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Ever-shifting Alberta oil sands Climate-change plan could affect asset values; Suncor talks up 60% boost in value; Synenco treads water; Imperial talks tough Gary Park For Petroleum News
Another week in the life of the Alberta oil sands. Another stomach-lurching time.
It started with the Canadian government announcing tougher environmental standards on future projects, creating unease among investors, and ended with Suncor Energy touting the possibility its market value could soar to C$80 billion from C$50 billion.
In between, Imperial Oil, a 25 percent partner in the Syncrude Canada consortium, put out word that it won’t settle for a new royalty deal with the Alberta government if its shareholders get the “short shrift,” while struggling oil sands rookie Synenco Energy announced a major internal shakeup as it continues a 10-month strategic review.
Forget the fact that oil has been flirting with US$110 a barrel, the oil sands have a full plate of other problems to work through.
In their latest annual report on global mergers and acquisitions in the oil industry, John S. Herold and Harrison Lovegrove (a unit of British-based Standard Chartered Bank) warn that the oil sands sector is sailing into stormy waters.
New Canadian government rules on greenhouse gas emissions, higher Alberta royalties and the unrelenting pressure of high construction costs are a deterrent to potential investors, despite the fact that Canada had a record number and value of oil sands deals last year, including such major international buyers as Royal Dutch Shell, Marathon, ConocoPhillips, BP and StatoilHydro, they said.
Deals soared to C$18.6 billion In fact, oil sands deals in 2007 soared to C$18.6 billion from $2 billion three years ago
Tom Biracree, senior vice president with Connecticut-based John S. Herold, said that until there is clarity relating to the impact of taxation and the GHG regulations are clarified “some parties will be reluctant to make major commitments.”
The proven reserve value of oil sands transactions climbed in 2007 to $14.78 per barrel from $11.85 in 2006, with proved plus probable reserves jumping 40 percent to $9 per barrel, the study reported.
But others agree with the suggestion that 2008 could see a slowdown.
Andrew Potter, an analyst with UBS Securities Canada, said in a note that the uncertainty stemming from the GHG regulations won’t be resolved until the government announces in 2009 exactly what percentage of their carbon emissions oil sands producers who start operations after 2011 will have to capture and store.
He said the mandated reduction of 25 percent per unit of production could potentially be accomplished through carbon capture and storage at C$65 per metric ton, which would translate into a “tolerable” incremental cost of C$1.50 per barrel. Beyond that level there could be “significant” reductions in net asset values.
He believes those values could still rise substantially over the next year, even after factoring in the added costs.
Oil sands, coal-fired power plants major targets The barebones outline released by the government made it clear that the oil sands and coal-fired power plants are the major industrial sectors being targeted for GHG reductions, which will take effect in 2018.
Environment Minister John Baird said Canada will not be able to achieve its 2020 goal of a 20 percent “absolute” reduction in 2006 GHG levels without mandating carbon capture and storage for the oil sands, adding “tough measures are needed to put us on a path to meeting our commitments.”
Even so, his department believes oil sands production alone will account for 25 percent of Canada’s GHG by 2020, up from 18 percent today.
What the industry doesn’t know is whether the Canadian and Alberta governments will contribute to the multi-billion-dollar cost of implementing carbon capture and storage.
The Integrated Carbon Dioxide Network, an industry coalition, said large-scale carbon capture and storage could cost C$35 to C$70 per metric ton, plus C$10 per metric ton for transportation from the oil sands to saline aquifers and enhanced oil recovery sites.
Baird said the cost of implementing the measures could start at C$20 per metric ton in 2010, rising to C$50 in 2016 and C$65 in 2020.
The two governments figure that carbon capture and storage — still a largely unproved and undeveloped technology — has the potential to handle 50 million to 55 million metric tons of CO2 a year by 2020, barely one-third of the GHG reductions targeted for the industrial sector.
Petroleum producers troubled Little wonder Pierre Alvarez, president of the Canadian Association of Petroleum Producers, is troubled by government assumptions about how quickly and affordably the carbon capture and storage solution can be introduced, given that it has never been attempted on such a scale anywhere in the world.
Among producers, there is unhappiness that the costs of carbon capture and storage will be dumped on them, with Nexen Chief Executive Officer Charlie Fischer arguing the burden should be carried by consumers.
He noted that 30 percent of CO2 emissions originate with oil sands production, 15 percent is attributable to refineries, but 55 percent is tied to fuel users.
However, there is no sign that the Canadian government is ready to consider a user-based tax.
It’s quite happy to sit back and watch developments in British Columbia, where the province is taxing the purchase and use of fossil fuels by imposing an extra 2.4 cents per liter on gasoline this year, rising to 7.2 cents in 2012 — mere fractions of the wildly fluctuating pump prices these days — as it targets a 33 percent reduction in GHG by 2020.
Upstream concerns On top of the uncertainty for the oil sands sector, pending the release of final regulations next year, there are questions about what the Canadian government has in mind for upstream oil and gas operating, gas pipelines and petroleum refineries, all of them labeled for a contribution to lowering GHGs.
The “composite” challenge of climate-change regulations, construction costs and Alberta’s planned royalty hikes are posing major “external” challenges as Synenco tries to reshape its future, company spokesman Scott Ranson told Petroleum News.
The impact of these pressures has forced Synenco to cut 60 to 70 of its 100 employees, after lopping 46 last year, as it narrows the focus on its Northern Lights project, which has SinoCanada Petroleum (wholly owned by China’s Sinopec) as a 40 percent partner.
Since announcing a “strategic repositioning” 10 months ago, which most analysts interpret as leading to outright sale of the company, it shelved plans for a 100,000-barrel-per-day upgrader after costs tripled to C$6.3 billion and is now moving ahead with a small pilot plant and is drilling to evaluate a resource estimated at 1.6 billion barrels, as well as hoping for regulatory hearings this year.
But Synenco has set no timelines for wrapping up the review or starting production at its mine, where it plans to produce 114,500 bpd over 28 years and the most recent cost was C$4.4 billion.
Ranson said the one “constant” remains “our well-delineated ore body,” which is based on eight seasons of drilling.
Following the resignation in February of Synenco Chief Executive Officer Todd Newton and the transfer of controls to co-founder and Chairman Mike Supple the review process has come under “direct oversight from the board,” which Ranson said is a “big step” towards a result.
Sky the limit at Suncor While Synenco battles on after posting a C$15 million loss last year and slashing its 2008 capital budget to C$40 million from C$130 million (itself down from an original C$235 million) last year, the sky is the limit for Suncor Energy, an oil sands giant.
Chief Executive Officer Rick George told a FirstEnergy conference in New York March 13 that a C$100 investment in his company 16 years ago is now worth C$7,000, boosting the stock market value to almost C$50 billion from C$1 billion.
“The ride is not over,” he said, suggesting C$80 billion or more is attainable once Suncor reaches its target of 550,000 bpd after 2012.
By then, he said the company will have multiple options, including higher dividend payouts and share buybacks that lift the stock value.
However, he conceded earlier in the week there “are a number of storm clouds threatening to rain on our parade,” linked mostly to the gathering rumble on the environmental horizon.
Syncrude Canada, the only producer ahead of Suncor, has yet to sign off on a new royalty deal, despite Suncor’s agreement with the Alberta government to replace a contract not due to expire until 2016 and start paying 20 percent royalties in 2010.
Tim Hearn, the retiring chief executive officer of Imperial, told the Financial Post the Syncrude partners are ready to negotiate new terms provided “the inherent value of the (existing) contract is somehow recognized in the new arrangement.”
If Syncrude reaches a better deal than Suncor then Suncor is entitled to the “same terms and conditions.”
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