OGJ Newsletter

CGES noted that US gasoline demand logged year-on-year growth in 2001 of 1.7%; that level reached 2.2% in the fourth quarter (see table). The think tank cited as demand drivers consumers' massive substitution of road travel for air travel in the wake of the Sept. 11, 2001, terrorist attacks on the US and the collapse in gasoline prices last year.

Gasoline prices fell 5.4% in 2001 from the prior-year level to an average $1.38/gal, a drop attributable to the plunge in crude oil prices in the fourth quarter and the earlier build-up in gasoline stocks. That big stockbuild had occurred because strong gasoline demand and stout refining margins pushed refiners into overdrive on gasoline production, resulting in a jump of almost 6% in gasoline stocks.

"With the onset of the driving season, and as the US economy begins its expected recovery in the third quarter of 2002, gasoline inventories will fall, especially given the low refinery runs expected this year," CGES said. "A fall in gasoline stocks will reduce stock cover in 2002, causing upward pressure on prices."

Distillate outlook

It's a different story on the distillate side, with demand growth this year more bearish vs. an especially strong spurt in distillate demand last year.

Distillate demand grew by 3.2% in 2001, with most of the surge coming early in the year when high natural gas prices spawned a wave of fuel switching by industrial and power generation users from gas to fuel oil. Demand then dropped in response to depressed industrial activity, owing to the recession, and to mild winter weather. By the fourth quarter of last year, distillate demand was actually running 3% less than it did the prior year, CGES noted.

That dramatic reversal in demand led to a stockbuild for distillates that reached a rate of 10%, leading to a jump of 20% in distillate stock cover.

"Recently, lower gas prices, mild weather, and weak industrial activity have continued to depress distillate demand, which the CGES predicts will remain below last year's levels in the first half of 2002, after which it is expected to recover," the think tank said. "Owing to weak demand, distillate stocks are expected to increase by 5% in 2002. Weak demand and depressed industrial activity will keep stock cover relatively high, maintaining downward pressure on distillate prices in 2002."

Rebounding margins

While 2001 was a tough year for US refiners in many respects, signs of recovery were already evident at the start of the year.

CGES pointed out that a pickup in refinery runs early in the year helped dissipate some of the crude stock overhang from 2001-although stocks were still up 8.5% year-on-year as of January.

Margins nevertheless improved a bit in January. There's still some upside for margins, as the evolving rebound in demand in tandem with the still-to-arrive reduction in OPEC and some non-OPEC oil supplies-a result of the Jan. 1 accord between both groups of oil exporters-should whittle away the crude stock overhang still further.

With refinery runs certain to accelerate as the summer driving season approaches, the outlook is for continued firming of gasoline prices and some growth in margins-at least until the next spike in crude oil prices.

Industry Scoreboard

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Industry Trends

The oil services industry may be set up for a "boomerang effect" from the convertible bonds that it has sought out in recent years, said Houston-based Simmons & Co. International.

"Over the past few years, several oil service companies issued convertible debentures as a means to raise capital at a very low cost," Simmons said. "As with all things in life, 'you don't get something for nothing.'"

Over the last 5 years, oil service firms were able to raise $5.2 billion in capital via convertible debt offerings, Simmons noted, with $4.7 billion raised during 2000-01 (see table).

"Most of these debentures contain features that allow for the holder to put the note back to the company after a set number of yearsellipse2-5 years after the issue date," Simmons said.

Simmons added that should a note be put back to the borrower, there would be "little impact," so long as the firm has enough in cash to cover the financial obligation. "On the other hand, should a company have a highly leveraged balance sheet heading into what appears to be a significantly weaker year for free cash flow generation," Simmons noted, "it will likely face incremental liquidity pressure should the note be put back to them.

"While we do not foresee any solvency risk, the downside from redemption is to [a company's] future cash flow potential," Simmons said.

Offshore drilling contractor GlobalSantaFe Corp., Houston, reported that its worldwide Summary of Current Offshore Rig Economics (SCORE) for January dropped by 0.2% from the previous month.

"Rig supply and demand remain in balance in the key international markets, and day rates show signs of leveling out in the Gulf of Mexico," noted GlobalSantaFe Pres. and CEO C. Stedman Garber Jr. In the Gulf of Mexico, the January rating was 29.9, down 3.7% from December 2001, down 36% from a year ago, and down 44.2% from 5 years ago.

"However, despite increasing drilling activity internationally, excess rig capacity in the Gulf of Mexico could result in near-term day rate softness in West Africa, as rigs in this region may end up competing with rigs mobilizing from the gulf," Garber added.

Off West Africa, January's rating fell to 55.5 from 58 the month prior. West Africa's rating was up 24.3% from a year ago and down 7.6% from 5 years ago.

SCORE compares the profitability of current mobile offshore drilling rig rates with the profitability of rates at the 1980-81 offshore drilling cycle peak, when speculative rig construction was common. SCORE reflects current rig day rates as a percentage of the estimated rate required to justify building rigs on speculation.

Government Developments

State and federal regulators have issued a draft environmental impact statement for coalbed methane development in south-central and southeastern Montana.

The preferred alternative recommended by the Department of the Interior's Bureau of Land Management would require operators to submit plans of development and plans for handling water generated during coalbed methane production, the Independent Petroleum Association of Mountain States said. BLM also wants water from production recycled for irrigation or livestock watering.

The EIS assumes 10,000-26,000 wells will be drilled in the region and could include 4,000 wells on Indian lands. The deadline for comments is May 15; five public meetings are scheduled before then across the state. A final EIS is anticipated in the summer.

In a related effort, Region 8 of the US Environmental Protection Agency Region and the Montana and Wyoming departments of environmental quality received comments by industry, landowners, and other stakeholders on the surface discharge of coalbed methane water.

IPAMS said regulators may try to apply water quality regulations originally intended for conventional oil and gas to "relatively new" coalbed methane production. The agencies' analysis will also help determine whether reinjection and other water containment methods are suitable in some areas, IPAMS officials said.

The association said industry prefers to continue using the surface discharge method under an EPA guideline that allows for "best professional judgment." But several ranchers said they are worried that the guideline allows too many permits to be issued that circumvent regulations intended to protect existing land uses.

Oil companies drilling on federal lands are mulling an appeal to the US Supreme Court following a recent decision by the US Court of Appeals for the DC Circuit that largely affirmed the Minerals Management Service's "duty to market" gas royalty rules.

Industry has several legal options it still can consider: it can file a petition for rehearing before the full appeals court by March 25; it can also petition the Supreme Court before May 9. Industry could also seek a rehearing before another appeals court.

Producers say downstream marketing adds to the value of the gas at the lease, and therefore the royalty owner should share the costs with the government.

It may be several weeks before industry officials decide to pursue more litigation. And on the regulatory front, things are equally unclear, government officials and industry lobbyists say. MMS is unlikely to further tinker with its existing gas royalty rules in the near future for two key reasons, sources say.

First, the agency wants to wait until legal challenges are settled; second, a new MMS director, Johnnie Burton, former revenue director of the state of Wyoming, does not take office until next month, and it will take some time for any new policy directions to be set in motion.

According to the Feb. 8 decision, the American Petroleum Institute and Independent Petroleum Association of America argued MMS was wrong for refusing to permit deductions for costs incurred in marketing gas downstream of the wellhead.

Quick Takes

Production from the Brutus tension leg platform has been shut in for repairs to the TLP.

Shell Exploration & Production Co. said it shut down Brutus on Feb. 12 be- cause of valve failures in the production processing system.

During the shutdown, work will be initiated to expand production capacity to 130,000 b/d of oil, Sep- co said. Brutus had been producing 60,000 b/d of oil and 90 MMcfd of gas from four wells.

The valve failures caused no safety or environmental risk to the platform or the personnel.

Although the cause of the problem remains under investigation, Sepco said initial indications suggest that stimulation fluids from a well may have entered the gas processing system, causing equipment damage.

Sepco Pres. and CEO Raoul Restucci said the repairs and expansion activities could take at least a month.

Oil and gas production from Brutus began in August 2001 (OGJ, Sept. 10, 2001, p. 66). Brutus is in 2,985 ft of water on Green Canyon Block 158.

FOUR NEW power plants are on the drawing boards for the US South.

Duke Energy North America has awarded Duke/Fluor Daniel contracts to perform engineering, procurement, and construction services for four natural gas-fired, simple-cycle merchant power generation plants with a combined capacity of 2,560 Mw. The four projects are the 640 Mw Southaven generation station in Southaven, Miss., the 640 Mw Enterprise generation station southwest of Enterprise, Miss., the 640 Mw Marshall generation station in Calvert City, Ky., and the 640 Mw Sandersville generation station north of Warthen, Ga.

A total of 32 combustion turbine generators will be used in the four projects, which are targeted for commercial operation to begin this summer. The four projects were booked into Fluor's backlog during the second half of its 2001 fiscal year.

Duke/Fluor Daniel expects to bring into commercial operation more than 13,000 Mw of new power generation in 2002. The company is a partnership between Duke Energy, Charlotte, NC, and Fluor Corp., Aliso Viejo, Calif.

DEVELOPMENT PLANS are progressing for the Aspen deepwater discovery in the Gulf of Mexico.

BP PLC and Nexen Petroleum USA Inc. signed a contract outlining the development of Green Canyon Block 243 about 150 miles south-southwest of New Orleans. The discovery lies in 3,000 ft of water.

Nexen will increase its holding in the field to 60% from 20% and pay incremental development costs for Aspen, which is being fast-tracked to production (OGJ, Nov. 19, 2001, p. 36). The field lies 5 miles from BP-operated Troika field. BP will operate the Aspen project.

Nexen estimates the field's gross proved reserves to be 40 million boe. On a total resource basis, Aspen could hold as much as 70 million boe with 15% being gas. "Aspen has potential of up to 150 million [boe] that could be established with additional drilling," Nexen said.

The early production system, which will cost $194 million, entails drilling, completing, and tying back two subsea wells to a host platform. Development is slated to begin in the second quarter, with production expected to start in the fourth quarter.

REGULATORY SNAGS in Costa Rica have created drilling delays there for Harken Energy Corp., Houston.

The company said it does not expect to receive the permits needed to drill the Moin well any time soon. Consequently, Harken is fully impairing its $8.8 million investment in Coast Rica in its yearend 2001 earnings.

Harken's subsidiary, Global Energy Development Ltd., holds 40% interest in certain properties, both on and off the eastern coast of Costa Rica (OGJ, Sept. 25, 2000, p. 44). All work, surveys, and assessments needed to request the environmental permit were filed in March 2001 with SETENA, Costa Rica's environmental agency.

SETENA must issue an environmental permit before the Ministry of Environmental Energy can issue a drilling permit. Meanwhile, in a case unrelated to Harken, the Costa Rican Supreme Court recently ruled that SETENA lacks the ability to grant environmental permits.

"We intend to continue lobbying and pursuing any legal avenues available for a reasonable resolution to these impediments being raised against the project and for the issuance of the permits," said Mikel D. Faulkner, Harken chairman.

A NEW PTT plant leads petrochemical news.

Shell Chemicals Canada Ltd., Montreal, has announced a contract with Ste. Generale de Financement du Quebec subsidiary SGF Chimie to form a 50:50 limited partnership to build and operate a polytrimethylene terephthalate (PTT) plant near Montreal.

Shell described the project as the world's first world-scale plant for production of the thermoplastic polymer.

The partnership will be called PTT Poly Canada, and project value is estimated at more than $100 million. The primary focus for the new plant will be the North American carpet market.

The facility is expected to begin operation by fourth quarter 2003. The capacity will be 95,000 tonnes/year. The plant will use proprietary technology developed by a Shell affiliate and Zimmer AG, which will be licensed to the partnership. A Shell affiliate also will provide sales and marketing services.

The primary feedstocks for PTT are 1,3-propanediol (PDO) and purified terephthalic acid (PTA). The PTA will come from a $700 million (Can.) SGF-Interquisa plant being built nearby. A Shell affiliate will supply PDO from its Geismar, La., plant.

The project will receive $15 million from provincial government investment agency Investissement Quebec, including a $5 million loan.

THE WORLD'S first diesel electric LNG carrier is on order.

Gaz de France signed a contract with French shipbuilder Chantiers de l'Atlantique for the construction of a 74,000 cu m LNG carrier, GdF reported. The order includes an option for a second vessel, said international classification society Bureau Veritas.

The vessel's tanks will use a cargo containment system developed by Gaztransport & Technigaz, a unit owned 40% by GdF. The carrier will be propelled by four natural gas-fired diesel engines, which will, in turn, generate electricity to power the ship's engines. GdF said the vessel is the first of its kind in the world that uses diesel-electric propulsion.

The new carrier will join six others already chartered by GdF. Gazocean Armement, a unit of GdF, will manage the French-registered vessel, which will operate in the Mediterranean Basin.

TOPPING pipeline news, a contract was signed for construction of a 142 mile, 36-in. natural gas system that will carry as much as 750 MMcfd of natural gas from the Chicago hub near Joliet, Ill., to Ixonia, Wis.

Guardian Pipeline signed a deal with H.C. Price Co., Dallas, to build the system. Guardian also signed a contract with Murphy Bros. Inc., Moline, Ill., for construction of the line's 22,225 hp compressor station, which will be built near Joliet. The station will consist of five engine compressor units.

Also, an 8.5 mile, 16-in. lateral is planned to a point near Eagle, Wis. Guardian Pipeline has agreements with Wisconsin Gas and others to transport 662 MMcfd (88% of design capacity) when the pipeline goes into service in November 2002.

George Hass, Guardian project manager, expects Guardian will meet its scheduled November in-service date. The Federal Energy Regulatory Commission approved the line in March 2001 (OGJ, Mar. 26, 2001, Newsletter, p. 9).

Construction on the compressor station is slated to begin next month. Pipeline construction will start June 1.

Guardian will transport gas from interconnections with Alliance Pipeline LP, Northern Border Pipeline Co., Midwestern Gas Transmission Co., and Natural Gas Pipeline Co. of America.

Guardian is a partnership of CMS Energy Corp., Dearborn, Mich.; Wicor, a unit of Wisconsin Energy, Milwaukee; and Viking Gas Transmission Co., a unit of Xcel Energy Inc., St. Paul, Minn.

In other pipeline news, Kerr-McGee Oil & Gas Corp., Oklahoma City, and partners have selected a unit of Williams Cos. Inc., Tulsa, to gather oil from Gunnison field in the deepwater Gulf of Mexico. Other participants in Gunnison development are Nexen Inc., Calgary, and Cal Dive International Inc., Houston. The three firms dedicated production to Williams from 10 blocks operated by Kerr-McGee in and around Gunnison field. The field lies in 3,100 ft of water. Initial production from Gunnison is expected in early 2004 (OGJ, Feb. 18, 2002, Newsletter, p. 8). To accommodate Gunnison production, Williams has agreed to install 90 miles of 18-in. gathering pipeline to move the oil from Garden Banks Block 668 to a shallow-water platform that Williams recently built on Galveston Block A244. From the platform, the oil will be delivered onshore under a joint tariff with ExxonMobil Corp.'s Hoover Offshore Pipeline System (HOPS). The 88,000 b/d capacity HOPS line is expected to be operational by late 2003.

Gas Authority of India Ltd. (GAIL) and Hindustan Petroleum Corp Ltd. (HPCL) signed a memorandum of understanding to establish a joint venture company-tentatively called Bhagyanagar Gas Ltd. (BGL)-for the distribution of natural gas, LPG, and other gas liquids in Andhra Pradesh state, India. BGL is expected to have an equity base of 1 billion rupees ($20.5 million). The project envisions an investment of 7-10 billion rupees over the next 7 years. Under the MOU, GAIL and HPCL will each hold 22.5% of the JV equity, with the government of Andhra Pradesh state having the option to acquire a 5% equity stake. The remaining 50% would be offered to financial institutions, both domestic and foreign. "The joint venture will distribute gas to the residential, commercial, and automotive sectors," said GAIL Chairman Proshanto Banerjee. "It will pursue the development of infrastructure and lay, operate, and maintain its own pipeline."

Duke Energy Corp. subsidiary East Tennessee Natural Gas has released a study it commissioned regardin the proposed Patriot natural gas pipeline extension project. Energy consulting firm Merrimack Energy, Salem, NH, compiled the study. Future incremental natural gas demand and transportation needs in the US Southeast target market exceed the capacity that the proposed project would provide, the study concluded. The project proposal is pending before FERC. "Without additional gas infrastructure, such as the capacity provided by the Patriot extension, regions of the Southeast could face limitations on pipeline capacity, which could limit the construction of new power generation options needed to meet market growth," the study said (see table). The Patriot extension will consist of about 94 miles of pipeline from Virginia to North Carolina to bring gas for the first time to parts of Southwest Virginia and introduce a competitive supply to North Carolina from Appalachian and Gulf Coast producers, said the consultant (OGJ, Feb. 4, 2002, p. 69).

The 24-in. Patriot extension would originate from Duke's East Tennessee system in Wythe County, Va.; cross Carroll, Patrick, and Henry counties in Virginia; and terminate in Rockingham County, NC. About 7 miles of lateral line would run from Rockingham County to Henry County, Va., the study said. The power market is driving regional gas demand, the report said. Peak electric demand in the Virginia-Carolinas area is projected to grow 2.3%/year through 2010.