Markets Main Concern For Bitumen Producers
by Shaun Polczer
Markets rather than supply are the main concern for
heavy oil and bitumen producers over the next seven years, according to a newly completed study by the Canadian Energy Research Institute.
"The primary concern is no longer production, but the
availability of downstream markets," Vincent Lauerman, CERI researcher, told a seminar at
the Petroleum Club in Calgary.
The objective of the multi-client study was to identify the best types
of refineries for taking Western Canadian bitumen-based feedstock in 2007,
calculate potential markets values for these feedstocks and estimate potential
regional and total demand.
Product quality, operating costs, differentials to West Texas Intermediate and technical specifications of downstream refineries all play into a
complicated formula to help determine demand for various grades of Western Canadian bitumen over the next seven years, Lauerman said.
Also playing a role will be the degree of processing and upgrading
performed in Canada, including the amount of upgrading performed by other producers.
Although Alberta is known to possess heavy oil and bitumen reserves in
excess of 300 billion bbls, higher costs and lower quality "has relegated
bitumen based feedstocks to the margin of the market," Lauermen said.
Downstream refiners must weigh the price paid for heavier feedstocks
against the proportions of products that can be extracted from particular
grades. For instance, a hydrocracked synthetic crude oil will yield higher
proportions of diesel and jet fuel than gasoline. "The value placed by the
refiner is critical to the producer," Lauerman said.
The dilemma, said Lauerman, is for producers to determine the degree
of upgrading suitable for the market. Generally, the study found that a higher
degree of upgrading will increase marketability of bitumen feedstocks.
Another wild card variable is the price of natural gas,
which is used extensively as a source of both fuel and hydrogen to upgrade oil.
Although the CERI study factored historical levels of gas prices into production
costs, Lauerman suggested a future economic yardstick for heavy oil viability
might be based on a differential of gas to WTI -- especially in light of
New York Mercantile Exchange
gas prices in excess of $7.50 (U.S.) per
mmBtu.
For the purposes of the study, CERI assumed pipeline specifications
would stay the same over the seven-year period. In addition, it never factored
in variables such as a carbon tax or tighter environmental regulations.
Despite reversal of Enbridge Inc.
's Line 9 in Eastern Canada, which
has backed 180,000 bbls per day of Western Canadian crude oil out of Ontario,
Lauerman said declining conventional production the U.S. is expected to open
up opportunities for heavy oil players in eastern markets over the next
several years.
The bulk of the displaced Line 9 oil is ending up in PADD II, which
includes Chicago and the U.S. Midwest. In 1998, PADD II refineries accounted
for a 54% market share for Western Canadian crudes. Lauerman noted most
refiners in this market are presently concerned with reformulated product
specifications.
Although demand for bitumen is expected to grow to an aggregate demand
of 555,000 bbls per day from 311,000 bbls per day in 1998, bitumen production
is expected to meet or exceed market requirements.
Likewise, markets for synthetic crude oil are expected to remain tight
through 2007. CERI estimated 806,000 bbls per day of potential synthetic
demand by 2007 compared to 356,000 bbls per day at present. Estimated
synthetic production in 2007 is expected to be about 725,000 bbls per day.
However, CERI's projections include demand for 150,000 bbls per day of
hydrocracked/aromatic saturated, a hypothetical higher grade of synthetic
crude that presently doesn't exist. Consequently, the study found "potential
demand for synthetic crude oil is not as promising relative to expected production unless price discounting or hydrocracked/aromatic saturated (is)
available."
Price sensitivities also play a large role in determining demand.
Synthetic crude captures about 25% of share in its main markets at a price
discount to WTI of $2 per bbl compared to less than 10% market share at a
price premium of $2 per bbl.
Likewise, heavy oil and bitumen based blends enjoy about 18% of share
in natural markets at a $2 per bbl discount compared to about two per cent at
a $2 per bbl premium.
Blending costs will also affect the competitiveness of various grades
of bitumen. The CERI study factored in diluent costs at an effective 10%
premium based on a five per cent cost bump at Edmonton going into the pipeline
and a five per cent discount at the end user. Lauerman admitted the 10% discount figure used in the study is low.
Athabasca bitumen blends contain about 33% diluent content compared to
about 28% for Cold Lake deasphalted blends. The effect is that while Cold Lake
bitumen receives less of a discount relative to light oil, it also receives a
lower net return based on coke versus crack spreads due to the lower value of
diluent recovered at the receiving end of the pipeline.
In the shorter term, Lauerman said he expects heavy oil
economics to improve with narrower light/heavy differentials. "In the shorter
term, differentials should tighten up as OPEC (Organization of Petroleum
Exporting Countries
) pulls bbls ... because most of those would be heavy."
Regional Demand For Bitumen-based Blends
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