NORTH AMERICAN OIL SANDS: HISTORY OF DEVELOPMENT, PROSPECTS FOR THE FUTURE - Energy Research Developments: Tidal Energy, Energy Efficiency and Solar Energy - page 301

using the CSS recovery technique, supply costs are estimated higher at between C$20-
$24/barrel, an increase from C$13-$19/barrel. Cost increases/decreases for in-situ operations
are largely dependent on the quality of the reservoir and natural gas prices, but as SAGD and
other new technologies (e.g. VAPEX) become more efficient, industry is expecting some cost
declines. SAGD (in-situ) supply costs are less sensitive to capital costs than mining projects
because the capital investment is far less.
Natural gas is a major input and cost for mining, upgrading, and in situ recovery: Mining
requires natural gas to generate heat for the hot water extraction process, upgraders need it for
heat and steam, and in situ producers use natural gas to produce steam which is injected
underground to induce the flow of bitumen. Natural gas accounts for 15% of the operating
costs in mining operations compared to 60% of operating costs in SAGD in-situ production.
The major cost for thermal in-situ projects (SAGD, CSS) is for the natural gas that powers the
steam-producing generators. For SAGD projects, 1 thousand cubic feet is needed per barrel of
bitumen. Reducing the steam-to-oil ratio (SOR) — the quantity of steam needed per barrel of
oil produced — is critical for lowering natural gas use and costs.[50] SAGD has a lower SOR
than CSS projects but cannot be used for all oil sand in-situ production. However, most new
in-situ projects will use SAGD.
Canadian oil sand producers continue to evaluate energy options that could reduce or
replace the need for natural gas. Those options include, among other things, the use of
gasification technology, cogeneration, coal, and nuclear power.

Table 3. Estimated Operating and Supply Cost by Recovery Type
(C$2005 Per Barrel at the Plant Gate)

Crude Type Operating Cost Supply Cost

Cold Production - Wabasca, Seal Bitumen 6-9 14-18

Cold Heavy Oil Production and
Sand (CHOPS) - Cold Lake

Bitumen 8-10 16-19

Cyclic Stream Stimulation (CSS) Bitumen 10-14 20-24

Steam Assisted Gravity Drainage
(SAGD)

Bitumen 10-14 18-22

Mining/Extraction Bitumen 9-12 18-20
Integrated Mining/Upgrading SCO 18-22 36-40
Source : Canada's Oil Sands, Opportunities and Challenges to 2015, National Energy Board, Canada, June
2006.
Note : Supply costs for the first five technologies do not include the coat of upgrading bitumen to SCO.

Tax and Royalty on Oil Sands
In 1997 the Alberta government implemented a “Generic Oil Sands Royalty Regime”[51]
specific to oil sands for all new investments or expansions of current projects. Since then, oil
sand producers have had to pay a 1% minimum royalty based on gross revenue until all
capital costs including a rate of return are recovered. After that, the royalty is either 25% of
net project revenues or 1% of the gross revenues, whichever is greater.[52] The 1% prepayout
royalty rate is in stark contrast to conventional world royalties. Net project revenues
(essentially net profits before tax) include revenues after project cash costs, such as operating
costs, capital, and R&D are deducted. Royalty payments may be based on the value of
bitumen or SCO if the project includes an upgrader. Currently, 51% of oil sand projects (or