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The Value of Unused Transmission: Estimating the Opportunity
Cost for the Province of Quebec, Canada
Pierre-Olivier Pineau, HEC Montréal, Canada
Vincent Lefebvre, HEC Montréal, Canada
Pierre-Olivier Pineau, Associate Professor, Department of Management Sciences
HEC Montréal
3000, chemin de la Côte-Sainte-Catherine, Montréal (QC) H3T 2A7 CANADA
+1 514 340-6922 / +1 514 340-5634 / [email protected]
Summary
Electricity planners and regulators often warn about the alleged underinvestment in electricity, especially in
transmission. Their analysis, however, often overlooks the actual use of transmission networks, and even more
of interregional lines. We looked at three years of hourly transmission data (2006, 2007 and 2008) between
Quebec and its main neighbours: New Brunswick, New England, New York and Ontario. We found that
although trade across these transmission lines increases, especially exports, much unused capacity remains
available. About 25 TWh could have been profitably exported from Quebec every year, taking into account both
the hourly unused capacity of lines and the hourly spot price in adjacent jurisdictions. This unrealized trade had a
huge opportunity cost for the Quebec utility, about Can$1 billion every year –or about 50% of its dividend.
While transmission upgrades may still be required for reliability purposes, this analysis shows that the lack of
transmission capacity is not preventing profitable electricity exports to take place. The problem is rather
regulation in low-cost electricity jurisdiction, limiting the amount of power available for export. Because there
are also many unrealized environmental benefits when the price of hydropower is regulated (as it is the case in
Quebec, but also all across North America and in many places around the world), the real cost of such regulation
is still unknown. This papers points to the need of further research into the economic and environmental gains to
be made from electricity market integration.
Keywords: Electricity integration; Interregional transmission; Opportunity Cost; Quebec; Northeastern United
States.
Introduction
Open access to transmission networks is considered by many to be the “foundation for wholesale electricity
market competition” (e.g. Benjamin, 2007). In the United States, the 1996 Federal Energy Regulatory
Commission (FERC) orders 888 and 889 are two landmarks of US electricity market reforms. The first provides
non-discriminatory access to transmission services, and the second establishes an Open Access Same-Time
Information System (OASIS), to foster use and transparency in transmission networks. However, despite the
importance of transmission, investment in transmission lines is considered by many to be lagging behind needs
and to require important additional investments in the future. The International Energy Agency (IEA), for
instance, estimated that 8% of all worldwide energy infrastructure investments during the period 2007-2030
should be made in transmission networks (IEA, 2008:151). This represents US$2,106 billion over 23 years, or
just about US$92 billion every year. In North America only, about US$15 billion should be invested every year,
according to the IEA, while between 2000 and 2005 only US$2 to 4 billion were invested in transmission (Hirsh,
2004:7). The state of the transmission network in North America is a concern according to Hirsh (2004), and this
conclusion is shared by the North American Electric Reliability Corporation (NERC). Indeed, the NERC
1
identifies the need for more transmission as one of its five “Key Findings” for the period 2008-2017 (NERC,
2008).1
The lack of transmission capacity is often criticized for wasting “many opportunities to lower consumer power
costs” (Hirsh, 2004:vi), by isolating cheaper power from demand (see also Hale et al., 2000). This could be
especially true for interregional transmission, because significant price differences exist between regions. For
instance, in January 2009, the US industrial electricity prices varied between 4.17¢/kWh (Idaho) and
19.56¢/kWh (Hawaii) (EIA, 2009:111). Even without reaching such extreme difference, important gaps exist
between contiguous states: for instance Oregon (4.71¢/kWh) and California (8.93¢/kWh, +90%) or West
Virginia (4.71¢/kWh) and Pennsylvania (6.81¢/kWh, +45%). Between the province of Quebec (Canada) and
New York (immediately South of Quebec), the industrial price jumps from 4.47¢/kWh to 15.16¢/kWh (+239%),
according to Hydro-Quebec (2008a:50).
Although price regulation and generation technology largely explain these price differences (lower prices usually
being found in price-regulated jurisdictions with cheaper generation), lack of transmission is still considered a
problem. Regulatory differences would even be part of the explanation of the under investment in transmission.
Indeed, Benjamin (2007:41) connects opposition to transmission investments to the fear of seeing cheap power
exported to higher-priced areas.
This paper’s objective is to two-fold. First, to bring some new evidence on the “alleged transmission
inadequacy” (as already characterized by Brennan, 2006), and second, to estimate the value of the unused
transmission capacity between Quebec and the adjacent jurisdictions with which it has active trading connections
(clockwise: New Brunswick, New England –Maine, New Hampshire, Vermont2– New York and Ontario). To
achieve the first objective, we analyze three years of exports and imports on the interregional transmission lines
connecting Quebec to its neighbours (2006, 2007 and 2008). Then, for the second objective, we estimate for
each hour of these three years how much transmission capacity was left unused when it would have been
financially profitable to export. Through these objectives, the paper’s contribution is to shed a different light on
the discussion about transmission investment and to try to bring the debate on the opportunity cost of not
optimizing electricity use, within the existing power network.
In the next section, we provide an overview of how transmission capacity is usually assessed. Section 2 presents
the context and data we use and explains the methodology. Results and discussion are presented in section 3.
Finally, a conclusion summarizes our key points and possible future questions of interest.
1. Assessing Transmission Capacity
A traditional approach to assess transmission capacity is to look at the “amount” of transmission and to compare
it to peak demand. Transmission, in this approach, is measured by the total length of transmission lines (NERC,
2008:15). Figure 1 provides an illustration of this approach, followed by Hirsh (2004:6) in his much cited Edison
Electric Institute report. The indicator, in miles of transmission lines per gigawatt (GW) of peak demand, is seen
declining since 1990 in the NERC region (comprising the US, Canada and some small parts of Mexico).
1
The four other “Key Findings 2008-2017” are the improvement of capacity margins, the significant projected increase in
wind capacity, the increasing role of demand response to meet resource adequacy requirements and the emphasis on
maintenance, tools and training to provide adequate power supply (NERC, 2008).
2
The other New England states (Massachusetts, Rhode Island, and Connecticut) are not considered because they do not
share a border with Quebec.
2
Figure 1. Miles of Transmission Lines (230 kV and above) per GW of Peak Demand (NERC, 2009)
600
500
400
300
200
100
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1995
1994
1993
1992
1991
1990
0
1996
Northeast Power Coordinating Council (NPCC) - Quebec only
NERC region
NPCC US - NY & New England
Figure 1 also shows that there are important differences between jurisdictions. Quebec, for instance, has much
more transmission lines per GW of peak demand than the NERC average, and even more than other Northeast
Power Coordinating Council (NPCC) members in the US.3 Although the decline in this indicator shows that
there is relatively less transmission relative to peak power demand, it says nothing on what the right amount of
transmission should be. Variations across jurisdictions can largely be explained by population density and the
remoteness of power plants, but no optimal value is known, even if these geographic elements are factored in.
This observed decline is a concern, because of possible increased congestions and additional strains on existing
resources (NERC, 2008:17). But while these reliability issues are important, the conclusion that “more
transmission is needed” may be precipitous. Brennan (2006) analyzes the transmission inadequacy question and
points that the decline may simply be explained by the end of vertical integration, which may have led to
overinvestment in this capital intensive sector. Now that this era has ended, with the unbundling and
liberalization of the power sector, we might simply return to a more normal state of less transmission. Also,
other approaches can be used to maintain reliability, such as advanced load management through a smarter grid.
What an analysis of the literature reveals, however, it is that assessing transmission capacity is a difficult task.
Not only access to the grid (for new power plants, such as wind generation) and reliability should be taken into
account, but also the economic value of transmission. This value is mostly influenced by energy prices at both
ends of lines, by the cost of reserve margins and by the value of outages. Including economic assessments is
therefore essential to assess transmission capacity, as Hirsh (2004:2), Brennan (2006:43) and Benjamin
(2007:42) point out, among others.
Such economic assessment is however only partially done, at best. This is one conclusion of Hirsh (2004:37),
from his review of 20 transmission plans across the US, which “roughly split in their focus on transmission
needed to maintain reliability vs. transmission needed to reduce congestion”. It is also illustrated by the fact that
3
The “NERC’s mission is to ensuring the reliability of the bulk power system in North America” (NERC, 2008:1). It does
so notably through eight regional entities, enforcing reliability rules in their region. The NPCC is one of these eight regional
entities. It includes Ontario, Quebec and the Maritimes in Canada and New York and New England in the US.
3
NERC named its key finding “More Transmission Needed to Maintain Bulk System Reliability and Integrate
New Generation” (NERC, 2008). No mention is made of the net economic gains to be made with new
transmission. This can be understood by the fact that NERC’s mission is to ensure reliability in the power
system, not economic efficiency (see footnote 2). Assessing transmission capacity is even more complex with
interregional lines, because approvals and permits have to be obtained from two regulatory bodies, wealth
transfers happen (through increased trade) and no single entity is fully responsible of integrated planning.
This paper does not provide a full economic assessment of transmission capacity, but an additional element to
assess it: the value of unused transmission. In other terms, it estimates the opportunity costs of selling power
within a jurisdiction (in this case, Quebec) rather than exporting it, while transmission capacity is available.
2. Data and Approach
2.1 The Quebec Power System and its Interconnections
Quebec accounts for 33% of Canada’s power generation capacity with 41,018 MW of installed power, out of
which 91% is hydropower.4 The provincial production was 192 terawatt-hours (TWh) in 2007, almost entirely
from hydro sources (94%), and mostly (90%, or 174 TWh) from the government-owned utility, Hydro-Quebec.5
The utility sells within the province at cost-based regulated prices: its average 2007 residential revenue was
6.90¢/kWh. As illustrated in Figure 2, Quebec is well interconnected with its neighbours and can actively trade
in New Brunswick, New England, New York and Ontario.6
In order to obtain the right to trade in the US wholesale market from the FERC, Hydro-Quebec had to offer
reciprocity in terms of access to its transmission network. A distinct subsidiary of Hydro-Quebec, HQ
TransEnergie, was therefore created in 1997 to operate the transmission network (HQ TransEnergie, 2009b).
Two other subsidiaries were also created for production and distribution. As an obligation imposed by the FERC
to market players active in the US, hourly transmission data have to be made available on the OASIS. Figure 2 is
taken from the website created to comply with this FERC regulation.
4
The source of the information provided in this paragraph is Statistics Canada (2009a).
In addition to its own provincial production, Hydro-Quebec receives a further 30 TWh every year from Newfoundland.
6
Although Hydro-Quebec is the dominant producer and electricity trader, other small players also trade in these regional
markets, such as Brookfield EMI, DC Energy, Powerex and Silverhill (NEB, 2009).
5
4
Figure 2. Quebec Path diagram with its Neighbours, 2009/03/12 10:22 EDT (HQ TransEnergie, 2009a)
As shown in Table 1, providing the voltage and capacity limits of interregional transmission lines, there is a
combined maximum export capacity of 7,130 MW and a maximum import capacity of 4,875 MW. It allows
Quebec to export up to 17% or import up to 12% of its production at any given moment, if there are no other
network constraint. These numbers can appear high, and may not reflect a fear to see cheap power fleeing to
higher cost jurisdictions (which adequately describe Quebec neighbours). Nevertheless, more transmission
capacity is claimed to be needed. A new transmission line to Ontario is scheduled to be available in 2009 (Table
1), and a project for a 1,200-1,400 MW transmission line, to New England, is examined (FERC, 2008).
Table 1. Quebec Interregional Transmission Lines (HQ TransEnergie, 2009a)
Capacity (MW)
Name
kV
Export
Import
Ontario
DYMO
OTTO
CHNO
P33C
Q4C
LAW
CORN
Announced for 2009 ON
DEN
MASS
New York
New England
New Brunswick
HIGH
DER
NE
NB
120
120
120
230
230
120
120
Total
230
120
765
Total
120
120
735
Total
230 & 315
85
0
65
345
0
800
325
1,620
1,250
325
1,800
2,125
225
80
2,000
2,305
1,080
0
110
0
0
140
470
100
820
1,250
100
1,000
1,100
170
0
2,000
2,170
785
Total
7,130
4,875
5
2.2 Methodology
Starting from hourly data, we analyze the aggregate use of transmission lines and estimate the opportunity cost
of unused transmission over the years 2006, 2007 and 2008. All transmission data come from HQ TransEnergie
(2009c). Hourly market prices for electricity come from the ISO New England (ISO NE, 2009), NY ISO
(NYISO, 2008) and the Ontario IEMO (IEMO, 2009). The following subsections provide additional details.
Use of interregional transmission lines
For each line listed in Table 1, the OASIS keeps track of how many MWh circulated on the line, for every hour
of the year. For a single hour, both some export and import quantities can be recorded, as the direction of trade
can change within an hour. For instance, in 2008 on the Massena (MASS) line between Quebec and New York,
electricity flowed out of Quebec unidirectionally during 4,783 hours, was imported to Quebec during 220 hours
and was both imported and exported during 3,114 hours. The line was left idle during 667 hours, for a total of
8,784 hours.7
To know how much transmission capacity remained unused, the difference between the total transit capacity of
the line (in MW during one hour, so in MWh) and its actual use (in MWh) can be computed. The “Total Transfer
Capability” (TTC) of lines, defined as “the amount of electric power that can be transferred over the
interconnected transmission network in a reliable manner while meeting all of a specific set of defined pre- and
post-contingency system conditions” (NERC, 1996:2), is reported according to NERC standards into OASIS
(NERC, 2005). TTC changes over time, from its maximum value (shown in Table 1) because of certain network
contingencies. This means that in practice, values of Table 1 are not always technically available, but lower
capacities are. In determining the unused portion of the transmission capacity, we used the listed TTC values, as
reported by HQ TransEnergie (2009c). Let’s note that an “Available Transfer Capability” (ATC) is also defined
by NERC. However, we could not directly use these values because HQ TransEnergie does not directly post the
ATC of its lines. It is probably exempted from this standard, as allowed in some cases (NERC, 2005:1).
When both export and import occurred during the same hour, the unused capacity estimate is the amount of
further possible exports (in MWh), given how much export and import already took place. We assume that listed
exports and imports were done at full capacity to compute the used capacity. For instance, if a line had a TTC of
1,000 MW during a specific hour, 1,000 MWh could transit through the line. If 100 MWh of export and
200 MWh of import were listed, we assumed that the export were done at full capacity (therefore over 6 minutes,
10% of an hour), that import were also done at full capacity (therefore over 12 minutes), so that the line
remained fully available during 42 minutes, allowing 700 MWh (1,000*42/60) to be exported. This latter value
is the unused transmission capacity of the line.
Opportunity cost
Hydro-Quebec sells every year 165 TWh of hydroelectricity at a regulated cost of Can$27.90/MWh to Quebec
consumers. As total energy requirements are above these 165 TWh, some power has to be produced or
purchased at higher, non-regulated price (by HQ Production, the generation subsidiary). However, the resale of
this power (by HQ Distribution, another subsidiary) is regulated and linked to the procurement cost. In 2007, HQ
Production sold 171.5 TWh in Quebec, and obtained an average revenue of Can$30.53/MWh. In contrast to this
average revenue, the 17.5 TWh sold by HQ Production outside its jurisdiction generated on average
Can$89.37/MWh. See Hydro-Quebec (2008b:9) for the source of the information provided in this paragraph.
This means that per MWh, the electricity sold outside the Quebec border in 2007 generated almost three times
the revenue of local sales. Production costs were however mostly similar, as electricity production is almost
entirely hydro-based. There is therefore an opportunity cost for Hydro-Quebec, when it sells within its
jurisdiction. The opportunity cost is the difference with the market price in neighbouring markets. Using the
hourly market price in New England, New York and Ontario, as defined in their respective spot market, this
opportunity cost can be computed. For the sake of simplicity, the opportunity cost is defined as the difference
7
2008 being a leap year, there are 366 days of 24 hours and hence 8,784 hours. A common year has 8,760 hours.
6
between the hourly spot market price (converted in Can$, at the daily exchange rate; Statistics Canada, 2009b)
and the Quebec energy only price of Can$30/MWh.8 Of course, this opportunity cost is only estimated up to the
unused transmission capacity defined previously.
For the case of New Brunswick, as there is no established spot market (the market is based on free bi-lateral
contracts, as in Texas), we use the New England spot price at the New Brunswick interconnection as a market
price proxy.
3. Results and discussion
3.1 Electricity Trade and Unused Capacity
During the study period (2006-2008), Quebec exported on average 1.46 TWh of electricity every month, and
imported 0.44 TWh/month. As Figure 3 shows, the US market (New York and New England) are the main
buyers of Quebec electricity. Less exports take place during Fall (especially September) and Spring months
(April and May), as weather conditions require less cooling and heating.
Figure 3. Monthly Exports, in TWh
1.40
New England
New York
1.20
Ontario
New Brunswick
1.00
0.80
0.60
0.40
0.20
Nov-08
Sep-08
Jul-08
May-08
Mar-08
Jan-08
Nov-07
Sep-07
Jul-07
May-07
Mar-07
Jan-07
Nov-06
Sep-06
Jul-06
May-06
Mar-06
Jan-06
0.00
As Figure 4 illustrates, imports are much less important than exports, especially imports from New Brunswick
and New England. From these four jurisdictions, Ontario represents the steadiest supplier of electricity for
Quebec, and the only jurisdiction from which Quebec imports more than it exports to (monthly average of 0.198
TWh of imports, compared to 0.09 TWh of exports). This is explained by both lower import and export prices in
Ontario (see Figure 7).
8
The rounded number of Can$30/MWh was used as an approximation of slightly different 2006, 2007 and 2008 average
revenue for Quebec sales.
7
Figure 4. Monthly Imports, in TWh
1.40
New England
New York
1.20
Ontario
New Brunswick
1.00
0.80
0.60
0.40
0.20
Nov-08
Sep-08
Jul-08
May-08
Mar-08
Jan-08
Nov-07
Sep-07
Jul-07
May-07
Mar-07
Jan-07
Nov-06
Sep-06
Jul-06
May-06
Mar-06
Jan-06
0.00
In terms of use of transmission lines, Table 2 presents some key results. First, many of the interconnections with
Ontario remain idle most of the time (more than 6,000 hours per year). This is not the case, however, of the main
Ontario line (LAW), which has seen its number of hours with no activity going down, the percentage of its TTC
actually used steadily growing, both when used for exports and imports.
For the South (New York and New England) and East (New Brunswick) connections, there are much less hours
without activity (less than 1,000 for most of them), and the use of the export capacity has been also steadily
growing over the three years. Imports from these jurisdictions, however, are becoming more marginal. It is
however a likely consequence of more exports, as these jurisdictions lack power.
Table 2. Use of Transmission Lines
Hours with no activity
Name
2006 2007 2008
% of TTC - Export
2006 2007 2008
DYMO
7459
7333
8460
17%
15%
OTTO
5361
2621
3384
..
..
CHNO
7337
6442
8141
11%
20%
P33C
7398
6273
6175
9%
15%
Ontario
Q4C
7326
2260
538
..
..
LAW
3566
3118
1699
8%
17%
CORN*
..
..
0
..
..
CRT**
1
18
0
31%
33%
DEN**
..
..
1321
..
..
New York
MASS
678
483
667
30%
41%
HIGH
573
887
701
75%
83%
DER
644
650
928
25%
24%
New England
NE
704
520
513
34%
47%
NB
2228
1679
423
5%
32%
New Brunswick
st
* This line entered in operation on October 1 , 2008
th
** The CRT line ended its operation on September 30 , 2008, and then DEN took over.
8
5%
..
5%
11%
..
37%
45%
29%
12%
47%
83%
35%
56%
43%
% of TTC - Import
2006 2007 2008
..
46%
..
..
58%
34%
..
..
..
28%
7%
..
4%
22%
..
69%
..
..
63%
37%
..
..
..
33%
13%
..
18%
8%
..
55%
..
..
61%
51%
..
..
30%
22%
3%
..
8%
2%
To better illustrate the usage pattern of these transmission lines, Figure 4 focuses on one line, the Quebec-New
York Massena line. It displays, by decreasing hourly export and import values, how much of the line is used
during each of the three years under review. We can clearly observe that export grew, with more capacity being
used, on average, every year (from 609 MW every exporting hour in 2006 to 767 MW in 2008). However, with a
maximum export capacity of 1,800 MW (which comes down, on average to about 1,600 MW in terms of TTC),
it becomes obvious that the transmission line is not used to its full capacity most of the time. It is indeed used at
less than 50% of its capacity, on average.
Figure 4. Transmission Load Duration Curve for the Quebec-New York Massena (MASS) line, in MW
2000
Average Hourly Export
2006: 609 MW
2007: 745 MW
2008: 767 MW
1500
1000
500
1
285
569
853
1137
1421
1705
1989
2273
2557
2841
3125
3409
3693
3977
4261
4545
4829
5113
5397
5681
5965
6249
6533
6817
7101
7385
7669
7953
8237
8521
0
-500
-1000
Export (2008)
Average Hourly Import
2006: 408 MW
2007: 395 MW
2008: 347 MW
-1500
Export (2007)
Export (2006)
Import (2006)
Import (2007)
Import (2008)
Figure 6 and Table 3 present the main results of this section: the amount of available transmission capacity, that
would have been profitable to use (because the export price was greater than the average Quebec price of
Can$30/MWh), but wasn’t. New England and New York lead in terms of monthly average: 0.748 TWh and
0.659 TWh could have been profitably exported from Quebec, every month, given the market price and
transmission availability. In Ontario and New Brunswick, only 0.46 and 0.41 TWh could have been exported.
The monthly total average is 2.28 TWh.
9
Figure 6. Monthly Unused Transmission Capacity (hours with market price above Can$30), in TWh
1.40
New England
New York
1.20
Ontario
New Brunswick
1.00
0.80
0.60
0.40
0.20
Nov-08
Sep-08
Jul-08
May-08
Mar-08
Jan-08
Nov-07
Sep-07
Jul-07
May-07
Mar-07
Jan-07
Nov-06
Sep-06
Jul-06
May-06
Mar-06
Jan-06
0.00
Table 3 summarizes key export, import and unused transmission results. Over the three years, if Quebec
exported 52.7 TWh (and imported 16 TWh), we see that it could have profitably exported an additional 82 TWh.
The distribution of this potential is relatively well distributed across the four markets: between 15 and 27 TWh
could have been exported in each of these markets over the three years.
Table 3. Quebec Exports, Imports and Unused Transmission Capacity, in TWh
2006
2007
2008
Export Total
2006
2007
2008
Import Total
2006
2007
2008
Unused Total
New Brunswick
New England
New York
Ontario
0.31
1.88
3.41
5.60
1.00
0.44
0.15
1.58
5.29
4.83
4.66
14.77
6.92
8.96
9.93
25.81
0.61
1.13
0.20
1.94
10.89
8.53
7.51
26.94
4.83
6.50
6.71
18.04
1.86
2.28
1.22
5.36
8.81
6.94
7.96
23.71
1.07
1.11
1.07
3.25
2.18
2.24
2.75
7.16
6.38
5.26
4.94
16.57
13.14
18.45
21.12
52.70
5.64
6.08
4.32
16.04
31.36
25.56
25.07
81.99
3.2 Electricity Trade: Value and Opportunity Cost
The trade that took place between Quebec and its neighbours was driven by sound economics. As Figure 7
shows, export prices are on average higher than import prices: they range between $50 and $100/MWh while
import prices mostly stay around $50/MWh. As mentioned before, it is Ontario that has the lowest average
import price, with $40.51/MWh and the lowest export price: $68.31/MWh. This is to compare against export
prices of $75.93 for New Brunswick9, $77.42 for New England and $68.73/MWh for New York.
9
Let’s however recall that the New Brunswick price is estimated with the New England-New Brunswick zonal price, which
means that is only a proxy market price.
10
Figure 7. Average Monthly Export and Import Prices, in Can$ per MWh
150
Export NB
Export NE
Export ON
Export NY
Import NB
Import NE
Import NY
Import ON
100
50
0
-50
-100
Nov-08
Sep-08
Jul-08
May-08
Mar-08
Jan-08
Nov-07
Sep-07
Jul-07
May-07
Mar-07
Jan-07
Nov-06
Sep-06
Jul-06
May-06
Mar-06
Jan-06
-150
Overall, as shown in Table 4, the market value of Quebec exports grew every year: from just about a billion
dollar to $1.5 billion. Imports stayed relatively stable, between $200 and $300 million. The opportunity cost of
not using the unused transmission lines was close to one billion every year –totalling $2.8 billion over the three
years. This is really an opportunity cost: it is the revenue above the Quebec sales price of Can$30/MWh that
could have been made in the export markets. The main markets are New England and New York, where most of
the transmission capacity is already in place (more than 50% of it connects Quebec to these markets).
Table 4. Market Value of Trade and Opportunity Cost, in Million of Can$
New Brunswick
2006
2007
2008
Total Export Value
2006
2007
2008
Total Import Value
2006
2007
2008
Total Opportunity Cost
22.94
126.44
292.27
441.65
56.10
21.64
8.58
86.32
202.85
177.58
216.69
597.12
New England
543.51
727.53
773.33
2,044.37
27.84
65.23
10.12
103.18
386.60
318.86
362.84
1,068.31
New York
352.72
435.94
447.68
1,236.34
95.76
136.93
61.06
293.75
276.58
212.25
300.85
789.68
Ontario
76.81
74.53
72.21
223.55
84.14
88.43
120.68
293.24
128.71
127.32
122.03
378.05
995.99
1,364.44
1,585.48
3,945.91
263.83
312.23
200.43
776.49
994.73
836.02
1,002.41
2,833.16
3.3 Discussion
Two main conclusions can be drawn from our results: (1) In the Northeast region, significant profitable trade
could technically be made –at least from the perspective of interregional transmission lines. (2) The opportunity
cost for Quebec is significant: about $1 billion per year, which is about half of the declared dividend for HydroQuebec in 2007, which was $2.095 billion (Hydro-Quebec, 2008b).
11
This missed economic benefit for Quebec does not take into account other benefits: increased supply of lower
cost energy in importing regions and environmental benefits obtained by substituting Quebec hydropower to
some of the thermal power of its neighbours.
Clearly, the main problem here is not the lack of interregional transmission capacity. The hourly transmission
and market price data show that a lot of profitable and feasible trading opportunities were left on the table. The
question, therefore, is why was the capacity left unused? Two hypotheses could be devised to explain this.
The first would be purely technical: some network constraints, beyond interregional transmission lines,
prevented the delivery of energy from generation to load. It is beyond the scope of this paper to explore this
hypothesis. However, given the fact that peak load in Quebec is during the winter (due to heating), while it is
during the summer in the US (due to air conditioning), and given the fact that interregional transmission lines
were designed with the knowledge of current power networks, there is no reason to believe that networks would
be internally constraints before interregional transmission lines are. At least, this is unlikely to explain entirely
all of the unused capacity.
The second is purely physical (but derives from a costly regulatory choice): there is not enough water in HydroQuebec’s dams to supply the additional yearly 25 TWh (see Table 3) that could be soaked into the regional
markets. Additional water could come from additional dams and further derivation of rivers, in such a way that
Quebec low prices are maintained and export opportunities are satisfied. This seems to be the path chosen by
Hydro-Quebec, with current hydropower developments (see Hydro-Quebec, 2009). Alternatively, better price
signals to Quebec consumers could be provided, making them pay a price closer to the regional market price.
Such a policy could mean to double the price of the energy component in the Quebec market (from the current
$30 to about $60/MWh). Given a price elasticity of -0.2 (a realistic short-term value, see Lijesen, 2007), this
would immediately “free” about 10 TWh from the local Quebec consumption. With more aggressive energy
efficiency programs, which would be much easier to implement under higher electricity price, an additional
4 TWh/year could be saved from the industrial sector (AEE, 2008a:20) and 8 TWh/year from the residential
sector (AEE, 2008b:19). This would provide another 12 TWh/year, available for export, before any analysis of
the institutional and commercial sector is made (which represents 18% of the Quebec electricity consumption of
192 TWh in 2006, see Statistics Canada, 2008:21). Finding 25 TWh, or at least a good share of it, from Quebec
consumers is therefore far from being unrealistic. Additional environmental benefits would also have to be taken
into account, as much of the additional hydropower export would substitute coal and natural-gas produced
electricity.
Conclusions
Complains and warning of underinvestment in the transmission network, and in interregional transmission lines
are frequent. The analysis behind such statements is however usually superficial, looking only at the length of
transmission networks, and comparing it with peak load demand. Economic analysis of transmission projects is
lacking, and so are detailed studies of the actual use of transmission lines.
This paper considered the case of interregional trade between Quebec and its neighbours (New Brunswick, New
England, New York and Ontario) over the years 2006, 2007 and 2008. The actual use of all transmission lines
was analyzed, and the value of the unused transmission capacity was estimated. Although all interregional
transmission lines were found to be increasingly used, some of them remain idle most of the time (more than
6,000 hours per year) and most of them are used, on average, at much less than 50% of their capacity. Given the
market price of electricity in Quebec and in the bordering jurisdictions, a lot of technically feasible, profitable
exports could take place. There is therefore an important opportunity cost, borne by Hydro-Quebec, which sells
within its market at a much lower price than the export price. These trade opportunities (totalling about 25 TWh
per year) would generate about $1 billion/year in additional profit for Hydro-Quebec (increasing by about 50%
its dividend).
This opportunity cost shows that price regulation in Quebec has a high cost, because it prevents the utility to sell
where the price is the highest. Further environmental benefit would be derived from such exports, as hydropower
12
(from Quebec) would mostly replace thermal power in the importing markets. Estimating the extent of the
environmental greenhouse gas reduction is a research area to explore.
Contrary to many claims in the literature, interregional transmission capacity is not lacking to the point of
limiting profitable trade. This is true for the Northeast American region, and would have to be studied in other
regional contexts. This does not mean that more transmission capacity is not needed for reliability purposes, but
simply that some significant amounts of transmission capacity remain unused. It also points that a major problem
for the power sector may not be transmission, but price regulation in jurisdictions with lower price. Although
consumers benefit from these low prices, the overall social cost is greater. Both economic and environmental
gains could be made by better integrating electricity markets.
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