Market Movement

July 7, 2003
Last week, the US rolled toward a long Fourth of July weekend with unusually tight gasoline inventories and futures prices for natural gas near a 3-month low in expectation of another large build in US underground natural gas storage.

Gasoline stocks tighten prior to US holiday

Last week, the US rolled toward a long Fourth of July weekend with unusually tight gasoline inventories and futures prices for natural gas near a 3-month low in expectation of another large build in US underground natural gas storage.

Yet futures prices for oil and petroleum products last week slumped in midweek profit taking on the New York Mercantile Exchange, following a rally by those commodities over the previous three trading sessions that was sparked by Tropical Storm Bill threatening refineries along the Louisiana Gulf Coast and by a strike in Nigeria over the increased price of petroleum products there.

Traders expecting an increase in US oil inventories were told July 2 instead that crude and gasoline stocks fell during the week ended June 27. The American Petroleum Institute reported US oil inventories fell by 2.1 million bbl to 278.5 million bbl in that period, with gasoline stocks dropping by 2.3 million bbl to 207.8 million bbl. API said US distillate inventories barely increased during the period by 23,000 bbl to 109.3 million bbl. The US Energy Information Administration said US gasoline inventories plunged by 3.2 million bbl to 205 million bbl during the week ended June 27, with crude stocks falling 2.1 million bbl to 282.1 million bbl. It put the increase of distillate stocks at 300,000 bbl to 109.7 million bbl.

"The main story is yet again gasoline," said Paul Horsnell, J.P. Morgan Securities Inc., London, in a July 3 report. "The seasonal build in (US gasoline) inventories came to an end 3 weeks earlier than normal. Inventories are now 600,000 bbl lower than they were at the end of April, when a normal pattern over that period would be a build of 10 million bbl," he said, referring to EIA data.

"From this point, inventories would normally fall until the start of September, on average falling by about 20 million bbl from a base of around 217 million bbl. This year, the end of June base is just 205 million bbl," Horsnell said. He warned, "To finish (this summer driving) season at normal levels, inventories can only fall at one-third of the normal rate. To achieve that, price differentials will have to adjust sharply, and so far that is not happening."

Horsnell noted, "In 2001, when gasoline prices spiked to $17/bbl above crude oil, the end of June inventory base was 221 million bbl. Gasoline prices are currently less than $7/bbl above crude oil, and it doesn't look to be enough yet. The end of June base was almost the same in 2000, when demand was lower and gasoline was $10/bbl higher than crude oil."

His conclusion: "The market may have been caught napping in the gasoline situation. Inventories have failed to rise even when weather in June was bad and demand subdued. However, the breaking of the bad weather has produced a very high implied demand figure in the last week of 9.48 million b/d."

Natural gas market continues slump

The natural gas market continued its slump early last week, "pressured by technical selling and a soft physical market amid expectations for soft demand during the holiday-shortened week," said analysts at Enerfax Daily. EIA on July 3 reported injection of 97 bcf of gas into US storage in the week ended June 27, somewhat lower than analysts expected.

Natural gas futures prices on NYMEX have been in the doldrums since June 26 when EIA reported a record injection of 127 bcf of gas into US underground storage for the week ended June 20. That marked the fourth consecutive week that EIA's tabulations of gas injections exceeded 100 bcf, and it apparently has convinced traders that the previous bullish gas market has ended.

But in a June 27 report, Robert S. Morris at Banc of America Securities LLC, New York, claimed EIA's figures have "everyone scratching their heads." EIA's previous report of a record injection, he said, indicated "an additional 2 bcfd of backed out demand (and) 'reverse line pack,'" in which excess gas previously "packed" into pipelines is drawn down. He earlier estimated 40-75 bcf more gas can be packed into the US pipeline grid at maximum allowable pressure vs. the amount required for minimum operating pressure.

An incremental 2 bcfd of "just purely backed out demand," as major consumers reduce purchases of high-priced natural gas, would equal "nearly 10% of total US industrial plus electric generating consumption," said Morris. "We believe it is highly unlikely that nearly 10% of total domestic industrial-electric generating sector shut down (in 1) week."

Industry Scoreboard

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Industry Trends

RENEWABLE POWER generation technologies including geothermal energy and biogas-fueled generators are contributing a growing percentage of the world's total bulk generating capacity.

Norwalk, Conn.-based Business Communications Co. Inc. (BCC) said the total electricity generating capacity from renewable energy systems outside of large hydro surpassed 100 Gw in 2002.

With a world total bulk generating capacity from all sources of 3.35 Tw in place, the renewables percentage has climbed to nearly 3%—up from a minuscule percentage 10 years ago, BCC said in a recent report.

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Geothermal and biogas together account for more than 10% of renewables capacity. Their share of total capacity varies from region to region, depending on resource availability and the project economics.

Most renewables generating capacity is found in developed economies. Geothermal breaks this trend because Indonesia and the Philippines have large geothermal capacities.

Similarly, bulk capacity biogas is confined to countries having landfills, sewage treatment infrastructure, and industrial animal operations.

Power-on-demand systems, such as biogas-fueled energy conversion devices and small hydro, have outputs as much as 10 Mw. Biomass combustion and geothermal power systems can be larger.

"Biogas from organic waste matter has a horizon in the tens of gigawatts of capacity," BCC said.

Regional growth rates approaching the double digits are forecast for biogas-fueled generation industry.

US TUBULAR prices could hit record highs, analysts said.

Increased US oil and natural gas drilling activity has resulted in higher oil country tubular goods (OCTG) demand. Prices are on the increase because of rising demand coupled with a weak US dollar.

In 2001, US drilling activity peaked at nearly 1,300 rigs, driving OCTG consumption to peak levels of about 250,000 tons/month of pipe. This increased demand led to nearly a 30% increase in tubular prices from the lows experienced in 1999, J. Marshall Adkins of Raymond James & Associates Inc. said in a June 9 research note.

Despite the peak pipe consumption, "pricing was still 2-3% shy of the previous decade highs experienced in 1997 when US drilling activity topped at just over 1,000 rigs and OCTG consumption hit a peak rate of only about 225,000 tons/month," Adkins said.

Government Developments

THE US is worried a UK-sponsored anticorruption initiative is too restrictive on multinational oil companies that do business in developing countries because it does not hold government officials accountable for their own misdeeds.

Multinational oil and gas companies are working with the US and the UK on a voluntary anticorruption program championed by UK Prime Minister Tony Blair aimed primarily at resource-rich developing countries.

The UK's Department for International Development held a high-level conference in London on June 17 on its Extractive Industries Transparency Initiative with 30 nations and 17 oil and mining companies in attendance.

US Department of State officials said the current EITI proposal, inspired by George Soros's "Publish What You Pay" scheme, "presents a much more restricted approach to transparency and accountability that is focused primarily on company disclosure of payments to governments. Such an approach will not shed light on government actions to increase transparency and allocate resources," according to an internal briefing statement. "Further, it will not hold government officials accountable for misuse or mismanagement of these resources," the background statement said. "We are also concerned that the state-owned enterprises will escape scrutiny."

US government officials told OGJ that the document confirms the US remains committed to greater transparency in the extractive industries sector, but that the EITI plan in and of itself may not be adequate. They added that any international consensus on anticorruption should reflect broader discussions made at the recent G-8 summit in France that called for greater government accountability.

US public statements on the UK plan were more conciliatory.

In remarks to the group, Janice Bay, deputy assistant secretary for international finance and development, said, "We look forward to cooperating with the UK and other developed country governments, with the governments of interested developing countries, with international organizations, with companies, and with civil society to implement greater transparency in the extractive industries sector."

Identifying countries willing to be part of a voluntary pilot program that ties future development deals with specific transparency goals "must be a high priority," she said.

None of the attending countries specifically committed to being part of a pilot, although Azerbaijan, Ghana, Trinidad and Tobago, Indonesia, Timor-Leste, and Nigeria are expected to be possible candidates within the coming year. Iraq may also be considered as a test case, but its participation ultimately hinges on pending US government decisions on the timetable in which a democratically elected government is allowed to form.

Multinational oil companies that attended the meeting downplayed the US criticism of the UK plan, saying the EITI draft is a good first step on the anticorruption issue. They also stressed that they expect to see calls for greater transparency on several fronts.

Companies including BP PLC, ExxonMobil Corp., ConocoPhillips, and ChevronTexaco Corp. told the EITI gathering in separate statements that they oppose corruption in any form. But they also said requiring oil companies to disclose deal terms without holding governments themselves accountable won't stop corruption.

Quick Takes

Two KERR-McGEE CORP. affiliates acquired 100% interest in nine oil and gas exploration and production licenses in the Blake Plateau basin about 100 miles north of Freeport, Grand Bahamas Island. The licenses—acquired from the Bahamas government by Kerr-McGee Bahamas Ltd. and Atlantic Exploration & Production Co.—cover 6.5 million acres in 650-7,000 ft of water.

The exploration period under the licenses extends for as long as 12 years, while the production phase is for 30 years with possible extensions.

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The first phase of the work program includes interpretation of existing seismic data and acquisition of new seismic data, Kerr-McGee said. The firm is not aware of any previous drilling on that acreage.

The Blake Plateau basin is on the southern margin of a large structural terrace between the shelf margin and Atlantic abyssal plain. These blocks contain multiple play types, including large untested carbonate structures that Kerr-McGee said are similar to producing fields in North Africa and the Middle East.

BHP Billiton Ltd. has found oil with a wildcat on ultradeepwater Chinook prospect in the US Gulf of Mexico, reported interest owner Petroleo Brasileiro SA (Petrobras). The BHP Billiton-operated C.R. Luigs drillship on Jan. 13 spudded the Chinook No. 3 well on Walker Ridge Block 469. The well, drilled in 8,830 ft of water, reached 27,650 ft TD and discovered a gross oil column of 620 ft, with 260 ft of net pay. It was temporarily abandoned for future use. Operator BHP Billiton has 40% interest in Chinook prospect; Petrobras owns a 30% interest, and Total SA and Amerada Hess Corp. are the other interest holders, with 15% each. In other exploration action, Talisman Energy Inc., Calgary, has entered into an agreement with Total E&P USA Inc. to farm in to 360 sq miles of Total's lease in 10 National Petroleum Reserve Area blocks on the Alaskan North Slope. The prospects lie west of the Lookout-Rendezvous area, site of 430 million bbl Alpine field and other recent discoveries. Talisman unit Fortuna Exploration LLC will participate in drilling an exploration well on a selected prospect to earn a 30% interest in the prospect, with the right to earn a similar interest in the remaining prospects. First drilling is expected in early 2004.

Partners in the Sakhalin II LNG project on Russia's Sakhalin Island have awarded $95 million in lump sum contracts for the construction of two LNG storage tanks at a planned natural gas liquefaction plant at Prigorodnoye on Aniva Bay, Sakhalin Island (see map, OGJ, Oct. 1, 2001, p. 58).

The contracts were awarded to CB&I Europe BV and CMP Holdings BV, both units of The Woodlands, Tex.-based Chicago Bridge & Iron Co. NV (CB&I).

The CB&I units will handle the engineering, procurement, and construction (EPC) of two 100,000 cu m LNG storage tanks, which will be the first LNG tanks designed and constructed in Russia, according to CB&I.

The CB&I units were selected to construct the tanks by Chiyotec Ltd. and CTSD Ltd., both of which were awarded contracts along with their Russian partners, NIPIgasperabotka and Khimenergo Consortium, for the implementation of the overall LNG project by the project's owner, Sakhalin Energy Investment Co. Ltd. (SEIC). SEIC shareholders are Shell Sakhalin Holdings BV, Mitsui Sakhalin Holdings BV, and Diamond Gas Sakhalin BV.

CB&I said that completion of the tanks is anticipated in spring of 2007 and first LNG is expected to be delivered from the terminal during 2007.

BG Group PLC unit BG Gas Marketing Ltd. agreed to principal terms set by Egyptian LNG (ELNG) Train 2 partners for purchase of the entire 3.6 million tonne/year output of LNG from the proposed Train 2 unit in Egypt.

In turn, ELNG Train 2 partners awarded a contract and a notice to proceed to Bechtel Corp. for the EPL of the $550 million Train 2 facilities, which are scheduled to start commercial operations in 2006. LNG to be purchased by BG Gas Marketing is to be supplied to BG LNG Services at the Lake Charles LNG import terminal in Louisiana. A second agreement stipulates that LNG from Train 2 also will be supplied to a LNG import terminal being developed by BG Group and Ente Nazionale Energia Elettrica SPA at Brindisi, Italy, beginning about 1 year after Train 2 initiates commercial operations.

In other LNG activities, Dominion Resources Inc. Richmond, Va., is pumping nitrogen into 3 miles of pipe at its Cove Point, Md., LNG terminal as part of a cooling down process prior to receiving a "commissioning load" of LNG "sometime during the week" of its July 23 target date. Dominion Resources has invested $180 million in reactivating the LNG facility that it bought last year from Williams Cos. Inc., Tulsa, for $217 million. Cove Point LNG LP, owner of the terminal, was among assets Williams sold to resolve liquidity problems. Williams's efforts to reactivate the terminal were pushed back when local elected officials forced a rehearing by the US Federal Energy Regulatory Commission of its 2001 decision in favor of reopening the facility in 2003 (OGJ Online, Dec. 20, 2001).

WOODSIDE ENERGY LTD. has awarded a contract to Samsung Heavy Industries Co Ltd. of South Korea to construct the hull for a floating production, storage, and offloading vessel for its Enfield oil development off Western Australia.

The 150,000 dwt, double-hull vessel will be 260 m long and will have a storage capacity of 900,000 bbl of oil. Design work will begin in advance of environmental approvals and a final investment decision, Woodside said, to ensure that the project will remain on schedule.

Subject to anticipated governmental approvals, Woodside expects to make a final investment decision in second quarter 2004, with production from the field expected in fourth quarter 2006.

Woodside holds a 100% interest in the Enfield project, which lies in permit WA-271-P, about 40 km northwest of the North West Cape. The permit includes Enfield, Vincent, and Laverda discoveries. The fields' combined proven oil reserves are estimated at 146.4 million bbl. Combined probable oil reserves are currently 216.4 million bbl, and the combined probable scope for recovery volumes are estimated at 103.1 million bbl.

Total Enfield development capital costs are estimated at about $1.5 billion (Aus.).

PROGAS PAKISTAN, formerly Keloil Pakistan (Pvt.) Ltd., has awarded a $38 million EPC contract for the second phase of its Port Qasim LPG terminal at Karachi.

Canadian firm SNC Lavalin Energy Control Systems Inc. and China Shanghai (Group) Corp. for Foreign Economic and Technological Cooperation, Shanghai, will engineer and construct 4,500 tonnes of LPG storage and an LPG import handling terminal at the site, enabling the facility to handle vessels of 1,500-50,000 dwt.

Islamabad-based engineering firm Usmani Associates is constructing the first phase of the project—2,000 tonnes of LPG storage and a fully automated, 12-filling-head operation capable of handling 5,000 tonnes/month of LPG at Port Qasim. It is expected to be commissioned by the fourth quarter.

Three regional distribution centers are being set up in Islamabad, Quetta, and Muzaffargarh with 300 tonnes bulk storage and semiautomated LPG bottling operations.

In the third phase, the company plans to increase the capacity of its import jetty to 15,000-50,000 tonnes, and it will construct additional satellite operations in 22 locations throughout Pakistan. This phase is scheduled to go into operation in 2005, once the company reaches its anticipated throughputs.

TERRA INDUSTRIES INC., Sioux City, Iowa, suspended ammonia and urea production at its Blytheville, Ark., facility in late June, citing high natural gas cost and the seasonal decline in nitrogen fertilizer demand and prices.

Terra said the facility would resume production when ammonia and urea selling prices increase or natural gas costs decrease to the point where the facility can operate with positive cash flow. The Blytheville facility's ammonia and urea manufacturing capacity represent 14% and 73%, respectively, of Terra's total ammonia and urea manufacturing capacity in the US and Canada. Terra will continue to operate its Blytheville ammonia and urea storage and shipping facilities.

"We continue to hope that a balance of natural gas costs and nitrogen products prices that will allow us to restart production in Blytheville will be achieved within the next several months," Terra said.

JAPAN appears to have won no further concessions from Russia concerning the proposed Angarsk-Nakhodka oil pipeline, despite a reported $7.5 billion sweetener offered during a meeting June 29 between Japanese Foreign Minister Yoriko Kawaguchi and Russian Deputy Prime Minister Viktor Khristenko.

"The decision on building the pipeline to Nakhodka will be made after a full examination of the project which would include economic, technical, and ecological aspects," Khristenko said after the meeting in Vladivostok.

Khristenko's statement echoes earlier remarks by Russian officials. In May, Energy Minister Igor Yusufov said feasibility studies for the Angarsk-Nakhodka and Angarsk-Daqing pipelines would be put on a list of priority measures. "Priority will be given to the most economically effective and achievable projects," he said (OGJ Online, May 30, 2003).

In June, Russian President Vladimir Putin fed Japanese hopes, saying, "The Angarsk-Nakhodka option looks preferable because it allows broad access to markets." But while acknowledging "that's an attractive option," Putin also said, "the only question is whether it's economically feasible."

Japan and China have been lobbying Moscow for separate routes to get better access to Russian oil. While Japan wants the 4,000 km Angarsk-Nakhodka line at a cost of $5 billion, China prefers the 2,400 km Angarsk-Daqing line at around $2.5 billion.

Russian authorities repeatedly have said there currently is not enough oil available for export in eastern Siberia to justify both pipelines, insisting that substantial investment is needed to develop the resources required to supply the lines.

STATOIL ASA's development and use of a new compact in-line separation at its Sleipner T platform in the North Sea has improved recovery from the field, the company said, and the new technology holds promise for improving production from other deepwater subsea developments in producing fields, possibly making platforms unnecessary in the longer run.

The technology also could reduce carbon dioxide emissions from existing offshore platforms by as much as 50%, Statoil said, compared with existing technology.

Statoil, which developed this method in cooperation with the offshore supplies industry, said it has achieved success with a prototype installed last September to separate liquid from gas. The company plans to install similar equipment on its Statfjord B platform further north this autumn.