Environmental Engineering Reference
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75% of production volume) under the Generic Royalty regime are paying the 25% royalty
rate. Two major oil sands producers, Suncor and Syncrude (accounting for 49% of bitumen
production) have “Crown Agreements” in place with the province that have allowed the firms
to pay royalties based on the value of synthetic crude oil (SCO) production with the option to
switch to paying royalties on the value of bitumen beginning as early as 2009. Royalties paid
on bitumen, which is valued much lower than SCO, would result in less revenue for the
government. The agreements expire in 2016.
Royalty revenues from oil sands fluctuated widely between 1997 and 2005. For example,
royalties from oil sands were less than $100 million in 1999, then rose to $700 million in
2000/2001, but fell in 2002/2003 to about $200 million as production continued to rise.
Royalties from oil sands rose dramatically in 2005/2006 to $1 billion, and the Government of
Alberta forecasts royalties of $2.5 billion in 2006/2007 and $1.8 billion in 2007/2008.[53] Oil
price fluctuations are the primary cause for such swings in royalty revenues.
The Albertan provincial government established a Royalty Review Panel in February
2007 to examine whether Alberta was receiving its fair share of royalty revenues from the
energy sector and to make recommendations if changes are needed. In its September 2007
report, the panel concluded that “Albertans do not receive their fair share from energy
development.”[54] When the oil sands industry was ranked against other heavy oil and
offshore producers such as Norway, Venezuela, Angola, United Kingdom, and the U.S. Gulf
of Mexico, Alberta received the smallest government share.[55] This is, however, a difficult
comparison to make because it is not among oil sand producers only and the fiscal regimes of
the various producing countries is dynamic. However, based on a general analysis by T.D.
Securities, typically, on average, world royalty rates could add as much as 45% to operating
costs while the 1% rate may add only 3% to operating costs.[56]
The Panel recommended keeping the “pre-payout, post-payout” framework intact (see
footnote 52), which would retain the 1% pre-payout royalty rate, but in the post-payout phase,
firms would be required to pay a higher net revenue royalty rate of 33% plus continue to pay
the 1% base royalty.
On October 25, 2007, the Alberta Government announced and published its response to
the Royalty Review Panel's report.[57] It retained the “pre-payout,” “postpayout” royalty
framework but concluded that a sliding-scale rate structure would best achieve increasing the
government's share of revenues from oil sands production. The pre-payout base rate would
start at 1%, then increase for every dollar above US$55 per barrel (using the West Texas
Intermediate or WTI price) reaching a maximum increase of 9% when prices are at or above
$120 per barrel. In the post-payout phase, the net revenue rate will start at 25%, then rise for
every dollar oil in priced above US$55 per barrel, reaching a maximum of 40% of net
revenues when oil is $120 per barrel or higher. The new rate structure will take effect in 2009.
The Government of Alberta has initiated negotiations with Suncor and Syncrude in an attempt
to include them under the new oil sands royalty framework by 2009.
Oil sand firms pay federal and provincial income taxes and some differences exist in the
tax treatment of the oil sands and conventional oil industries. Since the Provincial 1996
Income Tax Act, both mineable and in-situ oil sand deposits are classified as a mineral
resource for Capital Cost Allowance (CCA) purposes which means mineral deposits receive
higher cost deductions than conventional oil and gas operations (i.e. acquisition costs and
intangible drilling costs).[58] The provincial government of Alberta has agreed to the 2007
federal budget proposal to eliminate the CCA deduction for oil sands. The Royalty Review
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