OGJ Newsletter

Dec. 24, 2001
Deadline looms for OPEC, non-OPEC output accord OPEC will need to reach some agreement soon with non-OPEC members on oil production cuts if logistics are to be arranged by next month's suggested combined reduction of 2 million b/d, said Paul Horsnell, head of energy research for London-based JP Morgan Chase & Co.

Market Movement

Deadline looms for OPEC, non-OPEC output accord
OPEC will need to reach some agreement soon with non-OPEC members on oil production cuts if logistics are to be arranged by next month's suggested combined reduction of 2 million b/d, said Paul Horsnell, head of energy research for London-based JP Morgan Chase & Co.

"The three dimensions of the issue at the moment are deadlines, quantities, and duration," Horsnell said in a report issued earlier this month. "Beyond [mid-December], it will become difficult to achieve much of a cut in January, given the need for tanker scheduling at ports and the normal process of notifying customers about lifting allocations."

He said, "That process can be, and indeed already has been, delayed a little. But some certainty is now needed fairly quickly."

In an effort to boost world prices for oil, OPEC ministers agreed at their Nov. 14 meeting in Vienna to reduce production quotas by another 1.5 million b/d effective Jan. 1, but only if major non-OPEC producers would also cut back by 500,000 b/d to prevent further loss of the cartel's market share.

OPEC members already had slashed production quotas by 3.5 million b/d, or 13%, on three earlier occasions this year, while non-OPEC producers increased production by 500,000 b/d during the same period.

IEA reported earlier this month that total world oil production increased by 290,000 b/d during November, despite an output quota cut of that same amount among the 10 unrestricted OPEC members (see related story, p. 30). That's because those cuts were more than offset by a sharp rise of 630,000 b/d in non-OPEC oil production during November, IEA officials said.

Much of the recent increase in non-OPEC production has come from Russia. In negotiations with OPEC officials since Nov. 4, Russian companies agreed to curtail their oil exports first by 30,000 b/d, then 50,000 b/d, and finally by 150,000 b/d, starting in January. That's still below the 200,000 b/d reduction that OPEC had requested from Russia, but it was matched by Norway.

US natural gas prices likely to decline through 2002
US DOE said in a study earlier this month that natural gas prices will continue to decline through 2002 as supplies increase.

Energy Sec. Spencer Abraham had directed EIA to conduct the study because of broad concerns about tight supplies, volatile prices, and regional price disparities.

Abraham said, "EIA's analysis is welcome news for US consumers and for our economy. The data clearly shows that the natural gas difficulties of 2000 were not caused by a fundamental inadequacy in the marketplace, such as a serious limitation in stock levels, but by an increase in demand overlaid with a shortage of supply."

EIA reported natural gas prices are expected to continue declining from $4.09/Mcf in 2001 to $1.96/Mcf in 2002, while supplies should increase from 22.45 tcf in 2001 to 23.53 tcf next year.

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With a more bullish outlook for gas prices, UBS Warburg projects prices will average $2.70/MMbtu for 2002 (see table), despite record storage levels at yearend 2001.

EIA noted that gas prices have declined substantially because additional drilling, mild weather, and a slowing economy have reduced the growth in consumption.

It said prices have returned to levels consistent with historical patterns, and significant price reductions and record storage additions have occurred since May 2001.

"Taken together, these factors indicate that the US natural gas market contains self-correcting mechanisms associated with well-functioning markets," DOE said.

Industry Scoreboard

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Industry Trends

ANALYST Raymond James & Associates said that Enron's financial collapse centered around the firm not taking advantage of the "true convergence" of natural gas and electric power through a balanced portfolio of soft and hard assets.

"The market, post-Enron, certainly needs to begin rationalizing where capital is employed each day," RJA said. "To us, it seems like trading firms leveraging billions to make tens of millions ought to be passed over, given the bumpy outlook for 2002. We believe that more firms will choose to own the physical production (either gas or power) rather than leveraging the firm's balance sheet to a trading desk.

"You can run all the spreadsheet simulations you want, but nothing beats owning the physical asset, whether it is gas in the ground or electrons coming out of a power plant," RJA added.

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WORLDWIDE E&P SPENDING PLANS among oil and gas companies for 2002 are down only 1.4% vs. budgets set in 2001, according to a recent Lehman Bros. poll of 357 E&P companies (see table).

"The surprising part of the surveyellipsewasn't the 18% and 20% drops budgeted for the US and Canada, respectively, but the strong 10.5% gain budgeted for international [outside the US and Canada] E&P expenditures," Lehman said.

In addition, the analyst noted that more companies overspent their 2001 E&P budgets than underspent. "This reflected overspending on the part of the majority of US independents and Canadian companies, which spent aggressively in the first half of the year," Lehman said.

Lehman also noted that the survey results indicated an increasing percentage of independents that plan to spend less than their cash flow on E&P expenditures for 2002 vs. those that plan on spending more.

SOME IDLE JACK UPS in the Gulf of Mexico have found new commitments in recent weeks, observed Bassoe Offshore Consultants, London. However, utilization has remained un- changed from the recent 2-year lows, it said.

"US gulf contractors have reported an increasing number of operator inquiries, so we anticipate utilization levels to rise in coming weeks," Bassoe noted, adding that day rates could start rising during the second and third quarters next year.

"Commodity prices are generally unstable, but some operators see this as an opportunity to drill prospects that were not economic earlier this year due to the cost of drilling. The current surplus of rigs in the [gulf] gives operators lining up drilling programs for early 2002 the opportunity to get their 'pick of the litter' at a more cost-effective price than earlier this year," Bassoe said.

Government Developments

ALASKA GOV. TONY KNOWLES has tightened the monitoring of environmental and workplace safety at oil and gas production facilities on the North Slope and Cook Inlet, while streamlining the permitting process.

Knowles said the initiative would cost $4.8 million, of which $1.1 million would be collected under existing industry fees. No new fees are proposed.

Knowles
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The governor, who issued the directive Dec. 11, said, "Alaska already boasts the world's safest marine transportation system for oil, and we must continue to lead with the highest standards for safety in the oil field and at production facilities. This commitment is not only 'doing it right' but is the key to future oil and gas development in Alaska."

Knowles said evolving industry technology and state vigilance have improved safety and minimized the environmental impacts of oil and gas development over the past 25 years, but conditions are changing.

He said pipelines, safety valves, and other infrastructure are aging, while there has been a rapid increase in exploration and development.

Earlier this year, Knowles directed the six state agencies involved in oil and gas permitting and regulation to find ways to improve capabilities in permitting, inspection, and compliance from leasing and exploration to development and production and closure and remediation.

"This initiative will improve the capacity of state agencies to do their jobs more proactively, more efficiently, and more effectively. It is not a 'gotcha'-based enforcement effort. Rather, it will engage agencies with industry early in the leasing and permitting processes for better planning, better designs, better actions, and fewer problems," Knowles said.

AN UNUSUAL COALITION of business and labor interests has urged US Senate leaders to oppose legislation mandating ethanol's use in gasoline, saying it would hurt consumers.

The coalition-which included refiners, labor unions, and highway-user groups-also urged Majority Leader Tom Daschle (D-SD) to drop his proposal in Senate energy bill S 1766 that would mandate use of renewable fuels, the most commercially available of which is ethanol, increasing from 2 billion gal/year in 2003 to 5 billion gal/year by 2012.

The letter, which also went to Minority Leader Trent Lott (R-Miss.), said the groups oppose "any attempt to add an ill-conceived and problematic ethanol mandate to legislation considered by the Congress."

The coalition said, "As ethanol use is required farther from its traditional Midwest markets, its inability to be transported by pipeline coupled with its specialized [gasoline] feedstock demands will increase gasoline prices across the nation." The groups said a recent study of a proposed ethanol mandate estimated the direct increased cost to consumers at $6.7 billion.

Quick Takes

DEEPWATER GULF OF MEXICO action leads off this week's development news.

Conoco said it will develop Magnolia field in 4,700 ft of water, and the project will cost $600 million. Magnolia, discovered in 1999, is 180 miles south of Cameron, La., on Garden Banks Blocks 783 and 784. Magnolia was discovered with the first well drilled by Conoco's Deepwater Path- finder drillship in 1999 (OGJ, Feb. 22, 1999, p. 28).

Conoco/R&B Falcon's Deepwater Pathfinder. From OGJ archives.
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Conoco and partner Ocean Energy, which holds 25% of the field, expect Magnolia to produce 150 million boe. Three existing wells will be converted to producers, and five more will be drilled to bring the field on full production. A platform that can support a completion rig will be installed in summer 2004. The partners are considering either a tension-leg platform or a spar. They are negotiating for an offtake provider and route. The production facilities will be rated at 50,000 b/d of oil and 150 MMscfd of gas. First production is expected in fourth quarter 2004, with peak production in 2005.

Conoco said Magnolia will be able to serve as a regional offtake point for future Conoco-operated developments or third party tie-ins in the southeastern Garden Banks area.

The Magnolia facilities will provide "early infrastructure in a very active part of the deepwater Gulf of Mexico." said Rob McKee, Conoco's executive vice-president, exploration and production.

ExxonMobil and its partners late this month plan to start drilling the first test wells in Doba basin oil fields in southern Chad, Reuters reported from N'Djamena. The wells are part of an overall $3.5 billion project to produce the country's first oil. Backed by the World Bank with a $200 million initial loan, the project is planned to have a 25-year life, with peak production from 300 wells expected to reach 250,000 b/d by 2005. First oil is expected in 2003, and output will be exported via a 24-in. pipeline 650 miles to the Cameroon coast, where export facilities are under construction. Project operator ExxonMobil-through its subsidiary Esso Chad-holds 40% interest in the project. Other partners are Malaysia's Petronas Carigali 35% and ChevronTexaco 25%. In the UK North Sea, BHP Petroleum and partners will proceed with a second phase of development at Keith field, which is on Block 9/8a in production license 209. BHP holds 31.83% stake in Keith, BP 34.83%, TotalFinaElf 25%, and Marubeni Oil & Gas 8.33%. Marubeni said plans call for drilling another subsea production well, expected to cost $43 million. Partners anticipate the well will increase Keith's gross proven and probable reserves to more than 21 million boe from 10 million boe. They also hope to boost output to 15,000 boe/d from 6,900 boe/d. The well will be drilled in summer 2002, and the partners expect first production in November.

IN PIPELINE NEWS, Iran awarded a feasibility study contract for a pipeline that would extend from Iran through Pakistan to India.

Australian consultant BHP Kinhill along with Snamprogetti of Italy won the contract to study the proposed $6 billion gas pipeline.

The proposed 58-in., 2,670 km line would start at a National Iranian Oil Corp.'s gas fields in southern Iran, and would transport 66 million cu m/year of gas. The report is expected to be ready by March 2002.

It was proposed that 70% of the line's capacity be contracted to India and the rest to Pakistan. Planners have suggested that a consortium of multinationals develop the project in order to moderate potential conflicts between the countries involved.

In other pipeline action, a Petrobras subsidiary has stopped BG from using the Bolivia-Brazil gas pipeline. BG was moving 2.2 million cu m/d (MMcmd) of gas on the line, but pipeline operator Transportadora Brasileria Gasoduto (TBG)contends that Petrobras has priority access to the line. Previous disputes over pipeline access had forced Brazil's National Petroleum Agency to authorize third-party access (OGJ Online, Oct. 8, 2001). Francois Moreau, BG Brazil corporate affairs director, said the company has sent lawyers to Bolivia to try to resolve the situation. Capacity of the line is 30 MMcmd, but utilization is only 12 MMcmd. TBG said the pipeline is expected to reach full capacity next year, when new electric power plants come on stream. But BG believes Petrobras will be transporting only 24 MMcmd by 2003. The Brazilian government wants to increase the natural gas portion of the nation's energy mix to 12% by 2005, up from the present 3%. The government estimates that within 4 years, consumption should reach 90 MMcmd.

OFFSHORE TRINIDAD, already a major gas province, may yet be prospective for more oil as well.

BHP Billiton said its Canteen delineation well in shallow waters off eastern Trinidad has indicated a "significant oil resource." The Global Marine Labrador I spudded the Canteen-1 this fall on Block 2(c) in 164 ft of water a mile north of the Kairi-1 oil and gas discovery on the same block. Further appraisal drilling will be required to determine the amount of reserves.

Canteen-1 was drilled to 7,070 ft TD and encountered 700 gross ft of hydrocarbon-bearing sands that included 200 ft of net oil pay and 179 ft of net gas pay. The well was tested at a rate of 3,700 b/d of 33° gravity oil from a 60 ft interval through a 11/8-in. choke. BHP Pres. and CEO Philip Aiken said, "We will look to fast-track the development, which, given the relatively shallow water and proximity to the coast, could be in production within 2-3 years." BHP operates Canteen with a 45% interest, Elf Petroleum Trinidad has 30%, and Talisman Energy holds 25%.

GAS HYDRATES research leads alternate fuel news.

US DOE awarded a gas hydrates research contract to Halliburton affiliate Westport Technology Center International, an exploration and production laboratory.

Halliburton said the $820,000 contract will provide laboratory experiments and computer modeling.

Westport will characterize gas hydrate reservoirs and develop simulators for methane gas production from Gulf of Mexico hydrates. The company also will develop lab services and software tools for operators to use in prospect evaluation, well planning, and life-of-field management processes.

Halliburton Energy Services Pres. Jody Powers said, "Naturally occurring hydrates may be a detriment to the development of conventional hydrocarbon resources; however, methane production from these now troublesome zones may become a new and important hydrocarbon resource for the future."

Meanwhile in wind power news, the Bonneville Power Administration (BPA) and PacifiCorp Power Marketing, (PPM) announced the federal power agency's largest renewable energy purchase in BPA's history. The deal calls for PPM to supply 90 Mw/year to BPA to power 18,000 Northwest homes for the next 25 years. PPM will supply the energy from the Stateline wind generating plant on the Washington-Oregon border. In addition to the BPA contract, PPM has signed the biggest public utility wind power contract to date in the US-a 20-year supply deal with Seattle City Light, the municipal utility for Seattle. Seattle City Light will start buying 50 Mw of power in January 2002, doubling to 100 Mw in August 2002, then 150 Mw in January 2004 and, potentially, to 175 Mw in August 2004.

ON THE REFINING FRONT, Kazakhstan's national oil firm Kazakhoil awarded Marubeni and JGC a contract to modernize its 104,000 b/d refinery at Atyrau. The refinery processes light crude from Tengiz oil field.

Previously, Marubeni conducted a feasibility study for the project, and JGC and Marubeni began engineering work. The $235 million project includes the revamp of the existing crude distillation unit and the construction of a naphtha splitter, naphtha hydrotreater, isomerization, diesel hydrotreater, and utility and offsite facilities.

Out of the total project cost, about $200 million will be financed by the buyer's credit from the Japan Bank for International Cooperation and the Nippon Export & Investment Insurance. The project's goal is to improve the quality of Kazakhoil's gasoline and diesel fuel, as well as to make the plant more efficient.

ALON USA, a subsidiary of Alon Israel Oil, and Wright Asphalt Products, will build a tire rubber modified asphalt plant in Big Spring, Tex. The plant, which will use ground tires to make asphalt for roads in West Texas and eastern New Mexico, will be built at Alon's 61,000 b/d refinery. TotalFinaElf sold the refinery to Alon as part of the Total-Petrofina merger (OGJ Online, May 23, 2000). Groundbreaking is slated for January, with project completion expected in April. Alon will employ 50 extra people for the construction phase, but current refinery employees will operate the asphalt plant.

PHILLIPS PETROLEUM plans to begin producing China's largest offshore oil field, Peng Lai 1903 field in Bohai Bay, starting in August 2002.

Phillips China operates the field with 49%. The remaining interest is held by CNOOC,which has a right to 51% of any offshore developments.

Peng Lai 19-3 is expected to eventually produce 120,000-150,000 b/d.

Phillips China has invested $2 billion at Peng Lai, which analysts say hold China's second-largest reserves behind the onshore Daqing field complex controlled by PetroChina.

Renovation work is expected to enhance production on the Groningen acreage in the northern Netherlands. Dutch firm NAM awarded the Stork GLT consortium a 135 million euro, 3-year contract involving three production sites at Slochteren gas field. Work is slated for the Zuiderpolder, Schaapbulten, and Oudeweg sites. The contract was awarded under a 1997 outline agreement. The first phase of the project, covering 11 of the 29 production installations, is worth more than 454 million euros to Stork GLT, which has an option for the remaining installations. NAM and Stork GLT also signed a contract in 1997 for the maintenance of all the renovated production installations for 25 years. The consortium has performed similar work for NAM at the Tjuchem, Beierum, de Paauwen, and Siddeburen sites. In Venezuela, Statoil and state-owned PDVSA have signed a memorandum of understanding to increase oil production from Ceuta Area 2 Sur field in Lake Maracaibo. The companies plan to increase oil production from the current level of 18,000 b/d through the use of new well technology. In the first phase, expected to take 3-4 months, Statoil and PDVSA will conduct joint studies to assess possibilities for increasing production in the technically challenging field. Statoil's project manager Ole Preben Berget said work will begin immediately on the studies. Arabian Oil signed a memorandum of understanding with the Kuwaiti government that would allow it to keep producing Khafji oil field beyond the January 2003 expiration date. Arabian Oil, a consortium of Japanese companies, is Japan's largest crude producer. A final agreement is expected by Jan. 29, 2002. The field straddles the border of Saudi Arabia and Kuwait. Arabian Oil lost the concession rights to the Saudi Arabian side of the field in February 2000. Japan, heavily dependent on imported crude from the Middle East, is trying to maintain a strong foothold in overseas oil-producing basins, especially in the Middle East.

NEGOTIATIONS ARE under way for Bolivian gas to supply a proposed LNG terminal in North America.

Utility holding company Sempra Energy and Pacific LNG, a consortium formed by Repsol-YPF, BG, and PanAmerican Energy, agreed to begin negotiations for a 20-year supply of Bolivian LNG to be delivered to northwestern Mexico and southern California. PanAmerican Energy is a joint venture owned by BP 60% and Bridas 40%.

The proposed agreement will include the output of a two-train LNG plant on the Pacific coast of South America, which could export 800 MMcfd of gas from Bolivia to North America. The LNG will be delivered to the proposed Sempra Energy-CMS Energy LNG terminal to be built near Ensenada, Baja California, Mexico (OGJ Online, Oct. 5, 2001).

The gas would serve new and existing power plants and industries in both Baja California and southern California.

The companies involved in Pacific LNG are also partners in Bolivia's 13 tcf Margarita field, which will be the gas source. Repsol-YPF operates Margarita.