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Sands in shake out year Not all upstream plans to survive; focus shifts to settling market, downstream Gary Park For Petroleum News
It’s the C$100 billion question that is expected to get some significant answers in 2006.
Quite simply, how many of the oil sands projects making up that gigantic spending plan will actually proceed?
There is a growing view that the upstream line-up has reached, if not exceeded saturation point in terms of the sector’s ability to raise financing, hire engineers and construction workers, obtain materials, refine and transport their production and, ultimately, find markets.
Adding to the pressures on labor and materials is the prospect of the two Arctic gas projects — North Slope and Mackenzie Delta — moving ahead in the next decade.
The sense that the oil sands might be overheated peaked in November when Canadian Natural Resources and EnCana startled the market by announcing plans to add another C$37 billion to projects proposed or under construction. Bullish mood based on oil prices EnCana Chief Executive Officer Randy Eresman, defending his company’s decision to embark on building its oil sands output from 42,000 barrels per day to 500,000 bpd over the next 10 years, said rising oil prices are “going to be here for a long time, meaning the oil sands have simply gained in economic value.”
“While the numbers are big, they seem doable if oil prices stay strong,” said Alistair Dunn, a money manager at Connor Clark & Lunn, which is among the largest shareholders in Canadian Natural (best known by its stock symbol CNQ).
Wilf Gobert, vice-chairman of Calgary-based investment dealer Peters & Co., said the latest project announcements reflect the level of confidence in a resource that was once viewed as a marginal mining venture.
“When you know that 80 percent of the oil sands is recoverable (using current extraction technologies), you have unleashed the potential for a massive number of projects,” he says. Momentum of announcements But the mood is not all bullish.
Murray Edwards, CNQ vice-chairman and one of the industry’s most respected voices, said it “would be naïve of anybody to think there are not tremendous challenges in execution in the oil sands projects.”
More analysts and observers are suggesting the frenzy is partly tactical, as companies roll out long-term strategies to improve their chances of retaining existing staff and scaring off smaller competitors.
Jiri Maly, an energy expert at McKinsey & Co., said announcements on a grand scale generate their own momentum, with companies serving notice of plans to put their competitors “on edge about whether to invest or not.”
Some might conclude that the sector “has become overheated and is not an attractive place to go.”
Given the sweeping nature of some of the forecasting, Marcel Coutu, chief executive officer of Canadian Oil Sands Trust, the largest partner at 35 percent in Syncrude Canada, the world’s largest producer of synthetic crude, said he is concerned about the accuracy of long-range production and pricing forecasts.
He also questions the ability of the Fort McMurray region of northeastern Alberta to meet the infrastructure needs when the boom city of 70,000 is already unable to meet the demand for housing, health-care, education and other basic services.
Coutu said the Syncrude consortium, which has already paid the price for over-ambitious expansion plans, now prefers to take a “discreet” approach to disclosing plans that “are more than five to 10 years out.”
In unveiling additions to its existing bitumen and heavy oil program that could cost C$25 billion more than its current C$10.8 billion Horizon project and yield 860,000 bpd by 2020 CNQ said it is confident the plan could be paid for out of cash flow, with little or no need to issue new shares or add debt if oil stays above US$28 per barrel.
Regardless of how the big-ticket plans shake out there is every reason to believe that oil sands production will triple to 3 million bpd by 2015 and could climb to 5 million bpd by the 2025-2030 period.
That forces the sector to get to grips with the next phase of oil sands expansion — opening new markets, building pipelines and meeting refinery demands. To market, To market Other than meeting Canada’s domestic oil needs, the obvious market bet to absorb the bulk of new production is the United States, where the oil sands have registered among federal energy officials and lawmakers.
Sen. Orrin Hatch of Utah, one of the most influential Republicans on Capitol Hill, gave a ringing endorsement to the oil sands during October when he said the northern Alberta resource means Canada “will inevitably overtake Saudi Arabia as the world’s oil giant. It means that the United States can enjoy a new gigantic source of oil from a friendly neighbor.”
David Conover, the U.S. energy department’s assistant secretary for international affairs, echoed Hatch’s sentiment by conceding the United States will not be able to meet its future energy needs without the oil sands.
To that end, he says, finding ways to get the heavy oil to market must be addressed if the resource is to have any hope of reaching its full potential.
But the Canadian government, infuriated by a series of cross-border trade spats, has delivered a clear message that the United States should not take Canada’s oil supplies for granted.
Natural Resources Minister John McCallum pursued market diversification in a fall visit to China where he met with heads of PetroChina and China National Offshore Oil Corp.
Emboldened by their reception, he said 450,000 bpd of oil sands production — one-quarter of current Canadian crude exports south of the 49th parallel — could be destined for China by 2011.
McCallum also found a strong desire among the Chinese companies to build on the oil sands foothold they established in 2005 when CNOOC and Sinopec became partners in production ventures and PetroChina struck a deal to become the 50 percent anchor tenant in Enbridge’s Gateway pipeline proposal to ship 400,000 bpd to the British Columbia coast, targeting 300,000 bpd for Asia and 100,000 bpd for California. Pipe dreams The pipeline sector has awoken from its prolonged slumber with a jolt.
Canada’s three established oil and gas carriers and one unknown are trying to round up support for connections from northern Alberta to the U.S. Gulf Coast, California and Asia.
It has turned into the most competitive battle among established and emerging companies in North American pipeline history.
“There is a lot of opportunity and a lot of capital available right now,” says Guy Jarvis, Enbridge’s upstream vice president.
But Brian Purdy, an analyst with FirstEnergy Capital, cautions that few of the major upstream projects have been confirmed and “not all can go ahead at the same time” because of the accelerating demand for construction labor, engineering and materials, for both oil sands production and the prospect of natural gas pipelines from Alaska’s North Slope and Canada’s Arctic in the next decade.
The general consensus points to the need for about 750,000 bpd of new pipeline capacity out of Alberta in the next five to seven years.
Winners and losers among the contenders are expected to be determined over the next few months by the oil sands producers, who must select their preferred carrier and commit volumes. Nothing like current competition Rich Ballantyne, the former president of Terasen Pipelines (now Kinder Morgan Canada, with Ian Anderson as president), said last year he had seen nothing to match the current competition in more than 20 years in the business.
What was once a “relatively monopolistic business now has all of us in each other’s business,” he said, indirectly referring to TransCanada’s surprise entry into the big-time oil side of the transportation sector.
Enbridge and Kinder Morgan, as Canada’s two leading oil pipeline companies, are obvious favorites to grab a slice of the action; TransCanada, traditionally a natural gas carrier, has emerged as a serious contender; and a privately held Altex Energy has surfaced with plans for a direct Alberta-to-Texas link.
Enbridge, as well as testing producer support for a staged extension of its pipeline network from the U.S. Midwest to the Gulf Coast refinery region, has surprised even itself with the response to a non-binding open season for the Gateway pipeline project from Alberta to Kitimat, British Columbia, for tanker connections to California and Asia.
Having set 400,000 bpd as its economic threshold, Enbridge easily surpassed that level, although it will not say by how much until firm shipping contracts are in place and an application is filed with the National Energy Board in the second quarter.
But the company has given broad hints of the level of support by studying expansion of the pipeline to 36-inch diameter from 30 inches, which it says could lead to peak capacity of 800,000 to 1 million bpd with the addition of compressor stations.
Just as significantly, thoughts that the U.S. West Coast would take 25 percent or 100,000 bpd of the initial volumes have now been revised, with thoughts that the U.S. percentage could be even higher. PetroChina could be anchor tenant Also still “very much alive” is a joint effort by Enbridge and PetroChina to secure producer commitments for 200,000 bpd, making PetroChina the anchor tenant on the C$4 billion pipeline.
To broaden Gateway’s appeal, Enbridge is willing to sell 49 percent ownership to investors who make shipping commitments. It has already signed definitive agreements to provide services for the 100,000 bpd oil sands project being developed by a ConocoPhillips-Total partnership.
Kinder Morgan is testing support for a rival scheme to carry up to 650,000 bpd of oil sands production to a deepwater port on the British Columbia coast for tanker shipment to Asia and California. It is reporting “significant progress” in its discussions with potential shippers.
Altex is the surprise late entry, unveiling plans for a US$3 billion, 250,000 bpd pipeline to Texas, but it has yet to identify any clients. Illinois refining centers a target TransCanada, despite its limited experience carrying oil, is going head-to-head with Enbridge to access the Illinois refining centers of Wood River and Patoka. Its chances were bolstered in November when ConocoPhillips negotiated an option for a 50 percent stake in the 435,000 bpd Keystone pipeline.
That was a sharp reversal from a mid-summer warning by TransCanada Chief Executive Officer Hal Kvisle, who said that if Enbridge and Kinder Morgan succeeded in locking up several hundred thousands barrels of production the need for Keystone would evaporate.
“We don’t think it serves the producing sector’s best interests to overbuild a lot of pipe that people are paying unnecessarily high tolls on. And we’re not about to build a large pipeline on spec.”
Teaming up with ConocoPhillips has sharply improved TransCanada’s odds. Purdy said that taking on such a major partner “validates” the Keystone proposal. Getting refined Of all the obstacles, the need for new upgrading/refining capacity is perhaps the most troublesome, given the reluctance of North American companies to enter that sector over the past two decades.
However, U.S. lawmakers, shaken by last year’s gasoline shortages, are scrambling to find answers.
Dennis Hastert, speaker of the House of Representatives, reflected the mood in Congress when he told oil companies to “do their part to help ease the pain American families are feeling from high energy prices.
“When are new refineries going to be built?” he asked, challenging ExxonMobil and BP to divert some of their record profits to ease tight supplies by building the first new U.S. refineries in 30 years. Alberta-industry initiative Eager to become part of that solution, the Alberta government and 16 energy companies including Petro-Canada, EnCana and Canadian Natural Resources, pipeline companies Enbridge and TransCanada, utility TransAlta and petrochemical manufacturer Nova have taken a bold initiative.
They expect to release findings by June of a study weighing the merits of a combined refinery-petrochemical complex, costing up to C$7 billion and capable of processing up to 300,000 bpd of bitumen and heavy crude.
Alberta Energy Minister Greg Melchin says the objective is to explore the economics of doing more refining in the province after two decades of excess capacity, gyrating oil prices and shaky profits that have driven producers away from investing in refineries.
But, given predictions of oil sands output tripling to 3 million bpd by 2010 and adding a further 2 million bpd within 20 to 25 years he says “someone” has to move on the refinery front.
Spokesmen for EnCana and Canadian Natural say they are eager to determine whether a shortage of refining capacity is hindering oil sands investment and whether the integration of an upgrader (which converts bitumen into synthetic crude), refinery (which upgrades the synthetic crude to fuels) and a petrochemical plant makes economic sense. Companies have own plans In addition to their success in blending synthetic crude and bitumen as feedstock for existing US refineries, oil sands producers are also working on their own upgraders and refineries.
CNQ, as part of its plan to invest about C$35 billion in the oil sands over the next 25 years, is evaluating the economics of building its own C$6 billion upgrader to process up to 175,000 bpd by 2015.
Company Vice Chairman John Langille said the upgrader would help open new markets for synthetic crude and give Canadian Natural a chance to “capture more value from the heavy oil chain.
But there was a sharp setback for EnCana late in 2005 when negotiations with Valero Energy to convert the Lima refinery in Ohio at a cost of US$2 billion to process 140,000 bpd of oil sands production, and help set EnCana on the path to 500,000 bpd of oil sands volumes by 2015, fell through.
Valero said the project would not have competed with the economic returns from “other strategic investment opportunities,” forcing EnCana to return to a shortlist from 20 companies it said have expressed interest in oil sands initiatives.
A Canadian Energy Research Institute report last September underscored the value of following CNQ’s example, estimating that, based on oil prices of US$32 per barrel, upgrading more raw bitumen into synthetic crude could generate an economic spinoff for Canada of more than C$1 trillion by 2020.
Currently only 64 percent of all low-grade bitumen produced in Alberta is upgraded. Petro-Canada looks at reconfiguration But simply adding new refining capacity is not the only answer.
Reconfiguration of existing plants to handle greater quantities of heavy crudes is just as important.
Petro-Canada has made one of the boldest moves in that direction, spending C$1.4 billion to convert its Edmonton refinery to exclusively process oil sands feedstock.
By mid-2008 the plant will handle about 135,000 bpd, displacing 85,000 bpd of conventional crude feedstock, reflecting Alberta’s declining conventional output and its swing to oil sands development.
Of the 2.5 million bpd that Canadian refineries can handle, only 360,000 bpd or 14 percent can be heavy oil, indicating there is ample scope for others to follow Petro-Canada’s lead.
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