“There certainly appear to be a lot
of forces increasing the demand for Canadian heavy, particularly in the US,”
says Steve Wuori. Enbridge’s executive
vice president observes that right now only Venezuela
and Mexico are seriously
competing for the heavy oil market in the Gulf Coast,
and “there are declines in Mexican supplies for geologic reasons, and
Venezuelan declines for both economic and political reasons. So structurally
it’s a very good time for Canadian heavy oil to secure that
market."
Wuori’s comments reflect a sea change in Canada’s
approach to selling the stuff. Early bitumen development in Alberta
was slow and easy – regional producers supplying heavy oil to
refineries in America’s
northern tier states, with virtually no competition from overseas. Today,
with surging supplies projected well into the future, Canadian producers,
pipelines and marketers have had to become aggressive. Global forces are
having a greater impact on the industry than ever before.
This is a good news/bad news story. The good news is that there are chinks in
the armour of our offshore competitors – lots of them. The bad news is
that the chinks in Canada’s
armour are costing the country dear. Consider the following.
- Already the world leaders in bitumen production and an
important producer of conventional heavy, Canadians have roughly doubled
their non-upgraded bitumen production in less than four years.
- American decision-makers would be
delighted to replace politically volatile Venezuelan supply with
low-risk Canadian product, and Venezuela’s present
leadership would be equally happy to develop markets elsewhere.
- Mexico’s
supergiant Cantarell
heavy oil field is in steep decline, but Canada has the productive
potential to offset the shortfalls.
- The isolation of the Canadian
prairies from the world’s sea lanes and from America’s major
refining centres means bitumen producers can’t freely compete in
world markets. Consequently, they get lower prices.
- As price-takers in North American
markets, Canada’s
producers have to settle for lower profits, and the province has to
settle for diminished royalty revenue.
All
these matters have geopolitical overtones. One way or another, each calls for
the economic fix of more fully integrated global markets. This article
focuses on the importance to Canadian producers of integration into world
markets, and some of the ideas in play to achieve it. Let’s begin with Alberta’s
relative isolation.
The
Economic Burden of Under-Priced Oil:Western Canada’s heavy oil sells for less than the price it would fetch on
the open seas. “Alberta is not an
island,” observes FirstEnergy’s Steven Pachet,
with a somewhat understated taste for the obvious. “If it were, world
market prices for heavy oil would be easier to obtain. Alberta is landlocked, and pipeline
capacity to other markets is sometimes restricted. Mountains to the west make
pipeline transportation to the Pacific difficult, while the bulk of North
America stands between Alberta and the
Atlantic and Gulf
Coasts.”
While
heavy oil and bitumen sell at a discount to light crude both in Alberta and around the world, sometimes the Alberta discount increases when heavy crude from Alberta cannot reach
markets. Known as the heavy oil differential, it represents the difference
between the prices of Alberta’s Lloyd
blend heavy oil and Mexico’s
Maya crude, adjusted for transportation costs.
Lack
of transportation is the main reason for the differential. The refineries
that are accessible to Alberta
heavy crude and bitumen can only handle so much supply. Alberta
producers have limited access to US markets because of pipeline constraints,
and the refining and upgrading systems in Western Canada
are not nearly large enough to handle all the new production. As available
supplies rise, refiners lower the price they will pay for Alberta’s
heavy and oil sands-based crude until it is below world prices: the greater
the competition to sell that oil, the lower the market price and the greater
the differential.
This
market behaviour costs Alberta,
big-time. To help put it in perspective, during the final quarter of last
year the differential averaged US$17.94 per barrel – the largest
discount ever for Canadian heavy.
Such
discounts are an economic burden on both producers and government. By
Paget’s calculations, in 2008 bitumen producers will forego $1.88
billion because of the differential. This estimate uses very specific
assumptions about how oil prices will behave this year.
When
he presents an estimate for the cost of the discount to the provincial
government, however, Paget uses a range of assumptions for its impact on
royalties. In his view, the discount could cost Alberta some $200-$500 million in foregone
royalty income. Also, of course, foregone revenues mean foregone taxes at
every level of government.
The
size of the prize can be measured in billions, but the penalty for inaction
could be greater still: growing surpluses leading to greater discounts and
diminishing development. The simple logic of this situation is clear. The
large sums in play mean a lot of incentive for change, and a lot of change is
on the way.
According
to Paget, “Oil sands producers have a choice. Upgrade the bitumen into
synthetic crude for higher unit revenue, or sell the bitumen and let others
invest the capital to refine it into lighter crude and petroleum
products.” This fundamental choice can be resolved with three kinds of
development: New and expanded upgrading systems; expanded pipelines for
existing markets; the creation of new markets. All are under consideration,
and all are needed to meet the growing heavy flow from Alberta.
Getting
to the Gulf: Here is the problem in a nutshell. Access to the
world gives you the best available prices for your heavy oil. Access to a
crowded regional market gives you Western Canada’s
heavy oil discount. That is why the marketing Shangri-la for the heavy oil
sector is the Gulf of Mexico, and why it’s important at this point to
discuss the labyrinthine world of pipelines.
Cushing, Oklahoma,
is now the southernmost delivery point for Canadian oil, and the closest
delivery point to the vast coastal refinery complexes in Texas
(4 million barrels throughput per day) and Louisiana (3.3 million barrels per day). Cushing
itself has more than half a million barrels per day of refining capacity, so
you can see the importance of delivering oil to these key markets. However,
Enbridge’s pipeline to land-locked Cushing now supplies only 120,000
barrels of oil per day – soon to be increased by more than half. Shipping
capacity from Canada
to Cushing will increase by another 155,000 barrels per day with the
completion two years from now of TransCanada’s Keystone Oil Pipeline
extension.
Steve
Paget explains the inexorable implications of these expansions. “By
late 2010, total Canadian shipping capacity to Cushing will increase to
345,000 barrels per day. This is 65 per cent of Oklahoma’s total refining capacity.
Canadian producers will need access to new markets to avoid swamping Oklahoma
refineries.” After all, swamped refineries mean lower oil prices
because of greater competition.
At
the moment, Canada
has no direct access to the Gulf, although small amounts – in the order
of 15,000 barrels per day – are transhipped there from Cushing. Both
Enbridge and TransCanada are proposing further pipeline extensions to the Gulf Coast
to avoid Canadian crude being stuck in Oklahoma.
The American Gulf Coast
has refining capacity for bitumen, and it also needs new sources of heavy
crude.
Of
course, heavy oil developments in Canada are creating the need for much
greater pipeline access to the coast than the volumes Enbridge and TCPL will
be providing to (and south from) Cushing. At this writing there are four
other proposals to increase pipeline capacity to the Gulf.
- Enbridge’s Access Pipeline
would expand existing pipe and extend the system from central Illinois to the
Gulf. This would provide 445,000 barrels per day of capacity. ExxonMobil
is a 50 per cent joint venture owner of the proposed pipeline and owns
useful rights-of-way.
- TransCanada is also considering
several possibilities – notably (with Conoco
Phillips) the Keystone project, which will convert a segment of TCPL’s natural gas mainline for oil
transportation.
- Another possible entrant is the
Chinook system – a 300,000 barrel-per-day proposal by two American
firms, which would use existing rights-of-way to ship.
- The Altex
Pipeline – proposed by a private company – would use new
technologies to ship 425,000 barrels of bitumen per day south.
Ironically,
increased oil sands production in Alberta
has greatly increased the province’s need to import condensate –
the mix of light hydrocarbons used to dilute bitumen to enable it to flow
through pipelines. That need, in turn, is leading to the construction of yet
another pipeline. According to Steve Paget, “diluent
(condensate) is being shipped into the province by railcar these days. There’s
plenty of diluent in North
America, but how much do we want to move in by train? It’s
like the old Rockefeller days. The problem is getting it here at a reasonable
price, and that problem is being resolved by construction of the Southern
Light pipeline, which will move diluent from Chicago to Edmonton.”
As Canada develops greater access to Gulf Coast
markets, Canada’s
heavy oil differential should disappear. The reason is simple. Unfettered
free-market oil prices reflect just two factors: transportation costs and
crude oil quality. Canada’s
competitors into the Gulf Coast region – notably Mexico and Venezuela – have the option
to cheaply take their production by tanker, anywhere in the world, to the
highest bidder. This means their prices are driven by competition for the
world’s highest prices. By contrast, Western Canadian producers are
competing in a small and crowded marketplace.
The
Competition: Markets always face complicating factors, and the
situation along the Gulf
Coast is no different. As
Steve Wuori points out, “The issues are
increasing Canadian supply and possible political issues between Venezuela and the United States. Venezuela has gravitated toward China and
possibly other customers. This has made it more feasible for Canadian oil to
replace Venezuelan production in Chicago
and south.” Because of political turmoil, employees at Petróleos de Venezuela struck some years ago,
cutting deeply into production a few years ago. Also, of course, the
country’s disputes with ExxonMobil and other multinational companies
have made international headlines.
Closer
to home, the vast Cantarell heavy oil field, which
provides about half of Mexico’s
oil production, is in rapid decline. According to the director-general of
national oil company PEMEX, production from the offshore field declined by
more than 13 per cent in 2006 alone. Cantarell’s
production peaked at 2.1 million barrels per day barely four years ago, but
is forecast to average only a million barrels per day by the end of this
year.
According
to FirstEnergy’s Steven Paget, “There’s a possibility of Mexico
becoming a net oil importer if the decline at Pemex
is not turned around, so it is for several reasons not wise to depend on
those two countries for oil.” Enter Canada
– a secure and reliable supplier with vast and growing supplies of
heavy oil and eager to displace imports from Latin America to the Gulf Coast.
The
geopolitical considerations do not end there, however. Venezuela’s Hugo Chavez is increasingly
unpopular at home, the country’s economy is in disarray, its heavy oil
resources rival Canada’s,
its labour costs are low and its transportation costs to the US Gulf Coast
are a fraction of Western Canada’s. It
is possible to imagine a post-Chavez Venezuela developing those
resources and becoming a resurgent competitor.
Don’t
put all your eggs in one basket: such is the weakness in the Canadian
strategy of focusing on markets in Texas and
Louisiana. From
the Gulf, Canada’s
heavy oil producers would have tanker access to the whole world, but not
before paying huge pipeline costs from Alberta.
To help forestall such an eventuality, Enbridge has proposed a project named
Gateway.
A
Nearby, Open-water
Port: "Usually
to create a market you need producer push and refiner pull,” says
Steven Paget. “We are definitely seeing (both) for Gulf coast
markets,” but right now the producer push to reach Asian markets is
pretty slim. However, Enbridge is planning just such a line.
Gateway
is “a heavy oil pipeline from Edmonton
to Kitimat (British
Columbia) to carry oil to a different market than
the southern US,” Steve Wuori explains. “It
would carry oil to California and to Southeast Asia, by ship. The appeal to Canadian
producers is that you would get another bid on the crude oil from somewhere
other than the United
States.” Also, of course, pipeline
costs would be less.
“When
(Enbridge) first started we were aiming for 2011,” Wuori says. “But now we are targeting 2012-2014” to get
this line into production. Will Canada be able to supply all
these markets with heavy? Wuori thinks so.
“The production forecasts up to 2020 for the oil sands support that
kind of growth potential, even if you risk it for economics and environmental
concerns.” Indeed, Enbridge is even looking for ways to take Canadian
heavy to refineries in Ohio and Kentucky “and even beyond that to the east coast
of the US
– to ensure that there is market for Canadian production.”
Canada’s
bitumen production is the ultimate example of the blackening of the barrel in
the petroleum world. For more than two decades there has been a shift in
global production from light, sweet, high-quality oils to heavy, sour,
poor-quality crude. This “blackening of the barrel” has been
problematic for many refiners, since black barrels bring with them
environmental drawbacks, require capital-intensive equipment, and refine into
lower-value barrels of fuel and other products.
Most
refiners prefer higher-quality oils, and producers prefer to sell those oils
because they fetch a better price. So does the government of Alberta, because it
wants to realize as much of the economic benefit from the oil sands as
possible. What’s a province to do? FirstEnergy’s Paget has an
idea that deserves sharing.
Upgrader Option: As resource owner,
the government of Alberta
receives its royalty share from bitumen and heavy oil production in kind
– that is, it receives oil, which it then needs to turn around and
sell. Most producers that upgrade their oil sands in Alberta into lighter crude or petroleum
products pay royalties based on the bitumen price.
Therefore,
any discount for Alberta oil sands bitumen
results in decreased royalties and decreased Government of Alberta revenue,
whether the crude is upgraded in Alberta
or elsewhere. “Assume that bitumen royalties are 10 per cent”
this year, says Paget, and that the oil sands produce 1.3 million barrels per
day.” This would mean the province receives 130,000 barrels of bitumen
each day in royalties – a volume forecast to grow into the foreseeable
future.
“Why
wouldn’t Alberta
guarantee that amount as feedstock for a private-sector upgrader?”
Paget asks. “If the government believes in upgrading in Alberta, then taking the oil which it in fact owns and
dedicating it to Alberta
upgrading is a good way to do it. It’s a good way to make policy
without investing much money directly. A hundred and thirty thousand royalty
barrels per day is easily enough to support one or two stand-alone upgraders.”
Paget
weighs the possibilities. “The government of Alberta is faced with a dilemma. Investment
is lost (whenever raw) bitumen is exported. How much investment might be lost
if bitumen exports from the province increase by 500,000 barrels per day? With
current pipeline constraints and artificially high differentials, royalty
revenue is already being lost.”
The
new pipelines under construction don’t present an obstacle to this
proposal, since most of the oil pipelines from the province can ship both
bitumen and other crudes, including synthetic oil. Indeed,
this idea seems to be one that will benefit the province in many ways. Provincial royalties would increase, and so would producer
profits.
By : Peter
McKenzie-Brown
Language Instinct
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