MARKET ACTIVITY / TRADING NOTES FOR DAY ENDING TUESDAY, MAY 26 1998 (1)
OIL & GAS TOP STORIES
Gas Price Fall 'Temporary'
The Financial Post
High storage levels in the U.S. and Eastern Canada have pushed down spot prices for natural gas, but the condition is temporary, industry analysts said yesterday.
The Alberta spot price for natural gas has dipped to about $1.80 per thousand cubic feet in recent days, down from $2.50 four weeks ago.
The weakness goes against oil and gas industry expectations natural gas prices will strengthen because of the addition of new pipeline capacity from Nov. 1.
Most Canadian producers that have the ability are switching capital spending to natural gas away from oil to weather the weakness in oil prices, which is partly caused by high inventory levels.
"We believe this is temporary and from July both U.S. and Canadian gas prices should be rising," said oil and gas analyst Peter Linder of CIBC Wood Gundy Inc. in Calgary.
Prices should strengthen in the U.S. with the retreat of the warm weather trend and the coming of the hurricane season, he said.
In Alberta, prices are headed higher because there won't be enough gas initially to fill the new pipeline space, Linder said.
Despite weakness with spot prices, forward prices in Alberta continue to be strong, remaining in the $2.70 to $2.90 range for winter delivery, he said.
"I think it's a short-term blip," said Patricia Mohr, vice-president, economics, commodity markets, with Scotia Capital Markets.
Alberta prices should increase by the fall to link up with higher U.S. prices, while allowing for a differential of about 60› to cover transportation costs, she said.
PanCanadian Cuts Spending For Third Time This Year
The Financial Post
PanCanadian Petroleum Ltd. is slashing capital spending for the third time this year to manage the impact of sliding oil prices.
The senior oil and gas producer, 87% owned by Canadian Pacific Ltd., said it is also accelerating its "farmout" program to other companies to get better value from its large assets in Western Canada.
PanCanadian said yesterday it is reducing 1998 capital spending by $90 million, to $870 million. This follows earlier cuts of $25 million and $15 million after a $1-billion budget was announced last fall.
No layoffs are planned, spokesman Alan Boras said. The company cut 250 jobs earlier this year.
"We have made a commitment to live within our cash flow for the year, and as prices remain weaker than many forecasts, we are adjusting to meet the current price environment and we will continue to do that as warranted," Boras said.
The company still plans to drill 1,075 wells, mostly in Western Canada, with a focus on natural gas to prepare for pipeline capacity expansion scheduled to be completed this fall.
West Texas intermediate closed yesterday at US$14.50 a barrel, about US$6 lower from a year ago. The latest weakness has been caused by reports of high U.S. inventories.
PanCanadian said it is accelerating farmout agreements with other producers to get more value out of the 5.8 million hectares -- mostly undeveloped -- it owns in Western Canada.
Farmouts will also be made on fee lands, on which the company retains mineral rights, a legacy from the railway.
A recent farmout involved Cabre Exploration Ltd., which negotiated an agreement to explore 160 sections of land near its core production area of Joarcam in central Alberta. On Monday, Avalanche Energy Ltd. finalized a gas development agreement in the Entice area near Calgary on 138 sections.
"We are open for business and we are looking to do deals where it makes strategic sense for PanCanadian," Boras said.
Gentry Resources Buys Gulf Canada Assets For $10.6 Million
Calgary Herald
Gentry Resources Ltd. has bought producing oil properties in Saskatchewan and Argentina from Gulf Canada Resources in a $10.6 million deal that also makes Gulf a shareholder of the Calgary junior energy company.
Gentry said Monday's deal, slated to close at the end of July, will nearly triple its daily output to 1,685 barrels of oil equivalent.
In addition, Gentry will acquire exploration and production sharing agreements in Romania and in three exploration licences in Albania. The Calgary company will also acquire Gulf's interest in two offshore exploration blocks in Cote d'Ivoire, West Africa.
As part of the deal, Gulf will get $2.6 million in cash and more than 7.5 million Gentry common shares, worth $8 million.
"The acquisition of this diversified package of revenue generating producing properties and international exploration licences offers Gentry exploration targets with much larger reserve potential than currently available in the mature Western Canadian basin," Gentry president Hugh Ross said in a release.
"The acquisition will greatly accelerate Gentry's growth and provide significant upside potential."
Gulf said the sale is part of its plan to reduce debt and focus on the company's core energy properties around the world.
"We have strong confidence in the people at Gentry," said Gulf president Dick Auchinleck. "We are pleased to have an ownership position in the company and to retain interest in the upside potential of these assets."
Big Bear Exploration's Appetite For Acquisitions Funded By N.Y. Company
The Financial Post
The last time Jeffery Tonken started an oil company, he and a group of friends kicked in $200,000 and sold it 10 years later for $1 billion.
"This time, we are going to start it with $200 million and see what we can do," said Tonken, chairman and chief executive of Big Bear Exploration Ltd., a newly listed company on the Toronto Stock Exchange with a hunger for acquisitions as voracious as its name implies.
Tonken is former president and CEO of Stampeder Exploration Ltd. The oil and gas producer was taken out by Gulf Canada Resources Ltd. last summer as part of a fast-paced acquisition campaign waged by then chief executive J. P. Bryan.
Soon after the sale, Tonken and his management team regrouped to lead Colony Energy Ltd., a junior oil and gas firm that was trading on the Alberta Stock Exchange. Colony changed its name to Big Bear Feb. 28 when it listed in Toronto to avoid confusion with a similarly named company.
But with oil prices sitting at about US$15 a barrel, production of 3,000 barrels a day and mounting debt, its future seemed uninspiring. So Big Bear went looking for cash and struck it rich with New York based Belco Oil & Gas Corp. The independent oil and gas producer with a market capitalization of about $900 million was also eager to grow by acquisition.
Under their deal, Belco, owned by the Belfer family, is paying US$10.5 million for preferred shares of Big Bear, convertible to common shares. It will also buy up to US$120 million in warrants convertible to shares and options to buy another US$10.5 million in preferred shares. If it exercises all conversions, warrants and options, it would own 80% of Big Bear.
Big Bear will use the money to chase mutually acceptable oil and gas acquisitions. A special shareholders' meeting will be held June 9 to vote on the transaction.
"What attracted Bob Belfer to us is that we had a proven track record to create value," said Tonken.
Belfer bought into Tonken's strategy of building a new Canadian energy producer of a significant size by cherry picking high-quality assets during a time of low commodity prices.
"I don't take any pleasure in seeking people under pressure," said Tonken. But he is finding himself in the unique position of rooting for low oil prices, at least in the short term. "There is no question our strategy is to buy good assets at reasonable prices, and that the current market situation is setting us up for that."
Increasingly, companies are being squeezed by continuing low oil prices, a situation compounded by nervous bankers calling in loans and the difficulty in getting new equity, he said.
Big Bear has talked to and been approached by several firms, ranging from junior producers to mid-sized outfits with large debt.
"There are a number of ways we can employ our money," Tonken said. "We can do a straight takeover bid. Or we have talked to a number of companies where we would like them to buy our company, Big Bear, and the resulting transaction would put us in a position where we would be the new management team."
Initially, the goal is to pay off bank debt. A second step would involve using credit facilities to build. Big Bear's shortlist is made up only of oil producers - natural gas assets, because of the buoyant outlook for this market, are too expensive. Heavy oil is also off the list. It is best suited to senior producers such as Gulf because it requires large amounts of capital.
Baytex Energy Sues Petro-Canada Over Property Auction
The Financial Post
Baytex Energy Ltd. is suing two energy producers, including Petro-Canada, and a leading Calgary investment dealer after losing out in a property auction.
PetroCan hired FirstEnergy Capital Corp. to sell what it calls its Gold Creek properties, near Grande Prairie, Alta. The assets include daily production of 15 million cubic feet of gas and 1,450 barrels of gas liquids, plus about 11,600 hectares of land.
Bids were due April 20. Baytex offered PetroCan an undisclosed cash payment or a combination of cash, debentures and properties. The Calgary-based junior's offer was conditional upon the seller throwing in two more properties and seismic data, a condition that was later waived.
The value of the bid was not reduced by putting aside the provision, Baytex says in its statement of claim filed with Alberta's Court of Queen's Bench.
PetroCan and FirstEnergy were accused of breaching the tender process by getting Rio Alto Exploration Ltd. to make a second bid in early May, which Baytex alleged was still below its price.
The court was asked for an interim injunction to prevent Rio Alto from taking over the Gold Creek assets. Baytex also asked to buy the properties at its bid price.
Warren Holmes, managing director at FirstEnergy, said he was surprised by the lawsuit. He said the firm, which has conducted billions of dollars of asset sales and purchases since its formation almost five years ago, tries to ensure all bidders are treated fairly.
Given the confidential nature of the auction process, Holmes wondered how Baytex could determine that its bid was worth more than Rio Alto's.
FirstEnergy intends to defend itself rigorously, he said. "We take it seriously. Our business is clearly a function of reputation, expertise and client confidence."
Holmes said FirstEnergy considers Baytex a valued client. The dealer was adviser to Dorset Energy Ltd. when it was sold to Baytex last fall.
An official with Baytex said the company had no comment about its legal action. A PetroCan spokesman said he couldn't comment until the firm's lawyers finished studying the document. Rio Alto did not return phone calls.
Canada To Be Top U.S. Oil Supplier
The Financial Post
Canada is pushing out Venezuela as the No. 1 supplier of oil to the U.S., according to the Canadian Association of Petroleum Producers.
Venezuela, with its huge production of heavy oil, has historically outranked all other countries as the top exporter of oil to the U.S., followed by Canada, Saudi Arabia and Mexico.
But pipeline expansion, rising production of heavy oil and more refinery capacity in the U.S. to upgrade it should put Canada ahead in the U.S. on a permanent basis within six months, said David Manning, president of CAPP.
"They like our stuff, they are set up for it and there are pipelines in place," he said.
Canada led in January and February, when average daily oil exports to the U.S. were 1.7 million barrels a day, a jump of about 200,000 b/d from 1997.
A year ago, oil exports averaged 1.47 million b/d, according to statistics compiled by the Washington-based U.S. Energy Information Administration.
During the same two-month period, U.S. imports from Venezuela declined to 1.65 million b/d, from an average of 1.73 million b/d in 1997.
Saudi Arabia exported 1.46 million b/d on average to the U.S. during the same period, up from last year's average of 1.39 million b/d; Mexico came in at 1.35 million b/d in the first two months, about the same as the average for 1997, 1.36 million b/d.
Canada's export jump in the first two months was likely due to a combination of more heavy oil production, along with more pipeline space, Manning said. "We have progressively, over the past three years, added pipeline capacity through expansion."
In March, Canada's exports to the U.S. slipped back to 1.45 million b/d, while Venezuela bounced to 1.66 million b/d, Saudi Arabia exported 1.5 million b/d and Mexico 1.23 million b/d.
But Canada is likely to move back on top with the Terrace pipeline expansion, which will add 95,000 b/d of export capacity starting in January 1999, and another 81,000 b/d by September 1999.
The U.S. government has long supported a policy of diversifying oil imports from the Persian Gulf, said Carmen Di Figlio, a senior director with the U.S. Department of Energy.
"Obviously, we have good relationships with both countries, and the significance of Canada or Venezuela being slightly ahead of one or the other in no way diminishes the importance of both sources of supplies to the U.S."
Venezuelans have been fierce competitors, purchasing U.S. refineries to ensure they have the capacity to process heavy oil.
The U.S. government estimates 4.6% of U.S. refinery capacity, or 700,000 b/d, out of total U.S. production of 15.2 million b/d, is now owned by Venezuelans.
Over the longer term, Canada's No. 1 spot will be sustained by rising U.S. demand for light sweet oil produced at the expanding Alberta oilsands plants and East Coast offshore fields like Hibernia and Terra Nova.
The reversal of Line 9, a pipeline between Sarnia, Ont., and Montreal that used to move western oil to the East -- will also result in more exports to the U.S. by the end of the year.
Controlling Offshore Oil
For the world's major oil companies, the East Coast offshore must be an ocean paradise compared to the Norwegian North Sea and the Norwegian Shelf.
For the last 20 years, the Norwegian Petroleum Directorate (NPD) has controlled that country's offshore oil resources with an iron fist, nailing international companies by limiting their ownership to an average of 15 per cent, and clawing back revenues with an extra 50 per cent corporate tax for oil companies.
The NPD even pounds out orders indicating who should partner with whom, and has tried to dictate what sort of platform should be built.
Free trade advocates would not be amused.
From 1976 to 1996, Norway's three major oil companies - state-owned StatOil, Norsk Hydro (owned 51 per cent by the state) and the private Norwegian firm Saga - were awarded the majority of all licences, the head of information for the NPD said in an interview last week.
"The politics so far has been that in general they have been awarded 85 per cent of all the licences and the foreigners had to fight about the rest of it," Jan Hagland said in Stavanger. "But this is not the case any more, it's 60-40 now."
The new Norwegian frontier, in deeper waters of the Barents Sea, is complex and challenging, and Norway now needs input from as many engineers as possible, Hagland explained.
It was only in the last licencing round, the 15th, that a requirement that StatOil be partner with at least a 50 per cent ownership was dropped.
Still, the NPD exerts a degree of control the Canada-Newfoundland Offshore Petroleum Board (CNOPB) wouldn't even dream of.
In Norway, for example, before an offshore parcel is open to bids, the NPD conducts offshore seismic work, interprets the data and sells it to the oil companies.
"That has been a vast source of revenue for government for man, many years," Hagland said.
"They buy it and then they go in and do more detailed seismic work."
The NPD then accepts detailed project proposals from various players, assesses the bids and awards the projects based on which one it believes will cost the least (development costs are about 85 per cent tax deductible so high costs spell bad news for the tax collection arm of the directorate) and generate the most taxable profit.
So autocratic is the NPD that it once tried to order an oil company to build a concrete platform instead of steel, because it would mean about $200 million more in tax revenues. But the Ministry of Petroleum overruled, Hagland said, and stated the oil companies had the right to assess their risk and determine how best to tackle it.
Non-Norwegian oil companies have long complained about procedures, Hagland said.
"They have always threatened to leave Norway," Hagland said. "But they haven't done it so far, I think it's part of their job to complain. They say we are too heavily taxed and we don't make any money in Norway but still they are with us, still they are applying for new blocks."
In Newfoundland, the CNOPB has a simple, total free enterprise approach.
Oil companies perform seismic work and suggest to the board which parcels they might be interested in through a call for nominations process.
The CNOPB then issues a call for bids and awards the offshore parcel to whichever group promises to spend the most money on exploration. The winning group can then keep the parcel for about nine years - as long as it drills a well - and can hold an oil field virtually for ever once it is granted a major discovery licence.
Of course, petroleum resources on opposite sides of the North Atlantic are hardly comparable. Norway's production is expected to peak at nearly 4 million barrels per day in the next couple of years, while the Jeanne d'Arc basin will reach about 550,000 barrels per day when the four major projects - Hibernia, Terra Nova, Hebron and Whiterose - are producing.
Norway has 29 fields in production or approved for development and an additional 15 in the late planning stages. And Norway's industry started in the middle 1970s, at a time when analysts were predicting an $80 barrel of oil and global shortages within a decade.
The NPD started with 40 employees in 1973 and now has 370.
The CNOPB has 29 employees. For 3 1/2 years, it has not had an official director because provincial and federal governments could not agree on a candidate.
Yet in many ways, the system had worked well for Newfoundland.
The Hibernia platform - though it had $1 billion in subsidies and $1.6 billion in loan guarantees - provided employment for thousands of Newfoundlanders at Bull Arm.
The company's latest figures indicate 85 per cent of Hibernia workers are Newfoundlanders and the target is 90 per cent.
Ask any worker about the concrete platform - which is now considered too costly an option by the industry - and he or she will tell you there is no structure they would rather be on when a storm breaks across the Grand Banks.
But ask anyone in the industry - on either side of the Atlantic - about the local benefits from the $2-billion Terra Nova project, led by Petro-Canada, and they will quietly tell you the CNOPB has fumbled the ball.
Many of the local employees have been parachuted in from away and the core engineering team is still based in England - despite the CNOPB's requirement that "as soon as practicable after project sanction, the proponent relocate engineering and procurement activities for the project to Newfoundland."
The CNOPB is still negotiating with Petro-Canada on how it will meet this requirement but it is likely all fabrication engineering work will be completed by the time the team moves to St. John's.
The CNOPB's new director, Hal Stanley, would not comment on the Terra Nova situation Friday, saying he needs time to be brought up to speed on the project.
"It's very, very much too early to get into that kind of discussion, I'm in the process of being fully briefed," said Stanley, who previously served as chairman of the provincial committee looking after Terra Nova and deputy minister of Natural resources.
Terra Nova is about 2 1/2 years away from First Oil and has about 125 employees working in the province. Two years before Hibernia produced its first barrel it employed about 5,000 here.
But even Norway didn't start out with total control. The first discovery, at Ekofisk, was made by the U.S.-based Phillips Petroleum Co., with a 37 per cent ownership; and the first licence was granted to Esso, which owned 100 per cent of the Balder oil and gas field.
Hibernia Platform To Pump More Oil
Canadian Press
Production at the Hibernia offshore oil platform is set to resume its upward climb when the first water-injection well begins pushing more crude through the reservoir.
Workers began perforating the 5,600-metre well over the weekend, a job that is expected to take up to a week to complete, said David Slater, who heads the reservoir team for Hibernia Management and Development Co. Ltd.
Once the filtered sea water begins moving through the reservoir, two production wells will be able to gradually increase their daily flow to about 60,000 barrels of oil a day.
Additional water-injector wells will be drilled in the coming months to further increase production, said Slater.
"For the rest of the year, the timing of the water injectors will determine how you will see us continue to build toward the 100,000 barrel-a-day mark," said Slater.
By early next year, the platform is expected to produce an average of 135,000 barrels per day. The platform was initially designed to pump 150,000 barrels per day, but could eventually exceed that level with some restructuring.
As oil is taken from the reservoirs in the sandstone beneath the ocean floor, the pressure drops, deflating the reservoir like a balloon and slowing the flow.
The water revitalizes the reservoir, sweeping the oil toward the producing wells.
In recent months, total production has been reduced to as little as 15,000 barrels a day while the water-injection well was being put in place.
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