S.A. Gabriel et al. r Energy Economics 22 2000 497]525 511
Table 1 Carbon emission factors in the electric utility sector
Fuel type Millions of tons of CO rTeraWatthour
2
Coal 1.20
Oil 0.83
Gas 0.40
for example, the total demand is given as follows:
q
nt s
Ž . TD
z dz TD
p
Ý
H
n t s n t si
n t si
o i
where TD , p
are, respectively, the total demand for gas in node n, time t,
n t si nt si
season s, in increment i, and the associated price for this increment; see Appendix Ž .
A for further details. The objection function in Eq. 2 is related to the objective Ž .
function for the standard total surplus maximization problem Eq. 1 by noting that Ž
the operating costs term OC includes the cost of supply production, peak-shav-
t s
. ing, and extra projects , approximating the producer surplus. In addition, the
operating costs term includes pipeline transportation costs, and storage operations costs. The investment costs term, IC , considers capacity expansion for pipelines,
t
electrical power plants, as well as storage reservoirs.
5. The carbon stabilization study results
Before modeling a case corresponding to carbon stabilization, it was first necessary to decide upon a method for estimating carbon emission levels. Given
that carbon emissions are directly proportional to fuel consumption, a carbon Ž
. Ž
emission factor Table 1 was determined for each fuel type with input from .
Natural Resources Canada . To evaluate the effect of Canadian carbon stabilization programs on gas exports
to the United States, we compared the outputs from GSAM using a base case and three carbon stabililization cases. In all cases, we made use of electricity produc-
tion figures supplied by NRCAN by various fuel types. These figures are shown in Table 2 below
7,8,9
.
7
NRCAN’s data were interpolated for 1993, but actual figures were made use of for the remaining years. For hydrorother power in 1993 and nuclear power for 1995, the model was allowed to deviate
somewhat from the NRCAN values due to avoid internal infeasibilities that were encountered.
8
GSAM’s downstream model used the following years in its integrating linear program: 1993, 1995, 2000, 2005, 2010
9
Note that for history matching purposes, the model starts in the year 1993.
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 512
Table 2 TeraWatthours of electricity production by fuel type
Fuel type 1993
1995 2000
2005 2010
Coal 83.5
83.4 71.0
79.7 88.4
Oil 11.8
8.2 5.6
8.3 10.9
Natural gas 12.7
16.3 24.4
31.7 38.9
Nuclear 81.4
92.3 100.2
98.8 97.3
Hydrorother 323.9
337.0 356.1
361.6 365.1
Total 513.4
537.2 557.3
579.0 600.6
5.1. The base and stabilization case assumptions Since the only differences between the base case and these stabilization cases
were the stabilization activities, we can attribute the change in the solution to the stabilization effects
10
. This difference is thus an estimate of the influence of these measures in Canada on the North American natural gas market. The various levels
of the CO emissions constraint, applied to the year 2010 for the Canadian
2
Electrical Power Generation Sector, are shown in Table 3. The nominal target Ž
. 115.12 short tons was based on the 1990 baseline figures from the Canadian
Ž .
Electricity Association CEA with 10 participating utilities. CEA represents 11 major utilities involved in the VCR program which constitutes over 95 of the
Ž total carbon emissions from fossil fuel fired generation in Canada Canadian
. Electricity Association, 1996 and hence their forecast can be considered appropri-
ate. Based on discussions with energy professionals at NRCAN and elsewhere in
Canada, the base case assumptions included:
v
Using coal electricity production values from Table 2 for 1993]2010.
v
Using nuclear, hydrorother, gas, and oil electricity production values from Table 2 for 1993 and 1995 only
7
, but allowing the model to select appropriate
Table 3 CO limits
2
CO limit Description
2
104.44 short tons Most restrictive stabilization case
115.12 short tons Nominal target stabilization case
126.90 short tons Least restrictive stabilization case
Ž .
99999.0 short tons No stabilization case base case
10
To keep the comparison appropriate, both the base case and stabilization cases were started from the same estimates of equilibrium gas prices.
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 513
Fig. 7. Electric generation sector in Canada } base case.
values for nuclear, hydrorother, gas, and oil to match total electricity production in the years 2000, 2005 and 2010.
Forcing the model to prohibit additional nuclear or hydrorother capacity from 1995 or later.
Not imposing a CO emissions constraint on Canada.
2
The carbon stabilization cases’ assumptions included: Using coal electricity production values from Table 2 for 1993]1995, but al-
lowing the model to select appropriate values for the years 2000, 2005 and 2010,
Using nuclear, hydrorother, gas and oil electricity production values from Table 2 for 1993 and 1995 only
7
, but allowing the model to select appropriate values for nuclear, hydrorother, gas and oil to match total electricity production in
the years 2000, 2005 and 2010, Forcing the model to prohibit additional nuclear or hydrorother capacity from
1995 or later, Ž
Imposing a CO emissions constraint on Canada in the year 2010 which varied
2
. by stabilization case .
5.2. Summary of results The carbon emissions and electrical demand levels for the Canadian electrical
power sector under the most restrictive stabilization cases as well as the base case are shown in Figs. 7 and 8. While the base case shows an increase in both
electricity demand as well as carbon emissions, the most restrictive stabilization case shows for the same electricity demand levels, an abrupt decline in carbon
emission in 2010.
11
11
The only difference between the most restrictive stabilization case and the other stabilization cases is the steepness of the decline of emissions from 2005 to 2010.
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 514
Fig. 8. Electric generation sector in Canada } most restrictive case.
One particularly interesting result from this study was that the CO limits
2
imposed can have a significant impact on the regional results. In particular, eastern Canada, where there was a dramatic increase in demand for gas, was the most
Ž .
sensitive to the three stabilization limits imposed as compared with the base case . Other regions showed less variation in the results as a function of different CO
2
caps. This points to the need to carefully estimate the stabilization limits due to their strong but regionally disparate influence.
The imposition of carbon stabilization programs in the electrical power genera- tion sector of Canada in 2010 resulted in a major shifting of fuels used in this
sector. As can be seen in Fig. 9, under the base case, the use of coal does not Ž
12
. change dramatically from 1995 to 2010 83.4 ]88.4 BkWh whereas the use of gas
increases substantially from 16.3 to 86.0 BkWh. The most restrictive stabilization
Fig. 9. Electricity demand in Canada by fuel type } base case.
12
1 Bkwh represents 1 billion kilowatt hours and is the same as 1 terawatthour; these two terms are used interchangeably in this paper.
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 515
Fig. 10. Electricity demand in Canada by fuel type } most restrictive case.
case showed much more dramatic results, namely coal use dropped from 83.4]40.5 BkWh whereas gas increased significantly from 16.3 to 135.5 BkWh as shown in
Fig. 10. In terms of carbon emissions produced in the Canadian electrical power sector,
as shown in Figs. 11]13, the contribution of coal diminishes somewhat between Ž
. 1995 and 2010 88]74 even under the base case. However, this decline is greatly
accelerated under the most restrictive case showing a dramatic shifting towards gas and away from coal due to the lower emissions factor for gas. Note that oil does
not play a significant role in this analysis. Fig. 11 shows the share of carbon emissions in 1995 for the fossil fuels considered. These shares are the same for
Fig. 11. Source of carbon emissions in the electric generation sector in Canada base casermost restrictive stabilization case, 1995.
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 516
Fig. 12. Source of carbon emissions in the electric generation sector in Canada base case, 2010.
both the base and the most restrictive carbon stabilization case. In contrast, in the year 2010, the share for coal drops significantly and the share
for gas rises significantly due to carbon stabilization efforts that induce fuel switching as shown in Figs. 12 and 13.
The imposition of the CO emissions constraint in 2010 for the Canadian regions
2
in GSAM resulted in a major shifting of the fuels in Canada used to produce electricity. These adjustments led to dramatic changes in imports and exports of
gas between Canada and the United States and resulted, in some cases, in significantly elevated prices of natural gas in demand markets. As shown in Fig. 14,
we see that in 2010, under the most restrictive stabilization case, Canada on the whole dramatically increased its imports from and cut back its exports to the US.
In comparing the most restrictive stabilization case vs. the base case, we see that
Fig. 13. Source of carbon emissions in the electric generation sector in Canada most restrictive stabilization case, 2010.
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 517
Fig. 14. Net effects of carbon stabilization programs in Canada on national flows in 2010: most restrictive stabilization case } base case.
432
13
Billion Cubic Feet more gas is in Canada. For the nominal and least restrictive cases, the net imports of gas from the US compared with the base case
were, respectively, 334 and 211 BCF. It is interesting to note that while the CO
2
Ž .
limit increased by only approximately 22 126.90 short tonsr104.44 short tons , a Ž
significantly greater need for gas in Canada resulted, namely, a 105 jump 432 .
BCFr211 BCF in net imports from the US. The shifting CO limits caused some dramatic changes in the pipeline flows as
2
might be expected. In particular, as shown in Fig. 15, as this limit became tighter Ž
. lower , more of the flow between the aggregated regions was directed towards
eastern Canada, the major demand market for increased levels of gas in order to comply with stabilization.
Ž .
The increased demand for gas in eastern Canada and neighboring US regions resulted, under the most extreme stabilization, in some sizeable gas price increases
in the US electric power sector. In particular, the largest increases in the US regional gas prices for 2010 were registered by the South Atlantic, New England
and Middle Atlantic regions with increases of 0.20, 0.16 and 0.15, respectively. These price increases were matched by decreases in quantities demanded in these
regions by 0.0, 6.5 and 28.4 BCF, respectively. The increased demand for gas in Canada also produced higher electric power sector prices for gas in Eastern
Canada of about 0.62rMCF. The increased prices for combined GSAM demand regions are shown in Table 4 under the three stabilization cases. In addition, the
increase in prices in the aggregated regions shown above were coupled with changes in demand quantities are also shown in Table 4. Again, it is eastern
Canada that is most sensitive to the stabilization limit.
13
This figure of 432 is the increased levels of exports from the US to Canada less the decrease Ž
. imports from Canada to the US, i.e. 200 y y232 .
S.A. Gabriel et al. r Energy Economics 22 2000 497]525 518
Fig. 15. Net effects of carbon stabilization programs in Canada on pipeline flows, 2010 } most restrictive case.
6. Conclusions
