OGJ Newsletter

Feb. 12, 2001
Will a major shortfall of natural gas supply this winter spell tight gas markets for the foreseeable future?

Market Movement

Gas markets to remain tight despite recent respite

Will a major shortfall of natural gas supply this winter spell tight gas markets for the foreseeable future?

That likelihood continues to persist even though a demand slump has brought gas prices back down from their stratospheric peaks of December.

The market may not yet have crested the top of a full-blown panic that Greenwich, Conn., analyst Charles Max well of Weeden & Co. was still predicting at the end of December.

Maxwell last summer was warning of a likelihood that a return to normal winter weather patterns-as the US has seen this season-would pull storage levels down to dangerously low levels, resulting in a crisis that would spawn price spikes and supply rationing to priority users (OGJ, Aug. 7, 2000, Newsletter, p. 5).

To some degree, those developments have already occurred. Gas prices reached $10/MMbtu in December, and price-induced spot curtailments have occurred in California and the US Northeast. But is a full-blown panic still in the offing?

Maxwell at the end of 2000 foresaw storage levels shrinking to 500 bcf by late February. This would, he said, result in a prioritization of supplies to residences, schools, hospitals, government offices and the like and away from industrial users. It would also result in gas prices in late winter soaring to $10-15/MMbtu.

Midwinter respite

Since those predictions a little over a month ago, there have indeed been significant reductions of gas supply to industrial users, but these have been mostly in response to sky-high prices, not official rationing.

Meanwhile, gas storage levels in recent weeks have remained higher than anticipated, and prices have moderated somewhat (although persisting at above $6/MMbtu as of last week).

Why is the outlook for storage suddenly brighter than expected just a few weeks ago? Put simply, withdrawals from storage have not been as strong as most analysts reckoned would be the case.

Salomon Smith Barney contends that the natural gas demand "has evolved in a relatively short period of time to the point of establishing a clearing price to balance supply."

That happened in January, the analyst says, when a good deal more fuel-switching and conservation occurred than most market observers would have thought possible. With oil prices off their fall peaks by as much as $10/bbl at the time, gas prices accordingly subsided to a level of near-parity with fuel oil and distillate prices, notes Salomon Smith Barney: "Consequently, crude oil prices appear to have more of a near-term effect on natural gas prices than most had originally anticipated."

Storage squeeze

Nevertheless, if the current level of fuel switching, conservation, and other demand-reducing actions remains unchanged, then Salomon Smith Barney pegs storage levels at the end of March at 800 bcf. That is still well below the 1 tcf level that is viewed as the accepted end-of-season minimum for gas storage, in order to ensure healthy storage levels throughout the cooling season.

But crude prices are firming again, thanks largely to OPEC discipline, and another round of arctic weather descended upon the northeastern and upper Midwest states last week. That could again jack up demand for natural gas and thus slash storage levels closer to the "panic" level of 500 bcf than to the merely worrisome level of 800 bcf.

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Either scenario calls for continued pressure on natural gas storage levels in the US. Maxwell projects that, even with a production surge from the ramp-up in gas drilling and reduced consumption of about 5-7 bcfd, US storage probably will not exceed 2.4 tcf in 2001 (see chart). That's considerably lower than the onset-of-season level of 2.74 last November that spawned $10/MMbtu gas.

Salomon Smith Barney sees a similar squeeze on storage, because it expects little significant growth in US wellhead deliverability. It sees US gas production growth rising only 3% this year.

The upshot is a gas price averaged over all of 2001 that Maxwell puts at a minimum of $5.50/MMbtu and that Salomon Smith Barney sees sustained at least at $5/MMbtu.

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Industry Trends

EIA reported that its voluntary greenhouse gas program has reduced emissions three-fold.

According to figures compiled through its Vol-untary Reporting of Greenhouse Gases program, EIA says that 1,715 projects claimed emission reductions in 1999 of 226 million tonnes of carbon equivalent-three times the amount reported in 1994, the first year of the program.

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The electric power sector once again accounted for the bulk of the volunteers, with 100 companies reporting to EIA. Among the projects reported were plant efficiency improvements; use of cogeneration; use of nonfossil fuels, such as nuclear and renewable fuels; demand-side management programs that reduced power use; methane recovery projects at landfills; urban forestry; and worldwide tree-plant- ing projects (see chart).

The number of firms reporting to EIA outside the power sector was eight times greater than when the agency started the program. These included auto- makers, petroleum producers and refiners, coal firms, and chemical companies.

EIA said that electricity generation projects accounted for over half of all reported reductions and that waste treatment and disposal projects claimed 20%-mostly through methane emissions reductions at landfills.

Oil and gas production in the UK moved in opposite directions last year, as total energy production fell 2.5% from the year before, according to preliminary UK DOE and Industry data.

Oil production dropped 7.9% in 2000 due to summer maintenance in the North Sea that lasted longer and had a greater impact than the prior year. Gas output rose 9.5%.

Yearend figures were mirrored by those of the fourth quarter, when oil production fell 8% while natural gas production climbed 9.5%, with four new fields coming on stream.

Overall indigenous primary fuel output in 2000 was 2.7% lower than in 1999, totaling 289.7 million tonnes of oil equivalent.

Consumption of gas rose 4%, largely due to its use to generate electricity, while oil use fell 1.7%.

Total motor spirit deliveries for 2000 were slightly lower at 1.8%, but deliveries of unleaded gasoline-which accounts for 93% of all motor spirit deliveries-climbed 4.3%. Fuel oil deliveries fell 22.2% due to "the general move away from fuel oil as a source of energy by industry and electricity generators" during 2000.

UK Department of Trade and Industry noted that prices of motor spirits and diesel dropped in the first 2 weeks of January-a reflection of the "large" fall in crude oil prices in December-but added that prices of motor fuels in 2000 generally were up, in response to higher crude oil prices.

Government Developments

STATES ARE LINING UP BEHIND PLANS TO BUILD AN ALASKAN GAS PIPELINE TO THE LOWER 48.

With hydroelectricity at all time lows and power demand growing, western governors this month called for construction of a natural gas pipeline from Alaska to the Lower 48 and an immediate assessment of gas availability and transmission capacity to determine if supplies will be adequate to meet this summer's peak demand.

Concluding a hastily called energy summit, the Western Governors' Association also agreed to ask the federal interagency task force headed by Vice-Pres. Dick Cheney to work with them to streamline regulations to allow retired generation to be reactivated, increase production from existing generation, and allow backup generation to come on line. The governors also offered these resolutions for the energy problems facing the region:

  • Encourage long-term contracts to reduce dependence on the spot electricity market in California.
  • Encourage non-California utilities and direct end use customers to hedge power purchases against future price spikes.
  • Ask state public utility commissions to approve demand-exchange tariffs to allow consumers to voluntarily agree to reduce demand in exchange for compensation.
  • Streamline permitting energy facilities, implement research and development into clean coal technologies, accelerate development and deployment of renewable energy technologies, and review environmental policies to ensure they are as efficient as possible.
  • Review and improve energy efficiency building codes for western states, develop federal appliance efficiency standards unique to western state climates, and support federal and state tax incentives to accelerate new energy-efficient technologies.

Alaska Gov. Tony Knowles has named a 28-person task force to consider construction of a gas pipeline from Prudhoe Bay field to the Lower 48 via the Alaska Highway route (see related story, p. 74).

Knowles created the council Jan. 26 with an administrative order. It will help him and the Alaska Highway Gas Pipeline Cabinet to determine how the state can promote the pipeline project.

Retired ARCO Alaska Senior Vice-Pres. Frank Brown and Jim Sampson, executive director of the AFL-CIO in Alaska and a former mayor of the Fairbanks North Star Borough, will co-chair the panel.

Knowles said, "Commercialization of North Slope natural gas via the gas line project is the biggest economic opportunity to come to Alaska in years. Taking full advantage of this opportunity won't be easy, though, and that's why we need a broad-based, diverse group of Alaskans to work through the many issues that have to be addressed."

The council will consider how the line could benefit Alaska communities; how to attract investment for in-state gas processing; whether to take the state's royalty share of the gas or sell it in Lower 48 markets; options for GTL, LNG, and NGL projects; state demand for gas; environmental issues; the impact on the Alaskan labor market; and potential ownership by the state of some or all of a pipeline project.

Quick Takes

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Anadarko Petroleum has started production from the Tanzanite and Hickory subsalt discoveries off Louisiana in the Gulf of Mexico.

The fields began producing from one well each in the last week of December. Tanzanite, on Eugene Island Block 346, is producing more than 10,000 b/d of oil and 23 MMcfd of gas from the A-1 well. A second well is expected to be on stream in February. Once both wells are on line, Tanzanite will produce 15,000 b/d of oil and 50 MMcfd of gas.

Anadarko holds 100% of Tanzanite, which is in 314 ft of water. Hickory, on Grand Isle Block 116, is producing 62 MMcfd of gas and 4,100 b/d of condensate from the A-1 well. Three more wells will be completed and tied in over the next few months, after which Hickory will produce more than 200 MMcfd.

Anadarko operates Hickory, which is in 320 ft of water, with 50% interest. Shell E&P holds 37.5%, and Ocean Energy holds 12.5%.

In other production news, Southern Pacific Petroleum NL and Central Pacific Minerals NL, along with JV partner Suncor Energy, produced 16,000 bbl of naphtha and medium shale oil in a December test run at the Stuart project near Gladstone in Queensland. The companies said the demonstration plant has produced 17,000 bbl of naphtha and 18,000 bbl of medium shale oil since late 1999. More-continuous production is expected during 2001. Oil sales will begin in the second quarter when sufficient volumes are in storage. The companies said results of the December run showed good progress, with an emissions-reduction program implemented in 2000. Feedstock rates were kept to 160 tonnes/hr of oil shale (64% of plant capacity). The plant removed more than 95% of SO2 and cut more than 60% of odors and dioxins. Shale dust emissions dropped to a third of the plant license limit. The companies said the improvements resulted from an 8-week turnaround in the third quarter that included installation of turboscrubbers on the processor flue gas systems, addition of a second thickener vessel to increase the capacity of the shale dust scrubber, operation of the shale dryer in a low-odor mode, and partial incineration of the processor preheat flue gas stream in the main stack burner. Southern Pacific and Central Pacific said they will restart the plant this month and gradually increase feed rates during the year.

Texaco and partners have MADE two gas discoveries in the Northern Carnarvon basin off Western Australia.

The Iago-1, on exploration permit WA-25-P, and the Io-1, on permit WA-267-P, follow the discoveries Geryon (1999), Orthrus (1999), Urania (2000), Maenad (2000), and Jansz (2000) made by Texaco and its partners in the same area adjacent to the giant Gorgon gas field.

The Iago-1 well was drilled to a TD of 11,100 ft in 387 ft of water. Logs and formation tests confirmed hydrocarbons in the Triassic Mungaroo. The well was plugged Jan. 3. The Io-1 well was drilled to a TD of 9,941 ft in 4,436 ft of water. It was plugged Jan. 14.

Texaco Australia holds 28.6% in WA-25-P and 25% in WA-267-P. Partners are operator Chevron Australia, Mobil Australia Resources, and Shell Development (Australia) BP Exploration (Alpha) participates in WA-267-P only.

Elsewhere on the exploration front, PTT Exploration & Production (PTTEP) will launch a $40 million second drilling campaign to assess Arthit, one of the most promising gas areas in the Gulf of Thailand. PTTEP, the upstream unit of state-owned Petroleum Authority of Thailand, will drill at least 10 wells in the three-block area designated as Arthit in the second quarter. They will use a Transocean Sedco Forex jack up. PTTEP plans to spud two exploratory wells in 14A and two in 16A, then follow up with six appraisal wells in the core area in 14A and 15A. PTTEP estimated that Arthit, 35 km northeast of Bongkot field, holds 3.64 tcf of potential gas reserves. Maroot Mrigadat, senior vice-president of PTTEP, said Arthit could produce at 500 MMcfd. PTTEP said that, due to lower-than-expected Thai demand, it does not expect to bring Arthit on stream before 2005. As of yearend 2000, PTTEP and its partners have spent $89 million on the acreage.

Gambela Petroleum has signed a production-sharing agreement with Ethiopia, said parent company Pinewood Resources. It has committed to spend more than $5 million on work commitments. The 15,000 sq km concession area is in the Gambela area in southwestern Ethiopia. It includes the entire Melut basin, said Pinewood. The agreement provides for a 4-year exploration period, which Gambela can extend 4 more years through work commitments and minimum expenditures. During the first exploration period, Gambela must spend $50,000 the first year, $2.1 million the second year, $900,000 the third year, and $2 million the fourth year. The company must shoot, process, and map at least 1,000 km of seismic within 17 months of the signing and drill one exploration well within 38 months. During the first 2-year extension, Gambela must shoot, process, and map at least 200 km of seismic data, which will cost at least $600,000, and drill one exploration well costing at least $2 million. During the second 2-year extension, Gambela must acquire at least 200 km of seismic and drill one more exploration well at a total cost of $2.6 million.

PetroChina has made three major oil discoveries in Junggar basin in northwestern China's Xinjiang region that it estimates together hold combined postulated reserves of almost 200 million tonnes. PetroChina estimates the Luliang prospect, discovered in June last year in the center of the basin, has probable oil reserves of 100 million tonnes, with 70 million tonnes proven recoverable. In the west of the basin, PetroChina discovered Kayingdike field last July. PetroChina estimates potential reserves at 70 million tonnes. The discovery well Ka-6 flowed 409 b/d of oil. The Tugu 2 well in the southern part of the basin flowed 241 b/d of crude. PetroChina estimates that the Tugu prospect has reserves of 20 million tonnes.

Peru last month launched another exploration and production licensing round. It plans a Feb. 27 presentation in Houston on the round. Peru is offering four unexplored blocks in deep water off its northern coast. They are near Occidental Petroleum's Block Z-3, where the operator has completed seismic work and is seeking a partner to continue exploration. Perupetro, the state oil agency, also is offering E&P contracts for six other offshore north coast blocks and technical evaluation agreements (TEAs) for eight blocks on the south coast. Petroperu is also offering two TEAs in the northern jungle and one in the Titicaca basin.

Occidental Petroleum has signed an 18-month agreement with Perupetro to evaluate Blocks 21 and 22 in Peru's Pachitea and Ucayali basins. Perupetro said that the accord goes further than a TEA and includes a guarantee that studies will be completed. Perupetro also signed an E&P license with Repsol-YPF for Block 27 in the Marañon basin. The North Peruvian pipeline runs through the southern end of the block. And Perupetro has been authorized to sign an E&P contract with Maple Gas for Block 31-E in the Ucayali basin, where the company produces an average 400 b/d of crude oil from two other small blocks. Maple will complete seismic studies in an initial 2-year period and will drill an exploration well in the second 26-month period.

Santos, operator for the South West Queensland unit, had a zone discovery in the Queensland sector of the Cooper-Eromanga basins. Challum-19 flowed 212,380 cu m/day of gas through a 13-mm choke from a pre-Permian carbonate at 2,339-2,367 m. Nearby production is from the Permian Toolachee. Block interest holders are Santos (60.0625%), Delhi Petroleum Pty. (23.2%), Origin Energy (16.5%), and Oil Co. of Australia (0.2375%).

Santa Fe International has placed an order with PPL Shipyard for two jack ups.

In December, Santa Fe said it intended to build two deepwater semisubmersibles and up to four jack ups.

The jack ups will cost $125 million each and take 2 years to complete. The agreement includes options for additional jack ups, with the first two at a similar price. Construction of the second jack up will begin a year into construction of the first unit. The jack ups, which will be capable of drilling in 400 ft of water in moderate environments and in 300-350 ft in harsh environments, will be marketed worldwide.

They will have 75-ft extended-reach cantilevers; three 7,500-psi, 2,200-hp mud pumps; and a large mud storage and deck load capacity.

Santa Fe is negotiating with several shipyards to build the semis and expects to award a contract later this quarter.

In other drilling sector action, 5-year charter and service contracts for two newly built deepwater semis will effectively resolve a principal part of its troubled Amethyst JV, Pride International officials told financial analysts last month. Under the new contracts with Petrobras, Pride will collect a higher day rate of $122,000, producing aggregate revenues of more than $500 million over 5 years. In addition, Petrobras now will pay mobilization costs totaling $16.5 million for the two rigs. In a separate deal, Pride agreed to buy out its partners in the two rigs, making stock transactions to obtain sole ownership. The rigs being obtained by Pride are the former Amethyst 6, renamed Pride Brazil, and the Amethyst 7, now the Pride Carlos Walter, both built in South Korea. The Pride Carlos Walter is en route to Brazil by way of South Africa, while the Pride Brazil is scheduled to leave South Korea on Feb. 9 along the same route. The rigs are expected to complete acceptance testing and to be ready for work by June or July, officials said.

Topping pipeline news this week, Olympic Pipe Line is conducting safety checks on a 16-in. petroleum products pipeline in Washington state in a move that could phase in the restart of a 37-mile section within a month, officials said.

The pipeline ruptured June 10, 1999, spilling 229,000 gal of gasoline into a creek in Bellingham, Wash., 90 miles north of Seattle. The spill ignited into a fireball that killed three people.

The 37-mile section of pipeline was shut down following that accident when federal investigators reported several safety violations by Equilon Enterprises, which then operated the pipeline. The US Department of Transportation's Office of Pipeline Safety (OPS) subsequently assessed fines of $3 million against Equilon.

Last month, OPS officials approved Olympic's plan to start pumping diesel fuel-the least volatile product-into the pipeline to test its reliability and the new safety equipment installed after the accident.

At the time of the accident, ARCO was a minority stockholder in that pipeline. BP took over its interest when the two companies merged. Then last July, BP Pipelines made a successful bid to become operator.

In other pipeline news, Horizon Offshore and Cal Dive International signed a letter of intent to form a JV to conduct reeled pipelaying projects in the deepwater Gulf of Mexico. The companies have already formed a strategic alliance to work in the gulf. Once the JV agreement is completed, the companies will perform small-diameter pipelaying projects in 800 ft or more of water. The companies will jointly fund construction of pipelaying equipment to be used with CDI's Sea Sorceress lay vessel, which is undergoing conversion.

Tennessee Gas Pipeline began an open season for its proposed Connecticut-Long Island lateral. The 100-mile project would move up to 450 MMcfd from Tennessee Gas Pipeline's mainline in Massachusetts to Suffolk County on eastern Long Island, NY. Service could begin in November 2003.

CMS Oil & Gas (Congo) has selected Global Offshore International to lay 2 miles of dual 18-in. lines in 380 ft of water at Yombo field off Congo (Brazzaville). Global will use the Comanche pipelay-derrick barge to install the lines from the Yombo A and B platforms to a floating production, storage, and offloading vessel.

The Yanpet JV has started up a major expansion at its petrochemical complex at Yanbu, Saudi Arabia, said ExxonMobil Chemical.

Yanpet is a 50-50 JV between Mobil Yanbu Petrochemical-an affiliate of ExxonMobil Chemical-and Saudi Basic Industries.

The expansion included a second 800,000 tonne/year steam cracker, a 535,000 tonne/year polyethylene plant, and a 410,000 tonne/year ethylene glycol plant.

The complex is producing 260,000 tonnes/year of polypropylene, a new product line for Yanpet. The expansion brings Yanpet ethylene capacity to 1.7 million tonnes/year.