Règie de l'énergie
Modalités d'établissement et d'implantation des tarifs de fourniture
No: R- 3398 - 98
Evidence of Michael Margolick, Ph.D.
Prepared for
L'association québécoise des consommateurs industriels d'électricité (AQCIE)
May 5 1998
AQCIE-2
1. INTRODUCTION
1
2. CANADIAN HYDRO UTILITIES AND ELECTRICITY MARKET REFORM
2
2.1. Similar physical characteristics
3
2.2. Similar policy environments
5
3. PRINCIPAL PRICING MODELS
9
3.1. Full competition
9
3.2. Performance-based regulation (PBR)
12
3.3. Allocated cost of service
15
3.4. Unbundled costs versus unbundled tariffs
18
3.5. Characteristics of market-sensitive pricing
20
4. EXAMPLES OF MARKET-SENSITIVE SUPPLY RATES
23
5. THE HYDRO- QUÉBEC PROPOSAL
27
6. CONCLUSIONS
30
-1-
1
1.
Introduction
2
This first hearing by the Régie of Hydro-Québec may set important precedents for
3
electricity regulation in Québec for many years. The focus of the hearing is the principles
4
and methods to be used in determining the rate for supply of electricity by Hydro-Québec.
5
"Supply" in this context means the provision of electricity, but not its transmission or
6
distribution.
7
At present, Hydro-Québec has a retail monopoly for approximately 97% of electricity
8
sales in the Province. It also has a wholesale transmission tariff to which the remaining
9
3% of load has access. Under this structure, the proposed rates would therefore apply to
10
offers of sale from Hydro-Québec to, and only to this small proportion of customers. All
11
others would continue to be served by Hydro-Québec at bundled retail rates for
12
generation, transmission and, where applicable, distribution. While retail tariffs are not
13
under review in this proceeding, the results may nevertheless be significant for the
14
majority of customers for two reasons:
15
 for setting definitions and precedents for future retail rate design; and
16
 information for investment planning through an Integrated Resource Planning process.
17
This report has been prepared by Dr. Michael Margolick at the request of L'association
18
québécoise des consommateurs industriels d'électricité (AQCIE). It covers four areas:
19
1. A review of Hydro-Québec's position within the context of electricity industry reform
20
in North America, and in relation to other utilities with common characteristics,
21
specifically BC Hydro and Manitoba Hydro
22
23
2. A discussion of basic options for setting the supply rate, including price-based
regulation, cost-based regulation and open competition
24
3. A critical analysis of Hydro-Québec's proposal
25
4. General conclusions and advice to the Régie concerning principles to be applied in
26
determining the supply rate.
-21
This report attempts to abstract the most important features of existing policies and
2
emerging market environments and to suggest rate structure ideas are compatible with
3
both.
4
These ideas are fully consistent with, and support the government's policy concerning
5
rates under the mandate of the Régie:
6
"Pour le gouvernement, les tarifs autorisés pour la vente de gaz naturel et
7
d'électricitié doivent tout à la fois refléter les coûts, respecter la capacité de payer
8
de la clientèle, avoir des effets équitables et être simples dans leur définition. Ces
9
principes ont plusieurs implications: il faut que les tarifs du gaz naturel et de
10
l'électricité se rapprochent le plus possible du coût de desservir chaque catégorie
11
de consommateur. Bien que le niveau des tarifs soit basé sur les coûts moyens, les
12
tarifs devraient ainsi évoluer vers une meilleure intégration des coûts marginaux,
13
les tarifs de base traduisant plus directement la valeur de l'énergie
14
consommée….La Régie ne devrait pas hésiter à intégrer, dans ses pratiques de
15
régulation, des mécanismes incitant les fournisseurs d'énergie à améliorer leur
16
performance."1 (emphasis added).
17
This is understood to mean that rates should recover average, or embedded costs in total,
18
but should also evolve towards reflecting marginal costs. Specifically, these marginal cost
19
elements should be reflected in the prices paid by customers.
20
2.
21
The three "Hydros" of Québec, Manitoba and BC share characteristics that provide them
22
with distinctive challenges and opportunities within the context of electricity restructuring
23
in North America. A description of these characteristics provides useful context for the
24
pricing discussion that follows. Some of the characteristics are inherent in the physical
25
systems themselves, while others are government policy. Government policies include
26
long-standing policies and those arising more recently from restructuring.
1
Canadian hydro utilities and electricity market reform
L'Energie au service du Québec, 1996, p.25
-32.1.
1
Similar physical characteristics
2
3
First, generation is based almost entirely on hydroelectric plants. By contrast, in Canada,
4
all other provinces, except Newfoundland, are primarily nuclear and/or
5
thermally-sourced. In the US, by State, only Idaho, Oregon and Washington have
6
comparable concentrations of hydropower2 and this resource lies largely within the
7
domain of the Bonneville Power Administration, an agency with substantial nuclear
8
liabilities, if not operations.3
9
Second, the concentration of generation capacity in individual plants or river systems is
10
also high: Approximately 80% of total energy generation by BC Hydro is on the Peace
11
and Columbia Rivers4; in Manitoba approximately 80% of hydro generation capacity lies
12
on the Nelson River5, and the collectivity of the La Grande, Manic-Outardes and
13
Churchill systems in Québec also supplies approximately 85% of the generation of
14
Hydro-Québec.6
15
Third, the utilities have transmission links to neighbouring utilities and are part of a
16
continental electricity market that is undergoing reform. Export transmission capacity, as
17
a proportion of generation capacity, varies among the three utilities. Manitoba's
18
transmission export capacity is over 50% of the utility's generation capacity7, while the
19
corresponding number for BC is approximately one third and Québec is more constrained
2
Idaho at 100%, Oregon: 93%, Washington: 88%, South Dakota: 79%. Next is Montana with 53% Data are
for 1996. http://www.eia.doe.gov/cneaf/electricity/epm/epmt11.dat [US Dept. of Energy, Energy
Information Administration]
3
BPA is mostly hydro-based, but in 1995 approximately 25% of its costs related to debt service, operations
and mothballing costs on nuclear plants [Source: Clearing Up, Mar 6, 1995, #663 p. 5]. The three Canadian
hydro utilities discused here are not so encumbered.
4
Making the Connection: the BC Hydro Electric System and How it is Operated; BC Hydro;1993, p. 3:
5
A Powerful Future: Manitoba and the Evolving Power Industry; April 1997 Manitoba Hydro, Fig. 2.2
6
Ouverture des marchés de l'électricité au Québec; Options, impératifs d'une réelle concurrence et
conséquences pour les prix; Centre Hélios, Montréal, octobre 1997; note 67
7
A Powerful Future: Manitoba and the Evolving Power Industry; April 1997 Manitoba Hydro; p. 9
-41
(about 18%)8. Current export revenues derive from assets that cost very little to operate
2
and are therefore quite profitable. The profitability of future hydroelectric development
3
for the export market is not as clear, as the cost of construction of the facilities, rather
4
than only their operation, would have to be taken into account.
5
Amounts exported depend on streamflow, domestic load and market conditions. In 1995,
6
for example, Manitoba Hydro exported about 40% of its total energy sold, while the
7
corresponding figures for BC and Québec were approximately 8% and 15%,
8
respectively.9 Hydro-Québec sold 17.7 TwH on the export market in 1996, which is
9
about the same as the average for the 1993-96 time period.10 The value of these export
10
sales in 1996 was $601 million, a significant amount of money by any standard.11
11
Fourth, their reservoirs can be used to store energy for later sale. This is a valuable
12
capability that is not available in the primarily thermal and nuclear systems with which
13
Hydro-Québec, in particular, trades. BC Hydro has good multi-year storage in Williston
14
and Mica reservoirs. A 10-year average of total system monthly energy storage ranges
15
from 10 to 25 TwH, which is 20 - 50% of annual sales.12 Hydro-Québec also has very
16
substantial storage and multi-year capability. Manitoba's Lake Winnipeg has good
17
seasonal, but not multi-year storage.
18
19
20
8
If Hydro-Québec generation capacity is 31,000 MW [http://www.hydroquebec.com/en/deco.html] and
export capacity is 5515 MW [Strategic Plan 1998, p. 35] the ratio is 18%.
9
A Powerful Future: Manitoba and the Evolving Power Industry; April 1997 Manitoba Hydro, Fig. 2.10
10
Hydro-Québec has built a solid reputation for quality and reliability in the Northeastern U.S. (Hydro's
Web Page); Exports of 14.1, 18.0, 23.5, and 17.7 TwH are shown for 1993 - 1996.
11
An attractive market (Hydro's Web Page); " Just last year, Hydro-Québec sold electricity outside Québec
worth $601 million"
12
BC Hydro Annual Report, 1996, p. 4.
-52.2.
1
Similar policy environments
2
3
The three utilities are under three different governments. However, the governments share
4
important policy directions in response to the challenges and opportunities raised by
5
liberalization of the generation market in North America.
6
No privatization
7
First, all utilities are state-owned and no jurisdiction is considering privatization. For
8
example, the proposal of Hydro-Québec states:
9
"La politique du gouvernement du Québec à ce sujet est très clair: il n'est
10
aucunement question pour le moment, de privatisation, partielle ou totale,
11
d'Hydro-Québec…" (p.4)
12
Wholesale transmission rates
13
Second, all three governments have formally implemented wholesale transmission rates.
14
The implementation of these rates has been primarily to secure access to US markets
15
under wholesale reciprocity conditions imposed by FERC and/or Regional Transmission
16
Groups (RTGs). BC Hydro and Hydro-Québec have FERC-approved "market-based rate
17
authority" required for access to wholesale buyers beyond the US border. Manitoba is
18
considering applying for market-based rate authority.13
19
Near-monopolies for retail sales
20
Third, the three utilities have near-monopolies for retail electricity sales in their
21
respective provinces. BC Hydro has about 94% of GwH sales; Hydro-Québec: 97%; and
22
Manitoba Hydro effectively has 100% share of retail sales.14 End-users not served by the
13
It may not yet have applied, either because it feels satisfactory deals can be made at the border, and/or
because it has some unexpired long term firm contracts.
14
Although Winnipeg is a distinct distributor in Manitoba, its rates are required by the City of Winnipeg Act
to be the same as those of Manitoba Hydro. In addition, Winnipeg Hydro's costs are determined through a
cost-sharing agreement with Manitoba Hydro. It may be formally possible for Winnipeg to access the
existing wholesale transmission tariff of Manitoba Hydro, but true competitive conditions for supply to
Winnipeg cannot be said to exist under the current structure.
-61
utility are typically large industrial facilities with independent water rights, such as Alcan,
2
or small municipalities that remain separate for historic reasons.
3
There does not appear to be government interest in greater domestic wholesale
4
competition. There is no apparent government interest in either creating additional
5
wholesale buyers (through the offer of sale of distribution assets to municipalities or
6
others), nor in breaking up the existing generation systems into competing entities to
7
serve domestic wholesale markets competitively.
8
Government policies with respect to retail access are as follows:
9
 In Manitoba, Sec. 15.2 of the 1997 Manitoba Hydro Amendment Act restricts retail
10
11
supply to Manitoba Hydro and the City of Winnipeg.
 In BC, the January 1998 Report of the Electricity Market Reform Task Force did
12
recommend phased-in retail access for industrial customers (half of industrial load in
13
Phase 1, the remainder in Phase 2), after the 1995 BC Utilities Commission's
14
Electricity Market Structure Review, rejected it "at this time". 15 However the Task
15
Force report was not based on consensus, or even general agreement of the
16
participating stakeholders, and the government appears to prefer providing industrial
17
concession rates to providing customer access to multiple suppliers.
18
 In Québec, paragraph 3 of Article 167 of the Act (Bill 50) assigns responsibility for
19
advising the Québec government on market liberalization to the Régie, "within the
20
time determined by the Government". To date no such process has been initiated.
21
Hydro-Québec also "does not intend to promote the opening of the Province's retail
22
electricity market".16
23
If neither retail nor expanded wholesale competition are to be placed into effect, then, for
24
almost all retail customers, prices will continue to be set by provincial regulators and/or
25
governments.
15
Reforming British Columbia's Electricity Market: A Way Forward, January 1998; and The British
Columbia Electricity Market Review, September 1995, BC Utilities Commission, p. xi.
16
Strategic Plan 1998 - 2002, p. 11
-71
Domestic rates at embedded cost
2
Fourth, revenues from tariffed sales are approximately equal to average, or embedded
3
costs – return on rate base, operating expenses and interest payments. Utility rates and
4
costs have been reviewed by regulators in BC and Manitoba. Hydro-Québec stated in
5
1993:
6
"Costs of supply include all expenses required to meet the electricity requirements
7
of a given market or rate category. For customers in Québec, these expenses
8
reflect the average cost of new and existing facilities. For the export market, the
9
rates reflect anticipated costs for new facilities. Export costs are therefore
10
established first, in order to exclude them from Québec market costs"17 (emphasis
11
added)
12
Contributions to government
13
Fifth, each utility also pays dividends, or contributions to government that arise largely
14
from the profitability of exports. The dividends are not necessarily equal to export
15
earnings, either by policy or in practice. However, all else equal, increases in export
16
earnings increase the overall profitability of the enterprises and therefore the dividends
17
that can be paid in any given year.
18
Industrial concession rates
19
Sixth, BC Hydro and Hydro-Québec have adopted concession rates for industrial
20
customers – either to attract them to set up operations or to keep jobs when they might
21
otherwise close or move due to market conditions.18
22
Québec has, for some time, offered shared-risk and special contracts. In BC, a strong
23
orientation to concession pricing for industry has recently emerged:
24
 The Economic Development Electricity Rate Act (1996) overrides the BC Utilities
25
Commission Act in providing the Lieutenant Governor in Council with the power to
17
18
Long-Term Rate Orientations, Development Plan 1993, Proposal p. 41.
Manitoba has the lowest industrial electricity rates in North America and less than a half-dozen large
industrial customers.
-81
specify quantities to be made available at a lower rate than the regulated rate for new
2
plant construction or expansion.
3
 The Power for Jobs Development Act, passed in 1997, makes available electricity,
4
including that being returned to the Province under the Columbia River Treaty,
5
available to businesses using more than 35 kW at a "development power rate" for the
6
purposes of creating new jobs and maintaining existing jobs. This Act also overrides
7
the ratemaking authority of the BC Utilities Commission. Phase I of Power for Jobs
8
offers 200 MW of power to new investors. Existing industries in distress may also
9
apply for discount prices. In both cases the prices will be set by the government on a
10
11
case-by-case basis.
 B.C. Hydro's real-time pricing (RTP) rate, discussed below, is in part a concession
12
(load retention) rate, arising from the terms of its provisions for reduction in
13
Customer-Based Load.
14
Concession rates are to be distinguished in concept from market-sensitive rates discussed
15
below. Market-sensitive rates may benefit the province, but the benefit arises from more
16
efficient use of equipment and hydro generation rather than from a specific policy to
17
attract or keep industrial activity.
18
The remainder of the paper works toward the development of supply pricing options in a
19
"Hydro" system that:
20
 meet basic regulatory and policy requirements, specifically recover average costs in
21
total but provide price signals relating to marginal costs
22
 reflect characteristics of the competitive market, and
23
 exploit the advantages of hydroelectric power
24
Development of such supply pricing options would be fully consistent with the
25
government's policy as stated in the introduction.
26
First, it is necessary to consider different basic supply price models. The three considered
27
are deregulation, performance-based ratmaking (PBR), including regulation on the basis
28
of price, and cost of service regulation. Next, we explain the distinction betwen
-91
unbundling costs versus unbundling tariffs. Then we describe characteristics of
2
market-sensitive pricing. The most important of these are the concept of "electricity" as a
3
commodity, as opposed to distinct generation energy and generation capacity, and the
4
high time-variance of prices for electricity. Examples of market-sensitive pricing in BC,
5
Québec and Manitoba are then briefly described. Then we critique the proposal of
6
Hydro-Québec, given the perspectives developed here. This is followed by general
7
conclusions.
8
3.
9
Principal pricing models
3.1.
Full competition
10
The principal markets with which Hydro-Québec trades are becoming increasingly
11
competitive, and any pricing model used in Québec must take this into account. In
12
general, competition reduces commodity prices because it reduces costs of production.
13
Electricity is no exception, and on average across North America, the price of generation
14
is expected to go down. However, in a perfectly competitive market, all producers
15
receive, and can only receive, a price equal to the marginal cost of production (the
16
"one-price" law). Producers whose average cost is below the marginal cost of production
17
will therefore see an increase in price and in profitability when the market moves from
18
(average-cost-based) regulation to competition.
19
"Moving from regulated cost of service pricing to competitive pricing does not, in
20
and of itself guarantee that prices will fall for everyone. In general, if marginal
21
costs are lower than the historical average embedded costs (or increased
22
competitive pressures leads to falling production costs), as is the case in most
23
parts of the U.S. market today, prices will fall with increasing competition. For
24
example, in many areas, the combination of low-cost new generating technologies
25
and low fossil fuel prices has made power from new plants less expensive than
26
power from some older plants or from old power supply contracts. On the other
27
hand, the operating and capital-related costs for some existing power plants and
28
utilities are very low, and absent other cost saving induced by competition, their
- 10 1
prices could rise in a competitive market. Thus regions of the country that are
2
largely dependent on older, low-cost plants may see higher end-use electricity
3
prices when the prices are set by the marginal, rather than average, cost of
4
generation."19 (emphasis added)
5
Although prices in the East Coast market with which Hydro-Québec trades are falling, the
6
current average cost of production in Québec is expected to continue to be below
7
competitive generation prices in the external market.20 Therefore, if it were given a
8
competitive pricing mandate and if it were fully integrated with the much larger East
9
Coast market, Québec's prices would approximate those in the East Coast market, which
10
are expected to be higher than today's rates.
11
However, there are two important factors that act together to complicate matters:
12
generation market power and transmission constraints (also called transmission market
13
power). The existence of transmission constraints indicates, in particular, that Québec is
14
not fully integrated within the larger East Coast market. The combined effects of
15
generation market power and transmission market power on prices under competition in
16
Québec are now discussed.
17
Generation market power is the ability of suppliers to control prices or discriminate
18
among customers at will. It exists when a large enough market share belongs to a small
19
enough number of suppliers. If one were to consider Québec as a physically isolated
20
market, Hydro-Québec would have generation market power due to its overwhelming
21
share of the generation market. Attempts to control market power by creating competing
22
generation systems in Québec would be unlikely to be reasonable or successful.21 Buyers
19
Electricity Pricing in a Competitive Environment: Marginal Cost Pricing of Generation Services and
Financial Status of Electric Utilities; August 1997, Energy Information Administration, US Department of
Energy, p. 2-2.
20
For example, the report Electricity Pricing in a Competitive Environment: Marginal Cost Pricing of
Generation Services and Financial Status of Electric Utilities; (August 1997, Energy Information
Administration, US Department of Energy) shows estimated prices based primarily on short run marginal
costs for different regions in the U.S.
21
First, there are only a small number of hydroelectric plants in total. Second, a competitive market
requires that suppliers are able to independently set their volumes and prices offered for sale. Generators
sharing a single river system cannot do so because their water supplies cannot be set independent of each
other. Therefore disaggregation of the generation market would be further limited to distinct river systems.
- 11 1
would be captive to the dominant player(s) who could raise prices greatly, even above
2
East Coast market prices. This represents the "classic" case of monopoly power.
3
Alternatively, if there were no transmission constraints on imported electricity, competing
4
suppliers from the larger market outside the province could control potential generation
5
market power in Québec, as there would be no constraint on access by them to buyers
6
within the province. Hydro-Québec would have to compete for customers. It could not
7
command a price above the market price.
8
The reality is between these two extremes of near-absolute generation market power and
9
no generation market power. The existence of a very large constraint on import of
10
electricity – i.e. near-isolation of the market – would mean that the hydro generators
11
would continue to have domestic market power because domestic buyers' purchase
12
options would be limited to supply from within the province once further imports were
13
not physically available. With nowhere else to turn, buyers would continue to be captive
14
and prices could be forced above the market price, as in the monopoly case.
15
For these reasons, introduction of unrestricted competition in Québec would not make
16
economic sense. The conditions necessary for unrestricted competition to be efficient do
17
not exist.
18
The benefit of hydro costs below competitive prices is described as an "entitlement",
19
"endowment" or "acquis tarifaire". The entitlement is an inherent property of the hydro
20
dams. Setting rates at average cost allocates the entitlement to domestic customers. If,
21
alternatively prices were at competitive levels, the entitlement would belong to the
22
shareholder, rather than the customers. The entitlement can only be eliminated if
23
competitive prices go down, for example through the development of new generation
24
technologies, or if average costs of the hydro systems go up, for example through
25
uneconomic investment.
26
If the "Hydro" provinces do not implement fully competitive generation market
27
structures, prices of power for sale inside the provinces, whether to retail customers or to
Finally transmission system load/generation balancing requirements further restrict the autonomy of dam
operation decisions.
- 12 1
the limited number of wholesale buyers, will necessarily continue to be regulated, or
2
controlled by governments. Below, the two principal models for regulation -- PBR and
3
Cost of Service -- are discussed.
4
5
3.2.
6
Performance-based regulation (PBR)
7
8
PBR was originally designed to reduce problems of over-capitalization and "managerial
9
slack"22 connected with cost-of-service regulation. PBR seeks to improve utility
10
efficiency by reducing profit where expenditure is not strictly required to provide service.
11
This may be achieved by extending the time between rate cases, (or equivalently, by
12
freezing rates), or by employing external measures of cost for the purposes of setting
13
rates. The latter case includes price caps and revenue caps. Price caps generally tie rate
14
increases to inflation, less a factor to account for productivity improvements ("CPI minus
15
X"). Revenue caps set a total revenue requirement in terms of specified revenue growth
16
allowances, which typically reflect growth in the customer base as well as productivity
17
gains. Revenue caps set revenue requirements in total, not rates.
18
A full discussion of PBR is beyond the scope of this report. PBR has been in existence for
19
many years and has strengths and weaknesses. Some specific concerns with its use in the
20
case of Québec are raised below.
21
However, there is one completely general issue regarding PBR in this, the initial stages of
22
regulation. Price and revenue caps pertain to growth rates applied to base year rates or
23
revenue requirements. The regulator may conclude that the growth rates are fair and
24
reasonable, but could not conclude that the proposed prices are fair and reasonable unless
25
it had also determined that the prices or revenues to which the increases apply were also
26
fair and reasonable. At this stage, the regulator has made no determination as to whether
22
Also called "X-inefficiency".
- 13 1
the existing rates, especially the L-rate upon which Hydro-Québec's proposal is based, is
2
fair and reasonable.
3
The purpose of this proceeding may be to recommend methodologies as opposed to
4
numerical values. However, the above logic applies to both numerical values and
5
methodologies. In the latter case, the Régie could at most conditionally conclude that a
6
price/revenue cap methodology would produce a fair and reasonable outcome. The
7
conclusion would be subject to acceptance of the (un-reviewed) hypothesis that the
8
methodology used to generate the L-rate is also fair and reasonable. However,
9
Hydro-Québec appears to argue that the Régie should not independently investigate the
10
latter assumption at this stage.23
11
In any case, PBR has the following difficulties and complexities in Hydro-Québec's case:
12
1. Hydro-Québec is subject to wide and uncontrollable revenue and cost variations due to
13
streamflow variation and interest rates, respectively.24 Within PBR, these
14
uncontrollable events are typically taken care of by exogenous (so-called "Z-term")
15
changes to the cap formula. In Hydro-Québec's case they may be substantial enough to
16
render the "CPI - X" part of a price cap formula, or a revenue growth allowance of
17
relatively little effect. The intent of the (retail) price freeze is to isolate customers from
18
these effects, but the risk could easily fall onto customers after the freeze is removed,
19
for example through the use of additional borrowings during the freeze.
20
2. The reservoirs and generators themselves represent, by and large, fixed costs. The
21
controllable costs of generation service lie in relatively minor areas such as
22
maintenance and operation. The productivity gains available under the PBR incentive
23
would be small, compared to thermal systems with a higher proportion of controllable
24
generation costs.
23
Response to Régie Information Request #1 Question 1. The response appears to suggest that the Régie
need not concern itself with either numbers or methodology and Hydro-Québec offers no evidence to
suppport either.
24
The Strategic Plan also shows other uncontrollable risks in exchange rates, temperature and the price of
aluminum (p. 51).
- 14 1
3. A price freeze is not a price cap. In a hydro system with on-going debt amortization,
2
permanent reservoirs whose energy capability does not depreciate, few operating costs,
3
and no price risk relating to exhaustible fuels, the rates needed to recover embedded
4
costs could go down over time. The shareholder would then make profits in excess of a
5
reasonable return simply by staying at the cap.25
6
4. PBR requires an initial revenue requirement, based on the cost of service, from which
7
caps may be defined. As indicated above, this has yet to take place in a regulated
8
setting.
9
It should be noted that the Hydro-Québec proposal is not a price cap. For example, there
10
is no productivity factor brought forward (or defence of an implicit value of zero), no
11
proposed period until the next review and no regulator-approved cost base from which to
12
begin the growth-capping process. Hydro-Québec agrees that its proposal is not a price
25
Recent events in BC provide a cautionary story. The government capped the residential rates of BC
Hydro in 1996, through the Tax and Consumer Rate Freeze Act. Despite the use of the word "freeze" in its
title, nowhere in that Act does it state that rates must not go down. BC Hydro had a very profitable year in
1997/98, based on strong exports. However, Special Direction 8 to the BC Utilities Commission limits BC
Hydro's rate of return on equity. On November 18, 1998, the industrial customers applied to the BC Utilities
Commission for a rate reduction of 7.5%, based on a preliminary reading of financial results and in
accordance with the Commission's powers to enforce the Special Direction. The residential customers filed
for a rate review at the same time. Then, on November 25, the government amended Special Direction 8 to
the BCUC, including, among others a provision that:
"The Commission must determine any matter respecting B.C. Hydro in a manner that permits B.C.
Hydro to undertake any construction, enter into any contract or modify its rates in a manner that
complies with any government policy directive."
On March 5, 1998, the residential customers commenced a court challenge to the amendment, arguing that
it abrogated the statutory power of the Commission. The industrial customers and an association of
environmental interests subsequently joined the challenge. Then, on March 13, the government re-amended
the Special Direction, removing the above paragraph, among other changes. Finally, on March 27, it
announced the British Columbia Hydro and Power Authority Rate Freeze and Profit Sharing Act, which
states that
"the rates and schedules that were in effect on December 10, 1997 and that are prescribed by the
regulations are the only lawful, enforceable and collectable rates that the British Columbia Hydro
and Power Authority may collect, charge or enforce from December 10, 1997 to March 31, 2000
for the services to which those rates apply".
December 10, 1997 is one day before the Commission made Hydro's existing rates interim as part of the rate
review process. In effect, the government appropriated the surplus revenue through legislation, converting a
cap to a freeze, and, it would seem, after realizing that it might not have been successful through direction to
the regulator.
- 15 1
cap in the conventional sense. Furthermore it agrees that the starting point for price caps
2
is cost of service.
3
"La seule
4
de type “price cap” est que dans les deux cas, on retrouve une réglementation par
5
le prix et que ce prix est fixe pour une certaine période de temps. Mais
6
Hydro-Québec n'a jamais prétendu que sa proposition correspondait à un “price
7
cap” comme ceux que l'on retrouve typiquement dans la réglementation.
8
Généralement, le point de départ d'un “price cap” est le coût de service. Ensuite,
9
un “price cap” est généralement associé à divers paramètres tels un facteur de
association qu'Hydro-Québec fait entre sa proposition et une approche
10
productivité, le taux d'inflation et des variables exogènes. On ne retrouve aucun
11
de ces paramètres dans la proposition d'Hydro-Québec."26
12
In sum, PBR is not the logical place to start in the context of this, the first regulatory
13
examination of supply rates. That process should focus initially on costs as a basis for
14
determining how much the utility should collect from tariff customers. Once revenue
15
requirements are set, they may be allocated to customer classes and rates evaluated on the
16
basis of revenue collection in relation to costs of service. PBR is also unlikely to be the
17
appropriate means of regulating the supply price in the future, for the first three reasons
18
discussed above.
3.3.
19
Allocated cost of service
20
As indicated above, any initial quantitative recommendations or decisions on rates should
21
be based on costs. In particular, if the energy supply price is to have economic meaning, it
22
must be based on costs to Hydro-Québec as a whole, or Québec as whole, and not internal
23
transfer prices as proposed. Even if the Régie wishes to consider a rate proposal that is
24
not based on costs, it is difficult to see how it could make judgements about the proposal's
25
effectiveness or fairness unless it had the appropriate cost information.
26
It is assumed here that "effective" means that retail rates recover, in total, the embedded
27
costs of generation, transmission and distribution prudently used to serve tariff customers,
26
Response to AQCIE Information Request 18 a)
- 16 1
i.e. a revenue requirement based on total embedded costs. Rates must then be designed
2
and the revenue under each rate estimated. Collectively the rates should collect an amount
3
equal to the given revenue requirement. Determination of the fairness of the rates among
4
tariff classes would then be based on:
5
1. An allocation of embedded costs among the tariff classes, and
6
2. A comparison, for each tariff class, of revenue earned under the proposed tariffs with
7
the allocated costs of that class.
8
Fully-Allocated Cost of Service (FACOS) is a standard methodology for allocating
9
embedded costs. FACOS contains the following elements:
10
11
12
13
14
15
16
17
 Identification: define the costs to be included and categorize them by rate base and
expense items;
 Functionalization: categorize rate base and expense items into generation,
transmission, distribution and other;
 Classification: Split the functionalized costs into "demand", "energy" and "customer"
service parameters;
 Allocation: Allocate the functionalized and classified costs to the different rate
classes.
18
This methodology could be adopted by the Régie, as is. It is used in regulatory
19
proceedings in BC and Manitoba. However, the Régie may also wish to re-think the
20
classification step to be consistent with concepts emerging from electricity industry
21
reforms. Traditional integrated utility planning considers "energy" and "capacity" (or its
22
billed analogue, "demand") as two distinct delivered products. These are jointly provided
23
by a single system that includes generation, transmission and distribution. This in turn
24
requires that functionalized costs be split into components corresponding to energy and
25
capacity. In some cases, this is straightforward: 100% of transmission capital cost
26
assigned to demand or 100% of fuel cost to energy, for example. However, allocating
27
hydro generation to demand versus energy is less straightforward. Various conventions
- 17 1
have arisen, but, since they are divisions of common, sunk costs of assets that provide
2
both energy and capacity, classification is somewhat arbitrary.27
3
However, it may not be necessary to make those judgements. The requirement to classify
4
generation into demand and energy could be reconsidered, given the development of
5
electricity markets and utility de-integration. This would be consistent with
6
Hydro-Québec's view:
7
"L'ouverture des marchés et la concurrence qu'elle entraine nécessitent également
8
que le mode de réglementation de la production retenu pour le Québec soit adapté
9
à ce contexte et qu'il soit équitable par rapport à ce qui est exigé de la
10
concurrence" (Proposal p. 1)
11
A market-sensitive approach would consider electricity generation the way the market
12
does: as a single commodity measured in kwh. Generators produce the electricity
13
commodity while transmission and distribution systems simply deliver it, losing some
14
along the way. Wholesale buyers or customers purchase the commodity from electricity
15
suppliers and independently rent capacity on the wires needed to deliver it to them. Using
16
this model in a regulated context, generation costs would not need to be split into energy
17
and capacity components, nor would generation energy costs and generation capacity
18
costs need to be separately allocated across customer classes.28 Put another way
19
generation costs would be recovered through sales of kwh of electricity, not sales of the
20
capacity that allows kwh to be produced, in the same sense that there is no market in
21
which vegetable growers (electricity producers) sell rights to use their greenhouses and
22
tractors (production capacity) to grocery shoppers (electricity buyers). Allocation of
27
Hydro-Québec's response to AQCIE Information Request 39e) describes several methods. For example,
the BC Hydro 1991/92 FACOS study classifies 100% of powerhouses, power equipment and switchgear to
demand, and splits dam and reservoir facilities 27/73 between demand/energy. The overall split is 55/45
demand/energy. The 1995/96 and 1996/97 FACOS use 50/50 splits. Several other methods have been used
in past studies.
28
Some portion of "pure" generation capacity costs may appear in the market as an ancillary service (e.g.
generation reserves that can be bid into an ancillary services market). But in the competitive commodity
market, a traditional (generation) capacity contract would be viewed in terms of a contract for the (future)
right to buy kwh – an option contract for the commodity – and not the firm purchase of capacity.
- 18 1
generation costs to different rate classes would then be on the basis of energy
2
consumption, plus losses.
3
The market value of a kwh of supply is different from the embedded unit cost of
4
electricity supply. Therefore pricing all generation at market value would not produce the
5
same result as assigning 100% of embedded generation costs to energy in a FACOS
6
process. Nevertheless it would be desirable to reflect properties of the market price in the
7
supply rate. The market price represents an opportunity value of electricity to
8
Hydro-Québec. Consideration of market price characteristics in domestic supply rates
9
would support the development of economically efficient price signals to domestic
10
customers, assisting Hydro-Québec to realize the greatest value from its operations.
11
Important characteristics of market prices and some options for rate design based on them
12
are discussed below.
3.4.
13
Unbundled costs versus unbundled tariffs
14
15
Once costs are split into electricity supply versus electricity transmssion and distribution,
16
tariffs can be split into components that reflect the costs of electricity supply separately
17
from the costs of transmitting and distributing it. It is not sufficient for these purposes to
18
simply have separate billing demand and energy charges within the tariff.
19
For example, the current L-rate structure charges separately for billing demand
20
(corresponding to capacity) and for energy consumed, but the proposed supply price (2.5
21
cents/kwh) does not appear in the tariff.29 It is also not clear, on the basis of the proposal,
22
whether or not any, or what portion of allocated generation capacity cost (if indeed it is
23
allocated) is included in the demand charge. In short, the tariff does not necessarily show
24
prices "PE" for electricity supply and "PT" for transmission such that the bill is the sum of
25
consumption of electricity at price PE and transmission at price PT. Customers may wish
29
For example, the energy charge is 2.38 cents/kwh (or 2.42 if the 1.6% general rate increase figure is
applied [see Annexe D]). If the customer increases electricity consumption by 1 kwh, but does not increase
billing demand, it pays 2.38 or 2.42 cents more, whereas the proposed rate would indicate that the cost of
supply increased by 2.5 cents.
- 19 1
to see these prices, which reflect costs of distinct enterprises within the context of vertical
2
de-integration of utilities. Hydro-Québec agrees that the current L-rate is a bundled tariff.
3
"Comme tous les tarifs d'Hydro-Québec, le tarif L est un tarif intégré qui ne
4
distingue pas le prix de la production du prix du transport." (proposal p.20)
5
It is important to note that tariff unbundling has financial consequences for customers and
6
is not simply the provision of additional information. Individual customers' bills may
7
change under tariff unbundling. Assuming that rates recover embedded costs for the given
8
rate class, total revenue collected from the rate class would not change. However some
9
customers' bills would go up, while others' bills would go down.30
10
Customers would require tariff unbundling in preparation for a competitive electricity
11
supply market. However, if competition is not an option, they may still wish to see
12
separate prices for electricity supply and transmission. Tariff unbundling would also help
13
simplify the development of market-sensitive rates because market-sensitivity applies
14
only to the electricity supply portion of costs.
15
In its proposal, Hydro-Québec argues that tariff unbundling would engender confusion
16
among customers.31 Most or all large customers are able to pay for expertise in
17
understanding and controlling electricity bills. Even a 5 MW load will pay approximately
18
$1 million per year for delivered electricity. In any case, most L-rate customers belong to
19
industries that now have ten or more years of experience in separately contracting for gas
20
commodity (with competing producers) and gas delivery (with competing shippers). It is
21
difficult to imagine this would be less complex than choosing consumption levels in
22
electricity commodity and electricity delivery from a single supplier.
23
30
For example, in the case of rate L, unbundling could preserve the rate structure as a "demand"
[transmission] charge in $/kw-month and "energy" [electricity supply] charge in cents/kwh. However it
could shift the proportions of a fixed total revenue requirement for the L-class between amounts recovered
for energy/electricity supply versus demand/transmission. This would increase the average bills of some
customers and reduce it for others, depending on load factor.
31
See AQCIE Information Request 35 b) and f), and responses.
- 20 3.5.
1
Characteristics of market-sensitive pricing
2
3
The most significant characteristic of the market price is its variation over time. As
4
generation comes on the market in the U.S., the variance of prices over time has
5
increased, both daily and seasonally. The variance reflects variations in operating costs of
6
marginal, mostly thermal plant as the specific type of plant at the margin varies with
7
demand.
8
While price variability is characteristic of spot markets and power pools generally, many
9
buyers will enter into contracts that do not vary with the spot price, such as options and
10
contracts for differences. Nevertheless, it is expected that the market as a whole will
11
continue to show short term price variations significantly greater than prior to the
12
introduction of competition.
13
In view of its storage capability, Hydro-Québec may pay special attention to these
14
variations in market prices because it can use its unique (for the East Coast market)
15
storage capability to optimally time export sales. Estimating volumes and prices for these
16
opportunities may be complex. Variables to be taken into account may include
17
streamflow conditions, line loadings and forward price curves in the export market.
18
Congestion pricing for transmission constraints within the US may also need to be
19
considered.
20
Hydro-Québec might also use time-varying prices to reduce its own costs.
21
Hydro-Québec's own demand "spikes" on cold winter nights, possibly requiring
22
expensive purchases or thermal generation.32 In the long run, time-sensitive pricing could
23
be an option for reducing new generation capacity investments. At any given time,
24
therefore, the opportunity cost of electricity may be an export price, a domestic system
25
operating cost, or a domestic system investment cost.33
" .. For example, costs incurred during peak periods (winter)… will be higher because this period
requires the use of costly thermal power plants and additional hydroelectric capacity" (Long-Term Rate
Orientations, Development Plan, 1993, p.41).
32
33
Time-sensitive pricing can also defer transmission and distribution investment and is therefore a potential
tool within transmission and distribution planning.
- 21 1
Incorporation of the resulting time profile(s) of opportunity cost would then be reflected
2
in prices offered to domestic customers, subject to the constraint that total revenue
3
collected from each customer class approximate that class' allocated costs. Consideration
4
of the types of customers to whom such rates would be appropriate should take into
5
account the costs of metering and accumulating billing information at the required time
6
intervals and the customers' own flexibility in responding to price signals.
7
Time sensitive rates include traditional utility rates such as seasonal and time-of-day
8
rates. The development of a competitive market provides an opportunity for a greater
9
variety of price signals and perhaps greater customer interest in rate options. Competitive
10
electricity markets (outside of, as well as in the US) are also pushing the technology
11
frontier, perhaps making market-sensitive rates more acceptable and effective.
12
"In the long term, new technologies are likely to play a key role in determining the
13
level of consumer response to changing prices. Faced with more volatile prices,
14
equipment vendors will develop, and consumers will seek to purchase, equipment
15
that allows for better control of electricity use. For example, intelligent electricity
16
meters, which monitor the electricity use of a household or business minute by
17
minute are already entering the marketplace. Combining this equipment with a
18
real-time pricing signal and the ability to control key appliances or equipment may
19
enable consumers to reduce electricity usage during high cost periods. Many
20
residential customers participating in demand-side management programs are
21
already familiar with the boxes connected to their hot water heaters and/or air
22
conditioners that allow local utilities to shut them off during periods of high
23
demand. Similarly, some commercial establishments have cool storage systems
24
that make ice during low cost periods and then use it for space cooling when price
25
srae higher. Such systems may become more prevalent where competitive
26
electricity prices and time-of-use rates are implemented."34
34
Electricity Pricing in a Competitive Environment: Marginal Cost Pricing of Generation Services and
Financial Status of Electric Utilities; August 1997, Energy Information Administration, US Department of
Energy, p. 2-3.
- 22 1
Examples of market-sensitive rates in Québec, BC and Manitoba are described below.
2
These are provided to illustrate potential options, in terms of tariff structure, time interval
3
(e.g. hourly spot price versus seasonal interruption) and customers eligible. Most of the
4
effort has been applied to large customers. However, small customers can also supply
5
price-responsiveness. In New Zealand, for example, retail suppliers rely on ripple
6
control35 of hot water heaters to provide load reductions that are then bid into the
7
quarter-hourly reserve market. One major retailer there is studying how to aggregate
8
different load reductions to create biddable demand-side "packages"36
9
Market-sensitive pricing and load factor adjustment
10
In a competitive market, load factor is irrelevant because capacity is not a traded
11
commodity. Any two purchasers buying at the same time pay the same amount per kwh,
12
after adjusting for line losses. The average price, per kwh, is the sum of the prices paid at
13
different times multiplied by the amounts bought at those times, divided by total
14
consumption.37
15
In a competitive market, low load factor (residential and small commercial) customers
16
would generally pay a higher average annual price per kwh than high load factor
17
customers because low load factor customers' energy consumption tends to be greatest
18
when demand, and therefore prices, are high. Conversely a flat (time-undifferentiated)
19
load would pay less than the average because, relative to the average of all customers, its
20
use is concentrated less on expensive (peak) times.
21
Time-sensitive pricing is a more finely-tuned instrument than load factor adjustment. For
22
example, if a particular customer were on time-sensitive pricing, and could self-generate
23
at some expensive times, or shift purchased consumption from expensive times to less
24
expensive times, its bill could go down even though its load factor might not increase.
35
Remote operation through signals over power lines
36
S. Terry, Simon Terry & Associates, Wellington, NZ, pers. comm.
37
If one bought 5 kwh at 3 cents/kwh and 2 kwh at 6 cents/kwh, the average cost would be
[5 x 3 + 2 x 6]/[5 + 2] = 3.86 cents/kwh
- 23 1
Differences between low- and high load factor customer costs also arise in the
2
transmission and distribution system. These would be determined through cost allocation
3
of transmission and distribution, which is independent of electricity supply cost.
4
5
4.
Examples of market-sensitive supply rates
6
7
The theoretically best market sensitive rate would simply be an hourly spot market price,
8
scaled appropriately so that revenue equals embedded cost. However, this type of
9
volatility is unlikely to be attractive to most customers, and is not necessary for efficiency
10
objectives. An efficient rate design can still lead to total bills that do not vary too greatly,
11
while providing price signals that affect consumption at the margin. For example, a fixed
12
amount of load may be supplied at a standard tariff, with the increment subject to
13
market-sensitivity. Rate design should also identify the most probable types of beneficial
14
customer responses and adjust the frequency of price change accordingly – e.g. a seasonal
15
rate versus light/heavy load hours versus opportunistic pricing, such as interruptible
16
service or demand-side bidding. Market sensitive rates are more likely to be approved if
17
they are optional. This also reflects the market's characteristic of providing customers
18
with a range of choices.
19
Market sensitive rate options include:
20
1. Interruptible, seasonal and time of day rates
21
2. Real-time tariffs, generally taken to be a two-part rate in which incremental
22
consumption is billed at a market price or market-sensitive price.
23
3. Demand-side bidding, in which the buyer may offer to reduce load for a short time in
24
return for a payment from the supplier. The supplier can then sell the electricity in the
25
market. The supplier's price offers may be regularly posted
26
27
4. Long term wholesale contracts for energy from the major hydro plants. This option has
greater scope. It essentially transfers a fixed block of energy, representing most, or all
- 24 1
of the output (under specified streamflow conitions) of the large hydro assets providing
2
the entitlement, to transmission owners/distributors at embedded cost, while leaving
3
the remainder of generation (say the "top" 10 - 20%) to be sold fully competitively.
4
5
Examples at Hydro-Québec, BC Hydro and Manitoba Hydro
6
The rate structures of Canada's "Hydro" utilities presently contain many different
7
components that cause the average prices paid by customers to be different at different
8
times, such as inclining block rates for customers whose loads vary seasonally and excess
9
demand charges that vary by season. By way of illustration, some industrial/large
10
customer rates are described below.
11
BC has been experimenting with alternative industrial rates since the early 1990's when
12
BC Hydro produced an Industrial Rate Proposal. The tariff was brought forward at a time
13
of apparent tight supply. The rate was a two-part tariff, designed to collect embedded cost
14
in total, but such that customers would pay the long run marginal cost for approximately
15
half their consumption (the second "block" of the tariff).38 The proposal was theoretically
16
sound, but it was administratively complex and required predictions about long run
17
supply costs, which were seen as quite uncertain. The tariff was not well-received by
18
customers. In addition to its complexity and uncertainty, they were concerned about it
19
becoming mandatory and felt they were being "pushed" into self-generation. The proposal
20
was eventually rejected by the BC Utilities Commission.39
21
After a number of attempts to find satisfactory designs during the intervening years, BC
22
Hydro Tariff 1848 (Real time pricing) or RTP was approved in July 1997. It is an optional
23
rate for large industrial customers. It provides a pass-through of the Mid-Columbia price
24
index (split by heavy/light load hours) on consumption that is incremental to a
38
The proposal would produce a rate such that average revenue paid varies seasonally because the potential
self-generation capability of some major customers (pulp mills) varies seasonally. See e.g. Optimal
Electricity Generation in Pulp and Paper Mills with Seasonal Steam Requirements; Helliwell, J.F. and M.
Margolick; Global Economics: Essays in Honour of Lawrence Klein; B. Hickman, ed. MIT Press, 1984.
39
Decision, April 24, 1992
- 25 1
pre-determined Customer-Based Load (CBL). CBL is charged at the standard industrial
2
rate. No transmission charge is applied to the Mid-Columbia price.
3
The default CBL is the average of the past three years' consumption. In this case, market
4
prices are available only to "new" load. However, the RTP tariff provides for reductions
5
in CBL for load retention purposes, under approval by the BC Utilities Commission.
6
Since its inception, approximately 18 customers have utilized the rate. The
7
Mid-Columbia price (which excludes transmission in BC) was, until recently, below the
8
standard rate (which includes generation and transmission within BC), making it
9
advantageous, independent of any value of time-sensitivity. However, recently the
10
Mid-Columbia price has gone up, eliminating most of the benefit of lower average price.
11
The majority of sales under the tariff have been as a result of reductions in CBL for load
12
retention purposes and it has generally been considered by observers to be a load retention
13
rate. 40
14
More recently, the government announced "virtual access" for load at each facility of an
15
industrial customer.41 The rate will provide a pass-through of a market price, to which a
16
rate for transmission in BC will be added, for up to 25% of total (not incremental) load.
17
The details are now being worked out.
18
The BC experience has not been successful in terms of utility/customer/government
19
relations. It suggests that it is essential to distinguish, in policy, between rate options for
20
load retention or economic development purposes versus rate options for
21
market-sensitive, optimal resource use. The following distinction might be useful: if the
22
rate reduces the customer's bill below what it would otherwise be, for a fixed level of
23
consumption and a fixed time-profile of consumption, the rate would be for load retention
24
or economic development purposes. A "pure", market-sensitive rate, in the sense used
25
here, would reduce bills when, and only when customers change consumption or its time
"The Industrial Customers stated that Rate Schedule 1848 [RTP]… will only be attractive to customers
whose CBL [Customer-Based Load] has been adjusted downward for load retention purposes….
Accordingly they characterized Rate Schedule 1848 as being primarily a load retention rate." BC Utilities
Commission; Industrial Service Options Application; Decision, July 16, 1996, p. 8.
40
41
Ministry of Employment and Investment, March 27, 1998, Press Release and Backgrounder
- 26 1
profile, relative to consumption or time-profile that would occur under the rate otherwise
2
in effect.
3
Among other offerings, Manitoba Hydro has had, since 1991, market-sensitive
4
interruptible rate programs, targeted to different customer groups.42 The rates are
5
designed to make energy available to Hydro for alternative sales for weeks, up to several
6
months, on a seasonal basis. The Dual Fuel Heating program applies to up to 100% of
7
new commercial/institutional heating loads. These must have long term alternative
8
supply, such as oil or propane. Typical eligible customers include agricultural enterprises,
9
schools and the Town of Churchill. The two-year-old Surplus Energy Service to
10
Self-Generators rate applies to those who can supply their own generation to defer supply
11
from Hydro on a longer term basis. It currently has no subscribers. Typical eligible firms
12
would include limestone and gravel quarries that have diesel generation back-up.
13
The third, the Industrial Surplus Energy (ISE) Rate, provides about 90% of sales under
14
the interruptible rate program. It applies to customers whose total load (firm and surplus)
15
exceeds 2000 kVA (approximately 2 MW). Except under certain conditions, eligibility is
16
limited to 25% of incremental load for existing customers and 25% of total load for new
17
customers. Hydro guarantees availability 60% of the time during summer months and
18
60% of the time during winter months, but may otherwise interrupt with appropriate
19
notice. The customer does not require back-up to be eligible. The price on the ISE rate is
20
designed to make Hydro revenue-neutral, on an expected value basis, relative to
21
alternative sales. The program also has a "Spot Market Replacement Energy" provision:
22
upon request, and if energy is available, Hydro will supply electricity (instead of
23
interrupting) at a price based on the utility's opportunity cost at that time. The price offer
24
is made weekly.
25
The total number of large industrial customers in Manitoba is small and there were no
26
interruptions in the first five years of the program. There were six weeks of interruption
27
last year. However, the three programs, as a package, appear to be successful. With 23
42
R. Wiens, Manager, Customer Rates and Policies, Power Smart Energy Services, Manitoba Hydro, pers.
comm.
- 27 1
existing customers and 11 potential new customers, Hydro anticipates that demand will
2
exceed the annual limit of 500 GwH and the Public Utilities Board approved an increase
3
in the limit to 1000 GwH in early 1988.43
4
Information about Hydro-Québec's real-time pricing options are contained in its tariff
5
book. They are considered experimental and apply to M-class and L-class customers. For
6
example, L-class customers on the rate are charged the standard rate for base
7
consumption (generally set at historic levels). Consumption above that is charged at the
8
real-time price; consumption below the base amount is credited at the real-time price. The
9
real-time price varies hourly and is an energy price only (i.e. contains no demand charge).
10
The real-time price is set at the marginal value of storage, if the current marginal source
11
of supply is a hydroelectric plant, and is set at the variable cost of the thermal plant or the
12
value of a purchase or foregone sale or the value of a management contract, if a thermal
13
plant/purchase/sale/management contract is at the margin of Hydro-Québec's supply.
14
5.
15
The Hydro-Québec proposal is unconventional. One would normally expect an initial
16
definition of an electricity supply price to be based on the costs of electricity supply to the
17
Applicant. However, the Hydro-Québec proposal anchors the supply price methodology
18
to a pre-existing retail tariff whose relation to costs has not been assessed by the
19
regulator. It is therefore difficult to see how a regulator could assess the current proposal
20
until it understands the basis for that retail tariff. In particular, if the L-tariff design does
21
not appropriately reflect the structure of costs to Hydro-Québec of delivered electricity for
22
that customer class, and the transmission rate design does appropriately reflect the
23
structure of costs of transmission for that customer class, then the proposed supply price,
24
being the difference of the two, would not reflect the costs to Hydro-Québec of electricity
25
supply for that customer class.
26
The proposed supply rate is not a retail rate. It would appear in a retail tariff schedule only
27
if Hydro-Québec unbundled its retail rates. Hydro-Québec does not propose unbundling
43
The Hydro- Québec proposal
Manitoba Hydro Insights February 1998, Vol 7, Issue 4
- 28 1
its retail rates. Therefore, except for the small wholesale load, the proposed supply rate
2
has no effect on the prices customers pay. However, if the proposed supply rates were
3
used within unbundled rates, then the proposed supply rate would in no way contribute
4
towards reflecting marginal costs in the prices customers pay.
5
The proposal is not a price cap proposal, although it is regulation on the basis of price, as
6
opposed to cost. For reasons discussed in section 3.2 above, regulation on the basis of
7
price would not be appropriate for Hydro-Québec at this initial stage and appears to be of
8
dubious merit for the future.
9
Hydro-Québec's proposal adjusts for capacity on the basis of the average load factor for
10
the customer class. The proposed rate does not differentiate between customers with
11
different load factors within the same rate class and is therefore less refined than any
12
retail rate that charges for billing demand, such as today's Rate L. Differentiation on the
13
basis of load factor in retail rates is based in part on transmission, or transmission and
14
distribution system usage. This variation should not be reflected in the supply rate.
15
However, to the extent that a high ratio of peak to average use imposes higher unit costs
16
of electricity supply, such differentiation should be included in the supply rate on a
17
customer-by-customer basis wherever demand is metered or wherever energy is metered
18
sufficiently frequently.
19
Load factor considerations apply wherever demand/energy rates are used in preference to
20
pricing by time interval. As suggested above, pricing by time is more consistent with the
21
emerging market structure than is load factor adjustment, whether by customer class or by
22
individual customer.
23
The proposed formula for load factor and loss adjustments, used to determine different
24
supply rates for different customers classes, is directionally correct. However, it is
25
difficult to interpret. While many directionally correct possible formulas exist,44
26
Hydro-Québec cannot envisage alternative formulas that achieve correct directionality,
44
For example, the losses term (1+ Pertes)/1.083 could be applied only to the first term; or implicit
demand/energy splits other than that based on system load factor could be used (see e.g. footnote 27); or the
load factor adjustments could be replaced by numbers representing share of coincident peak, and so on.
- 29 1
has no studies relating to the proposed formula and cannot provide the name of any other
2
utility that uses it. 45
3
The rates proposed in Annexe F are very unlikely to be "revenue-neutral", in the
4
following, necessarily restricted, sense. 46 Suppose, illustratively, that all retail rates in
5
1997 collected $7 billion in total. Suppose the cost of service for transmission,
6
distribution and any other services to be included in the cost of service, other than
7
electricity supply, was $3 billion in 1997. Then the rates in Annexe F would be revenue
8
neutral, in the sense used here, if they would have collected exactly $4 billion, based on
9
the consumption of each customer in 1997. The proposed supply rate for Class L is (by
10
definition) revenue-neutral, as long as the transmission rate used in the proposal collects
11
the cost of service of transmission and no other costs of service apply to L-rate
12
customers.47 But it is not evident that revenue neutrality, in the sense used here, applies to
13
the other rate classes individually, nor for the total of all rate classes. Given the
14
complexity, and highly varied design of the current portfolio of rates, it could only be true
15
by coincidence.
16
The formula defining the rates in Annexe F is not internally consistent. Suppose
17
Hydro-Québec sold only electricity supply – no transmission or distribution – and sold it
18
at the prices shown in Annexe F. Then, by definition, its average revenue would be total
19
revenue divided by the total quantity sold. Total revenue would be the sum of revenues
20
from all rates classes. The revenue from each rate class depends on the quantity sold to
21
that rate class. However, all the prices, including the average (2.81 cents/kwh) in Annexe
45
AQCIE Information Request 40 and response.
46
In general, revenue-neutrality may be defined for a given rate class or for tariff revenue in total.
Revenue-neutrality occurs, by definition, when re-rating all bills according to a new rate or set of rates
would not change total revenue. Tests for revenue neutrality may be done on the basis of consumption in a
recent year, or on the basis of a forward test year. It is not possible to use the standard definition of
revenue-neutrality in the context of the rates in Annexe F, because they would not actually collect any
revenue, except from the municipalities.
47
This assumes there are no costs other than transmission and supply in the L-rate [See Response to Régie
Information Request #1, Question 7.6]
- 30 1
F are defined without reference to quantities. Therefore the actual average revenue and
2
the assumed average revenue of 2.81 cents/kwh could be equal only by coincidence.48
3
Finally, Hydro-Québec's competitive position would not be compromised by having to
4
make a FACOS (Fully-Allocated Cost of Service) study publicly available. FACOS
5
results pertain to embedded costs, while competitive price is set by marginal cost. Even
6
knowledge of current-period variable costs of hydro operation would have little impact.
7
Hydro plants' variable costs are so low that hydro would rarely if ever be competing at the
8
margin. In this case, competitors' knowledge of hydro plants' costs could not affect the
9
volumes the hydro plants could sell, nor the price received in the market. That price
10
would be based on another supplier's costs and not the costs of hydro plants.
11
6.
12
Hydro-Québec's proposal concerns hypothetical prices, not costs or rates, for 97% of the
13
its customer load. This is an unusual first step in the process of regulation. Accepted
14
regulatory practice would start with a revenue requirements hearing. A revenue
15
requirements hearing may occur in the near future. It would require the provision of cost
16
of service information. In this respect, the Régie's response to positions of Hydro-Québec
17
in this proceeding may affect the usefulness of a revenue requirements hearing. In
18
particular, Hydro-Québec does not wish to provide information about costs of service in
19
this proceeding. The reason provided, namely compromise of competitive position, is not
20
sound. But even if it were sound, the reason would apply in general, not just in the current
21
proceeding. Therefore if the Régie now accepts Hydro-Québec's reason for not wishing to
22
provide cost of service information, the Régie would also logically have to accept that
23
reason in a revenue requirements hearing, and not require the information then. This logic
24
applies even if the Régie does not see provision of the information itself as necessary in
25
this proceeding.
48
Conclusions
SupposeQj is the number of kwh consumed by rate class "j"; Q is the sum of the Q j; Pj is the rate shown
in Annexe F for rate class "j"; and P is the average rate of 2.81 cents/kwh. Then the equation
P1Q1 + P2Q2 + … + P6Q6 = PQ is true for only specific combinations of Qj 's.
- 31 1
Within the narrower confines of the current proceeding, the Hydro-Québec proposal is not
2
based on accepted principles of ratemaking – neither cost of service nor
3
performance-based. It does not reflect any element of marginal-cost pricing, which is
4
necessary for economic efficiency. It differentiates among customers with different usage
5
characteristics less than does the L-rate upon which it is based. And it is internally
6
inconsistent with respect to its formula for setting rates for the rate classes other than Rate
7
L.
8
Paradoxically, Hydro-Québec appears to have, within its portfolio, a number of retail
9
rates that contain elements of marginal cost pricing, such as real-time pricing. When it
10
comes to setting retail rates, the Régie should encourage Hydro-Québec to further develop
11
and expand this approach. The discussion above provides some information about options
12
but further specificity would depend on detailed knowledge of system and load
13
characteristics, and markets. While the examples discussed apply primarily to rates for
14
large customers, there may be substantial value for other customers, especially as
15
competitive forces elsewhere lead to new technologies appropriate to smaller loads.
16
Key principles for marginal-cost-based rates would be:
17
1. distinguishing clearly in policy between economic development rates and
18
19
20
marginal-cost-based rates (see last paragraph, p. 27)
2. consulting diligently with the relevant customers and obtaining support before going to
the regulator for approval
21
3. developing options, rather than uniform, mandatory changes, and
22
4. employing time-sensitivity wherever practical, in preference to load factoring or
23
demand pricing.