MARKET ACTIVITY/TRADING NOTES FOR DAY ENDING WED DECEMBER 17, 1997 (3)
OIL & GAS
Despite bearish inventory data, crude-oil and petroleum-product futures finished little changed Wednesday on the New York Mercantile Exchange. January light sweet crude settled up $0.02 at $18.19.
The American Petroleum Institute reported that U.S. crude oil stocks rose 5.08 million barrels during the week ended Dec. 12. But most of the build was on the West Coast, which tends to have little impact on Nymex trading, and inventory figures from the U.S. Department ofEnergy showed a less bearish build of 2.5 million barrels.
Gasoline stocks rose by 1.847 million barrels, according to the API. The DOE showed a larger build of 3.3 million barrels. Both figures are bearish, but unexpected shutdowns of gasoline production at two U.S. refineries reported earlier in the week offset some of the bearishness from the stock data, one trader said. Distillate stocks, which include heating oil, were unchanged in the DOE report, which offset any sentiment from the small build reported by the API, a trader said.
U.S. Spot Natural Gas Prices Gain Again On Weather
U.S. spot natural gas prices moved higher again Wednesday, as traders shrugged off the balmy temperatures blanketing most regions and focused instead on forecasts for more seasonal weather by the weekend.
"There is some colder weather coming in for the weekend, so people are anticipating that," said one Texas-based trader. Spot gas at Henry Hub firmed almost a dime to the mid-to-high $2.30s per mmBtu, still 15-20 cents below the December index.
Temperatures in the Northeast and Mid-Atlantic are expected to stay five to 15 degrees F above normal until the weekend when a cold front should drop readings to more seasonal levels. Texas was expected to move from several degrees above normal to 4-12 degrees below normal this week, while the Midwest should drop from as much as 25 degrees above to only slightly above during the period.
In the Midwest, prices gained almost a nickel to about the $2.20 level, still more than 10 cents below December 1, while Chicago was quoted more than five cents higher in the mid-$2.30s or better.
In west Texas, Permian Basin gas was talked in the mid-teens, up three cents on the day but still six cents below index. The Southern California border market was five cents higher at about $2.30.
On the East Coast, New York city gate gas gained about five cents to the $2.70 area despite the mild weather there.
Late NYMEX Natural Gas Pares Some Gains But Still Up
NYMEX natgas futures pared early gains but remained higher at the close Wednesday in fairly active trade, still driven by short covering ahead of today's weekly stock report and a cold front expected later this week. January natyral gas settled up $0.029 at $2.438 per million British thermal units. Most other months were still holding gains of between $0.020 and to $0.034.
"We seem to be up mostly on short-covering related to expectations for a considerably higher (weekly stock) withdrawal, but I don't really see cash supporting the move. Cash is being dragged up by futures," said one Texas-based trader.
A Reuters poll showed most expected a weekly AGA stock draw in the 90-100 bcf range versus a 53 bcf decline for the same week last year.
Forecasts this week call for mostly above-normal U.S. temperatures through Friday, with a cold front by the weekend expected to drop temperatures in most regions back to more seasonal levels. Some below normal weather is expected in Texas by Saturday.
While the technical picture improved yesterday with January's close above resistance, most agreed colder weather was needed to put the gas market back on the bullish track.
A trader noted one forecaster was expecting the season's first Arctic air mass to hit the upper Plains late next week, but most attributed recent gains to short covering and not to any long-term bullish enthusiasm.
Chart traders pegged next January resistance at $2.57 and then in the low-$2.60s, with better selling likely at the $2.81 double top from early December. Support was seen at $2.38 and then at $2.25, which is the low for January this year. More buying was expected around $2.14 and then at $2.05.
In the cash Wednesday, Gulf Coast prices firmed almost a dime to the mid-$2.30s. Midcon pipes gained about a nickel to the low-$2.20s. Despite some mild weather in New York, city gate gas firmed almost five cents to about the $2.70 level, while Chicago was more than five cents higher in the mid-$2.30s or better.
REFERRENCES
Charts: oilworld.com
NYMEX Reference quotewatch.com
Canada Spot Natural Gas Prices Rise On Tighter Supply
Canadian spot natural gas prices rose again on Wednesday as supplies tightened ahead of slightly cooler western weather forecast for Thursday.
Spot gas at the AECO storage hub in Alberta was quoted at C$1.37/1.385 per gigajoule, up about two cents from Tuesday and four cents on the week.
The transportation charge to the Empress border point in eastern Alberta jumped to an average of about 50 cents per GJ amid scarce interruptible capacity into the TransCanada PipeLines Ltd Canadian Mainline, a Calgary based trader said.
The Empress charge has been above the usual 10 cents for the past two months.
January AECO gas, meanwhile, was talked at C$1.41/1.42 per GJ, up one to two cents from Tuesday.
The trader said AECO was slightly stronger in response to forecasts for slightly cooler temperatures in Alberta on Thursday as well as a compressor outage in northern Alberta, which was expected to take 150 million cubic feet of gas off the NOVA Corp system until tomorrow.
"People are also still trying to inject into storage now and then," he said, adding he expected prices to fall back into the C$1.35 per GJ range when warmer temperatures returned by the weekend.
Spot gas for export at Sumas, Wash. fetched US$1.95 to US$2.05 per million British Thermal units, up about five cents from Tuesday and 15 cents from last week.
A marketer of British Columbia gas said a combination of interruptible transport constraints on Westcoast Energy Inc's "T South""mainline and a lack of supply was keeping prices strong.
"There's a little panic on behalf of the physical shorts," the marketer said.
But he pointed out that January Sumas, now at US$1.90/2.00 per mmBtu, had crept down into the spot price range and holders of term gas would likely start selling to those with short positions to cover.
In the east, Niagara was talked at US$1.48/1.52 per mmBtu, up about a dime from Tuesday, but down about two cents on the week.
September Gas Exports Raise Nearly $650 Million
Exports of Canadian gas to the United States in September put $644.7 million into the pockets of producers and brokers, up from $590.2 million in August.
A rise in spot volumes combined with higher prices raised revenues more than 28% from the $501.43 million collected in September a year earlier, National Energy Board statistics indicate.
Both revenues and volumes will likely set new records when data for October, the final month of the contract year, is compiled.
Spot deliveries in the month rose to 162.64 bcf from 147.62 bcf in 1996, while long-term volumes fell 12% to 74.71 bcf from 85.3.5 bcf a year earlier.
Both classes of exports managed to collect higher prices. Spot gas sold for an average for $2.25 per gigajoule, moving ahead from $1.66 a year ago. Long-term contract contracts carried an average of $3.10 per gigajoule, up from $2.58 in the previous September. The average price advanced 25% to come in at $2.51 per gigajoule this year versus $2.
Shipments of long-term gas raised revenues of $248.82 million and spot deals accounted for $395.88 million. The comparative totals from the preceding year were $235.91 and $265.52 million respectively.
The most recent data lifted revenues for the contract year, which be- gan in November, to $7.93 billion -- a 27% gain from the $6.24 billion recorded to the same point in the 1995/96 contract year. Long-term revenues were up almost seven per cent this year to $3.23 billion, but spot revenues skyrocketed more than 46% to $4.7 billion.
Given high spot prices in October, it's possible that total revenues for the contract year will come close to $9 billion. Total volumes will approach 2.9 tcf.
Revenues for the first 11 months of the contract year were lifted by better prices for both spot and long-term deals. Spot gas sold for an average of $2.54 per gigajoule in the 11 months compared to $1.94 in the 1995/96 contract year, while long-term deliveries moved at $3.19 versus $2.72 over the comparative periods. The average price was up 23% this year to $2.77 per gigajoule from $2.25 in 1995/96.
Overall volumes were also up, with a nine per cent decline in long- term deliveries offset by an 11.7% increase in short-term sales. Gas flowing under long-term arrangementsdropped to 943.12 bcf from 1.04 tcf in the 1995/96 contract year, but spot volumes rose to 1.72 tcf from 1.54 tcf in the corresponding interval. Total sales south of the 49th parallel were up to 2.66 tcf from 2.57 tcf a year ago.
The bright spot for sales in September was California, where demand was up almost 14.5% from the same month a year ago and reached 66.24 bcf. The state's average price jumped more than 44% to average $1.93 per gigajoule in the month.
The Midwest saw its imports of Canadian gas drop by more than eight per cent from September 1996, with the level falling to 74.39 bcf. However, the region's average price charged ahead 38% to hit $2.83 per gigajoule.
U.S. Oil Imports to Continue Rising; New Study Sees Level of 66 Percent of U.S. Demand in 2020
Source: Fuels for the Future
Oil imports are expected to increase to 66 percent of U.S. oil consumption by the year 2020, according to new estimates by the U.S. Department of Energy.
In a report entitled ''Annual Energy Outlook 1998,'' scheduled to be made public this week, the department's Energy Information Administration projects the average world price of crude oil to rise from $20.48 in 1996 to $22.32 a barrel in the year 2020.
The forecast of a 66 percent level of oil imports is a sharp increase over the average of 46 percent in 1996, the last year for which final import figures are available.
Earlier this year, imported oil amounted to more than 55 percent of U.S. demand during summer months.
The new forecast of rising oil imports continues a steady increase since the oil crisis of 1973, when oil imports were only 36 percent of U.S. consumption.
The Energy Department attributes the predicted increase in oil imports to higher domestic consumption and to declining domestic production. Crude oil production in the U.S. will continue to fall from 6.5 million barrels a day in 1996 to an estimated 4.9 million barrels a day in the year 2020, according to the study.
Oil imports in August reached 10,324,000 barrels a day, compared to 9,986,000 barrels a day in August, 1996. Persian Gulf imports were 17.2 percent of total imports in August, compared to 15.5 percent a year ago.
FEATURE STORIES
PETRO-CANADA (PCA/TSE) HUNGRY TO GROW
Oilpatch Giant Shopping For Global Opportunity
Sydney Sharpe, Calgary Herald
Rumors abound that Petro-Canada will stretch its global wings and buy an international company.
Like Gulf Canada Resources Ltd. -- whose refineries and gasoline stations Petro-Can bought years ago -- and Talisman Energy Inc., Petro-Canada is also looking for another post to tie its operations to.
"It's still a possibility, but there's nothing concrete," Petro-Canada spokesman Rob Andras said Tuesday.
And the company continues to assess its domestic businesses. It's been over a year since Petro-Canada noted it was reviewing the role of ICG Propane Inc. Wholly owned by Petro-Can, ICG commands about 30 per cent of the country's retail propane market.
Many observers thought ICG would take the income trust route that Superior Propane Inc. rode so successfully. In two separate offerings, Norcen Energy Resources Ltd. sold most of its wholly owned stake into an income trust.
Superior has been holding its value, and continues to be a good investment.
"We're still looking at a number of options," said Andy Wiswell, the president of ICG. "We could sell it to a strategic buyer or sell in the marketplace."
Andras insisted all possibilities are still being considered.
The shaky market isn't going to help Petro-Canada's decision over ICG or the evaluation of its refining and marketing operations in eastern Canada.
"The whole study focuses on our downstream assets," said Andras. "The results could be down the road or they could be tomorrow."
Petro-Canada has a lubricants facility in Oakville, Ont., and refineries in Edmonton, Mississauga and Montreal. There are also 1,800 service stations across the country.
"The study encompasses a possible reworking of current assets as well as looking at others," added Andras.
In that context, the name Ultramar keeps cropping up. Rumors continue to swirl that Petro-Canada will either do a joint venture or buy the Quebec refinery and service stations owned by Ultramar Diamond Shamrock Corp. of Texas. "Ultramar's Quebec assets stand out like a sore thumb," said one analyst. But Ultramar, one of the largest gasoline refiners and sellers in North America, is also headed by a Montrealer, who will become CEO of Ultramar Diamond Shamrock in late 1998. How keen could Jean Gaulin be to sell his Quebec base?
DRILLING HOPING FOR COOL DOWN
Jerry Ward -- Sun Media
El Nino may be putting smiles on the faces of Christmas shoppers, but Alberta's drilling industry could use some colder temperatures.
The lack of frozen ground could cause delays in the booming oilpatch as companies gear up for the winter drilling and maintenance season.
"We are getting some frost," John Inverarity, past-president of the Canadian Association of Oil Well Drilling Contractors, said yesterday.
"Although it hasn't been 30C below or anything, which would do a good number on ground conditions."
Drilling contractors aren't yet panicking, as most remote site drilling won't begin for another few weeks and all expectations are it will turn colder.
"I guess if it goes on the rest of the winter it well may (be a hindrance), but at this point and time, nobody really heads to the moose pastures until January anyway," said Inverarity.
He said to the end of October, 14,700 wells have been drilled in the province.
The group is estimating 16,000 wells will be drilled in 1997 -- a significant jump from the previous record set in 1996, of 12,836 wells.
AEC Pipelines Ltd. spokesman Dick Wilson said from Calgary a $5-million maintenance program on its system is to begin next month, weather permitting.
"There hasn't been any delays yet," Wilson said.
The warm, dry, windy conditions across much of the Prairies can be traced to the El Nino effect, said Environment Canada forecaster Howard Jacura.
A warming of the Pacific Ocean, El Nino tends to throw North American weather patterns into a tailspin.
TANKER TEST AT HIBERNIA
Hibernia Oil Transfer Test Scheduled 12/17/97
The first 280,000 barrels of oil from the Hibernia project will be placed on a tanker later this week in a test transfer, says Hibernia Management and Development Company (HMDC).
There now are two wells producing some 50,000 barrels of oil per day at Hibernia.
Oil began flowing from the second well Sunday and total production from the two wells is expected to reach an estimated 60,000 barrels a day, said Ken Compton, offshore team leader for production development.
The second well is producing at a rate of 10,000 barrels per day initially but that is expected to rise to 20,000 within a few weeks, Compton said. Oil is flowing from the first well at an average rate of 40,000 barrels per day.
"We are also making excellent progress on our third well which is now at a depth of 2,475 metres and spudded our fourth well Dec. 7," he said. "Those wells are expected to enter production in the first quarter of 1998."
Compton said the crude oil currently flowing is being stored in the gravity base structure (GBS) and a test transfer (called a lift) of 280,000 barrels to the tanker Kometik is scheduled for later this week.
"The Kometik will remain in the area to complete the first official tanker lift, expected before year end, when a further 570,000 barrels will be loaded."
The design capacity of the Hibernia platform is 150,000 barrels of oil per day and average plateau production of 135,000 barrels per day is expected to be achieved in 1999, Compton said.
SABLE ISLAND $3 BILION PROJECT A GO
TransMaritime Drops Rival Plan As Ottawa Backs Mobil-Led Venture
Claudia Cattaneo - Financial Post
The federal cabinet signed off yesterday on the $3-billion Sable Island natural gas and pipeline project off Canada's east coast, launching the development of one of the country's largest energy projects.
Project proponents said they now have all the government and regulatory approvals they need and are on schedule to start the gas flowing by November 1999.
The project has two components:
The $2-billion Sable offshore project to produce natural gas from a 3.5 trillion cubic foot pool discovered two decades ago. The venture is led by Mobil Corp., Shell CanadaLtd., Imperial Oil Ltd. and Nova Scotia Resources Ltd.
The $1-billion Maritimes & Northeast pipeline to move the gas, headed by Westcoast Energy Inc., with partners Charlotte, N.C.-based Duke Energy Co. and Mobil Oil Canada.
In a related development, proponents of a rival pipeline, the TransMaritime Pipeline Project, called off their plans after the Federal Court of Canada refused to hear their appeal.
An appeal filed by Tatham Offshore Inc., yet another proponent of a pipeline to transport Sable Island gas, was also rejected by the court.
Both rivals filed their plans late and did not take part in hearings leading to a National Energy Board decision backing Maritimes & Northeast.
The court decided the NEB decision would stand.
No further legal action is planned from the TransMaritime group, although it said the $1-billion project will be revived if there are more natural gas discoveries off the east coast.
TransMaritime was backed by a consortium that included Trans-Canada PipeLines Ltd., IPL Energy Ltd. subsidiary Consumers' Gas Energy and Gaz M‚tropolitain & Co. LP. It was favored by Quebec Premier Lucien Bouchard because it routed Sable Island gas through the Maritimes and Quebec before taking it to the U.S.
"Given the way the situation has unfolded, it just seems prudent to put the project on hold until there are additional reserves," said Tony McCallum, director of public affairs at TransCanada.
"There is probably a great wave of elation flowing through our ranks right across Canada," said Graeme Connell, a spokesman for Sable Offshore, a consortium led by Mobil Oil Canada of Calgary. "It's what our people have been working very hard for for a long time."
The project must still be approved by the Canada-Nova Scotia Offshore Petroleum Board, which considers socio-economic and environmental issues.
The board's ruling could have a bearing on royalties to be paid to Nova Scotia, as well as the provincial government's requirement for local processing of natural gas byproducts. Connell said the Sable project will create 3,000 to 4,000 jobs during the construction phase, which is expected to last two years. "We have a very tight construction schedule to produce the gas and get it to the main markets in November 1999."
Building the pipeline, which would deliver 530 million cubic feet of natural gas a day to consumers in Nova Scotia, New Brunswick, and the U.S., is expected to start next fall.
It is estimated the gas project will pump 85 billion cubic metres of gas from fields near Sable Island. Gas pools around Sable are thought to contain 142 billion cubic metres of gas.
The project is expected to provide 5,000 direct and indirect jobs. More than $500 million should be invested in Canada.
"This is a very important and major step for the Maritimes. It will be very valuable for their economy," said Westcoast president Arthur Willms.
For Vancouver-based Westcoast, it means pipeline development in a new area. Westcoast will build the Canadian portion of the pipeline, while Duke will manage the U.S. section.
"It ranks way up there with one of the largest projects we have."
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