OGJ Newsletter

Dec. 15, 2003
Energy futures prices spiked Dec. 8 with the January natural gas contract hitting $6.944/Mcf in overnight trading on the New York Mercantile Exchange, the highest price level since March for a front-month gas contract "and just shy of the contract high of $6.945[/Mcf]," analysts said Dec. 10 at Enerfax Daily.

Market Movement

Cold weather drives up energy prices

Energy futures prices spiked Dec. 8 with the January natural gas contract hitting $6.944/Mcf in overnight trading on the New York Mercantile Exchange, the highest price level since March for a front-month gas contract "and just shy of the contract high of $6.945[/Mcf]," analysts said Dec. 10 at Enerfax Daily.

On Dec. 11, The US Energy Information Administration reported 111 bcf of natural gas withdrawn from US underground storage during the week ended Dec. 5. That exceeded expectations of Wall Street analysts and was expected to help buoy gas prices throughout the week. US gas storage now exceeds 2.98 tcf and is above year-ago levels by 190 bcf and above the 5-year average by 79 bcf.

The major jump in energy futures prices occurred Dec. 8 as cold weather dumped record snowfalls on parts of the Northwest US, the world's biggest market for heating oil. Heating oil for January delivery escalated by 4.18¢ to 90.54¢/gal on NYMEX, while natural gas for the same month closed at $6.90/Mcf, up by 76.7¢ for the day.

In the following trading session, energy prices declined a little as traders took profits from that rally. But futures commodities resumed their advance Dec. 10 with government and industry reports of large drops in US oil inventories and forecasts of another wave of cold weather in certain areas of the US.

Oil stocks plunge

EIA reported US oil stocks plunged by 6.4 million bbl to 277.9 million bbl during the week ended Dec. 5. US commercial inventories of crude had fallen a total of 16.1 million bbl during the previous 3 weeks to 25.2 million bbl below the 5-year average, said EIA officials on Dec. 10.

The American Petroleum Institute reported an even bigger drop in US oil inventories for the week ended Dec. 5, down by 8.9 million bbl to 274 million bbl. However, both reported increases in US inventories of petroleum products for the same period.

EIA said US inventories of distillate fuel increased by 1 million bbl to 132.1 million bbl, with diesel fuel accounting for most of that gain. It said US gasoline stocks also increased for the second consecutive week, up by 3.4 million bbl to 200.5 million bbl.

API said gasoline stocks jumped by 5.1 million bbl to 203.4 million bbl during that week, with distillate stocks increasing by 2.7 million bbl to 134.5 million bbl.

Data from either group are "overwhelmingly bullish for crude oil, while bearish for oil products," said Paul Horsnell, head of energy research at Barclays Capital Inc., London, in a Dec. 10 report. For the past 3 weeks, he said, US oil inventories "have been falling relative to the normal pattern at a rate of 650,000 b/d, and oil product inventories have been rising relative to normal at a rate of 270,000 b/d."

The latest large draw on US oil inventories represents "a continuation of the recent pattern of relatively low imports and rising refinery runs. With the end of the year looming, and the incentive being to minimize inventories at that point for tax purposes, we do not expect the tightness in crude oil to abate significantly this month," Horsnell said.

The increase in US gasoline stocks tracks the usual pattern for this time of year. "With perhaps 2 weeks of seasonal build left, we remain gasoline bulls," said Horsnell. However, he said, "Heating oil figures are bearish, in that for a second week the path of inventories has diverged from last year and for the second week the implied demand figure is disappointing. The data should still improve as recent colder weather will, after a lag, result in the transmission of a drawdown of tertiary (i.e. final consumer) inventories to a drawdown in primary inventories."

Crude inputs into US refineries increased by 213,000 b/d to an average 15.7 million b/d during the week ended Dec. 5. US oil imports increased by 403,000 b/d to an average 9.5 million b/d during the same period. "It appears that crude oil imports from Saudi Arabia and Nigeria were relatively high," EIA said.

Meanwhile, two unions representing Nigerian oil workers are threatening to resume a suspended September strike if the Nigerian government fails to repair the country's four refineries and make them functional before yearend.

The workers suspended their strike after the government promised to roll back domestic gasoline. However, the government initiated deregulation of the downstream sector of the Nigerian oil industry on Oct. 1, allowing marketing companies to set gasoline prices.

Industry Scoreboard

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Industry Trends

GLOBAL E&P SPENDING is expected to increase slightly next year, a Lehman Bros. spending survey shows.

Worldwide exploration and production expenditures are expected to rise 4% to $144.3 billion in 2004. A flat outlook is anticipated for the US and Canada, offsetting a 6.1% gain expected elsewhere, said Lehman Bros. analyst James Crandell of New York.

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Based on a survey of 335 companies, Crandell said respondents' budgets are based on an average New York Mercantile Exchange futures oil price forecast of $25.29/bbl and a natural gas (Henry Hub) price forecast of $4.17/Mcf. Global 2003 E&P expenditures now are estimated to be moderately above the rates initially estimated in Lehman's surveys from a year ago and at midyear, Crandell noted.

SOME E&P SPENDING FORECASTS for next year will prove "far too pessimistic," said Raymond James & Associates Inc. analyst Wayne Andrews of Houston.

In a Dec. 8 research note, Andrews estimated that 2004 exploration and development spending would post 41% higher than a year earlier for the 29 companies in the analyst's coverage universe.

In late 2002, most forecasts called for flat-to-lower budgets for 2003. RJA predicted spending would be up 20%, but that was too conservative. By midyear, budget increases averaged 33% for the RJA coverage universe.

"Over the next few weeks, capex surveys will likely predict that 2004 spending will be flat or even lower," Andrews said (see story, p. 28).

He cited several reasons for the anticipated miscalculations. "One reason the surveys tend to be wrong is that most E&P companies have not yet set their 2004 budgets, so these surveys will only reflect a vague 'guess' on their part. In addition, Andrews said that most E&P firms are basing their spending plans upon $4.50/Mcf or lower natural gas prices, "while we believe gas prices will average closer to $5.50[/Mcf] in 2004."

WORLD TANKER MARKET tightness is expected to continue.

This trend was supported by the International Maritime Organization (IMO) Environment Protection Committee's recent decision to accelerate the phase out of single-hull tankers from international waters by 2010 instead of a previous 2015 deadline.

Jefferies & Co. Inc. analyst S. Magnus Fyhr of Houston expects that increasing global oil demand should result in annual tanker demand growth of 3% for the next 2 years. Tanker safety prompted intense debate after the Prestige tanker sank off northwestern Spain (OGJ Online, Nov. 27, 2002).

"While 2003 has been one of the strongest tanker markets on record, we believe that tanker supply-demand balance will remain very tight and result in continued firm tanker rates in 2004 and 2005," Fyhr said.

Government Developments

THE US CONGRESS formally ended its legislative session for the year on Dec. 9 without passing either a sweeping energy bill or a massive $328 billion spending measure designed to fund the federal government through next September.

Senate Democrats blocked both, arguing that the bills were crafted using legislative "tricks" that excluded them.

The House and Senate returned briefly this week after a Thanksgiving recess but left without finalizing the spending bill. Last month, Republican Senate leaders declared the energy bill dead for the year. They could not get the two votes needed to cut off debate on the measure (OGJ Online, Nov. 21, 2003).

A new session is slated to start mid-January. Until Congress can reach consensus on spending, most nonmilitary government agencies will operate under fiscal year 2003 levels as stipulated in an emergency funding measure.

House Republican leaders said they are hopeful they can pass both bills, and the White House has urged Capitol Hill to complete action. Although Congress must pass annual appropriations bills that fund the federal government, it's unclear what shape a final spending measure could take, especially in an election year.

This is the second consecutive year that the federal budget has been left in legislative limbo; the new fiscal year will already be one-third over if Congress takes final action by Feb. 1, 2004.

Unlike appropriations bills, there is no congressional mandate to pass energy legislation, and the current conventional wisdom among industry lobbyists is that the bill has received too much negative publicity to pass in its current form.

Republican leaders from oil and gas producing states call the energy bill a "high priority." But lobbyists disagree, saying that it has generated only low public interest.

Meanwhile, House Republicans last week said their position on clean fuel programs, most notably liability protection for the fuel additive methyl tertiary butyl ether, has not changed.

Both the energy bill and the omnibus spending legislation will be debated in late January when the GOP-controlled House and Senate return for the new congressional session.

THE US SENATE confirmed the White House's nomination of Rixio Enrique Medina for a 5-year term as an independent chemical board member.

Acting by unanimous consent, the Senate confirmed Medina as a member of the US Chemical Safety and Hazard Investigation Board. Following formal commissioning by President George W. Bush, Medina will join board members Carolyn Merritt, Gerald Poje, and John Bresland.

Medina was nominated in June. President Bush also has nominated Gary Visscher of Maryland to fill the remaining vacant seat on the five-member board. Visscher's nomination awaits action in the Senate Environment and Public Works Committee next year.

Currently, Medina is manager of corporate health, safety, and security for Citgo Petroleum Corp. He previously was manager of health and safety services for Citgo's Corpus Christi, Tex., refinery. Earlier in his career, he worked for Mobil Oil Corp. and Petroleos de Venezuela SA.

Quick Takes

SIX COMPANIES participating in Lease Sale 189 in New Orleans Dec. 9 submitted 16 bids totaling about $8.4 million in high bids for 14 tracts in the eastern Gulf of Mexico.

The US Department of the Interior's Minerals Management Service had offered 256 blocks comprising 1.47 million acres off Alabama adjacent the Central Gulf of Mexico planning area in an attempt to stimulate domestic production in an atmosphere of high natural gas prices. The blocks are 100-196 miles offshore in water 1,600-3,425 m deep.

Shell Offshore Inc. and Nexen Petroleum Offshore USA offered the highest bid on a block—$2.2 million for Desoto Canyon Block 398. The deepest block attracting a bid was Desoto Canyon Block 972, in about 2,713 m of water.

In other exploration activities, Libyan National Oil Corp. (NOC) signed a 30 year exploration and production-sharing agreement (PSA) with Woodside Energy Ltd. subsidiary Woodside Energy (NA) Ltd., Hellenic Petroleum SA of Greece, and Repsol Exploración Murzuq SA, a subsidiary of Repsol-YPF. The agreement includes five onshore exploration blocks in SA Sirte basin of northern Libya and one onshore block in the Murzuq basin in western Libya. The JV's cost is $102 million, which will fund geological studies, seismic acquisition, and the drilling of 13 exploratory wells within an initial 6 year exploration phase. It also covers a study for development of Atchan field in the Murzuq basin. Woodside is operator, with 45% of the PSA; Repsol-YPF has 35%; and Hellenic Petroleum 20%. Woodside said the 20,000 sq km of acreage in the two basins together has an undiscovered potential of 35 billion bbl. Separately, Repsol- YPF reached an agreement this summer for six new blocks in Libya, and RWE AG of Germany recently was awarded new exploration contracts. A new discovery was made at Repsol-YPFoperated giant El Sharara field; where it currently produces 200,000 b/d of oil from the NC-115 Block in Libya. Repsol-YPF began production in Field A in late October, and development of Structure D, recently approved by NOC, is in progress. By early 2005, oil production from these two structures is expected to reach 75,000 b/d. In Norway's first "Predefined Areas" licensing round, BG Group has accepted an offer from the Norwegian Ministry of Petroleum and Energy to own and operate Blocks 1/2, 1/5, and 1/6 in the Central Graben area of the Norwegian North Sea. BG said it expects to shoot 3D seismic over the blocks during 2004, with a drilling program to begin in 2006. Apache Corp. estimates reserve potential of its 100% owned Egyptian Qasr field in the Khalda Concession to be 1-3 tcf of gas and 20-70 million bbl of condensate based on test results of its Egyptian Qasr-2X appraisal well and the nearby discovery well, Qasr-1X. Apache reported that the Qasr-2X well flowed 34.5 MMcfd of natural gas on test along with 1,320 b/d of condensate in the Jurassic Lower Safa reservoir (OGJ Online, Nov. 5, 2003). The test at the base of the 707 ft gross hydrocarbon column was conducted from 70 ft of perforations at 13,444-13,514 ft through a 1-in. choke with 2,014 psi of flowing wellhead pressure. Apache said the well is 31 ft structurally higher than originally thought and has 200 net ft more pay. Before yearend, Apache plans to spud the first of three additional appraisal wells to fully delineate the 13,000 acre, seismically defined structure. An additional 62 ft of pay was logged at more-shallow depths of the Qasr-2X in the AEB sands, which produce oil in Ozoris field 2.4 miles to the northeast. Apache said it also would spud the Qasr-7X well, 215 ft south of Qasr-2X to exploit the AEB-3E and AEB-3D sands. Pogo Producing Co., Houston, has flow tested its Szolnok No. 2 gas well in Hungary. Drilled to 7,372 ft TD, it tested at 14.2 MMcfd of gas and 150 b/d of condensate, with 3,326 psi flowing tubing pressure through a 28/64-in. choke. The well found a 200 ft gross gas pay column, yielding at least 90 ft of net pay at 6,836-7,124 ft, Pogo said. Pogo plans to drill more wells in the coming months to fully develop the discovery. Operator Pogo said it is seeking a smaller completion rig while it contemplates fracture stimulation and flow-testing on one or both of the wells. The principal drilling rig will return to Pogo's Tompa license area to drill the next exploratory well. Pogo holds 100% working interest in the 782,000 acre Szolnok-Tompa license areas of central and southern Hungary.

Southwestern Energy Co., Houston, said it reached TD and logged apparent gas pay at an exploration well on the Ranger anticline 6 miles west of Waveland gas field in the southeastern Arkoma basin. It targets the same Pennsylvanian Borum sand reservoirs that produce in Waveland field in Yell County. This ad other fourth quarter exploration well are evaluating 35,000 gross undeveloped acres in the area. Southwestern earlier won state approval for 80-acre spacing in Waveland field.

QATAR PETROLEUM and ConocoPhillips signed a statement of intent (SOI) Dec. 8 in Doha preparatory to construction of a world-class gas-to-liquids plant in Ras Laffan Industrial City, Qatar.

The SOI initiates detailed technical and commercial pre-engineering studies and establishes principles for negotiating a heads of agreement (HOA) for the integrated reservoir-to-market GTL project. The participants expect to complete the HOA by yearend 2004.

PAKISTAN NATIONAL SHIPPING CORP. (PNSC) has purchased two more Aframax class oil tankers from a Croatia-based shipping company. The tankers, built in 1985 at El Ferrol shipyard in Spain, were registered in Malta.

The $17 million purchase increases PNSC's fleet of oil tankers to three, and the company has begun negotiations to purchase a fourth tanker after receiving approval from the Ministry of Communications.

Transportation savings will enable PNSC later to purchase two more tankers.

PRODUCTION HAS BEGUN from Jasmim field on deepwater Block 17 about 150 km northwest of Luanda off Angola. Angola's state oil company Sonangol EP is concessionaire, and Total SA subsidiary Total E&P Angola is operator of the field. Jasmim is the second of 15 discoveries on Block 17 to be brought on stream, following Girassol field in December 2001.

Production from Jasmim's eight subsea wells is being tied back 5 km to the Girassol floating production, storage, and offloading vessel, increasing oil flow to the FPSO to more than 230,000 b/d. Dalia field, also on Block 17, will be developed and is slated to come on stream in second half 2006, Total said.

In other production news, ExxonMobil Corp. subsidiary Esso Exploration Angola (Block 15) Ltd. also has initiated production off Angola—from Xikomba deepwater field on Block 15. Xikomba, the company's first producing field on the block, has estimated reserves of 100 million bbl of oil, and Esso is targeting production of 80,000 b/d (OGJ Online, Aug. 6, 2003). Xikomba, 370 km northwest of Luanda in 1,480 m of water, is producing from nine subsea wells tied back to an FPSO vessel that will accelerate Xikomba production while permanent facilities for the much larger Kizomba A project are being completed. ExxonMobil previously had announced two world-class deepwater developments on Block 15—Kizomba A and Kizomba B—both $3.4 billion developments, that together have estimated reserves of 2 billion bbl of oil and a combined target production of 500,000 b/d of oil. First oil from Kizomba A is scheduled for 2004, and Kizomba B first oil is expected in early 2006. BG reported that oil production from Karachaganak field in northwest Kazakhstan into the Caspian Pipeline Consortium export pipeline is not expected to resume until second quarter 2004. Although the caustic soda contamination reported earlier (OGJ Online, Sept. 25, 2003) has been successfully resolved. BG said that, testing during commissioning identified an unrelated issue associated with small-bore pipe welds and low-pressure instrumentation, which must be remediated for safety reasons. The delay will have no impact on BG's 2003 or 2006 production targets, the company said. BG's total production from Karachaganak in 2004 is projected to be 35 million boe—4 million boe less than planned and 12 million boe more than expected 2003 production. BG operates the field on behalf of partners ENI SPA, ChevronTexaco Corp., and OAO Lukoil. When the new facilities are commissioned, the field will have a production capacity of 200,000 b/d of oil and as much as 700 MMscfd of gas.

NORSK HYDRO ASA and partners have inked a $145 million engineering, procurement, and construction (EPC) contract with FMC Technologies Inc. unit FMC Kongsberg Subsea AS for FMC to supply subsea systems and related services for the first phase of development of Ormen Lange field in the Norwegian North Sea.

The EPC contract includes eight subsea trees and associated structures, manifolds and production control systems, as well as connection systems for flowlines and umbilicals. The contract also includes options for eight additional subsea trees and associated equipment as well as potential further equipment deliveries in the future. An additional contract includes technical services related to installation and start-up.

Ormen Lange is the largest undeveloped gas field on the Norwegian Continental Shelf, FMC said.

The Ormen Lange license group comprises Norsk Hydro, operator of the project's development phase 18%; Royal Dutch/Shell Group, operator of the production phase 17.2%; Petoro 36%; BP PLC 10.9%; Statoil 10.8%; and ExxonMobil 7.2%.

In October, British and Norwegian authorities reached an agreement on the main facets of a treaty that would pave the way for laying the two-part, 1,200 km Britpipe subsea natural gas pipeline from Ormen Lange field to the UK (OGJ Online, Oct. 7, 2003).

The license group last month awarded a $280 million contract to Stolt Offshore SA for the installation of part of the pipeline. Stolt Offshore will be responsible for the installation of 540 km of 44-in. pipeline, which will transport Ormen gas from the North Sea Sleipner gas export hub to Easington in the UK.

The contract includes an option in 2006 for installation of a 362 km, 42-in. pipeline from just outside Nyhamna to the Sleipner platform through the Norwegian Trench. Stolt plans to use the LB200 pipelay barge for both installation projects.

AN INTERNATIONAL NATURAL GAS PIPELNE connection between France and Spain is being planned, with construction slated for completion by 2005.

The proposal for the 30 km, 500 million cu m/year line evolved from efforts by regulators in France, Spain, and Portugal, who indicated in July the need to promote interconnections among the three countries and to develop a southern gas-trading hub needed to develop the liberalized European gas market.

The proposed pipeline will be constructed along the Bay of Biscay coastline to connect the regional Gaz du Sud-Ouest gas system in southwestern France with the Spanish grid. The connection will extend from Bayonne, France, near the Franco-Spanish border, to Saint Sebastian, Spain. The only other gas link currently between Spain and France is the Lacq-Calahorra gas line that crosses the Pyrenees Mountains further east.

Gaz du Sud-Ouest is owned 70% by Total and 30% by Gaz de France.

In other pipeline news, external corrosion is the likely cause of two pipeline breaks on the TransCanada PipeLines Ltd. pipeline system in Alberta in early December, the company reported (OGJ Online, Dec. 5, 2003). The breaks, 15 km apart, are on the NPS 36 Western Alberta System Mainline Extension in the Waskahigan region, about 100 km southeast of Grande Prairie, Alta. TransCanada reported no injuries as a result of either incident. However, Calgary-based ARC Energy Trust said it shut in about 4,000 boe/d of production from the Ante Creek area in Alberta due to the breaks.

SAUDI ARABIA'S Project Management & Development Co. Ltd. (PMD), Al-Jubail Industrial City, plans to construct a $3.5 billion petrochemical complex at Al-Jubail, with the primary facility an ethane-butane cracker to produce 1.35 million tonnes/year of ethylene, along with propylene and benzene feedstocks for downstream petrochemical units within the PMD cracker complex. The plant is planned for start-up in 2008.

When fully operational, the cracker will produce 2.7 million tonnes/year of marketable products including ethylene, polyethylene, polypropylene, ethylene glycol, bisphenol A, and amine derivatives.

PMD selected Foster Wheeler Ltd. subsidiary Foster Wheeler Energy Ltd., Clinton, NJ, as technical consultant for the project. Foster Wheeler currently is conducting a comprehensive cost estimate for the complex for PMD, which is seeking interest from potential overseas investors.