MARKET ACTIVITY/TRADING NOTES FOR DAY ENDING FRIDAY, DECEMBER 5, 1997 (4)
Some Heavy Oil Projects Not Likely To Proceed -- Analyst
The excitement over the flurry of announcements about heavy oil plants and expansions may be premature, a heavy oil conference in Calgary heard Wednesday.
"Not all the announced projects or intended projects ... can fly nor can all the players survive over the next two or three years," George Eynon, vice-president of Ziff Energy
Group, told the Canadian Heavy Oil Association conference. "There's just not enough pipeline and upgrading and refining capacity to take all those projects."
Gulf Canada Resources Limited is the most recent entry into the heavy oil sweepstakes with its plans for a $1.2-billion bitumen proposal arising out of a commercial extension at its Surmont oil sands pilot project. The company said peak production of 100,000 bbls per day could be achieved by 2006 given favourable market conditions.
The recent oil price drop and widening of differentials between light and heavy slates -- currently about $8 per bbl -- will likely produce some weeding out of players, Eynon predicted. Some of the culling will be through mergers and acquisitions over the next two or three years.
The coming changes, however, do not alter the fundamentally sound basis of the Canadian heavy oil industry in its ability to use new technology and provide a good cost structure, he emphasized.
The overall demand for oil in the United States is growing and Canadian petroleum exports of 1.5 million bbls per day in 1997 account for about 15% of the market share, Eynon said.
Heavy oil exports make up a significant portion of imports into both the Rocky Mountain region and the Midwest. Heavy oil will continue to be needed for U.S feedstock, in part to meet the demands for replacing aging infrastructure (asphalt for roads and bridges), he suggested.
However, Canadian heavy oil producers have to become more knowledge- able about pipeline transportation and refining if they are to compete effectively with Venezuela. This could mean developing some type of integrated business relationships with the downstream and midstream, he said.
An integrated approach to heavy oil development may be preferable in the future to the stand-alone model, said Martin Meyers, associate director of refined products at Cambridge Energy Research Associates of Boston.
In the stand-alone approach where the product is sold into the market for upgrading and again for refining, the owner of the asset is accepting commodity price risk at each step, he said.
But a producer with an equity position in upgrading and refining be- comes indifferent to the risk of changing differentials or values of the commodities in each of the markets, Meyers said. "If the producer has the wherewithal in terms of capital and can do it in a cost effective way, that's a lower risk way of doing things," he said.
As large surface mining bitumen projects such as Syncrude Canada Ltd. and Suncor Energy Inc. move forward, there's a clear reason to take an integrated approach and share the risk across the chain, Meyers suggested.
Vertical integration also offers significant opportunity for capital efficiencies. Shell Canada Limited's refinery at Scotford, near Edmonton, is currently running a very highly upgraded synthetic crude and the company plans to use much of the latent capacity to do more upgrading, Meyers said.
He noted in recent years the spot value of upgraded synthetic crude has increased in value relative to light sweet conventional crude. Cambridge expects this premium will persist through 2001-2002, but the scheduled startup in 2002 of expanded synthetic crude operations is likely to lead to discounting of upgraded synthetic crude in relation to conventional crude, Meyers said.
In another conference session, heavy oil producers were warned by Gary Webster, director of environment and health for the Canadian Association of Petroleum Producers, that climate change is potentially the most serious problem to face the oil and gas industry.
Climate change is potentially doubly damaging to the heavy oil com- ponent because it's more energy intensive. This is especially the case forthermal projects, he said. Operators need to measure and record what they are doing to reduce emissions so they can get some credit for their efforts.
Averaged company data indicates heavy oil has a carbon production in- tensity of 2.15 tonnes (the amount of fossil fuel based energy plus fugitive emissions generated in one cubic metre of production). That compares to 1.8 tonnes for natural gas and 0.25 for conventional oil, he said.
In addressing reduced emissions, Canada has relied mainly on the use of voluntary measures. About 90% of CAPP's member production has signed up, but only about 40% of production members are actively doing anything to reduce emission, he said.
There already has been some improvement. Between 1994 and 1996 com- panies reduced C02 emissions by 8.6 megatonnes -- about 1.5% of Canada's 1990 emissions inventory.
However, C02 emissions in Canada increased eight to nine per cent between 1990 and 1995 with about 30% of the total from Alberta, Webster said.
Friday December 5
British-Borneo , 3 More Win Atlantic Blocks
British oil exploration group British-Borneo Petroleum Syndicate Plc said on Friday it was a member of a licence group that had been awarded two blocks in the Atlantic Frontier.
British-Borneo holds 17.5 percent in the licence in which the other members were Conoco UK Ltd (NYSE:DD 32.5 percent), Ranger Oil UK Ltd (RGO.TO 17.5 percent) and ARCO British Ltd & Partners (NYSE:ARC).
The blocks, 204/14 and 204/15, are next to British Petroleum's Suilven oil discovery.
Friday December 5
Strong North Sea Oil Growth Must Wait Till 1999
The start-up of new North Sea oilfields will gather pace next year, sowing the seed for a healthy rise in crude output towards the end of the century, a Reuters industry survey suggests.
But near-term supply growth will be limited by technical delays, output shrinkages at older fields and the slow increase to peak production rates at new developments.
The survey showed that some 30 new oilfields coming onstream in 1998 off the coasts of Britain, Norway and Denmark should add an extra 1.3 million barrels per day (bpd) to output when they are producing at peak rate levels.
Typically fields take between six to 18 months to reach full production.
The 20 new fields that came onstream in 1997 should add 887,000 bpd to output when they are flowing at peak rate.
Total north European oil output has in fact risen little this year, averaging 5.95 million bpd against last year's 5.94 million bpd, said analysts Wood Mackenzie.
And with many of 1998's start-ups due onstream later in the year, actual additional oil flows by next December should amount to just 475,000 bpd, say Aberdeen-based consultants Petrodata.
Delays could trim that rise to a meagre 300,000 bpd, they added. Problems plaguing floating production vessels (FPSOs) and the shortage of drilling rigs have already put some projects months behind schedule.
Exxon's (NYSE:XON) 75,000 bpd Balder field in the Norwegian sector of the North Sea was due onstream in April 1996 but was now unlikely to produce oil before 1999.
The 25,000 bpd Tordis East development, due in August 1997, was pushed back to the spring and FPSOs bound for Norway's large Asgard and Varg fields have been delayed in their Asian construction yards.
Three large projects in Norwegian waters make up the bulk of the Scandinavian nation's projected 545,000 bpd of start-ups in 1998.
Statoil's (STAT.CN) $4.2 billion 170,000 bpd Asgard oil and gas project in the Halten Bank off mid-Norway is due onstream in October while its 125,000 bpd subsea development of the Gullfaks satellites should produce oil in the same month.
Norsk Hydro's (NHY.OL) 100,000 bpd Visund project, which will also flow via the Gullfaks crude stream, has suffered a 30 percent overrun on platform costs, taking the development budget to around $1.3 billion. It should be onstream in July.
Hydro is installing a separate platform to bring the Oseberg East satellite on stream, with first oil delivery via field centre facilities scheduled for October.
Saga Petroleum's (SAPOa.OL) 55,000 bpd Varg field, due onstream in May, was not seen producing before July, with industry experts predicting it slipping further behind schedule.
The biggest single project in British waters is the joint British Petroleum and Shell (RD.AS) Eastern Trough Area Project in the central North Sea, which will link seven individual reservoirs to produce 185,000 bpd at peak through a central processing platform.
BP will operate the fields, which by end-1998 should significantly increase the crude volumes loading at the Cruden Bay terminal at the end of the Forties pipeline.
BP also has the dominant interest in the second biggest British development, the $1.45 billion Schiehallion development 150 miles (225km) west of the Shetland Islands.
Schiehallion, peak-rated at 142,000 bpd, is due on stream mid-year and has not yet suffered the problems of Foinaven, the first Atlantic margin field, which technical problems delayed for 17 months until this December.
A diverse range of other developments take Britain's projected 1998 start-ups to some 650,000 bpd at peak rates.
Conoco (NYSE:DD) and Chevron (NYSE:CHV) have spent $1.55 billion
installing the largest platform seen in the North Sea over their jointly operated Britannia field in the central North Sea.
The 20,000 tonne platform will mainly handle gas, around 21 million cubic feet a day, eight percent of total British needs, but also some 55,000 bpd of condensate which will be exported via the Forties pipeline system.
Other 1998 start-ups show that with new British fields getting smaller, innovative and cheaper techniques are key to their development.
Conoco has contracted a Norwegian company to bring on its 60,000 bpd Banff field using a ramform (square stern) FPSO while Ranger Oil (Toronto:RGO.TO) will drill from Oryx Energy Co's (NYSE:ORX) Ninian platform to bring on its 14,000 bpd Columba field.
HOT STOCK
Friday December 5
Red Sea Oil Corp. (RSO/ASE), up 61› to $2.71, on volume of 794,749 shares. On Wednesday, the company said it had encountered oil shows at the B1-NC177 well in the Sirte basin in Libya, driving the stock up $1.05. Thursday the market took back 30›. Red Sea Oil is the property operator, with a 60% interest. Sands Petroleum AB holds 40%.
TOP 20, SPEC 12 & SERV 7 STORIES
Friday, December 5, 1997
Stock Slide Cools Canadian 88 Energy's Sale Talk
Impatience over delays in Canadian 88 Energy Corp's plans to pump sour natural gas from its southwestern Alberta deep wells has led to a drop in its stock price and a dampening of sale speculation, analysts and investors said on Friday.
Canadian 88's price slide and its recently stated intentions to develop all its big gas projects showed that a sale of the company was no longer an option being considered, or at least a friendly one, observers said.
"It's not for sale," said Ken Faircloth, analyst with Goepel Shields & Partners.
Canadian 88 shares remained under pressure on Friday after Alberta's energy regulator this week rejected its application for a new pipeline to ship sour gas to Shell Canada Ltd's Waterton plant.
The stock closed down 0.05 to 4.45 on Friday with 4.3 million shares changing hands, making it the Toronto Stock Exchange's most active issue. Its 52-week high was 7.05.
Trading was dominated by a 3.5 million share block crossed by Gordon Capital Corp.
"In the last couple of quarters, a lot of investors had expected a lot of this gas to come on stream," said David Taylor, portfolio manager for mutual fund company Altamira Management Ltd, the firm's biggest institutional holder.
"In fact, the company had expected a lot of this gas to come on stream in 1997 and it's now delayed until 1998. I suspect a lot of investors are getting a little bit impatient."
Citing public safety concerns, Alberta's Energy and Utilities Board on Wednesday rejected Canadian 88's first plan to build a pipeline from its Waterton foothills acreage, where it estimates gas reserves of 300-500 billion cubic feet, to connect with Shell's Carbondale pipeline.
Canadian 88 immediately announced it would re-route the line and build a new 100 million cubic feet a day pipeline to the plant, saying it would be a preferred option anyway.
"Our view is that it actually speeds the project up -- it doesn't slow it down at all," Canadian 88 Chief Executive Greg Noval said. Noval said he expected Waterton gas would flow to the plant in 1998, pending quick approval.
The regulatory cloud had another silver lining for Canadian 88 in the form of EUB recognition that large reserves were likely harbored deep beneath the region's foothills, said Ihor Wasylkiw, analyst with Research Capital Corp.
Wasylkiw also said investors could be overreacting to the threat of production delays. "All we're talking about here is two to three quarters, and from my perspective, I don't view that as long-term at all. By summer of '98, 88 should have resolved all if not most of their processing issues."
Altamira, which in June held almost nine percent of Canadian 88's stock in various funds, remained behind Noval and the company despite the price drop, Taylor said.
He declined to comment on whether Altamira was the seller of the 3.5 million shares on Friday.
Reports surfaced earlier this year that Canadian 88 was on the auction block. Noval rejected the talk at the time but said at the June annual meeting he had been approached by potential suitors and would consider a C$7 a share bid.
The company was now expected to end this year producing more than 11,000 barrels of oil equivalent a day and in 1998 producing well over 20,000, Noval said. "We're sitting pretty. We've got good cash flow, good bank lines and we're excited about drilling wells," he said.
Friday, December 5, 1997
Petro-Canada Among Familiar Names Win Canada Offshore Oil Acreage Bid
A consortium of major oil companies, all experienced operators off Canada's east coast, won exploration rights on Friday to four parcels of acreage on the Grand Banks of Newfoundland after agreeing to spend C$98.7 million over five years.
The group, consisting of Chevron Corp unit Chevron Canada Resources, Mobil Corp unit Mobil Oil Canada, Petro-Canada and Norsk Hydro , was awarded licences totalling 134,194 hectares (331,400 acres) by the Canada-Newfoundland Offshore Petroleum Board.
Each company has a 25 percent interest in the consortium.
Three of the licenses are located between the Hibernia, Terra Nova and Hebron/Ben Nevis fields, 300 km southeast of St. John's, Newfoundland. The fourth parcel is about 35 km northeast of Hibernia, the C$5.8 billion project which started pumping oil in November.
The winning bids represented exploration expenditures the companies expected to make during the first five years of the nine-year exploration licences.
The group said it expected to begin seismic surveys next year and likely start drilling in 2000-01.
More
The busy pace of oil and gas exploration and development off Canada's East Coast is about to get even more frenzied.
Four Calgary firms announced they will launch a major exploration program over a huge area of the Jeanne d'Arc Basin, 300 km southeast of St. John's, Newfoundland.
Chevron Canada Resources Ltd., Mobil Oil Canada Ltd., Norsk Hydro Grand Banks Inc. and Petro-Canada made the announcement yesterday after buying exploration licences totalling 134,194 hec-tares.
"We're very pleased with the outcome. It's part of our strategy to be a permanent presence on the East Coast," said Petro-Canada spokesman John Percic.
Three of the licences are located between the existing Hibernia, Terra Nova and Hebron/ Ben Nevis oil fields, and the fourth is about 35 km northeast of Hibernia.
Under an agreement signed by the firms, they will spend almost $100 million over five years to jointly explore and de-velop the properties.
The licences are for a nine-year period.
The highest bid -- $49.5 million -- was for a 17,000-hectare parcel adjacent to the 400-million barrel Terra Nova field.
A larger parcel on the south end of the Hibernia field fetched a bid of $32.4 million.
All four of the companies are already involved in the area, with major stakes in the $6-billion Hibernia development that pumped first oil last month.
Mobil, Norsk Hydro and Petro-Canada are involved in Terra Nova and Mobil has a major stake in the massive Sable Island natural gas play.
The exploration program will begin in 1998 with a 3-D seismic program and progress to exploratory drilling in 2000 and 2001.
"It is very big for Mobil.
"These lands are very close to Hibernia and Terra Nova," said Mobil spokesman Bill Simpkins.
"The area out there is actually one of the seven favorite areas for Mobil worldwide."
Simpkins said it's too early to say how production might be dealt with, if the consortium is successful.
But he noted like Hibernia, Terra Nova and Sable, "it is a seed project as well."
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