected to be down by 2.9% in the first quarter of 2002, said Wayne Andrews, RJA analyst. The producers surveyed represent 45% of US gas production.

"First quarter US natural gas production declined by 1.8% from the fourth quarter of 2001. This is significantly higher than the 1.3% sequential decline from the third to fourth quarter in 2001," Andrews said.

Supply is declining much faster than most analysts expected, Andrews said. US gas production trends generally lag the rig count by 3-6 months, but last year, US gas production began showing declines before drilling activity peaked in July.

Producers were drilling wells that they could bring on production quickly at high flow rates. But production from high-flow projects likely will be down by 30-40% this year, he projected.

"As a result, sequential production declines should continue to gain momentum as the year progresses, and we continue to believe that US natural gas production could be down by as much as 5-6% this summer on a year-over-year basis," Andrews said.

RJA has increased its 2002 Henry Hub natural gas price forecast from $3.25/MMbtu to $3.45/MMbtu.

Government Developments

THE INDUSTRY wants a rehearing on Minerals Management Service's gas royalty rules. The American Petroleum Institute is contesting a Feb. 8 decision by the US Court of Appeals for the District of Columbia Circuit in Washington, DC, that largely affirmed MMS's "duty-to-market" gas royalty rules.

If the full appeals court refuses to rehear the case or industry loses again, API could appeal to the US Supreme Court. Companies that drill on federal lands or waters say that if downstream marketing adds to the value of the gas at the lease, the government should therefore share the costs with the royalty owner (OGJ Online, Feb. 22, 2002).

David Deal, API's assistant general counsel and director, Office of General Counsel, said industry believes that royalty is due on the value of production at the lease, not on the value inclusive of value added downstream. The API court filing emphasized the plain terms of the mineral leasing statutes and the lease terms. API also contends that the court went overboard in its deference to the agency.

"For example, the MMS plainly has authority to issue regulations that affect the methodology it employs to arrive at the value of production, but it does not have authority to alter the basic bargain by categorically excluding marketing costs away from the lease," Deal said.

API also urged the judges to consider that MMS's categorical exclusion of marketing costs undercuts FERC Order 636, whose open-access character sought to encourage downstream marketing.

Gas royalties traditionally account for more than 60% of the agency's royalty revenues. According to an analysis by the House Committee on Resources, MMS programs will collect about $4.2 billion in revenues next year, mostly from gas and oil. The committee also predicted that $900 million in Gulf of Mexico-derived crude oil royalties will be diverted to fill the Strategic Petroleum Reserve by delivering royalty-in-kind volumes.

The court decision said API and the Independent Petroleum Association of America argued that MMS was wrong for refusing to permit deductions for costs incurred in marketing gas downstream of the wellhead. Industry's arguments focused on fees incurred in aggregating and marketing gas for downstream sales, intrahub transfer fees charged by pipelines, and any unused pipeline demand charge.

The appeals court reversed an earlier district court's decision and ruled that MMS's method of calculating downstream marketing costs was fair.

On the unused pipeline issue, the court affirmed the district court ruling and agreed with the producers' assertion that the cost of reserving space on a pipeline, i.e., the unused pipeline demand charge, should be considered by MMS.

The district court ordered MMS and industry to share the cost of the reservation fee, and the appeals court said the government offered no reason why industry should be liable for the entire amount.

Quick Takes

Apache Corp. announced its second oil discovery on the East Bahariya concession in Egypt's Western Desert.

Apache's Southeast Karama-1X discovery well, drilled on a prospect developed from interpretation of 3D seismic data gathered last year, flowed on test as a rate of 1,140 b/d of 43° crude oil from the Cretaceous Abu Roash G formation. It was Apache's seventh discovery worldwide in 2002.

The well is in the Abu Gharadig basin, about 1.2 miles southeast of Karama field. Including the latest discovery, which is now on stream, combined production from the Karama and Southeast Karama fields is averaging 1,800 b/d of oil. Six additional prospects have been identified in the area. Apache holds 100% interest in the 1.4 million acre concession. The company plans to drill at least three more wells in the concession by yearend.

In other exploration news, Pakistan's state owned Oil & Gas Development Co. Ltd. (OGDC) reported that tests of the Chak 63 No. 1 well in Sanghar district of Sindh province in Pakistan demonstrated commercial potential on the Sanghar block. Production testing started Mar. 21. An initial short duration test produced 2,000 b/d of oil and 4 MMcfd of natural gas. Chak 63 was drilled to 3,000 m. OGDC operates Chak 63 in a joint venture with Orient Petroleum Inc. and the government of Pakistan. Pakistan has been pressing efforts to boost oil and gas production for more than a decade (OGJ, Apr. 22, 1991, p. 37). Pakistan currently produces 54,600 b/d of oil. It lists oil reserves of 208 million bbl and gas reserves of 21.6 tcf.

Elsewhere in Egypt, Apache started oil and natural gas production from its Ras Kanayes lease.

The Ras Kanayes development lease was brought on production at the rate of 2,130 b/d of crude and condensate and 17.8 MMcfd of natural gas from the Jurassic Khatatba formation. Apache operates Ras Kanayes as part of its Khalda operations, with a 63.64% contractor interest. Kuwait's Kufpec Ltd. holds a 36.36% interest.

The lease comprises 77,690 acres in the Matruh basin 230 miles west of Cairo. Apache took over operation of the Khalda concession in 2001 with its acquisition of Repsol-YPF SA's interests in the Western Desert.

A temporary power outage at Suncor Energy Inc.'s oil sands facility in northern Alberta could prevent the company from reaching its 2002 production target. Partial production at the facility resumed Mar. 25 following a Mar. 20 power outage that interrupted the plant's operations for about an hour. Immediately following the outage, Suncor said the impact on the plant's production was expected to be "minimal." Production quickly was ramped up to 180,000 b/d of oil following the return of power. "Maintenance work previously scheduled to occur in April was brought forward to take advantage of the downtime," Suncor stated. Prior to the incident, the company expected first quarter production to reach 190,000-200,000 b/d of oil. Its production target for 2002 remains 210,000 b/d of oil, it said. The company reported increased flaring and emissions from the plant while it worked to restore production to full rates.

Talisman Energy (UK) Ltd., a unit of Talisman Energy Inc., Calgary, reported bringing Hannay field on production in the central North Sea. The field on UK Continental Shelf Block 20/5c, about 13.5 km northwest of the Talisman-operated Buchan Alpha facility, is producing 15,000 b/d of oil from a single horizontal subsea well. Hannay field has estimated reserves of 10 million bbl and a life expectancy of 8 years. The well was tested at 21,900 b/d of oil, but it will be produced initially at 14,000-16,000 b/d "in order to maximize recovery for the reservoir and due to process plant limitations on the Buchan facility," Talisman said. Hannay field partners are operator Talisman 85.72%, EDC (Europe) Ltd. 13.37%, and First Oil Expro Ltd. 0.91%.

BP PLC awarded Aker Kværner an $11 million contract to supply advanced drilling and mooring equipment for one of the largest oil fields-in almost 2,000 m of water-in the Gulf of Mexico. The equipment is for a semisubmersible platform that BP is having built for installation in Thunder Horse oil field in the Mississippi Canyon area. Together with three nearby oil and gas fields, Thunder Horse-formerly known as Crazy Horse-is part of a pioneering project for oil and gas production in ultradeep gulf waters.

The equipment has been developed and will be delivered by Maritime Hydraulics and Maritime Pusnes in first quarter 2003.

Meanwhile, Royal Dutch/Shell unit UK Exploration & Production let a contract valued at more than £10 million to Aker Kværner subsidiary Aker Verdal AS for engineering, procurement, and construction of a jacket and piles for the Goldeneye platform to be located on the UK Continental Shelf in June 2003. Shell UK Ltd. announced the go-ahead in March for the $300 million Goldeneye gas-condensate project in the outer Moray Firth area, 100 km northeast of St. Fergus, Scotland. Facilities for the project include the offshore, un- manned, minimum-facilities platform, a 105-km pipeline tying back the platform to St. Fergus onshore, and a new processing module at St. Fergus. Aker Kværner's work will be undertaken at the Aker Verdal yard in Norway. Aker Kværner Technology will start design engineering immediately, while fabrication will begin in October. At its base, the jacket will measure 35 m square; it will have a height of 140 m and a total weight of 3,000 tonnes.

South Korea's Korea National Oil Corp. (KNOC) continues to advance toward bringing natural gas on stream from Donghae-1 gas field in the Ulleung basin 60 km off Ulsan. Once the field is on line, it would mark the country's first commercial oil and gas production. KNOC let multiple contracts to Halliburton Energy Services Group (HESG), a unit of Halliburton Co., Dallas, for the provision of drilling fluids, drilling bits, coring services, measurement-while-drilling and directional drilling operations, and bundled subsea well completion services. Final planning stages call for drilling three subsea wells, which will be tied back to a production platform and pipeline to a gas processing plant onshore.

Transporte de Gas del Peru (TGP) will go ahead with preliminary work on the Camisea project's transmission pipelines.

Work on the Camisea natural gas project is on schedule according to Peru's energy and mines minister, Jaime Quijandria. The minister said the project should be ready in the first quarter of 2004, about 6 months ahead of the contract's deadline in September 2004.

Quijandria said preparation for drilling the first production well in San Martin field on Block 88 was beginning this month; drilling is expected to wrap up by August-September.

The minister said around 52,000 tonnes of equipment and materials had been barged so far on the Urubamba River to the Malvinas camp, where a dock has been built for unloading cargo. A consortium partner said about $100 million had been spent in the first year, mainly on studies, and the heavy spending begins this year.

Quijandria estimates total costs for the project at $2.6-3.0 billion. About $1.6 billion is estimated for exploitation, drilling, and production activities, and $1.2-1.6 billion is estimated for transportation and distribution.

Work is also scheduled to begin for construction of the gas and liquids pipelines within the coming weeks. The environmental impact study for the pipelines has been approved, although, as was expected at the time, the consortium must meet additional conditions specified by the authorities.

TGP is negotiating with InterAmerican Development Bank and Andean Development Corp. to finance some $125 million towards construction of the gas and liquids pipelines. TGP CEO Alejandro Segret said the company expects to raise another $500 million from corporate bonds to be issued by Techint. Techint unit Tecgas is operator of the Camisea transport and distribution consortium. Citibank is preparing the preliminary information for the issue of the bonds.

Although figures sometimes vary, the Camisea fields have proven reserves of 13 tcf of natural gas and 600 million bbl of condensate, according to the ministry.

In other pipeline news, China National Petroleum Corp. earmarked $700 million to invest in a crude oil pipeline linking Russian oil production with refineries in northern China. Russian companies will invest another $1 billion in building the 2,400 km pipeline linking Angarsk oil field in Western Siberia's Irkutsk region with refineries near China's top producing oil field complex at Daqing. The framework agreement on the construction of the pipeline was signed last September between CNPC and OAO Yukos, Russia's second largest oil company, and Transneft, Russia's major oil transportation company. CNPC and its Russian partners are expected to complete by August a feasibility study on the pipeline project. It is expected to take another 10 months for the Chinese government to complete the approval process. The project is scheduled to start construction in July 2003 and be completed in 2005. It will transport an initial volume of 20 million tonnes/year (400,000 b/d) by 2005, and design capacity will be expandable to 30 million tonnes/year (600,000 b/d) by 2010.

The crude initially will come from existing fields Yukos operates in Western Siberia. The expanded capacity will accommodate a ramp-up in production when Yukos later brings on stream new fields in the Angarsk region. Yukos currently ships crude by rail to China, at last report covering volumes of a combined 1.5 million tonnes/year (30,000 b/d) to Chinese state oil companies. The final route chosen bypasses Mongolia via Manzhouli, on the Sino-Russian border. The Russian companies earlier had indicated a preference for a shorter, lower-cost route of 2,330 km, traversing Mongolia. The Chinese preferred the longer route of 2,500 km that would bypass Mongolia for security reasons.

In gas processing, Sasol Petroleum Temane Ltda., a unit of South Africa's Sasol Ltd., let a $130 million contract to Foster Wheeler South Africa (Pty.) Ltd., a unit of Foster Wheeler Ltd., for the engineering, procurement, and construction management of an upstream gas facility to be built at Temane, Mozambique. It is part of a project that is the first major upstream and petrochemical development in Mozambique.

Based on the contract, Foster Wheeler will develop gas gathering and processing facilities in Temane gas field to collect sales-quality gas for transport to South Africa. The development will include the infield flow lines from 11 well sites and the central processing facilities, Foster Wheeler said. The facility will be able to produce 111.6 bcf/year of sales-quality gas.

Sasol late last year signed a deal with Mozambique that would govern construction of a $1.2 billion pipeline to move gas from that nation to South Africa (OGJ, Sept. 24, 2001, p. 9). Completion of the line, assuming certain approvals, is expected in the first half of 2004.

The overall project comprises the gas field development in Mozambique, the 660 mm pipeline extending 865 km to Secunda in South Africa, the conversion of Sasol's current town gas pipeline network, and the supply of gas to Sasol customers in South Africa.

The US Department of Justice, Environmental Protection Agency, and the state of Illinois announced Apr. 1 a settlement requiring Premcor Refining Group Inc. to pay $6.25 million in environmental fines.

Premcor Refining, formerly known as Clark Refining & Marketing Inc., will pay the penalty to resolve claims that its 80,000 b/d Blue Island, Ill., refinery violated five federal statutes, federal authorities said.

Justice department officials said that Premcor violated the Clean Water Act; Clean Air Act; Resource Conservation and Recovery Act; Comprehensive Environmental Response, Compensation, and Liability Act; Emergency Planning, Community Right-To-Know Act; and Illinois state environmental laws and regulations. Premcor closed the refinery in January 2001; it had been in operation under various owners since the 1920s.

A consent decree was filed in US District Court in Chicago and is subject to a 30-day public comment period and court approval.