| CALGARY, Alberta
CALGARY, Alberta Feb 25 The U.S. shale oil
revolution is forcing Canada's oil sands industry to question
whether there is a future in processing its crude into lighter
oil, a tried-and-true way of wringing the most money out of a
resource considered crucial to the country's prosperity.
Suncor Energy Inc, which nearly 50 years ago
pioneered the practice in Canada of mining and then upgrading
the oil sands bitumen into refinery-ready light crude at the
same site, served notice this month that the era of the
integrated project may be ending.
It said it was reexamining a plan to build a
multibillion-dollar upgrading plant in northern Alberta and
taking a C$1.5 billion ($1.5 billion) charge to account for
lower projected cash flow. The reason: cheap oil from North
Dakota and elsewhere is making it uneconomical over the long
haul to build such complexes.
"Why would you spend billions of dollars to build an
upgrader to create a product that is looking to be oversupplied
in the markets you can access today?" said Jackie Forrest,
director of global oil for consultancy IHS CERA.
The Suncor move is more evidence of a shift from upgrading
that is already well underway. Imperial Oil Ltd, for
example, is building the C$12.9 billion Kearl development - the
next major oil sands project to come online - without a
Once considered a sure winner by most Canadians, the oil
sands industry is now on the defensive on several fronts,
struggling to prove it can deliver its raw materials to refiners
at a competitive price and at an acceptable environmental cost
The dilemma over upgrading points to more problems ahead as
oil sands producers compete for capital against the developers
of the cheaper, less damaging shale oil.
With less-processed heavy oil competing with the increased
Bakken flows for pipeline space to U.S. refineries, a glut in
Western Canada has built up, generating a wide discount on
Canadian crude against benchmark West Texas Intermediate. That
has created an immediate problem, not the least for Alberta, the
province at the center of Canada's oil industry.
Alberta Premier Alison Redford blames the so-called "bitumen
bubble" for a forecast C$6 billion shortfall in revenues in the
coming fiscal year. Deep budget cuts are in the offing.
As a result, the province is pushing for ways to shore up
its budget against the falling revenue stream, while unions are
calling for more upgrading to create jobs.
The industry, however, seems to be moving in the opposite
direction. The problem is, building a new upgrader - a tangle of
pipes and vessels that transforms raw bitumen into an oil
product easily used by standard refineries - costs billions of
dollars and may make little sense over the long term.
In the short term, on-site processing would allow producers
to boost the price of their product by upgrading it, and the
wide price spread between cheap heavy oil and more expensive
light crude would mean hefty margins.
Indeed, the gap has recently ballooned to more than $40 a
barrel under U.S. benchmark West Texas Intermediate, compared
with a historical differential of less than $20.
But it takes years to build upgrading plants. In the
meantime, new pipelines to export markets are expected to be
built over the next decade - whether they are big ones such as
TransCanada Corp's Keystone XL pipeline or incremental
If that happens the discount on heavy oil should shrink.
That would leave the multibillion-dollar upgrading plants less
able to compete with shale oil.
IN THE PIPELINE
To be sure, the Keystone XL project - connecting the oil
sands with the U.S. Gulf Coast - is facing a full-scale push
back from U.S. environmental groups, and final approval from
Washington is not guaranteed.
If the pipeline gets built, it would move 830,000 barrels a
day of Alberta crude to Texas refineries, many of which are
configured to process the heavier grades that are now imported
from Venezuela, Mexico and elsewhere.
On today's pipeline network, it costs about $8.50 a barrel
to ship crude to the U.S. Gulf region from Alberta, traders say.
When new pipelines are built, the light-heavy oil price spread
is expected to come close to the shipping cost.
"You expect those bottlenecks will be gone, and once we get
global pricing, we've actually seen fairly narrow differences
between light and heavy crude," said IHS's Forrest.
Against that backdrop, Suncor says it hasn't made a final
decision on the proposed Voyageur upgrader, the centerpiece of
its expansion strategy.
"We're looking at all options," Chief Executive Steve
Williams said this month. "At one extreme you could go ahead
with the project as it is. At the other extreme you could cancel
the whole project and go ahead with nothing."
Williams fingered the U.S. shale boom as the main reason for
the indecision, as oil coaxed to the surface using hydraulic
fracturing does not need expensive upgrading to be run in
Oil production in North Dakota has jumped to 730,000 bpd
today from just over 100,000 bpd in 2006, making it the No. 2
oil-producing state after Texas. Large volumes of that crude is
transported on the same pipelines as the Alberta oil,
contributing to the disappearing spare capacity.
In the past year, both Bakken oil and upgraded light
synthetic crude, which have similar specs, have climbed in
tandem to around par with WTI, from around $13 a barrel below.
A recent PriceWaterhouseCoopers study said shale oil is
likely to make the largest single contribution to total U.S. oil
output growth by 2020, and that increased global shale output
could lead to lower crude prices than are currently projected.
Those barrels have begun to replace some heavy crude in the
U.S. market, squeezing the economics on upgrading plants that
would pump out products to compete, said Reynold Tatzlaff, PwC's
Canadian energy leader.
That's not to say upgrading is dead. Existing plants pump
out more than 1 million barrels of light synthetic crude a day.
Privately held North West Upgrading Inc and Canadian Natural
Resources Ltd are proceeding with a C$5.7 billion
stand-alone upgrader and refinery near Edmonton.
But the North West plant will get help from a steady supply
of bitumen from the Alberta government as part of an initiative
to generate more valued-added dollars. Expansions, such as one
that Canadian Natural is planning at its Horizon oil sands
project, come cheaper than starting from scratch, though it is
not rushing to start the project.
Mike Deising, a spokesman for Alberta Energy Minister Ken
Hughes, said he could not comment on various companies eschewing
upgraders, saying they all employ different forecasts.
In another trend working against upgrading, oil sands mining
is giving way to less-centralized steam-driven production
methods, which are less costly to expand and which can ship
diluted bitumen directly into the market. Several U.S.
refineries have been retooled to run more of the heavy crude.
Meanwhile, notorious construction cost overruns and a string
of outages at existing upgraders have raised questions about
reliability of returns and operations.
For more than a decade, most tar sands projects in Alberta
blew well through their budgets as the rush to develop the
resources stretched Alberta's skilled labor pool thin. Companies
sought to bolster manpower by importing workers from around the
world, and the rush to develop drove up the costs of steel,
other materials and equipment.
Several plants proposed before the 2008-2009 financial
crisis were canceled, as credit dried up.
"It's been the perception that any and nearly all upgraders
have been plagued with fires, maintenance issues, cold weather
issues. They're expensive to run, and even more so, they're
expensive to build," said Wood Mackenzie analyst Mark
(Editing by Frank McGurty, Janet Guttsman and Bob Burgdorfer)