OGJ Newsletter

May 14, 2001
The evidence continues to mount that a secular recovery is under way in the world refining industry.

Market Movement

Refining sector: secular recovery?
The evidence continues to mount that a secular recovery is under way in the world refining industry.

As always is the case in refining, any recovery-or downturn-varies widely by geographical region. But the case is clear for a rebound in the refining business with the strengthening of margins across the board.

Refining margins were already starting to look much better a year ago at this time, and they jumped sharply in the first quarter vs. the same period a year ago.

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According to Merrill Lynch, average first quarter 2001 refining margins for all of the major North American and European refining centers have outstripped those for first quarter 2000 (see table).

In the US, first quarter US refining margins were up almost 35% from a year ago, with margins on the Gulf Coast and West Coast each posting gains of nearly 50% year-to-year.

In Northwest Europe, complex margins in the first quarter were running 10% above those of first quarter 2000.

Merrill Lynch expects a continuing "stellar performance" from Mediterranean refiners, where leading-indicator complex margins posted a gain of almost 80% in the first quarter vs. a year ago and where simple margins are expected to move above the line of profitability after posting losses in first quarter 2000: "Here, the widening of the light-heavy spread has been a major boon."

US woes
But because the US market continues to be plagued with a refining-transportation infrastructure that cannot keep up with the complex welter of "boutique" fuels in various regions-as mandated by federal air quality rules-market tightness remains a constant, and the country will again set the pace for high refining margins this year.

That is borne out by the continuing bad news on inventories, underpinning prospects for a repeat of last summer's market disarray. That situation saw refinery and pipeline outages and a scramble for supply that spiked gasoline prices in the US Midwest high enough to spur yet another fruitless federal investigation into charges of collusion and price-fixing by refiner-marketers.

The reason there is likely to be a repeat of last summer's supply and price woes in the US-and the most compelling evidence of why this worldwide refining recovery is secular and long-lasting in nature-is that the underlying trends are entrenched, Merrill Lynch notes, and they include:

  • An overall lack of refining capacity.
  • Reduced gasoline yields as a result of accommodating more-stringent product standards.
  • A reduced level of imports owing to the creation of de facto "barriers" erected against products that don't meet these more-stringent standards.
  • Depleted product stocks.
  • An inability to sustain "capacity creep"-the process of gradual, incremental growth in refining capacity owing to revamps and debottlenecking.
  • A heavy round of maintenance turnarounds that is long overdue, taking a good deal of capacity offline.
  • Structural improvement in Europe's refining sector-specifically a long-overdue consolidation of capacity and companies.

Slight cooling
While the overall fundamentals suggest the global refining sector will continue to remain hot, Merrill Lynch nevertheless sees some cooling from the overheated state of the market last year. This cooldown owes largely to the slowdown in both the US and overall global economies. An exception to the market strength is Asian refining, where the analyst estimates first quarter 2001 margins averaged 30% below year-ago levels. This region still suffers from overcapacity and less-cohesive markets, and the kind of structural consolidation and streamlining seen in Europe is overdue in Asia.

Still, the continuance of the bullish trends points to the view that "refining has been on the cusp of a major secular improvement," Merrill Lynch said. "Central to this was the combination of tightening environmental standards and capacity constraint worsening an existing structural product imbalance in the Atlantic Basin. Evidence that this was already occurring was gleaned in 2000, but further analysis has only served to strengthen this conviction."

There is likely to be a severe contraction in capacity in the Atlantic Basin over the next 3-5 years, the analyst contends: "New environmental standards are set to remove already scarce gasoline and diesel through lower yields. Closures are a separate issue that also look set to shrivel capacity, as many small refiners are unable to justify investment."

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Industry Trends

THE NUMBER OF WELLS BEING DRILLED IN THE DEEPA DN ULTRADEEP WATER OF THE GULF OF MEXICO CONTINUES TO RISE SIGNIFICANTLY, says MMS.

As of mid-April, the number of rigs drilling in the deepwater gulf-in 1,000 ft of water or greater-rose to a record high of 42, MMS said.

"This level of deepwater oil and gas activity illustrates the tremendous level of industry interest in the deepwater portion of the Gulf of Mexico," said MMS acting director Tom Kitsos. Of these rigs, 36 are drilling in 1,500 ft of water or greater.

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Also, there are 8 wells being drilled currently in 5,000 ft of water or greater, which the MMS deems "ultradeep" (see table).

Rig utilization in the gulf is at a 3-year high, ODS-Petrodata Group said.

During the last week of April, more than 90% of the mobile rigs in the gulf were under contract for the first time since July 1998, the offshore data research firm noted.

ODS reported a net increase of 2 mobile rigs under contract in the gulf, pushing the utilization rate to 90.5%, with 191 rigs contracted out of the 211 available in those waters.

Meanwhile, Baker Hughes reported earlier this month that drilling activity in the US has continued to increase, with 1,217 rotary rigs working during the first week of May. This figure is an increase of 5 from the week before and up from 833 during the same period last year.

US GULF OF MEXICO OIL PRODUCTION SET A RECORD IN 2000, BUT GAS PRODUCTION DECLINED FOR THE THIRD STRAIGHT YEAR, said MMS.

MMS said, "The phenomenal rise in oil production from the Gulf of Mexico has continued although the rise has slowed a bit in 2000." It attributed the oil production boost to deepwater gains.

MMS said an estimated 522 million bbl of oil was produced in 2000, up about 5.5% over the 1999 level. Of that figure, 271 million bbl was produced from fields in more than 1,000 ft of water, an increase of 20% over last year.

However, MMS said, "Natural gas production in the gulf continued its decline for the third straight year to a level of an estimated 4.88 tcf in 2000, a decline of 3.4% since 1999. Shallow water gas production [about 3.90 tcf in 2000] continued its steep decline. It was 7.4% lower in 2000 than 1999, and has declined 18.8% since 1996."

Government Developments

CANADA'S PROVINCIAL GROVERNMENTS ARE CASHING IN ON RESOURCE ROYALTIES FROM HIGH COMMODITY PRICES, WHICH HAVE ALSO BOOSTED OIL SECTOR EARNINGS, Canadian Association of Petroleum Producers reported.

A study commissioned for CAPP said tax and royalty revenues for the federal government and provincial governments, such as Alberta, will be an estimated $60.5 billion (Can.) for 2000-03. That's a 16% increase over what governments collected in the past decade. The report, prepared by Calgary-based research firm ARC Financial Corp., estimated oil and gas companies will pay $2.2 billion in federal taxes for 2000, $2.8 billion in 2001, $4.8 billion in 2002, and $3.2 billion in 2003. Federal taxes were $800 million in 1999.

CAPP warned high tax levels could divert capital from the oil industry and slow development of oil and gas resources.

Alvarez
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CAPP Pres. Pierre Alvarez said the industry must demonstrate adequate financial performance if it is to remain viable.

"Although we recognize that we operate in a world of cyclic oil and natural gas prices, if our relative financial performance is not competitive, investors will divert their capital dollars to other Canadian industries or to other regions of the world. This could slow down the development of new, much-needed supplies of oil and gas," Alvarez said.

Meanwhile, Ottawa's share of the industry's taxes is expected to increase to 67% from an average 60% in the 1990s. The study allows for some reduction in commodity prices from current high levels. CAPP has been lobbying Ottawa for tax cuts that have been granted to other industries.

MMS HAS DISBURSED FINAL PAYMENT TO SIX COASTAL STATES FOR CERTAIN DISPUTED OCS LEASES.

MMS said earlier this month that it recently paid $65 million to the six coastal states under terms of a 1986 law designed to give states an annual share of proceeds from certain federal Outer Continental Shelf oil and gas leases.

Fifteen years ago, Congress amended section 8(g) of the Outer Continental Shelf Lands Act. Those amendments required the federal government to share with affected states 27% of future revenues generated from leasing and developing oil and gas in the federal "8(g)" zone-an area 3-6 miles wide and located directly adjacent to a state's seaward boundary.

The law mandated a one-time payment of about $1.5 billion be paid to the affected coastal states from funds held in escrow and annual payments for 15 years.

Including the final 2001 disbursement, Alabama, Alaska, California, Louisiana, Mississippi, and Texas have received a combined $650 million in annual payments.

California, which opposes further leasing off its coast, got most of those funds, a total of $289 million. Alaska received $134 million, Texas $134 million, Louisiana $84 million, Alabama $7 million, and MisSissippi $2 million.

FRANCE WILL BE BROUGHT BEFORE THE EUROPEAN COURT OF JUSTICE FOR FAILING TO MEET DEADLINES FOR PARTIAL DEREGULATION OF ITS GAS MARKET, following the European Commission decision last week to initiate legal action.

France's parliament failed to import into French law the Aug. 10, 2000, gas directive to create a single European gas market by 2005; it also failed to inform EC that it had pushed back submission of the relevant draft law beyond next April's elections.

Quick Takes

Glomar Adriatic VI jack up testing the York appraisal well. Photo from Amerada Hess Corp.
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AN APPRAISAL WELL DRILLED INTO THE YORK FIELD AREA OF THE SOUTHERN NOETH SEA CONFIRMED AS MUCH AS 200 BCF OF PROBABLE NATURAL GAS RESERVES says Amerada Hess.

The well, confirming a 1991 discovery, flowed 24.7 MMcfd of gas from a Rotliegendes Leman reservoir that Amerada called "good quality and productive."

With its partner CalEnergy Gas (UK), Amerada is mulling fast-track development plans. CalEnergy, an affiliate of MidAmerican Energy Holdings, owns 8.5% of York oil field's reserves.

The well was drilled with the Glomar Adriatic VI jack up (see photo). York field is predominantly in Block 47/3a, about 40 km southeast of Flamborough Head off Yorkshire and 8 km north of Rough gas field facilities.

In other exploration news, Esso Exploration Angola has made yet another oil find-the company's 11th-on Block 15 off Angola. Discovery well Vicango-1 is in 3,199 ft of water 193 miles northwest of Luanda. It was drilled to 6,890 ft TD. Esso and Angolan state oil firm Sonangol previously announced 10 discoveries on Block 15, which has estimated reserves of more than 3.5 billion boe. Planning for multiple developments is under way, with the first due to come on stream in 2004.

Sudan has awarded an exploration and production-sharing agreement for Block 5B in the Muglad basin to four companies. Petronas Carigali and Sudapet were designated joint operators, having 41% and 10% respective interests in the block, while Lundin Oil subsidiary Lundin Muglad and OMV each hold 24.5%. The agreement for Block 5B covers 20,119 sq km. The block adjoins Block 5A, which is operated by Lundin Sudan and includes the recent Thar Jath oil discovery. Thar Jath was drilled to 1,820 m TD and encountered 63 m of net pay in Bentiu and Aradeiba sands. The well flowed at 4,260 b/d from three drillstem tests in both zones (OGJ, Mar. 12, 2001, Newsletter, p. 8). Block 5A adjoins Blocks 1 and 2, which produce more than 200,000 b/d of oil.

Latvia plans to launch its first oil and gas licensing round for exploration acreage in the Baltic Sea. The Ministry of Economy will offer 7 permits for exploration and drilling and 66 blocks for "preinvestigation." Preinvestigation licenses must be applied for by Oct. 31, while the deadline for bidders for exploration licenses is Jan. 25, 2002. The preinvestigation licenses would be for 2 years, with an option to extend 5 years. E&P permits will be granted for 30 years, inclusive of a 5-year maximum exploration phase. The ministry noted that the government would retain a 10% stake in all awarded licenses, with the licensees subject to a 25% corporate tax and an oil royalty of 2-12%.

Santos, operator of Australian Exploration Permit 154 in Victoria's Otway basin, made its fourth discovery in that area this year. The Lavers-1 wildcat intersected an 11-m gross gas column in Cretaceous Waarre sand at 1,542-1,553 m. The well reached 1,627 m TD. Santos and its partner in the well are evaluating logs, which indicate 10 m of net gas pay. Lavers-1 will be cased and suspended as a future gas producer. The well is 2 km northwest of the McIntee gas find and 16 km northwest of the Heytesbury gas facility. Santos owns 90% of Lavers, and Beach Petroleum, 10%. The rig will move to the Naylor-1 site, the last in a five-well Otway basin exploration program. Naylor-1 was to spud by May 10.

WILLIAMS COS. COMPLETED REPAIRS ON A RUPTURED SECTION OF A PIPELINE SPUR NORTH OF KANSAS CITY, MO.

A fire occurred after the line break, although the cause of the accident has not been determined.

The incident occurred between Platte City, Mo., and Weston, Mo., on a 10-in. section of the Mid-America Pipeline, which carries ethane and propane from Conway, Kan., into Iowa City, Iowa, and central Illinois. The spur branches from the mainline between Conway, Kan., and Janesville, Wis.

The pipeline, built in 1970, is owned and operated by Williams subsidiary Mid-America Pipeline Co.

The company's Tulsa operations control center detected low pressure at noon May 1 and shut down the line, isolating a 10.5-mile segment (OGJ Online, May 1, 2001).

Williams said its crews worked through the night and installed two sections of pipe totaling 100 ft by 3 a.m. the next morning.

In other pipeline happenings, El Paso Corp. unit Southern Natural Gas applied to US FERC to build a $240 million natural gas pipeline system in Georgia and Florida. Using the proposed 166-mile, 310 MMcfd pipeline, SNG subsidiary Cypress Natural Gas will transport gas from El Paso's LNG terminal at Savannah, Ga., to interconnections with SNG's South Georgia Lateral; Florida Gas Transmission Co. (a jointly owned subsidiary of El Paso and Enron); Atlanta Gas Light near Brunswick, Ga.; and Jacksonville Electric Authority's new Brandy Branch generating plant near Jacksonville, Fla. If approval is granted, construction is to begin in third quarter 2002; the in-service date is June 1, 2003.

El Paso Corp. unit Tennessee Gas Pipeline plans to expand its New England pipeline capacity by 200 MMcfd to more than 600 MMcfd at a cost of $35 million. The company plans to replace 12 miles of 16-in. natural gas line from Dracut, Mass., to Burlington, Mass., with a 24-in. line, using existing rights-of-way. The expansion will be available for service in fall 2002. "By 2005, natural gas is expected to generate 45% of the electrical power in New England, compared with only 16% in 1998," said Stephen Beasley, TGP president. He said use of existing ROWs will allow the company to minimize the environmental impact, while still delivering an economic project.

TOPPING GAS PROCESSING NEWS, multinational joint venture Malaysia LNG Tiga said it has secured two loans worth $816 million to finance the construction of a third LNG plant and related facilities at Bintulu, Sarawak.

The plant,45% complete, will consist of two 3.4 million tonne/year trains.

Related facilities to be built include an LNG storage facility and an LNG loading jetty.

Scheduled to begin operation in 2003, the plant will make the Bintulu LNG complex the world's single largest LNG production facility, with a combined capacity of about 23 million tonnes/year.

The loans entail a $651 million, 13-year overseas investment credit facility provided by the Japan Bank for International Cooperation and a $165 million, 8.5-year term loan facility provided by a syndicate of seven international commercial banks: Industrial Bank of Japan, Bank of Tokyo Mitsubishi, Sakura Bank, Tokai Bank, Citibank Malaysia, Fuji Bank, and Dai-Ichi Kangyo Bank.

In other gas processing news, Abraxas Petroleum has successfully completed the expansion of its gas processing facilities in the Pouce Coupe-Valhalla area in the Peace River arch area of northwestern Alberta. A 10-mile sour gas pipeline connects wells at Pouce Coupe to Abraxas's wholly owned gas processing plant at Valhalla. Abraxas owns 90% of the processing plant, and Grey Wolf Exploration owns 10%. The pipeline, owned 100% by Abraxas, delivers 5 MMcfd at a savings of 42¢ (Can.)/Mcf compared with processing costs charged by the previous third-party processor. Another 2.5 MMcfd will be connected to the pipeline once a determination of the remaining available sour gas processing capacity is completed. Meanwhile, engineering for additional future plant expansion is under way. Abraxas anticipates the Valhalla plant will reach capacity and that drilling successes will demand additional gas processing capacity.

PDVSA MOVED TO "MINIMIZE THE POSSIBLE EFFECTS" THE SHUTDOWN OF A CATALYTIC CRACKER UNIT AT ITS CARDON REFINERY MAY HAVE ON GASOLINE SUPPLIES TO THE US, the company said.

The 77,000 b/d unit was shut down May 3 for the second time in a week.

The 300,000 b/d Cardon refinery forms part of the Paraguana Refining Center in northwestern Venezuela. Gasoline output at the faulty cat cracker is shipped mainly to the US market.

Operations at the unit were first interrupted Apr. 29 due to an electric failure. Some 36 hr later, PDVSA attempted to restart the unit but was forced to shut down operations again just days later.

"The unit was taken out of service after several attempts to stabilize operations without satisfactory results," said PDVSA. PDVSA said it estimated the unit would be out of service for about a week.

"At this moment, the possible impact the shutdown could have on deliveries to clients is being evaluated, and PDVSA is trying to minimize as much as possible the effects it may have on our contractual commitments," said PDVSA.

In other refining news, Oman selected Fortum's proprietary etherification technology and Institut Française du Pétrole's proprietary gasoline desulfurization technology for a new refinery in Oman. Fortum unit Neste Engineering and IFP cooperated during the tender competition. Fortum said that making its NExTAME and IFP's Prime-G+ technologies compatible has achieved major cost savings. IFP and Neste will begin work on the etherification unit as soon as possible. The Fortum-licensed NExTAME unit will produce a high-oxygen gasoline component that is a mixture of tertiary amyl methyl ether and heavier ethers. Fortum said the component reduces harmful air emissions. The TAME unit will have capacity of 120,000 tonnes/year, and the Prime-G+ unit will have capacity of 1.1 million tonnes/year.

HARSH WEATHER AND THE GENERAL DECLINE IN OUTPUT FPRM OLDER UK NORTH SEA FIELDS COMBINED TO REDUCE THE COUNTRY'S OIL AND GAS PRODUCTION IN THE FIRST QUARTER, the UK Department of Trade and Industry reported earlier this month.

Production of oil and gas fell by 13.9% and 3.8%, respectively, compared with the same period last year, DTI reported. Overall, production of indigenous primary fuels, including coal, fell 8.4% to 74.6 million tonnes.

Total UK inland consumption of oil and gas, however, rose by 2.1% and 3.6%, respectively, in the first quarter vs. a year ago.

Petroleum use, though, declined to 19.9 million tonnes, 2% lower than a year earlier. Deliveries of motor fuels were also down, 3.9%, with those of unleaded fuel falling 0.8%.

DTI said the decline in deliveries was "assumed to be linked" to publicity surrounding the reduction in duty on ultralow-sulfur fuel in advance of the Labour government's March budget, whereas a spike in deliveries a year before had coincided with a tax hike on fuel. Deliveries of DERV (diesel-engined road vehicles) fuel were "virtually unchanged" from the same period a year ago, while deliveries of other gas oils, chiefly used for heating purposes, fell by 10.9%.

Fuel oil deliveries rose by 25%, as oil-fired power stations reacted to higher natural gas prices, while deliveries of other products increased by 8%. Deliveries of aviation fuel increased 6.3%, heating oil 12.3%, and LPG 1%.

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In development news, Samedan Oil awarded CSO Aker Engineering a contract to provide engineering and project management services to the proposed Mari-B and Noa subsea development off Israel. Mari-B field is in 240 m of water 25 km from Ash- kelon, and Noa is in 790 m of water 42 km from shore (see map). CSO will provide preliminary engineering and, if approved, detailed engineering, procurement, and management of installation and commissioning for the subsea development, flowlines, and export pipeline.