OGJ Newsletter

Feb. 11, 2002
The most recent arctic blast across much of the US and Canada has led many to wonder: could natural gas prices be rescued from their sagging levels during an otherwise forgettable heating season?

Market Movement

Return to 'normal' temperatures?

The most recent arctic blast across much of the US and Canada has led many to wonder: could natural gas prices be rescued from their sagging levels during an otherwise forgettable heating season?

Several analysts have taken note of the US National Weather Service's near-normal temperature forecast for the US for the balance of the season. "Normal" temperatures in winter spells robust gas demand, which-sustained over much of the season-might pull down a huge overhang in gas storage, enough to keep prices from being further depressed before the start of the summer cooling season. If the cold weather doesn't materialize to the extent forecast, however, a further plunge in gas prices may result before the cooling season (and economic recovery) turn things around.

The last week of January marked the third consecutive week of warmer-than-normal temperatures and the 11th such week of the overall heating season, noted UBS Warburg analysts Ron Barone and James Yannello.

As of that week, US temperatures had averaged 18% above normal for the season and 26% higher than last year. All major sectors of the US had been warmer than normal, except for the West Coast, which was 12% colder than normal.

Market factors

It remains to be seen how much of a dent the recent cold snap will put in US gas storage levels, which remain historically high.

According to AGA, industry withdrew 111 bcf of gas from storage during the last week of January, vs. 125 bcf the week before and 128 bcf the same time a year ago.

However, US storage levels remain more than 1 tcf above year-ago levels and 600 bcf above the prior 3-year average for this time of year. This time a year ago, year-on-year US gas inventories were posting a deficit of more than 500 bcf.

Inventories during the last week of January rose to 2.3 tcf vs. 1.2 tcf during the same week last year, well below the record of 3.1 tcf set on Nov. 23 but still 600 bcf above the prior 7-year average. It's likely that the most recent cold blast prevented an even worse buildup in the year-to-year storage surplus spawned by the earlier, milder winter weather.

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"Nevertheless," said Barone and Yannello, "if one were to apply the average 7-year historical weekly withdrawal rate of 81 bcf going forward, Apr. 1, 2002, storage supplies would approximate [1.5 tcf] vs. the prior 7-year Apr. 1 average of 946 [bcf] (see table)."

Even with the storage glut and an overall lag in seasonal demand, ironically, there have been some underlying bullish market signals, said Kristin Dall, senior analyst with Wakefield, Mass.-based Energy Security Analysis Inc.

The amount of speculative short overhang for NYMEX gas futures contracts would normally signal a bullish warning to the market, she said: "If the market is threatened by some extremely bullish event, there is enough potential for prices to skyrocket and turn things around."

But until the weather intervenes, the short strategy seems a safe bet, she added.

With gas prices hovering near $2/MMbtu-a level not sustained this low since early 1999-lagging demand has lowered the floor under prices.

Dall also believes that, "Funds have helped to drive this contract to $2/MMbtu and could take it even further." She cited two other incidents in recent years "when noncommercials have held this high a percentage of overall open interest in Henry Hub contracts-both resulting in increased price pressure and volatility."

Industry Scoreboard

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Industry Trends

US natural gas production volumes for fourth quarter 2001 were down 1.14% vs. fourth quarter 2000, based on a survey conducted by Lehman Bros. of 22 companies-which collectively produce 45% of US gas. These same companies reported a 3.04% decline in total 2001 production vs. year-ago levels.

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That compares with Lehman Bros.' forecast for a sampling of 45 companies that account for 70% of US gas production. That forecast shows a 0.2-0.5% quarter-to-quarter decline for fourth quarter 2001 and a 1.5-2.5% year-on-year decline for 2002 (see table).

A key element in its forecast, the analyst said, was its attempt to rationalize the "unusually steep" decline in third quarter 2001 gas production, which was 1.1% lower than the analyst's model forecast.

"Lower natural gas prices of the past few months have reduced the incentives to drill high-rate wells," Lehman Bros. said, "As a result the production modelellipseassumes that shallower production decline rates will be experienced over the next several quarters."

US integrated oil companies' adjusted fourth quarter 2001 net income, meanwhile, is estimated to have fallen off by 56%, to $4.1 billion, according to UBS Warburg analyst Matthew Warburton.

"This marks the worst quarterly earnings for the US oil majors since third quarter 1999, as business fundamentals deteriorated across all the business segments," Warburton said.

The analyst expects individual firms' earnings to decline by 49-90% year-on-year, "with the worst comparisons reflecting those companies with the highest sensitivity to oil and natural gas prices," he said.

THE GLOBAL CRUDE OIL BARREL is not getting more sour, says Sarah Emerson, managing director of Energy Security Analysis Inc. Despite the seesaw effect of OPEC production decisions on global crude oil quality, there is little that can move the global ratio away from the 55:45 (sour:sweet) split over the next 5 years, says ESAI in the latest Stockwatch Quarterly Review-ESAI's view of the oil markets over the next 2 and 5 years. ESAI expects a gradual shift to a 54:46 ratio by 2006.

"Even though there are distinctly more heavy sour reserves in the world, andellipsethe North Sea has slowed down, the worldwide development of sweet production will prevent a shift in the quality of the global crude oil barrel," Emerson said.

Those sweet, often light, gains include discoveries in Africa, the Caspian, eastern Canada, and Persian Gulf condensates. "These developments will keep a more sour-and largely heavier-global barrel at bay, at least during the next 5 years," said Emerson.

Government Developments

US OIL COMPANIES are praising a recent White House decision to conditionally waive a decade-old sanction that blocks official US aid to oil-rich Azerbaijan.

President George W. Bush waived Sec. 907 of the Freedom Support Act. Congress put the sanction in place in 1992 because Azerbaijan refused to trade with its neighbor Armenia during a conflict over the disputed Nagorno-Karabakh region.

But central Asia's expanded role in the US fight against terrorism helped accelerate a tentative compromise between the two groups that had eluded US officials for much of a decade. Former President George H.W. Bush had sought to lift the sanctions, as did former President Bill Clinton, but Congress was not persuaded.

"The waiver clears the way for the US to deepen its cooperation with Azerbaijan in fighting terrorism and in impeding the movement of terrorists into the South Caucasus. The waiver will also provide a foundation to deepen security cooperation with Armenia on a common anti-terrorist agenda," the White House said in a Jan. 30 statement.

Industry lobbyists said the move will create a more positive business climate in Azerbaijan. Several multinational oil companies are working with the Azeris to facilitate the construction of a pipeline from the Azeri capital of Baku through Tbilisi, Georgia, and on to the Mediterranean Turkish port of Ceyhan.

"Additional US assistance would help improve the prospects for further democratization, legal and regulatory reform, and alleviation of poverty," ExxonMobil said in an opinion piece that ran in major newspapers in September 2000. "Regional coordination of energy development, environmental protection of the Caspian Sea, and multiple oil and gas pipeline projects would all be advanced by a supportive US role. But achieving these goals is compromised by sanctions."

The US MMS proposed a rulemaking to incorporate by reference into its regulations nine standards regarding floating production systems.

MMS explained that adopting the eight API and one American Welding Society standards would enhance its ability to permit floating offshore platforms that have not been specifically covered under its existing rules.

The floating production systems include column-stabilized units; floating production, storage, and offloading systems; tension-leg platforms; and spars.

"These specific standards were identified as critical to the continued success of deepwater developments that rely on floating production systems," said Carolita Kallaur, MMS associate director, offshore minerals management.

"Industry assumes the high financial risks of developing deepwater areas; this effort would provide certainty in the regulatory expectations for equipment and systems used in deepwater developments. These documents also improve MMS engineers' efforts in reviewing each new project to ensure structural integrity, operational and human safety, and environmental protection," Kallaur added. MMS requested public comment on the proposed rule by Mar. 27.

Quick Takes

PRODUCTION has resumed in Kuwait after recent shutdowns curtailed production there.

About 600,000 b/d-a third of Kuwait's output-was shut in after an explosion damaged a gathering station, a power plant, and a 300 MMcfd gas booster facility at the northern oil fields. Production resumed at 50,000 b/d and will rise to 100,000 b/d this week. It could be 6 weeks before production is back at 600,000 b/d. The explosion killed four persons and injured a dozen others.

Meanwhile, Norway will have lost about 1 million bbl in North Sea oil production from Statoil's 5-day shutdown of Statfjord field and its satellites-Statfjord East, Statfjord North, and Sygna. Corrosion damage to pipe in the flare system on the Statfjord C platform caused that shutdown. Aker Maritime, which holds the maintenance contract for piping systems on Statfjord, is carrying out repairs.

In other production news, Pakistan's privatization commission will proceed Apr. 15 with a long-delayed auction for working interests in nine producing oil and gas fields. The commission offered interests in the concessions-in Adhi, Badin-I, Badin-II, Dhurnal, Mazarani, Minwal, Pariwal, Ratana, and Turkwal fields-which produce an average 20,000 b/d net to the government.

PIPELINE PROJECTS IN AFRICA are heating up.

ExxonMobil and partners are planning a 650-mile, 24-in. oil pipeline from fields in Chad to an export terminal in Cameroon.

The pipeline will facilitate exports from a controversial $3.5 billion oil development project in Chad (OGJ, Feb. 4, 2002, p. 26).

The World Bank has issued a $200 million initial loan, and export facilities are under construction. Drilling of the first test wells in three Doba basin oil fields in southern Chad were due to start in December 2001 to produce the country's first oil.

The project is planned to have a 25-year life, with 300 wells producing a peak of 250,000 b/d in mid-decade. First oil is due in 2003.

ExxonMobil, operator through its Esso Chad subsidiary, holds a 40% interest; Petronas Carigali of Malaysia has 35%, and ChevronTexaco, 25% (OGJ Online, Dec. 10, 2001).

Meanwhile, the West African Gas Pipeline also appears to be going forward.

The Economic Community of West African States said work would begin in 2003, OPEC News Agency reported.

Chevron Nigeria is heading the project, which also includes Royal Dutch/Shell and Nigerian National Petroleum Corp., among others (OGJ, Oct. 11, 1999, p. 38).

The 600-km, 400 MMcfd line would link Lagos to Takoradi, Ghana, and with supply points at Cotonou, Benin; Lome, Togo; and Tema, Ghana. Construction is planned to start in 2003.

Participants at a meeting convened under the framework of the New Partnership For Africa Development also discussed the possibility of extending the line to Ivory Coast.

In other pipeline happenings, Maritimes & Northeast Pipeline has applied to FERC for a $250 million Phase IV expansion to nearly double capacity of its natural gas pipeline from Offshore Nova Scotia to the northeastern US. The proposed expansion would boost capacity to 800 MMcfd from 415 MMcfd. Recently completed open season nominations garnered substantial requests for transportation services from local natural gas distribution companies, natural gas-fired power plants, and third-party marketers.

M&NE has agreements to transport as much as 400 MMcfd from PanCanadian Energy Services' Deep Panuke project off Nova Scotia. The Phase IV expansion, expected to be in service in 2004, involves construction of four 26,800-hp compressor stations in Maine and 31.3 miles of additional pipeline loops in Maine's Washington County. M&NE is owned by affiliates of Duke Energy 37.5%, Westcoast Energy 37.5%, ExxonMobil 12.5%, and Emera 12.5%.

GULF OF MEXICO development continues apace.

ABS currently is providing classification services and facilitating fast-track fabrication and installation schedules for Murphy Oil's Medusa truss spar and for the Dominion-Williams Devils Tower truss spar, the world's deepest-water dry tree platform to date.

J. Ray McDermott is engineering, procurement, construction, and installation contractor for both the Medusa and Devils Tower spars.

Medusa will be located on Mississippi Canyon Block 582 in 2,223 ft of water. Operator Murphy Oil has a 60% operating interest; other interest holders include Agip Petroleum and Callon Petroleum.

McDermott's wholly owned subsidiary, SparTEC, is general contractor for Medusa engineering, procurement, installation, and construction, and another McDermott subsidiary, Mentor Subsea Technology, is handling design and procurement of the production risers. Upon completion, the facility will have capacities of 40,000 b/d of oil and 110 MMcfd of gas. First oil is scheduled for November 2002.

The Devils Tower spar is destined for Mississippi Canyon Block 773 in 5,610 ft of water. It is operating on a very fast track, with the project scheduled to be completed in 18 months. First oil is anticipated in mid-2003.

In other Gulf of Mexico development activity, El Paso Energy Partners has given MODEC International a letter of intent for the engineering, procurement, and construction of the hull, mooring, and production riser system for the world's deepest-water tension-leg platform.

The TLP, which EL Paso and Cal Dive International will own, will be a production hub at Green Canyon Block 608. It initially will serve to develop Anadarko Petroleum's Marco Polo field.

The TLP, to be installed in 4,300 ft of water-claimed as a record for a TLP-is capable of supporting equipment to process 100,000 b/d of oil and 250 MMcfd of gas.

The facilities are scheduled to be on line in 2004. MODEC International is a joint venture of FMC Technologies and MODEC.

Elsewhere in the world, Agip Gas, on behalf of ENI and Libyan state oil company National Oil Corp., has awarded a 1.2 billion euro ($1.03 billion) engineering, procurement, and construction contract for oil and gas production treating facilities near Mellitah, Libya, to a consortium led by JGC Corp. The other consortium members are Technimont and Sofregaz. The contract is part of the $4.6 billion, 1.8 billion boe development of offshore Block NC 41 and onshore Block NC 169 (OGJ, Oct. 13, 1997, Newsletter).

The development will produce 98,000 b/d of liquid hydrocarbons and 10 billion cu m/year of gas. Libya will use 2 billion cu m. The rest will be transported through a 32-in., 540-km subsea pipeline from Mellitah to Gela, Sicily, said ENI. Greenstream, owned by ENI and Noc, is building the line and a 170 Mw compression station. The system will cost $1 billion, said ENI. ENI and NOC will award five more contracts relating to the project in the next few months, said ENI.

YUKON TERRITORY officials have awarded oil and gas exploration rights in the Peel Plateau of northwestern Canada to Hunt Oil Co. of Canada.

Hunt plans to spend $1.16 million to explore 155 sections having an area of about 40,200 hectares just south of the Arctic Circle.

A resource assessment of the Peel Plateau basin, completed by Canada's National Energy Board and updated in November 2000, identified the potential for 2.29 tcf of gas and 21.3 million bbl of oil.

The government plans to initiate its next oil and gas rights disposition process in late spring.

Elsewhere on the exploration front, McMoRan Exploration Co. said a well on its Louisiana State Lease 340 flowed 10-20 MMcfd from a 42-ft interval. In addition to the tested interval, the Mound Point well found a laminated sand section at 16,890-17,275 ft that could also contain hydrocarbons. Mound Point No. 2 well was perforated at 18,558-600 ft. Initially, it flowed free of water, but the cement that isolated the hydrocarbon-bearing sands apparently failed, McMoRan said, and salt water from sands above the perforated zone encroached on the well. The company said the interval has excellent porosity and should achieve high flow rates.

It has shut in the well and expects to recement and retest it. McMoRan Cochairman James Moffett said the Mound Point area has one of the largest structures in shallow waters off Louisiana and has produced 3 tcf of natural gas from sands above 12,000 ft, but the Miocene sands immediately below the shallow sands have been sparsely drilled. McMoRan has exploration rights on 60,000 acres in the Mound Point area and an option to earn rights in an adjacent 20,000 acres.

Petronas affiliate Carigali Overseas has signed another production-sharing agreement with Equatorial Guinea for Corisco Bay Block N in the Rio Muni basin, said block partner Ocean Energy. Block N covers 678,000 acres in up to 660 ft of water. Ocean said its holding of 30% of the block will bring its total Equatorial Guinea holdings to more than 2 million gross offshore acres. Vanco Equatorial Guinea will hold 10%. Carigali will operate Block N and hold 60%, and GEPetrol, Equatorial Guinea's national oil company, will have a 15% carried interest in the block. The block is south of Ceiba field and three other recent discoveries and north of the northern Gabon Salt basin.

HEAVY CRUDE tops refining news of interest.

Valero Energy Corp. has selected Foster Wheeler USA to provide engineering, procurement, and construction services for the 45,000 b/d delayed coker at its 220,000 b/d Texas City, Tex., refinery.

Valero said it would install the coker to better process 90,000 b/d of heavy, sour Maya crude that it will begin taking under long-term contract from Pemex unit PMI Comercio Internacional (OGJ Online, Jan. 10, 2001).

Foster Wheeler said the contract is worth $275 million. Work includes design and construction of the delayed coker, a sour water stripper, miscellaneous offsites and utilities, and associated process unit revamps.

Foster Wheeler plans to use its proprietary delayed coking technology to process a combined feedstock of Maya vacuum tower bottoms and pitch from Middle Eastern crude.

Engineering is under way, and the project is scheduled for mechanical completion in fourth quarter 2003.

ANOTHER LNG MEGAPROJECT marks progress.

Egypt signed an $8 billion, 20-year agreement to supply Gaz de France with 3.6 million tonnes/year of LNG, paving the way for an LNG export plant at Idku, east of Alexandria.

BG Group and partners, Italy's Edison International, Egyptian Natural Gas Holding Co., and Egyptian General Petroleum Corp. (EGPC), have formed the Egyptian LNG (ELNG) joint venture to build and operate the plant.

Gaz de France is Europe's largest LNG buyer. The gas supply contract represents 10% of France's current annual gas demand.

Gaz de France will take a 5% stake in ELNG, which will involve the combined development of uncontracted offshore gas reserves in the West Delta Deep Marine Concession (WDDMC), associated large pipelines, and the LNG plant. BG Group is operator of WDDMC, with a 50% holding, and Edison International holds 50%.

The contract with Gaz de France, likely to be followed by sales contracts with US customers, is expected to lead to final project sanction, following completion of front-end engineering design studies.

The first train will have a capacity of 3.6 million tonnes/year of LNG, with first production scheduled for mid-2005. BG has WDDMC reserves sufficient to support a second train.

ELNG partners will operate the plant as a tolling facility. The commercial structure will facilitate future plant expansions and the processing of gas reserves from other fields and operators.

The Scarab-Saffron WDDMC is the first gas field development in deep water off the Nile Delta and is the largest gas field development in Egypt. First gas production is expected in January 2003.

Bechtel Group is the deepwater managing contractor on Scarab-Saffron-currently being developed for the Egyptian market-and has been involved in the early definition and engineering work for the LNG plant.

BG Group, with a $3 billion exploration and development program in Egypt, is the most successful explorer in Egypt, with discoveries since 1997 totaling more than 10 tcf of gas.

The associated Simian, Sapphire, Sienna, and Serpent discoveries will support the LNG export scheme. Large offshore pipelines sufficient to support a two-train LNG development are being installed.