By Richard Macedo
Nickle's Analytics
Nickle's Daily Oil Bulletin
16 November 2007
Liquefied natural gas will become a more important player in the continent's commodity mix over the next decade helping to maintain a relatively balanced supply and demand situation and steady North American prices, the National Energy Board predicts in its long term energy outlook released Thursday.
NEB Media Release: NEB report says future energy supply ample and will challenge Canadians to make smart energy choicesNEB Report: Canada's Energy Future - Reference Case and Scenarios to 2030
An Energy Market Assessment November 2007
The board also says a long term energy vision and strategy is needed in Canada to balance the multiple objectives on the table. "This plan must be well-integrated at the regional level, consider environmental issues and economic growth, and be developed with input from Canadians," the NEB says. "Only then will be able to overcome challenges ahead and take advantage of the opportunities available."
Despite relatively flat natural gas prices in its reference case scenario, the NEB expects gas drilling in Canada to recover to roughly 18,000 wells per year by 2009. (There was no attempt to incorporate the impact of Alberta's recent decision to increase royalties starting in 2009).
The board report outlines a reference case scenario, one of four hypothetical models used for its Energy Future through the year 2030 analysis. The reference case is the NEB's view of the most likely development of energy demand and supply over 10 years (2005-2015).
"That (scenario) definitely sees more LNG coming in," Paul Mortensen, the NEB's technical leader of natural gas, said in an interview. "There's pretty significant expansion in U.S. capacity coming in next year."
Three LNG import terminals in Canada are expected to be operational by 2015 with annual import volumes around 1.4 bcf per day.
Demand for natural gas increases steadily in the reference case, led by gas use in expanding oilsands operations and greater use as a fuel to generate electricity, the NEB forecasts.
The arrival of LNG on Canadian shores isn't too far off as the Canaport regasification terminal in New Brunswick continues construction and should be operational by the fourth quarter of next year.
Any reduction in net Canadian gas exports over the period is likely to be offset by increased LNG imports into the U.S. and by growing American unconventional gas production. As a result, relatively balanced supply and demand conditions are expected to persist in North American natural gas markets over the reference case period and maintain an average gas price of $6.65 per gigajoule ($7 U.S. per mmBtu).
"I think in the continuing trends case, the middle case, LNG would continue to be a price taker and so the domestic gas price is setting the stage there," Mortensen said. "In that sense it would have no effect on Canadian competitiveness but in the low price case, we are seeing that as an LNG abundant scenario and in that case, there's no incentive for Canadian producers to go looking for higher cost unconventional or frontier gas."
Western Canada is expected to continue to be the primary source of gas production in the reference case.
"The mid-range prices of the reference case and continuing trends encourage some northern development and some continued development of unconventional gas sources," noted John McCarthy, commodities business unit leader. "However, at these prices, it's not high enough to prevent the decline of natural gas production."
High prices in the fortified islands scenario results in an increase in production from northern, offshore and unconventional gas sources, leading to an overall boost in Canadian production.
"The production ... in the triple E scenario declines steeply and this is primarily driven by low...prices for natural gas. Given that this is a collaborative environment with access to global energy, there is an influx of (LNG) imports in this scenario which compensates for the reductions from Canadian basins," he added. "In fact in this scenario, LNG contributes to over half of the Canadian requirements by 2030. This is a scenario where Canada becomes a net importer of natural gas, in effect."
The Triple E scenario is one in which there is a balancing of economic, environment and energy objectives and has the most rigorous environmental policies of the three scenarios.
Despite the resumption of strong drilling activity, a continued downward trend in new well productivity leads to a gradual decline in production over the reference case period. Coalbed methane production in Western Canada increases steadily, reaching 1.4 bcf per day by 2015. Conventional natural gas production from the east coast contributes an average of 430 mmcf per day over the reference case period and includes the Sable project offshore Nova Scotia, the onshore McCully field in New Brunswick and CBM production in Nova Scotia.
Also included is the Deep Panuke project starting in 2010, subject to the necessary approvals.
In the reference case on the oil side, oilsands production rises to 2.8 million bbls per day by 2015, down from three million bbls from the NEB's June 2006 report, due to rapidly escalating costs.
Upgraded bitumen levels expand to 1.82 million bbls per day by 2015 and represents 65% of total bitumen supply. Non-upgraded bitumen levels expand to 970,000 bbls per day by 2015.
The reference case assumes that real crude prices will decrease from the high of recent years to $50 (U.S.) per bbl and remain at this level until the end of the reference period.
"We've learned that energy prices are expected to remain high - higher than historical levels due to primarily international supply and demand issues," McCarthy noted.
Declining Western Canadian Sedimentary Basin conventional oil production is more than offset by increasing oilsands and east coast production.
By 2015, the reference case production levels increase by 61% above 2005 levels, reaching 4.05 million bbls per day which in today's terms would rank Canada as the world's fourth largest producer.
The high oil-to-gas price ratio has resulted in a shift to more oil-directed drilling, the NEB noted. As well, recent success in exploiting the Bakken oil deposits of the Williston Basin in southeast Saskatchewan and in southwestern Manitoba has led to increased light crude oil production. The effect is a softening of the production decline in the WCSB for several years, after which historical decline trends are expected to resume.
Due to the WCSB being a mature supply basin, exploration efforts yield increasingly smaller pools, but development drilling and improved oil recovery (IOR), primarily waterflooding, make up a larger portion of reserves additions.
Following the success of IOR through carbon dioxide (CO2) flooding at the Weyburn and Midale fields in Saskatchewan, it's expected that CO2 flooding in mature oil reservoirs will increase across the WCSB.
In the reference case, production of conventional crude oil and equivalent from the WCSB is projected to resume its decline in the 2009-2010 timeframe, for both light and heavy crude oil, with 2015 production levels of 328,000 bbls per day for conventional light crude oil and 399,000 bbls per day for conventional heavy crude oil. By 2015, conventional crude oil from the WCSB has declined by about 30% compared to 2005 production levels.
Projections for eastern Canada oil production are dominated by the east coast offshore, with only minor amounts of production expected from Ontario. The White Rose field offshore Newfoundland and Labrador became the third producing field in 2005, after Hibernia and Terra Nova. Total production levels are predicted to reach 416,000 bbls per day in 2007 as White Rose expands and Terra Nova returns to full capacity after maintenance work in 2006. The Hebron field begins production in 2013. Contributions from smaller satellite pools in the Jeanne d'Arc Basin are also included, beginning in 2010.
It's also assumed that a new field is found in the relatively unexplored regions of the East Coast, potentially in the Flemish Pass region or in the Deepwater Scotian Shelf. The pool should come onstream in 2015, increasing production levels to 473,000 bbls per day.
http://www.nickles.com/brn.html
Scott Simpson
Vancouver Sun
Thursday, November 08, 2007
Increasing dollar hurts producers, provincial and federal governments
One of British Columbia's biggest cash generators, its natural gas exports, are taking a substantial hit from the increasing value of the Canadian dollar.
Greg Stringham, vice-president of markets and fiscal policy at the Canadian Association of Petroleum Producers, said in an interview Wednesday that the declining U.S. dollar hurts gas producers as well as provincial governments and the federal government in Canada, with "billions" of dollars lost across the country.
The situation is exacerbated by declining gas prices -- Stringham noted a recent National Energy Board report that said the average market price for Canadian natural gas was actually lower than the production cost in 2006.
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Oil, by contrast, is providing strong returns because increasing prices are offsetting the lower value of U.S. dollar-valued oil sale revenues.
"Natural gas probably gets hit the hardest out of all of them. Oil has gone up from $68 to $96 and the rise of the Canadian dollar has pretty well offset that. We're getting about the same amount of Canadian dollars back as we did when there were lower oil prices," Stringham said.
"But in natural gas we've had the opposite thing happening."
In October it got down as low as $4 US -- compared to spot prices that reached above $15 just two years ago in the wake of hurricanes in the U.S. Gulf of Mexico gas-production region.
Mild summer and winter weather since those events has cut into demand to the point that North American gas in storage is at a near-record volume.
"The rising exchange rate nails that even harder. Canadian natural gas essentially becomes more expensive for the Americans because they are now paying in $1.07-dollars versus 88-cent dollars.
"The people that take the brunt of that [Canadian dollar] rise are the ones who are converting that U.S. dollar sale back into Canadian dollars, and that happens to be the Canadian companies and the governments -- all the producers -- and the governments because of course they realize their royalties in U.S. dollars as well.
"You are getting less Canadian dollars back."
Stringham noted the effects are already being felt in northeast British Columbia, the province's natural-gas production hub.
"Activity in northeast B.C. has just plummeted. It has already been happening because of the lower price, but if you throw on top of that the exchange rate it just makes it even harder to get back out of that hole.
"Even gas produced and consumed in Canada is affected because it's priced in U.S. dollars."
The best scenario for Canada would see demand go up -- but even if it did, it could be six months before the volume of gas in storage drops enough to push prices up, Stringham said.
But in another energy sector, hydroelectricity, the impact of the rising Canadian dollar is much harder to measure.
BC Hydro says there is no simple way to calculate the impact changing currency values have on its bottom line, but overall the situation is working to Canada's benefit.
British Columbia has a natural hedge against a stronger Canadian dollar in the electricity realm due to its position as a net importer of electricity from the U.S.
The stronger our dollar versus U.S. currency, the fewer dollars Hydro dispenses in order to buy power from U.S. producers.
© The Vancouver Sun 2007
Claudia Cattaneo
Financial Post
November 06, 2007
PetroChina's remarkable ascendancy yesterday to the world's first trillion-dollar company is an important event for energy consumers and private sector energy companies.
It highlights that state-controlled companies (also known as National Oil Companies or NOC), such as PetroChina, are eating their private counterparts' lunch; it points to greater NOC control of the world's energy resources, which can only mean higher energy prices and lower energy security for the West; and it shows to private sector companies (also known as International Oil Companies or IOC) that if they want to stay in business, they need to rethink their views of energy security and their recent strategies of re-patriating their cash to North America, in plays such as Alberta's oilsands, that are supposedly more stable.
Justified or not, PetroChina's huge stock market value makes it a stronger company and gives it greater access to capital to make acquisitions. It builds on PetroChina's advantage relative to IOCs in places such as Africa, where it is ready to spend on infrastructure to complement its energy investments. With a strong stock price, it can afford to pay up, if it chooses, for Husky Energy Inc.
China's largest oil company isn't alone as a state-controlled company becoming a force in the stock market. Russia's Gazprom, already worth nearly US$300-billion, said it wants to be the world's largest company by market value. Saudi Aramco, the national oil company of Saudi Arabia and the world's largest oil company by output, yesterday announced plans to sell shares to the public for the first time by offering to investors 25% of the shares of a joint venture refinery with Sumitomo Chemical Co.
"[NOCs] are becoming much more sophisticated in every way -- financially, technically," said Peter Tertzakian, chief energy economist at ARC Financial Corp. and author of A Thousand Barrels a Second. "They have a boldness and a confidence that they didn't have before."
NOCs are already sitting on huge resources. Robert Skinner, a former director of the Oxford Institute for Energy Studies, said more than 75% of the world's oil and gas resources are vested in, owned or controlled by NOCs.
Further concentration of the world's energy riches in the hands of national oil companies is bad news for consumers. Many NOCs are owned by governments that rely on oil revenues to fund their budgets, hardly an incentive to keep prices low. Meanwhile, consuming nations are increasingly dependent "on a group of nations that are manifestly undemocratic, in many cases led by despotic leaders, some ravaged by civil wars fought over petroleum rents, and by regimes whose hold onto power, given demographics, largely depends on ever-increasing the production and export of their resources," Mr. Skinner said.
This changing environment calls for a new way of thinking by the IOCs about energy security. In the past few years, IOCs have sold off their international assets to concentrate in politically secure regions, sparking the torrent of funds into the oilsands. The Alberta government's new royalty strategy has demonstrated Alberta is as politically risky as other oil producing jurisdictions.
Future energy security will depend on private oil companies' return to the international arena through co-operation, said Lou Gagliardi, oil analyst at investment advisor John S. Herold Inc. in Norwalk, Conn.
"Industry and companies have to evolve with the times," he said. "You can dig in your heels or say, OK fine, I'll try to adapt. If you want to be a player, you got to be there."
By Steve Quinn
Wall Street Journal
November 3, 2007
JUNEAU, Alaska (AP)--If oil companies want to continue taking Alaska's oil, state officials say they need to up the ante.
In fact, Gov. Sarah Palin wants 25% off the top of all profits the companies make in Alaska, up from 22.5% and the second hike in as many years. In a special legislative session, oil giants are warning lawmakers that another increase will make the business climate look unstable.
But after Western oil companies have been effectively kicked out of Venezuela and Russia, these could just be hollow arguments.
"The financial impact pales in comparison to what's going on overseas," said Greg Priddy, analyst with New York based Eurasia Group. "In the end, with these oil prices, it will be something the industry is willing to absorb."
Already beset by federal corruption probes into last year's oil tax changes, Alaska is hardly alone in pursuing a greater state share.
Battles between governments and the industry are being played out worldwide. And with oil prices inching toward $100 a barrel - having already surged 20% in one month - the tension between the two is not likely to ease.
"It's a concern for us," said Kevin J. Mitchell, vice president of finance for ConocoPhillips' (COP) Alaska operations. "This global phenomena of increased government take continues to increase the cost of doing business"
Throughout the year, governments have aggressively gone after some of the oil companies staggering multibillion dollar profits.
- In April, Royal Dutch Shell PLC (RDSA) was forced to cede control of a project in Russia's Sakhalin island to state-controlled OAO Gazprom (GAZP.RS) at the behest of the government. Shell sold Gazprom 27.5% of its stake, leaving it with 27.5%.
- In May, President Hugo Chavez's government took over Venezuela's last privately run oil field, squeezing out major producers including BP PLC (BP), ConocoPhillips, Exxon Mobil Corp. (XOM), and Chevron Corp. (CVX)
- In June, BP agreed to sell its stake in a giant Siberian gas field project to Gazprom. This essentially meant the end of an era when foreign oil companies could control Russia's largest hydrocarbon deposits without a strong state-controlled partner.
And in a less severe blow to the industry in Canada, Alberta's provincial government just last month announced it would bump up its take from the industry by $1.45 billion starting in 2009.
"What you're seeing is a global pattern of governments trying to recoup more of the windfall," Priddy said. "What's happening in Alaska is a really mild form but a clear reflection of that."
In Juneau, the industry is balking at Palin's push to boost the tax rate for the second straight year. Last year the industry pushed for a 20% net profits tax or lower; it was the first rate change in 17 years. Exxon Mobil still is pushing for a tax lower than 20%.
Today, the stakes remain high for both sides, especially on the North Slope which accounts for close to 14% of the nation's domestic production, but is also in a 6% annual decline.
Annual net income in Alaska has reached the $2 billion mark for companies like ConocoPhillips and BP; Exxon Mobil doesn't disclose financial information for its Alaska operations.
A second new tax in as many years could create an unstable investment climate in Alaska, industry executives warn.
Companies cite rising costs and harsh arctic conditions in Alaska as inherent risks not found in other regions such as the Gulf of Mexico.
"I do all my investments on an after tax basis, said Claire Fitzpatrick, senior vice president for London-based BP's Alaska operations. "I have to be able to demonstrate that it's a better investment for London to give me the money rather than the Gulf of Mexico or the Rockies, and the tax is part of it."
BP, ConocoPhillips and Exxon Mobil stressed to lawmakers how there are no plans to leave the North Slope, but must still heed their warning at a time when production wanes.
In one case, ConocoPhillips said changing the tax structure could affect six projects currently being evaluated; first production would begin in three years.
Kevin Book, an energy policy analyst with Friedman, Billings, Ramsey & Co., said the impasse often lies with how elected officials whose term expires in two, four or six years, think differently from oil executives who evaluate projects on a 20- and 30-year cycle.
"It leads to self-deflating policy choices," Book said. "It deters production that brings you income, or at least it delays it."
The legislative debate enters its third week of a special session, which has been driven by much more than the need to bulk up the state's coffers. Four members of the state Legislature that passed that law have been indicted on federal bribery charges, and the federal corruption probe has stretched to the state's congressional delegation.
U.S. Sen. Ted Stevens and Rep. Don Young, both Alaska Republicans, have come under scrutiny for their ties to VECO Corp., which last year lobbied heavily for the new tax.
The measure, promoted as a way to provide a stable tax climate in Alaska, was sought by major petroleum producers before they would consider building a multibillion dollar natural gas pipeline tapping vast reserves on the North Slope.
VECO, whose top executives pleaded guilty to federal bribery charges, would have been in line to bid on lucrative construction and maintenance contracts if that project had been built.
The tax passed, but the pipeline deal never moved forward.
The issue of public trust hangs over both the industry as well as the legislature this time, said Republican John Coghill, chairman of the state's House Rules Committee.
"Because of the court action that's going on with those who were involved of the last go around, it's going to be very important," he said. "We have to look at it from a stewardship position and those bring some of the credibility issues."
The project will handle output from the oilsands region
Vancouver Sun
November 03, 2007
CALGARY -- Enbridge Inc. said Friday it will build a $2-billion oil pipeline to handle tar-like bitumen from Petro-Canada's planned Fort Hills oilsands project.
Enbridge, the country's second-largest pipeline firm, said the 480-km line will be capable of carrying 250,000 barrels of diluted bitumen a day from the project site near Fort McMurray, Alta., southwest to an upgrader near Edmonton.
The project, to be complete by 2011, includes storage facilities and a second line to carry 70,000 barrels of diluent, an ultra-light form of oil that is blended with the heavy bitumen so it can flow in pipelines.
The line will run for part of its length along the right-of-way for Enbridge's Waupisoo pipeline, which is to be completed next year and will initially carry 350,000 barrels of oilsands crude from the Fort McMurray region to Edmonton.
The planned pipeline is one of a number in the works to handle the burgeoning output from the oilsands region, where production is expected to triple to three million barrels a day by 2015 as companies rush to exploit the largest oil reserves outside the Middle East.
Petro-Canada's $26-billion Fort Hills project is expected to produce 140,000 barrels a day of synthetic crude when its first phase is completed in 2011, rising to 280,000 barrels a day by 2015, when all phases are done.
Petro-Canada, which operates the project, has a 60-per-cent stake, with the the remaining 40 per cent split between UTS Energy Corp. and miner Teck Cominco.
© The Vancouver Sun 2007