RÉGIE DE L’ÉNERGIE
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
FOR
GAZ MÉTRO
The Brattle Group
44 Brattle Street
Cambridge, MA 02138
(617) 864-7900
May 2009
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
TABLE OF CONTENTS
I.
OVERVIEW/SUMMARY .............................................................................................. 1
II.
DETERMINANTS OF BUSINESS RISK AND STANDARDS FOR ESTABLISHING
A FAIR RETURN ........................................................................................................... 5
III.
MARKET UNCERTAINTY, RISK, AND CHANGES IN THE GAS MARKET
ENVIRONMENT .......................................................................................................... 10
IV.
CHANGES IN GAZ MÉTRO’S BUSINESS RISK ....................................................... 17
A.
Gaz Métro’s Business Risk Environment ...........................................................17
B.
Effects Of Changes In The Level And Volatility Of Gas Commodity Prices On
Gaz Métro’s Business Risk ................................................................................23
C.
Effects Of Increased Competition With Electricity And Fuel Oil On Gaz Métro’s
Business Risk .....................................................................................................30
D.
Effects Of Gaz Métro’s Performance Incentive Mechanism On Its Business Risk
..........................................................................................................................36
V.
GAZ MÉTRO’S BUSINESS RISK COMPARED TO OTHER GAS UTILITIES IN
CANADA AND THE UNITED STATES ..................................................................... 39
A.
Gaz Métro’s Allowed Return Compared to Allowed Returns for U.S. LDCs ......40
B.
Gaz Métro’s Unique Business Environment .......................................................45
1. Natural Gas Penetration in Québec ......................................................................... 46
2. Competition from Electricity .................................................................................. 49
3. Gaz Métro’s Industrial Customer Load ................................................................... 53
C.
Gaz Métro’s Long-term Risk is Greater Than That of the U.S. LDCs in Dr.
Vilbert’s Pure Play Sub sample ..........................................................................55
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
I.
OVERVIEW/SUMMARY
2
Q1.
Please state your name, address and position.
3
A1.
My name is Paul R. Carpenter. I am a Principal of The Brattle Group, an economic and
4
management consulting firm with offices in Cambridge, Massachusetts, Washington
5
D.C., San Francisco, California, London, England, and Brussels, Belgium. My office is
6
located at 44 Brattle Street, Cambridge, Massachusetts 02138.
7
Q2.
8
9
Will you briefly describe your educational background and professional
qualifications?
A2.
Yes. I am an economist specializing in the fields of industrial organization, finance and
10
energy and regulatory economics. I received a Ph.D. in Applied Economics and an M.S.
11
in Management from the Massachusetts Institute of Technology, and a B.A. in
12
Economics from Stanford University. I have been involved in research and consulting on
13
the economics and regulation of the natural gas, oil and electric utility industries in North
14
America and abroad for over twenty years. I frequently have testified before federal, state
15
and Canadian regulatory commissions, in federal court and before the U.S. Congress, on
16
issues of pricing, competition and regulatory policy in these industries. Outside of North
17
America, I have advised governments and regulatory bodies on the structure of their
18
natural gas markets and the pricing of gas transmission services. These assignments have
19
included testimony before the U.K. Monopolies and Mergers Commission and the
20
Australian Competition Tribunal, and advice to the governments of, and regulators in,
21
Greece, Ireland, the Netherlands, New Zealand and Australia.
22
I have been extensively involved in the evaluation of the economics and regulation of the
23
natural gas industry in North America. In Canada, I have advised pipeline companies and
24
have previously testified before the National Energy Board (“NEB”) and the Alberta
25
Energy and Utilities Board (“EUB”) on matters relating to pipeline competition and
26
capacity expansion, including the Alliance Pipeline Ltd. certification proceeding. I gave
27
evidence on business risk previously before the NEB in the multi-pipeline cost of capital
1
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
case, on behalf of Foothills Pipe Lines, and in more recent NEB proceedings on behalf of
2
TransCanada PipeLines Limited and Trans Québec and Maritimes Pipeline (“TQM”). I
3
recently provided written evidence on business risk before the Alberta Utilities
4
Commission (“AUC,” successor to the EUB) on behalf of Nova Gas Transmission as part
5
of the AUC’s 2009 Generic Cost of Capital proceeding, and before the Ontario Energy
6
Board (“OEB”) on behalf of Union Gas Limited and Enbridge Gas Distribution Inc. as
7
part of their 2007 rate applications. I provided written evidence on business risk and
8
appeared before the Régie de l’Energie (“the Régie”) on behalf of Gaz Métro as part of
9
its 2008 rate application. Further details of my educational and professional background,
10
as well as a listing of my publications, are provided in my curriculum vitae, which is
11
appended to this evidence as Attachment A.
12
Q3.
What assignment were you given in this proceeding?
13
A3.
I have been asked by Gaz Métro to provide evidence concerning its business and
14
regulatory risks as they affect the return on equity required by investors in Gaz Métro
15
securities, and to render an opinion as to the adequacy of the current formula return to
16
compensate investors for bearing those risks. In particular, I have been asked to evaluate
17
whether, and the extent to which, there have been changes in the business risk and
18
regulatory environment faced by Gaz Métro that are not captured by Gaz Métro’s current
19
formula return. I have also been asked to provide evidence on the comparability of
20
business risk and allowed returns on capital for Canadian and U.S. local distribution
21
companies (“LDCs”), and to compare Gaz Métro’s business risk with the business risk of
22
the LDCs that make up Dr. Vilbert’s pure play U.S. LDC sub sample.
2
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q4.
When do you begin your review of Gaz Métro’s business risks?
2
A4.
I evaluate changes in Gaz Métro’s business risks since 1999 and 2004. The Régie has
3
used a formula-based methodology to determine Gaz Métro’s allowed return since 1999.1
4
The formula-based methodology was retained by the Régie when it was set to expire in
5
2004.2 The Régie made minor changes to the formula in 2007.3 It has now been 10 years
6
since the formula was adopted and five years since its first sunset date. In my opinion, it
7
is important for the Régie to conduct a de novo review of Gaz Métro’s business risk and
8
allowed return. Gaz Métro’s business risk has changed significantly during the period
9
that the formula-based methodology has been in place. It is important to evaluate whether
10
the formula-based methodology has adequately accounted for these changes, and this
11
evaluation should consider all changes since 1999.
12
Q5.
Could you summarize your conclusions?
13
A5.
Yes.
•
14
The market environment in which Gaz Métro and other gas utilities operate in
15
North America has changed significantly since 1999, reflecting greater
16
uncertainty in the supply of the gas commodity and greater uncertainty in the
17
extent and timing of the growth in demand. This uncertainty is partly reflected in
18
significantly higher gas commodity price levels and volatility, which has
19
significant implications for the need for, and investment risk of, gas utility
20
infrastructure.
•
21
Gaz Métro, in particular, has been exposed to greater business risk due to the high
22
level of market risk in its gas distribution business, in part due to the intense
23
competition it faces from electricity and fuel oil. This high level of market risk is
1
Decision No. D.99-11 dated 10 February 1999 for tariffs effective during October 1998-September 1999.
2
Decision No. D-200-196 dated 24 September 2004 for tariffs effective during October 2004-September
2005.
3
Decision No. D-2007-116 dated 15 October 2007.
3
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
compounded by the fact that Gaz Métro has low penetration in the residential
2
heating market, and serves an unusually large and vulnerable industrial load; by
3
recent changes in the level and volatility of natural gas prices; and by
4
environmental initiatives, which tend to harm the competitiveness of natural gas
5
relative to electricity. Gaz Métro is also exposed to regulatory risk related to its
6
Performance Incentive Mechanism. Incentive regulation creates greater expected
7
short-term variations in earnings than does traditional cost-of-service regulation,
8
particularly where deferral accounts are used to adjust for cost under- or over-
9
recovery.
10
•
The market risk to which Gaz Métro is exposed in its distribution business
11
manifests itself in uncertainty over the future utilization of its distribution assets.
12
Because Gaz Métro’s gas distribution assets are sunk investments and cannot be
13
redeployed easily to another use should market conditions change, Gaz Métro’s
14
future income earning capability depends critically on the maximum utilization of
15
its assets. Gaz Métro’s performance incentive mechanism encourages Gaz Métro
16
to improve its productivity and allows for productivity gains to be shared with
17
customers. However, if volumes decline over time, the performance incentive
18
mechanism only provides a partial protection from declining volumes. In this
19
way, Gaz Métro bears some market risk that depends on asset utilization.
20
•
Investors need to be compensated for bearing risks that they cannot diversify
21
away. An important part of the overall returns to Gaz Métro’s investors comes
22
from the operation of its performance incentive mechanism. However, this
23
mechanism includes volume risk: the incentive scheme is much less likely to pay
24
out if volumes fall. Volumes are likely to fall when general economic activity as a
25
whole is falling—for example, gas demand from industrial customers is likely to
26
fall when industrial output is falling. The volume risk in the incentive mechanism
27
is therefore a source of systematic risk, and thus contributes to Gaz Métro facing
4
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
increased business risk. The most recent results of the mechanism, at a time when
2
the general economy is performing badly, support this conclusion.
•
3
Gaz Métro’s allowed return under the formula is significantly below the returns
4
on equity and total capital allowed by regulators for LDCs in the U.S. These
5
differences in allowed returns cannot be explained by differences in business risk
6
or regulation. In fact, Gaz Métro’s business environment is unique relative to that
7
of other Canadian and U.S. LDCs in at least three respects: (1) natural gas has a
8
significantly lower penetration rate in Québec in Gaz Métro’s service territory
9
than in the service territories of typical LDCs in Canada and the U.S.; (2) Gaz
10
Métro faces significantly stronger competition from electricity than other LDCs in
11
Canada and the U.S.; and (3) Gaz Métro has a large industrial customer load, an
12
industrial customer load that is larger than the LDCs in Dr. Vilbert’s U.S. LDC
13
sample.
14
Q6.
How is the rest of your evidence organized?
15
A6.
In Section II, I discuss the determinants of business risk and the standards for establishing
16
a fair return. In Section III, I provide evidence that recent changes in natural gas markets
17
have increased the business risk of natural gas infrastructure. In Section IV, I discuss Gaz
18
Métro’s business risk environment, and demonstrate that Gaz Métro’s business risk has
19
increased in ways that are not captured by Gaz Métro’s current formula return. Finally, in
20
Section V, I discuss the relevance of comparisons between allowed returns and business
21
risk of U.S. and Canadian LDCs. I compare Gaz Métro’s business environment to that of
22
other U.S. LDCs, including the LDCs in Dr. Vilbert’s pure play U.S. LDC sub sample.
23
24
II.
DETERMINANTS OF BUSINESS
ESTABLISHING A FAIR RETURN
25
Q7.
What is investment risk and how does it relate to a regulator’s decision to establish
26
RISK
AND
an appropriate allowed return for a natural gas utility?
5
STANDARDS
FOR
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
A7.
One of the bedrock principles for establishing a fair return on equity for a regulated
2
utility that has been long recognized by economists, regulators, and the courts in Canada
3
and the U.S. is that a reasonable return should “be comparable with the return available
4
from the application of the capital to other enterprises of like risk.”4 This principle
5
implies that any evaluation of the reasonableness of a particular return should consider
6
the level of risk faced by investors in the enterprise, and how those risks and returns
7
compare with other companies with similar risks. Investment risk for a natural gas utility
8
has been defined to include financial and business risks. Financial risk involves the extent
9
to which debt is employed in the company’s capital structure. Business risk is a
10
somewhat more subjective concept and is more difficult to quantify precisely,5 but it is
11
sometimes categorized to include the supply, demand (or market), competitive, operating
12
and regulatory risks that might be faced by particular utilities.6 Both business and
13
financial risks are accounted for in the methodology employed by Drs. Kolbe and Vilbert
14
to estimate the cost of capital for Gaz Métro. For example, as discussed in their evidence,
15
the “equity betas” which are estimated using the Equity Risk Premium method capture
16
the combination of financial and business risks for the particular sample of publicly
17
traded companies employed.
4
National Energy Board, RH-1-70, p.7-5. See also National Energy Board, RH-2-2004, p. 17, where the
NEB stated that a fair or reasonable return on capital should meet three requirements. It should: (1) “be
comparable to the return available from the application of the invested capital to other enterprises of like
risk (the comparable investment standard)”, (2) “enable the financial integrity of the regulated enterprise to
be maintained (the financial integrity standard)”, and (3) “permit incremental capital to be attracted to the
enterprise on reasonable terms and conditions (the capital attraction standard).”
5
The NEB has recognized that the assessment of business risk is an inherently qualitative exercise. See
National Energy Board, RH-2-1994, p. 24: “The Board has systematically assessed the various risk factors
for each of the pipelines but has not found it possible to express, in any quantitative fashion, specific
scores or weights to be given to risk factors. The determination of business risk, in our view, must
necessarily involve a high degree of judgment, and the analysis is best expressed qualitatively.” See also
National Energy Board, RH-1-2008, p. 17.
6
See, for example, National Energy Board, RH-4-2001, p. 13. I understand that in past decisions the Régie
has treated regulatory risk as an element separate from business risk. In this evidence I include regulatory
risk as a part of business risk conceptually, but I also evaluate its implications separately for Gaz Métro’s
return on equity.
6
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q8.
2
3
What kinds of risks matter the most in evaluating a company’s business risk from a
cost of capital perspective?
A8.
The risks that matter the most from an equity investor’s perspective are those that cannot
4
be diversified away through the holding of a broad portfolio of securities. Risks that are
5
hard to diversify are those that are generally correlated with the level of (and changes in)
6
general economic activity. Such risks are referred to as “systematic.” Broadly speaking,
7
systematic risks associated with the gas distribution business include uncertainties in the
8
demand for, and supply of, distribution services that are affected by changes in economic
9
activity, including incomes, prices and governmental policies including environmental
10
concerns.
11
Q9.
How does rate regulation affect a company’s business risk?
12
A9.
On the one hand, rate regulation reduces a company’s business risk if it provides equity
13
investors some assurance that a fair return on and of capital will be earned over the
14
lifetime of the firm’s assets. On the other hand, regulation may enhance a company’s
15
business risk if investors perceive that there is uncertainty in the future regulatory
16
treatment of the firm’s businesses. That is why regulatory risk is sometimes evaluated as
17
a separate component of business risk. While the equity securities of rate regulated firms
18
are generally perceived as relatively stable, low-risk investments, the greater exposure of
19
such firms to competition from other regulated and unregulated businesses, and
20
alternative fuels, has changed that perception somewhat in recent years, particularly in
21
the energy utility sector.
22
Q10. Is there a time dimension to business risk, and if so, how should one think about it?
23
A10.
In prior cost of capital cases in other jurisdictions, distinctions have been drawn between
24
so-called “short-term” and “long-term” business risks. But these labels have actually been
25
used to describe two different types of risk and not just the time dimension. Short-term
26
risk has typically referred to factors that affect the year-to-year earnings of the utility in
27
question. One example, applicable to certain utilities, is variations in weather from year
7
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
to year which increase the variability of earnings, but do not affect the long term expected
2
earnings stream. While one would expect investors to pay more for a stable earnings
3
stream than for a more volatile one with the same long term expected value, it is not a
4
risk on which long term investors would place great importance. Other examples of short-
5
term risk include one time events such as a regulatory cost disallowance that would affect
6
year-on-year earnings, but would not be expected to affect an investor’s long-term
7
estimate of expected earnings. These short-term earnings variability risks may be
8
mitigated through the use of deferral accounts or weather normalization procedures.
9
In contrast, long-term risks refer to more fundamental uncertainties in supply, demand,
10
competition, and regulation. Changes in these factors occur over time and they have the
11
potential to result in a failure to recover the expected return of and on the capital invested
12
in the utility. Despite the label, long-term fundamental risks may be also realized in the
13
short term. Another important aspect of long-term fundamental risk that distinguishes it
14
from short-term variability risk is asymmetry. Under conventional cost of service
15
regulation, the potential for economic loss due to exposure to fundamental risk is not
16
offset by the potential to recover more than the return on and of capital. In my opinion,
17
equity investors give greater weight to these types of fundamental, capital recovery risks
18
in terms of their required return than they do to the short-term earnings variability risk.7
7
The NEB recently concluded that while it is important to “consider both long-term and short-term risks
and to weigh them based on the circumstances applicable to the pipeline,” regulators have a more limited
ability to respond to long-term risks, and that this tends to make them more important than short-term
risks. The NEB stated:
On the question of the appropriate weights for short versus long-term risks, the Board is
of the view that because of the more limited ability of regulators to respond to the
realization of long-term risks, there is a sense, in this aspect, that they are more important
than short-term risks. Long-term risks are more structural. Therefore, they denote more
fundamental factors and trends in the evolution of the overall risk landscape of a
company, while short-term risks tend to be either more cyclical or individual events.
See National Energy Board, RH-1-2008, p.46.
8
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q11. Why do you say that equity investors give greater weight to fundamental capital
2
3
recovery risk?
A11.
When investors buy a share of stock, they are buying a share of a long-term earnings
4
stream. They are not buying only a month, or even a year’s worth of performance. The
5
time horizon of any equity investment is inherently long term. The short-term variability
6
in the earnings of an equity investment is only a small part of the business risk picture.
7
This is particularly important for utility investments that when “sunk” into the ground are
8
difficult to redeploy to other valuable uses should their fundamental risks be realized.
9
Q12. How were changes in business risk under a formula approach to return on equity
10
11
traditionally accounted for by Canadian regulators?
A12.
Ever since various Canadian regulators began to employ formulas for the determination
12
of allowed ROEs, the practice had been to adjust the deemed equity thickness for
13
perceived changes in business risk. Higher business risk would imply that greater equity
14
thickness would be required.
15
Q13. Is there any assurance in theory or practice that adjustments to deemed equity
16
thickness or to formula returns on equity, based on perceived changes in business
17
risk, will ensure that the allowed return on capital that results will be fair or
18
reasonable?
19
A13.
No, there is no such assurance. The primary reason is that assessments of relative
20
business risks between companies, and changes in business risk for a particular company,
21
are inherently subjective exercises. Also, under a formula-based methodology there is no
22
necessary numerical connection between the amount that the deemed equity thickness or
23
formula return on equity has been increased by regulators, or in settlements under NEB
24
or provincial formulas, and the increase in the total return required by investors in the
25
equity securities of the benchmark utility to compensate them for bearing that increased
26
risk. That total required return is best revealed by the measures of risk contained in the
27
methodologies employed by Drs. Kolbe and Vilbert to assess the cost of capital for the
9
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
samples they employ. In a review of the total return results that the formulas such as Gaz
2
Métro’s ROE formula have produced, it cannot be assumed that changes in equity
3
thickness or formula return on equity have adequately accounted for changes in business
4
risk without re-estimating the cost of capital. Moreover, any such review should also
5
consider the underlying reasons for why the business risks may have changed since the
6
formula was established or reviewed. This is particularly true now, when very significant
7
changes have been occurring in the market and infrastructure investment environment in
8
which gas utilities throughout North America operate.
9
In the next two sections, I provide evidence regarding changes in the North American
10
natural gas market that have increased the business risk of natural gas infrastructure, and
11
evaluate changes in Gaz Métro’s business risk.
12
13
III.
14
Q14. Could you describe some of the changes in the natural gas market environment in
15
North America that have occurred since 1999 and their implications for natural gas
16
utility infrastructure investment?
17
A14.
MARKET UNCERTAINTY, RISK, AND CHANGES IN THE GAS MARKET
ENVIRONMENT
Yes. The market environment in which gas utilities operate in North America has
18
changed significantly since 1999 reflecting greater uncertainty in the supply of the gas
19
commodity and greater uncertainty in the extent and timing of growth in demand. This
20
uncertainty is partly reflected in significantly higher gas commodity price levels and
21
volatility. These changes have significant implications for the need for, and investment
22
risk of, gas utility infrastructure.
23
The uncertainty in the timing, location, and magnitude of increases in natural gas demand
24
is in part caused by changes in the economy, as relatively more economic activity is
25
concentrated in businesses which use less energy in general, and less natural gas in
26
particular. This trend can be seen in Figure 1, which shows that the energy intensity of
27
the Canadian economy as a whole has declined by more than 40% since 1990. The
10
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
change in the use of natural gas in Québec’s manufacturing sector is larger: since 1990
2
the intensity of gas use in manufacturing in Québec has declined by around 50%, and by
3
about 20% since 1999.8
Figure 1
Declining Energy Intensity of the Canadian and Quebec Economies
120
Each series relative to 1990
= 100
100
80
60
40
20
0
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Source: Statistics Canada. Statistics Canada changed its methodology for computing manufacturing value added starting in 2004, so that data for
2004-2007 is not directly comparable to data for earlier years.
Canada total energy / GDP
Canada natural gas / GDP
Canada manufacturing sector natural gas / value added
Quebec manufacturing sector natural gas / value added
4
5
These changes have been recognized in Canada by the NEB in its summary of the
6
feedback it received in 2006 during its Energy Futures Project consultation sessions. In
7
its report on these sessions under “Key Messages,” the NEB writes:
8
1. New Energy Paradigm
9
10
11
12
13
There is consensus that the energy system in Canada has
transitioned into a new paradigm characterized by tighter
energy markets, high and volatile energy prices, high value
currency, higher inflationary pressures, ageing infrastructure
at all levels, and an uncertain demand response.9
8
1990 is the first year for which the necessary data are available.
9
National Energy Board, Energy Futures Project: Consultation Sessions Feedback, July 2006, p. 2.
11
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Additional gas market uncertainty has also been created by the increased environmental
2
concerns associated with greenhouse gas emissions and their role in long-term climate
3
change. For example, the Government of Québec has instituted a “Green Fund” to
4
support reductions in greenhouse gas emissions. The financing for the Green Fund comes
5
from a duty levied on distributors of hydrocarbon fuels. Gaz Métro’s levy is passed
6
through directly to customers in its rates. The Green Fund has harmed the
7
competitiveness of natural gas relative to electricity in Québec which increases Gaz
8
Métro’s business risk, as I discuss in more detail in Section IV.C.
9
Q15. What is the evidence for changes in natural gas commodity prices and price
10
11
volatility since 1999?
A15.
Tighter supply/demand balances for natural gas have led to substantially increased prices
12
and price volatility in North America since 1999. To show this phenomenon, in Figure 2 I
13
have plotted the 12-month forward “strip” price of natural gas on the New York
14
Mercantile Exchange (NYMEX) from April 1990 to March 2009. This is a useful index
15
to reference because it reflects the broad market expectation of the level and volatility of
16
future prices in a way that is normalized somewhat for seasonal effects.
12
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 2
NYMEX Natural Gas 12-Month Average Future Prices
(April 1990 - March 2009)
15.00
Up to 1999
1999 - Present
Future Price (US$/GJ)
12.00
9.00
Up to 1999
1999 to Present
12-Month
Average
Standard
Deviation
1.89
5.63
0.29
2.49
6.00
3.00
0.00
1
4/
4/
0
3
1
4
2
5
6
7
8
9
00 001 002 003 004 005 006 007 008
99 199 199 199 199 199 199 199 199 199
2
2
2
2
2
20
2
2
2
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
4/
/
/
/
/
/
/
/
/
/
/
4/
4
4
4
4
4
4
4/
4
4/
4
4
4/
4/
4
4/
4/
4/
Note: Null prices are omitted to adjust for market inactivity.
Source: NYMEX data obtained from Bridge & Bloomberg.
1
2
Prior to 1999 the average of these forward prices was US $1.89 per GJ with a standard
3
deviation of US $0.29, a very low and stable price environment. As the figure indicates,
4
since 1999 the average forward price tripled to US $5.63 per GJ and the standard
5
deviation of those prices ballooned to US $2.49 per GJ, an eight-fold increase. A similar
6
pattern can be seen for 36-month NYMEX forward prices shown in Figure 3.
13
WRITTEN EVIDENCE OF
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Figure 3
NYMEX Natural Gas 36-Month Average Future Prices
(April 1997 - March 2009)
15.00
Future Price (US$/GJ)
12.00
Up to 1999
1999 - Present
9.00
6.00
3.00
Up to 1999
1999 to Present
36-Month
Average
Standard
Deviation
2.18
5.50
0.09
2.38
4/
1/
20
08
4/
1/
20
07
4/
1/
20
06
4/
1/
20
05
4/
1/
20
04
4/
1/
20
03
4/
1/
20
02
4/
1/
20
01
4/
1/
20
00
4/
1/
19
99
4/
1/
19
98
4/
1/
19
97
0.00
Note: Null prices are omitted to adjust for market inactivity.
Source: NYMEX data obtained from Bridge & Bloomberg.
1
2
While these changes in the commodity market pre and post-1999 are dramatic, even those
3
averages mask to some extent the market changes experienced in just the last 16 months.
4
Over this period, 12-month average forward prices have risen from roughly US $7.80
5
(since January 2008) per GJ in January 2008 to US $12.50 per GJ in July 2008, six
6
months later. The 12-month average has recently fallen to roughly US $4.50 per GJ
7
recently, a price level not seen since late 2003. Whether or not these changes in the gas
8
commodity market are permanent or temporary is a subject of debate. One thing that we
9
can have some confidence in, however, is that there will be continued uncertainty in
10
future prices and increased price volatility, which contributes to greater uncertainty in
11
demand growth and use-per-customer risk for gas utilities distributing the commodity.
14
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
These trends in North American natural gas prices stand in stark contrast to Québec
2
electricity prices, which have remained low and stable. I compare natural gas and
3
electricity prices in Québec in Section IV.C.
4
Q16. How have changes in natural gas prices and volatility manifested themselves with
5
6
respect to the WCSB?
A16.
By 1995, the Western Canadian Sedimentary Basin (the “WCSB”) had entered into a
7
period of rapid growth in productive capacity. At that time, the principal market concern
8
was whether pipelines could be built or expanded rapidly enough to move that supply to
9
eastern markets. Those market conditions persisted from 1995 until about 1999 and
10
during this time the price of gas from the WCSB was “disconnected” from (i.e., lower
11
than and not highly correlated with) the market price of gas from other North American
12
sources. This occurred because growth in WCSB production had outstripped the pipeline
13
capacity available to deliver that gas to the market. Thus, markets like Québec that relied
14
on WCSB production were enjoying a period in which natural gas was very cheap in
15
absolute and relative terms.
16
That era came to an end with the completion of the TransCanada and Foothills/Northern
17
Border expansion projects in 1998 and the construction of the Alliance and Vector
18
systems that went on line in 2000. Instead of too little pipeline capacity out of the WCSB,
19
the market was entering a prolonged period of excess capacity out of the basin.10 At that
20
point, the price of WCSB gas reconnected with the North American market and it has
21
been connected ever since. This change in the relative prices of WCSB gas and the
22
market price of gas from other sources (as represented by the market price at the Henry
23
Hub) is shown in Figure 4. At the same time the WCSB has reconnected with North
24
American markets, the optimism with respect to conventional WCSB supplies has turned
25
to pessimism. There has not been a significant supply response in the WCSB since 2003
10
In the recent NEB TQM proceeding (RH-1-2008), WCSB supply available for pipelines out of the basin
was forecast to be roughly 11 Bcf/day in 2009/2010, while total pipeline capacity out of the basin is
roughly 14 Bcf/day.
15
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
despite a period of sustained high prices. The WCSB has become a less desirable basin in
2
recent years as production has plateaued and development costs have increased.
Figure 4
Price Differentials between Henry Hub and NIT (AECO) as Percentage of Henry Hub Spot Prices
100
Differential as % of Henry Hub Price
80
60
40
20
0
6
5
6
4
7
8
7
5
9
8
9
0
1
2
4
3
199 7/199 7/199 7/199 7/199 7/199 7/200 7/200 7/200 7/200 7/200 7/200 7/200 7/200 7/200 7/200
7/-20
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-40
Pre-2001
Post-2001
-60
-80
Time
Notes: Null prices are omitted to adjust for inactivity.
Price differentials are calculated as Henry Hub spot prices minus NIT (AECO) spot prices.
Source: Platts Gas Daily.
3
4
Q17. But doesn’t the fact that Gaz Métro receives gas supplies from the Dawn hub in
5
6
Ontario mitigate its exposure to WCSB gas prices?
A17.
Yes, to some extent. However, the NEB found recently in its March 2009 TQM decision
7
that the supply of gas at Dawn is currently sourced primarily from western Canada.11
8
Moreover, the NEB found sourcing additional supplies for Québec and eastern Canada
9
from Dawn in the future will adversely affect the competitiveness of gas in these markets,
10
because it will raise tolls on the Transcanada Mainline. The NEB stated:
11
National Energy Board, RH-1-2008, p.47.
16
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
2
3
4
5
6
7
8
9
10
Today, the supply of gas at Dawn is primarily sourced from
western Canada. There was discussion by TQM witnesses
regarding growing production areas that could supply Dawn.
However, these witnesses explained that growing Dawn
supplies will impact tolls on the Mainline for long- haul
shippers of gas from the WCSB. Ultimately, the Board
agrees with the view that, in these circumstances, the higher
tolls would be passed on to the markets that are served off of
the TQM system, further impacting the competitiveness of
gas in the markets that TQM is serving.12
11
Gaz Métro, like TQM, cannot fully insulate itself from declining supply in the WCSB by
12
accessing gas supply at Dawn.
13
IV.
CHANGES IN GAZ MÉTRO’S BUSINESS RISK
14
A.
GAZ MÉTRO’S BUSINESS RISK ENVIRONMENT
15
Q18. How would you characterize Gaz Métro’s assets from a business risk perspective?
16
A18.
17
18
residential, commercial and industrial customers.
Q19. How does Gaz Métro’s gas distribution business subdivide in terms of customer
19
20
Gaz Métro’s assets are devoted to the provision of traditional gas distribution services to
classes?
A19.
Gaz Métro forecasted in the 2009 rate case that it would serve roughly 169,000 customers
21
in five tariff classes, D1 (general service), DM (modular service), D3 (stable service), D4
22
(stable service for large volumes), and D5 (interruptible service). In terms of customer
23
class, residential customers made up 66% of Gaz Métro’s customers and 5% of its
24
throughput, commercial customers made up 34% of customers and 44% of throughput,
25
and industrial customers made up less than 1% of customers and 51% of throughput. Gaz
26
Métro forecasted total throughput of 5,099 106 m3 for fiscal year 2009, which represented
27
a decrease from the prior year forecast (the fiscal year 2008 estimate) on a comparable
28
weather-normalized basis. This decrease in throughput is attributed primarily to the effect
12
National Energy Board, RH-1-2008, p.47.
17
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
of declining economic activity, increased competition from fuel oil and increased energy
2
efficiency.
3
Q20. How does Gaz Métro earn income on its distribution services?
4
A20.
Since 2000, Gaz Métro’s rates have been set using a Performance Incentive Mechanism.
5
Under this mechanism, Gaz Métro’s rates are set prior to the start of each fiscal year by
6
comparing its projected cost of service to a revenue cap. Gaz Métro’s projected cost is
7
computed using traditional cost of service ratemaking principles, with an allowed return
8
on equity set using the Régie-approved formula-based methodology at a deemed equity
9
thickness. Its revenue cap is computed by escalating the prior years’ cap based on the
10
Québec Consumer Price Index (CPI) minus an X-factor, minus a factor relating to past
11
productivity gains that benefited Gaz Métro. There have been a number of changes to the
12
incentive mechanism since its introduction in October 2000, most recently in October
13
2007. The following paragraphs describe the mechanism as it currently operates.
14
The X-factor is currently set at 0.3%.
15
As well as changing from year to year in line with CPI–X, the revenue cap is also
16
adjusted to account for certain exogenous factors, including: the impact of weather; the
17
impact of changes in interest rates on Gaz Métro’s allowed return; a partial adjustment to
18
take out the impact of changes in consumption by small and medium customers; and the
19
impact of changes to income and capital taxes on the cost of service.
20
The volume adjustment for small and medium customers13 works as follows: if the
21
change in actual total consumption between the preceding year and the year before that
22
by these customers is ΔV, the revenue cap is adjusted by (ΔV+0.86%) x 0.9 x –1. Thus,
23
for example, if volume decreased by 5%, the exogenous factor is (–5% + 0.86%) x 0.9 x
24
–1 = +3.73%. Since, in this case, the part of the revenue cap associated with these
13
Those small and medium load customers served continuously since 1999 without intervention by Gaz
Métro’s sales team.
18
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
customers will have fallen by 5% as a result of the reduction in volume, and by 0.3%
2
because of the X factor, the overall effect is that the revenue cap falls by 1.57%.14 This is
3
equivalent to Gaz Métro’s revenue cap changing by 10% of the change in volume,
4
together with an X factor of 1.07%15 for these customers. 16
5
If the revenue cap is greater than Gaz Métro’s projected cost of service, then rates are set
6
so that the projected productivity gain (i.e., the difference between the revenue cap and
7
projected cost of service) is shared equally between customers and Gaz Métro. If,
8
however, Gaz Métro’s projected productivity gain would be sufficient to increase the rate
9
of return on capital by more than 3.75%, Gaz Métro’s share is capped at this level and all
10
further projected gains go to customers.
11
The revenue cap is also adjusted so that Gaz Métro’s share of productivity gains in
12
previous years is passed back to customers after a lag: the revenue cap is reduced by an
13
amount equal to the average of Gaz Métro’s share of productivity gains in the preceding
14
five years.
15
If the revenue cap is less than Gaz Métro’s projected cost of service, then rates are set to
16
recover Gaz Métro’s projected cost of service. In this case, the difference between Gaz
17
Métro’s projected cost of service and the revenue cap must be repaid to customers before
18
Gaz Métro can share in productivity gains or overearnings in later years.
19
At the end of each fiscal year, Gaz Métro’s actual productivity gain is compared to its
20
expected productivity gain. If its actual productivity gain is greater than the expected
21
productivity gain, then the resulting overearnings are shared between customers and Gaz
22
Métro (in the form of a contribution to an energy efficiency fund and a reduction in rates
14
If ΔV is –5%, the component of the revenue cap for small and medium customers changes by –5%
+3.73% = 1.27%, plus an X factor of 0.3%, or 1.57% in total.
15
1.07% = 0.3% + 0.86% x 0.9.
16
i.e., if volumes are constant the revenue cap falls by 0.77% + 0.3% = 1.07%; if volumes fell by 5%, the
revenue cap would fall by (5% x 10%) + 0.77% +0.3% = 1.57%; if volumes rose by 5%, the revenue cap
would fall by (–5% x 10%) +0.77% +0.3%= 0.57%.
19
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
in the second subsequent fiscal year). Gaz Métro keeps 25% of the overearnings, and
2
customers receive 75% (again, if the overall cap of 3.75% extra return on capital is
3
reached, customers receive all of the overearnings).17 If the actual productivity gain is
4
positive but less than the expected productivity gain, then Gaz Métro absorbs all of the
5
difference between actual and expected productivity gain. If the actual productivity gain
6
is negative, then customers and Gaz Métro share the deficit equally (with customers’
7
share in the form of an increase in rates in the subsequent fiscal year). In this case, Gaz
8
Métro must repay customers for their share of the deficit with interest before Gaz Métro
9
can share in productivity gains or overearnings in later years.
10
Gaz Métro’s overall incentive payment (the sum of projected productivity gain plus
11
overearnings) is also adjusted according to Gaz Métro’s performance on a basket of
12
service quality indicators. If it achieves a service quality score of less than 85%, Gaz
13
Métro receives no incentive payment. If it achieves more than 85%, its incentive payment
14
is multiplied by its score. As a result, Gaz Métro can only achieve the full benefit of the
15
incentive scheme if it scores 100% on service quality.
16
There is an additional incentive payment relating to the Global Energy Efficiency
17
Program (GEEP). Performance under GEEP in terms of reduced consumption attracts an
18
incentive payment of up to $4m. The maximum payment would be achieved if
17
The treatment of overearnings and shortfalls relating to transmission and load-balancing services is
slightly different from other revenues and costs. In 2007 the incentive scheme was adjusted in respect of
these services, with the result that Gaz Métro is no longer to the same extent able to trade off poor
performance in other areas of operations with good performance on these services. In respect of operating
transactions (selling transmission and load balancing tools like storage which are not required to meet
forecast demand), a volume and price project is made at the start of the fiscal year. At year end, the
difference between actual price and forecast price is multiplied by the lesser of actual and forecast volume.
25% of the difference (positive or negative) is kept by Gaz Métro, but overearnings are kept irrespective of
whether Gaz Métro has hit its incentive cap. The remainder of the difference is treated as any other
revenue. Revenue from financial transactions related to these services (transactions such as loans of
unused storage space that do not have an impact on the total volume of transmission and load-balancing
tools available during a fiscal year) will be forecast at the start of a fiscal year. If actual revenues are lower
than projected revenues, then the deficit will be placed in a deferral account and recovered from
customers. If actual revenues are greater than projected revenues, then the difference will be shared
25%/75% between Gaz Métro and its customers, irrespective of whether Gaz Métro has reached its
incentive cap.
20
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
consumption is reduced by 120m m3 over five years, and if less than this is achieved the
2
incentive is pro-rated.
3
If the performance incentive mechanism expires, Gaz Métro will not receive any
4
payments owing to it as a result of out-turn productivity gains being greater than forecast
5
in the last year. Alternatively, if at the expiry of the mechanism, Gaz Métro has
6
accumulated a debt to customers as a result of its cost of service being above the revenue
7
cap, it will have to pay off half of this debt over the following three years, subject to a
8
cap of 0.75% times the rate base on the total amount repaid.
9
10
Q21. Is Gaz Métro continuing to make capital investments in its distribution business?
A21.
Yes, Gaz Métro continues to put additional capital at risk for security reasons and to
11
maintain the value of its investment. Gaz Métro proposed capital expenditures of $114
12
million for fiscal year 2009. This includes $40 million in network expansion
13
expenditures, $28 million in deferred charges expenditures (mainly commercial programs
14
and IT development), and $20 million in network improvement expenditures.
15
Q22. What are the principal classes of business risk to which Gaz Métro is exposed?
16
A22.
The principal classes of business risk to which Gaz Métro is exposed include market,
17
regulatory, and supply risks. Gaz Métro is exposed to an unusually high level of market
18
risk in its gas distribution business due to the intense competition it faces from electricity
19
and fuel oil. This high level of market risk is compounded by the fact that Gaz Métro has
20
low penetration in the residential heating market, and serves an unusually large industrial
21
load; by recent changes in the level and volatility of natural gas prices; and by
22
environmental initiatives, which tend to harm the competitiveness of natural gas relative
23
to electricity. Gaz Métro is also exposed to regulatory risk related to its Performance
24
Incentive Mechanism. Incentive regulation creates greater expected short-term variations
25
in earnings than does traditional cost-of-service regulation, particularly where deferral
26
accounts are used to adjust for cost under- or over-recovery. I will return to this topic in
27
more detail below.
21
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q23. How does market risk manifest itself in Gaz Métro’s gas distribution business?
2
A23.
The market risk to which Gaz Métro is exposed in its distribution business manifests
3
itself in uncertainty over the future utilization of its distribution assets. Because Gaz
4
Métro’s gas distribution assets are sunk investments, and cannot be redeployed easily to
5
another use should market conditions change, Gaz Métro’s future income earning
6
capability depends critically on the maximum utilization of its assets. Gaz Métro’s
7
performance incentive mechanism encourages Gaz Métro to improve its productivity and
8
allows for productivity gains to be shared with customers. However, if volumes decline
9
over time, the performance incentive mechanism only provides a partial protection from
10
declining volumes. In this way, Gaz Métro bears some market risk that depends on asset
11
utilization.
12
Q24. What factors could affect the utilization of Gaz Métro’s distribution assets?
13
A24.
Distribution asset utilization is a function of the wholesale and retail price of the gas
14
commodity itself, of the price of competing fuels, of general economic activity in its
15
service area, and of weather deviations from normal forecast conditions. Of these risk
16
factors, the ones most important to equity investors (i.e., those that are systematic) are the
17
level of prices and economic activity. Weather deviations from normal are less important
18
to equity investors because they are not likely to be correlated with the market and hence
19
they are a diversifiable risk. Again, this is because investors themselves can cheaply
20
diversify away risks that are not correlated with movements in the general economy by
21
holding a portfolio of equities, such as broadly-based mutual funds. Moreover, Gaz
22
Métro is compensated for weather deviations via a deferral account that is included in
23
rate base and amortized over a five year period.
22
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q25. Does Gaz Métro face a risk that the utilization of its system will decrease due to the
2
3
unavailability of gas supply?
A25.
No. However, Gaz Métro does face a form of supply risk. To the extent that gas supply
4
costs rise and become more volatile, the market risk to which Gaz Métro is exposed
5
increases. As the level and volatility of gas supply costs increases, Gaz Métro’s
6
customers will tend to use less gas and Gaz Métro will face more difficulty attracting new
7
customers. This tends to worsen outcomes under Gaz Métro’s incentive mechanism, as I
8
describe in more detail below.
9
10
11
B.
Q26. How do these changes in the natural gas commodity price environment translate to
12
13
EFFECTS OF CHANGES IN THE LEVEL AND VOLATILITY OF GAS
COMMODITY PRICES ON GAZ MÉTRO’S BUSINESS RISK
Gaz Métro and its customers?
A26.
Ultimately these price level and volatility changes in the wholesale market are reflected
14
in the retail market. To see this, I have plotted Gaz Métro’s total billing rate for several of
15
its tariff classes in Figures 5 through 7. Using Gaz Métro’s rate D1 as an example, Figure
16
5 shows that during the period October 1995 to September 1998 (“Pre-1999”) the total
17
average billing rate was 27 cents/m3 with a standard deviation of 1.1 cents/m3, and that
18
this amount had increased by 14% over the period. During October 1998 to September
19
2004 (“Post-1999”), the total average rate D1 monthly bill was 42 cents/m3 (a 56 percent
20
increase) while the standard deviation of those amounts increased to 7.6 cents/m3.
21
Starting in October 2004 (“Post-2004”), the total average rate D1 monthly bill increased
22
further to 52 cents/m3 (a 94 percent increase over pre-1999 levels) while the standard
23
deviation of those amounts remained high at 4.3 cents/m3.
23
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 5
Tariff D1
70
Monthly Total Billing Rate (¢/m³)
60
50
40
30
Rate D1
Total
Standard
Average % Change Deviation
20
Pre-1999
Post-1999
Post-2004
10
27.02
42.37
52.44
14.26
63.60
1.88
1.12
7.58
4.33
0
Oct-95
Oct-96
Oct-97
Oct-98
Oct-99
Oct-00
Oct-01
Oct-02
Source: Gaz Métro.
Notes: "Pre-1999" is 10/95 - 9/98. "Post-1999" is 10/98 - 9/04. "Post-2004" is 10/04 - 4/09.
1
24
Oct-03
Oct-04
Oct-05
Oct-06
Oct-07
Oct-08
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 6
Tariff DM
60
Monthly Total Billing Rate (¢/m³)
50
40
30
Rate DM
Total
Standard
Average % Change Deviation
20
Pre-1999
Post-1999
Post-2004
18.18
32.26
40.10
19.19
81.31
-4.83
1.03
7.06
4.38
10
0
Oct-95
Oct-96
Oct-97
Oct-98
Oct-99
Oct-00
Oct-01
Oct-02
Source: Gaz Métro.
Notes: "Pre-1999" is 10/95 - 9/98. "Post-1999" is 10/98 - 9/04. "Post-2004" is 10/04 - 4/09.
1
25
Oct-03
Oct-04
Oct-05
Oct-06
Oct-07
Oct-08
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 7
Tariff D3
60
Monthly Total Billing Rate (¢/m³)
50
40
30
Rate D3
Total
Standard
Average % Change Deviation
20
Pre-1999
Post-1999
Post-2004
10
17.95
31.59
37.87
12.69
77.33
-11.53
0.76
6.75
4.60
0
Oct-95
Oct-96
Oct-97
Oct-98
Oct-99
Oct-00
Oct-01
Oct-02
Oct-03
Oct-04
Oct-05
Oct-06
Oct-07
Oct-08
Source: Gaz Métro.
Notes: "Pre-1999" is 10/95 - 9/98. "Post-1999" is 10/98 - 9/04. "Post-2004" is 10/04 - 4/09.
1
2
Q27. What is the impact of Gaz Métro’s commodity price hedging activities on this
3
4
analysis?
A27.
The analysis above shows Gaz Métro’s rates paid by end users. These rates therefore
5
include the effect of Gaz Métro’s hedging activities. If Gaz Métro had not hedged part of
6
its exposure to commodity price volatility, the volatility in end-consumer rates would
7
have been even greater.
8
Q28. Have the commodity price changes resulted in changes in patterns of gas use?
9
A28.
The fundamental changes in the commodity price environment described above have
10
begun to induce changes in customer use of Gaz Métro’s network. This can be seen in
11
decreases in Gaz Métro’s historical and forecast usage per customer.
26
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
The statistics show significant declines in use per customer over time. Gaz Métro has
2
provided me with data on weather normalized average use per customer for several of its
3
tariff classes.18 These data are presented in Figures 8 and 9 below. For example, for tariff
4
class D1 estimated weather normalized average use in 1999 was 13.9 103 m3. By 2004,
5
estimated weather normalized average use declines to 13.3 103m3, a 4.3% decline. The
6
weather normalized average use estimate for 2009 was 11.3 103 m3, a decline of an
7
additional 14.4%.
Figure 8
Estimated Normalized Average Usage for Tariff Class D1
(Annual 10³m³ per Customer)
15.0
Normalized Average Usage (10³m³)
14.5
14.0
13.5
13.0
12.5
12.0
11.5
-2
00
9
8
20
08
-2
00
7
20
07
-2
00
20
06
-2
00
6
5
20
05
-2
00
4
20
04
-2
00
3
20
03
-2
00
2
20
02
-2
00
1
20
01
-2
00
0
20
00
-2
00
19
99
98
-9
9
19
97
-9
8
19
96
-9
7
19
19
95
-9
6
11.0
Source: Gaz Métro.
8
18
In forecasting weather normalized usage, Gaz Métro considers: diminishing demand due to extreme gas
prices, energy efficiency induced by Gaz Métro programs and undertaken independently by customers,
relative fuel prices (oil and electricity vs. natural gas), Hydro-Québec special rates, macroeconomic
indicators like Québec GDP, and decreases in 30-year average heating degree days for weather
normalization.
27
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 9
Estimated Normalized Average Usage for Tariff Classes DM and D3
(Annual 10³m³ per Customer)
700
Normalized Average Usage (10³m³)
650
600
550
500
-2
00
9
8
20
08
-2
00
7
20
07
20
06
-2
00
-2
00
6
5
20
05
-2
00
20
04
-2
00
4
3
20
03
-2
00
2
20
02
-2
00
1
20
01
-2
00
0
20
00
-2
00
19
99
98
-9
9
19
97
-9
8
19
96
-9
7
19
19
95
-9
6
450
Source: Gaz Métro.
1
2
Q29. Do the recent changes in Gaz Métro’s Performance Incentive Mechanism, namely
3
the new exogenous factor meant to account for declining usage, compensate Gaz
4
Métro for these decreases in average normalized usage?
5
A29.
No. I describe in Section IV.A. how the performance mechanism adjusts for changes in
6
normalized usage. It only adjusts for part of the change in volumes associated with Gaz
7
Métro’s SML (small and medium load) customers. It does not adjust for changes in
8
industrial load, which are more significant in volume terms. Moreover, the volume
9
adjustment is incorporated with a two year lag. Therefore, the fiscal year 2010 revenue
10
cap will be adjusted for annual variation in 2008 SML customer usage.
28
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q30. Has Gaz Métro continued to invest in its distribution business since 1999?
2
A30.
Yes. Gaz Métro continues to make capital investments in its network. As a result, the size
3
of its rate base has grown by about 29% since 1999 (about 9% since 2004).19 In every
4
year since 1999 capital investment has been greater than depreciation of existing
5
investments, indicating that the network continues to expand. This expansion exacerbates
6
the impact of declining per-customer throughput. In Figure 10 I show how the Gaz Métro
7
rate base has increased over time.
Figure 10
Increases in Gaz Métro's Rate Base Since 1999 ($ Million)
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
Source: Gaz Métro.
8
19
Figures for 2008/9 divided by figures for, respectively, 1998/9 or 2004/5.
29
20
08
-2
00
9
20
07
-2
00
8
20
06
-2
00
7
20
05
-2
00
6
20
04
-2
00
5
20
03
-2
00
4
20
02
-2
00
3
20
01
-2
00
2
20
00
-2
00
1
19
99
-2
00
0
19
98
-1
99
9
0
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
2
3
C.
Q31. What is the evidence that fuel oil is a significant competitor to natural gas in respect
4
5
EFFECTS OF INCREASED COMPETITION WITH ELECTRICITY AND FUEL
OIL ON GAZ MÉTRO’S BUSINESS RISK
of supply to industrial customers?
A31.
Figure 11 below shows the relative cost of natural gas and fuel oil for large firm and
6
interruptible customers (bars lower than 100% indicate that natural gas is more expensive
7
than fuel oil). As Figure 11 indicates, natural gas has been more expensive than fuel oil in
8
every year since 1999. Figure 11 includes the impact of the recently-introduced levy for
9
the Green Fund.
Figure 11
Relative Cost of Fuel Oil Vs. Natural Gas for Large Industrial Customers
120%
Firm Industrial Customers;
# 6 Fuel Oil, 1.5% Sulphur
100%
Over 100%, gas is cheaper
Interruptible Industrial Customers;
# 6 Fuel Oil, 1.5% Sulphur
80%
60%
40%
20%
19
99
-2
00
0
20
00
-2
00
1
20
01
-2
00
2
20
02
-2
00
3
20
03
-2
00
4
20
04
-2
00
5
20
05
-2
00
6
20
06
-2
00
7
20
07
-2
00
8
20
08
-2
00
9
20
09
-2
01
0
19
98
-9
9
19
97
-9
8
19
96
-9
7
0%
Source: Gaz Métro Analysis.
10
11
Figure 12 shows load for Gaz Métro’s large industrial (tariffs D4 and D5) customers for
12
selected years between 1999 and 2009. Gaz Métro has lost many large industrial
13
customers since 1999, and its large customer load has decreased significantly. Since 2004
14
the decreasing trend was partially offset by the addition of the TransCanada Bécancour
30
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
cogeneration plant in September 2006, but volumes for 2009 are again below 2004
2
volumes.
Figure 12
Gaz Métro's Large Industrial Customer Load
( Tariff Classes D 4 and D 5 )
Number of Customers
6
3
Volume (10 m )
1998–1999
2004–2005
2007–2008
2008-2009
388
3,550
339
2,650
257
2,980
243
2,310
Source: Gaz Métro.
3
4
Even though Gaz Métro’s industrial load has declined since 1999 and 2004, it is still
5
significant. As discussed above, Gaz Métro’s industrial load was forecasted to be 51% of
6
its total throughput in 2009.
7
Q32. How competitive is natural gas with electricity for home heating in Québec?
8
A32.
According to Gaz Métro’s rate cases filed with the Régie, natural gas has been more
9
expensive than electricity for home heating since 2000. Figure 13 compares the relative
10
fuel costs for natural gas and electricity in Québec (and note that natural gas costs are
11
higher than electricity costs when the bars are smaller than 100%). I show, in Figure 23 in
12
Section IV.B.2., the relative market share for natural gas and electricity use for home
13
heating. In Québec, unlike in Ontario or Canada as a whole, electricity dominates natural
14
gas for home heating.
15
Q33. Why is natural gas at a competitive disadvantage to electricity for residential
16
17
customers in Québec?
A33.
Hydro-Québec’s electricity rates are low because Québec has abundant, inexpensive
18
hydroelectric resources. Currently, Hydro-Québec’s rates are significantly below market
19
value, which offers a subsidy to electricity users relative to users of competing fuels like
31
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
natural gas. The relative value of this subsidy has risen while the formula-based
2
methodology has been in place.
Figure 13
Relative Cost of Electricity vs. Natural Gas For Residential One Family Households
140%
Over 100%, gas is cheaper
120%
100%
80%
60%
40%
20%
20
09
-2
01
0
20
08
-2
00
9
20
07
-2
00
8
20
06
-2
00
7
20
05
-2
00
6
20
04
-2
00
5
20
03
-2
00
4
20
02
-2
00
3
20
01
-2
00
2
20
00
-2
00
1
19
99
-2
00
0
19
98
-1
99
9
19
97
-1
99
8
19
96
-1
99
7
0%
Source: Gaz Métro Analysis; comparison is for Residential One Family Households with New Efficient Equipment.
3
4
Q34. What about the impact of relative price volatility?
5
A34.
As I have discussed, due to the volatility of gas commodity costs, Gaz Métro’s rates have
6
been very volatile since 1999. In contrast, electricity prices are relatively stable, changing
7
no more than annually, and only by small amounts. I compare Gaz Métro and Hydro-
8
Québec’s total billing rates for residential customers since 1998 in Figure 14 below.
32
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 14
3
Gaz Métro Gas Rate (Tariff D1, ¢/m ) Compared to Hydro-Québec Electricity Rate (¢/kWh)
70
10
9
Monthly Total Billing Gas Rate (¢/m³)
8
50
7
6
40
5
30
4
3
20
2
Monthly Total Billing Electricity Rate (¢/kWh)
60
10
1
0
May-98
0
May-99
May-00
May-01
May-02
May-03
May-04
May-05
May-06
May-07
May-08
Gas Rate
Electricity Rate
Sources: Gaz Métro and "Comparison of Electricity Prices in Major North American Cities", Hydro Québec, years 2002 to 2008.
Notes: Assumes electricity consumption for a domestic customer to be 1000 kWh per month. Excludes taxes.
1
2
Q35. What is the “heritage pool”?
3
A35.
The “heritage pool” is 165 TWh of electricity priced at 2.79 cents/kWh that is supplied
4
annually by Hydro-Québec Production to Hydro-Québec Distribution for its end use
5
customers. Both the size of the heritage pool and the price of heritage pool power are set
6
by law.
7
Q36. Is the heritage pool adequate to meet the needs of Hydro-Québec’s end use
8
9
customers?
A36.
No. Hydro-Québec makes some incremental power purchases at market prices to meet
10
the needs of its end use customers. However, these purchases are small relative to the size
11
of the heritage pool. Hydro-Québec stated in its most recent strategic plan:
12
13
In 2005, the heritage pool filled 98% of energy needs,
assuring Québec customers of electricity rates that are among
33
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
2
3
4
the lowest in North America. The relative share of the
heritage pool in terms of total supplies will gradually decline
in the coming years, but will remain above 90% in 2014.20
Q37.
5
6
Will incremental power purchases have the effect of increasing Hydro-Québec’s
electricity prices?
A37.
Yes, but the effect is very small because the amounts spent on higher priced incremental
7
purchases are averaged with a much larger amount of heritage pool power priced at 2.79
8
¢/kWh. Hydro-Québec recently accepted 15 bids in response to a tender call for wind
9
power resources at an average cost of 10.5¢/kWh.21 If all of the incremental power
10
purchases contemplated in Hydro-Québec’s 2006-2010 Strategic Plan are priced at
11
10.5¢/kWh, the expected incremental supplies will only cause electricity prices to
12
increase by 1.5% or less annually to 2014, as shown in Figure 15 below.
13
It should also be noted that, to date, actual Québec electricity demand has been lower
14
than forecast in Hydro-Québec’s 2006-2010 Strategic Plan. This led to the shutdown of
15
the Bécancour gas-fired power plant on January 1, 2008, and tends to decrease electricity
16
price expectations. Hydro-Québec’s states in its Strategic Plan that “lower-than-expected
17
sales would lower supply costs, and therefore limit projected rate increases.”22
20
Hydro-Québec, Strategic Plan, 2006-2010, Adjusted Version, September 15, 2006, p. 4.
21
“Tender call for 2,000 MW of wind power: Hydro-Québec accepts 15 bids,” Hydro Québec press release,
May 5, 2008.
22
Hydro-Québec, Strategic Plan, 2006-2010, Adjusted Version, September 15, 2006, p.52.
34
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 15
Hydro-Québec Electricity Price Increases Expected as a Result of
Incremental Supplies
Year
1998
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Heritage Pool
Supply 1
TWh
Incremental
Non-Heritage
Supply 2
TWh
3
Notes:
1
Québec Electricity Sales
(incl. transmission and
distribution losses)
TWh
Source:
Average Annual
Increase in Average
Cost of Supply Relative
Average Cost of Supply
to 1998
¢/kWh
%
182.6
182.8
187.1
188.1
189.9
192.0
178.6
178.5
178.9
178.9
178.9
178.9
4.0
3.9
9.1
10.7
11.1
12.4
2.79
2.79
2.96
2.95
3.16
3.23
3.24
3.29
194.8
178.9
15.0
3.39
1.4%
196.1
178.9
17.9
3.49
1.4%
1
Supply price = 2.79 ¢/kWh. Heritage pool is 165 TWh plus losses.
2
Supply price = 10.5 ¢/kWh.
3
Québec electricity prices were frozen at the 1997 level from 1998 to 2003 inclusively.
Forecast supplies and the heritage pool price from Hydro-Québec 2006-2010 Strategic Plan, p. 4.
2
Q38. What is the impact of the new Green Fund levy?
3
A38.
The new Green Fund levy on hydrocarbons increases the cost of both natural gas and fuel
4
oil. On an energy equivalent basis, the tax would normally be expected marginally to
5
favour gas over fuel oil, because natural gas is the cleaner fuel. However, the current
6
rates on fuel oil and natural gas are almost identical (the tax is 1.06 ¢/m3 for natural gas
7
and 1.09 ¢/m3 on an energy equivalent basis).23 Furthermore, after adding the Green Fund
8
levy fuel oil is still cheaper than natural gas for industrial customers (see Figure 11
9
above).
23
The rates are so similar because the natural gas tax rate is effectively equal to the emissions from natural
gas consumption last year, divided by the estimated volume distributed this year. Since natural gas
consumption is declining, the rate is higher than it would be on an emissions-equivalent basis.
35
0.8%
0.7%
1.4%
1.5%
1.4%
1.4%
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
The Green Fund levy will not increase the price of electricity to any significant extent,
2
because almost none of the electricity generated by Hydro-Québec results in greenhouse
3
gas emissions, so Hydro-Québec’s tax bill will be very low. The levy therefore favours
4
electricity over natural gas.
5
Part of the Green Fund is being used to support a program to reduce consumption of fuel
6
oil, and part of this program is aimed at encouraging industrial customers to switch from
7
fuel oil to natural gas (or, for those customers able to burn either fuel, to encourage them
8
to use more gas and less fuel oil). The total amount of support available is relatively
9
small (around $4.5m per year), and I understand that no projects have yet been proposed
10
under the program. The Green Fund levy therefore also increases gas market uncertainty.
11
The Green Fund levy encourages some consumers to switch to gas, but, for the average
12
industrial customers shown in Figure 11, gas is still more expensive than fuel oil.
13
14
D.
15
Q39. How does Gaz Métro’s performance incentive scheme expose Gaz Métro to volume
16
17
EFFECTS OF GAZ MÉTRO’S PERFORMANCE INCENTIVE MECHANISM ON
ITS BUSINESS RISK
risk?
A39.
A major source of business risk comes from the fact that Gaz Métro’s performance
18
incentive scheme gives a poor match between costs and revenues when volumes change.
19
Gaz Métro’s revenue cap is a cap on average revenue per unit of gas distributed, because
20
it is derived from the rates in the preceding year, less the X factor, multiplied by forecast
21
volumes distributed. If volumes distributed fall, Gaz Métro’s revenue cap also falls. The
22
reduction in revenue cap is not completely proportional to the fall in volumes because
23
there is partial protection for changes in small and medium load consumption. However, I
24
estimate that only about 30% to 40%24 of total volumes distributed are covered by the
24
Assuming that the number of customers covered by the exogenous volume factor has not changed since
2007.
36
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
volume change exogenous factor. Thus, in respect of more than half of volumes, Gaz
2
Métro is exposed to volume risk.
3
While Gaz Métro’s revenue cap is linked to volumes, most of its costs are fixed. As
4
volumes change over time, therefore, there is highly likely to be a mismatch between
5
costs—mostly fixed—and the revenue cap, which is mostly proportional to volume.
6
If consumption falls, and particularly if consumption by industrial customers falls, Gaz
7
Métro’s revenue cap falls, but its costs will not fall to the same extent. It would as a result
8
be much more difficult for Gaz Métro to out-perform its revenue cap and earn incentive
9
payments.
10
The results of the mechanism support this analysis: in 2008 the forecast productivity
11
gains exceeded the X factor by about $9.6M, whereas in 2009 the forecast gains were
12
only $3.6M above the X factor. 2008 rate case volumes were approximately the same as
13
2007 rate case volumes (an increase of 0.4%), whereas 2009 rate case volumes were 11%
14
below 2008 volumes. 2010 volumes are expected to be lower still.25 Gaz Metro’s
15
marketing forecast for 2010 volumes is about 400 million m3 below the equivalent 2009
16
marketing forecast. Most of the reduction is ascribed by Gaz Métro to the economic
17
downturn, the competitiveness of fuel oil and energy efficiency. Due to major
18
investments Gaz Métro must make in its aging gas network and the decrease in volumes
19
not compensated by the volume change exogenous factor, Gaz Métro expects that there
20
will be little or no productivity gains for 2010.
21
Q40. Why doesn’t the exogenous volume factor protect Gaz Métro from volume risk?
22
A40.
First, most of Gaz Métro’s volumes are not covered by the exogenous volume factor at
23
all: the exogenous factor only covers volumes distributed to small and medium load
24
customers that have been supplied since 1999 without intervention by Gaz Métro’s sales
25
Volumes for the 2010 rate case are not yet available.
37
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
team. As of August 1st 2006, that group included 126,235 customers.26 Assuming that no
2
customers have left this group and that the proportion of medium customers included is
3
the same as the proportion of the small customers that are included, I estimate that this
4
group accounts for 30%–40% of volumes. Thus, Gaz Métro is exposed to volume risk
5
with respect to 60%–70%% of volumes.27
6
Second, the exogenous volume factor only partially decouples revenues from volumes:
7
Gaz Métro is still exposed to 10% of the volume risk. For the D1 customer class (which
8
accounts for the majority of the customers and the volumes covered by the exogenous
9
volume factor), Gaz Métro estimates that approximately 96% of its costs to distribute gas
10
to these customers are fixed.
11
Third, Gaz Métro has to pay for the exogenous volume factor. In respect of volumes not
12
covered, Gaz Métro has to achieve productivity improvements of 0.3% per year in order
13
to “stand still”—the revenue cap falls by this amount each year due to the X factor. In
14
respect of the volumes that are covered by the exogenous factor, Gaz Métro has to
15
achieve productivity improvements of 1.07% per year in order to stand still.28
26
“Performance Incentive Mechanism Agreed in Negotiated Settlement Process (NSP) R-3599-2006,”
[Translation – Not approved by Participants], April 19, 2007, p. 15, line 29.
27
Gaz Metro is not fully exposed to changes in these volumes because some customers have made volume
commitments. However, these commitments do not fully protect Gaz Metro, as shown by the reduced
productivity gains in 2009 and 2010 and the reduced volumes in the 2009 rate case.
28
If volumes do not change from year to year, the exogenous volume factor falls by 0.86% x 0.9 = 0.77%.
The revenue cap additionally falls by the X factor of 0.3%, so overall productivity must improve by 0.77%
+ 0.3% = 1.07% in order to stand still if volumes are constant.
38
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q41. How does exposure to volume risk give rise to increased business risk?
2
A41.
Investors need to be compensated for bearing risks that they cannot diversify away. An
3
important part of overall returns to Gaz Métro’s investors comes from the operation of its
4
performance incentive mechanism. However, this mechanism includes volume risk: the
5
incentive scheme is much less likely to pay out if volumes fall. Volumes are likely to fall
6
when general economic activity as a whole is falling—for example, gas demand from
7
industrial customers is likely to fall when industrial output is falling. The volume risk in
8
the incentive mechanism is therefore a source of systematic risk, and therefore
9
contributes to Gaz Métro facing increased business risk. Again, the most recent results of
10
the mechanism, at a time when the general economy is performing badly, support this
11
conclusion.
12
13
V.
14
Q42. Have you compared Gaz Métro’s allowed return under the current, formula-based
15
16
GAZ MÉTRO’S BUSINESS RISK COMPARED TO OTHER GAS UTILITIES IN
CANADA AND THE UNITED STATES
methodology with allowed returns of other companies of comparable risk?
A42.
Yes. I have compared Gaz Métro’s allowed ROE and total return under the current
17
formula to those of U.S. LDCs. I find that since the formula-based methodology was
18
adopted, Gaz Métro’s allowed ROE and total return have been significantly lower than
19
those granted to U.S. LDCs. I find that this difference in allowed returns cannot be
20
justified based on differences in regulatory treatment or business risk. Indeed, I find that
21
Gaz Métro’s long-term risk tends to be greater than that of typical LDCs in Canada and
22
the U.S. due to Gaz Métro’s unique business environment.
23
Dr. Vilbert relies in part on market returns for a sub sample of U.S. LDCs to estimate the
24
cost of capital for Gaz Métro. I show that the companies in Dr. Vilbert’s sub sample are
25
of lower risk than Gaz Métro. Dr. Kolbe concludes, based in part on my evidence, that
26
Gaz Métro’s ATWACC must be at least as high as the ATWACCs of Dr. Vilbert’s
27
samples.
39
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
2
3
A.
Q43. How does Gaz Métro’s allowed return under the current, formula-based
4
5
GAZ MÉTRO’S ALLOWED RETURN COMPARED TO ALLOWED RETURNS
FOR U.S. LDCS
methodology compare to allowed returns for U.S. LDCs?
A43.
Gaz Métro’s allowed return on capital under the formula is significantly below the
6
returns allowed by regulators for LDCs in the U.S. I have compared Gaz Métro’s after-
7
tax weighted average return on capital (“ATWACC”) under the Régie’s formula with the
8
allowed returns (ATWACCs) awarded for U.S. LDCs by state regulatory commissions
9
during the period January 1999 – August 2008. The results are shown in Figure 16 below.
10
They show that during the period that the Régie-approved formula has been in place,
11
allowed returns for U.S. LDCs have always been greater than Gaz Métro’s allowed
12
return.
Figure 16
Gaz Métro's Authorized ATWACC Compared To Authorized ATWACCs for U.S. LDCs
Jan 1999-Oct 2008
10.00%
9.50%
ATWACCs for
US LDCs
9.00%
8.50%
ATWACC
8.00%
7.50%
7.00%
6.50%
6.00%
5.50%
5.00%
1/1/99
13
Gaz Métro's ATWACC
5/15/00
9/27/01
2/9/03
6/23/04
11/5/05
3/20/07
8/1/08
Source: "Regulatory Focus", Regulatory Research Associates, ROE Public Utilities Fortnightly 2006, 2007 and 2008 Surveys, Brattle research.
Notes: Assumes a 4.6% after-tax cost of debt. Treats preferred equity as debt.
40
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q44. Is this difference in allowed returns for Gaz Métro and for U.S. LDCs caused by a
2
3
difference in allowed return on equity or a difference in financial risk?
A44.
Gaz Métro’s allowed return on capital is lower than that of U.S. LDCs because its
4
allowed return on equity is lower than that of U.S. LDCs, and because its equity thickness
5
tends to be lower than that of U.S. LDCs. In Figure 17, I plot the allowed returns on
6
equity against the equity thickness for Gaz Métro and for the U.S. LDCs shown in Figure
7
16. Most U.S. LDCs have equity thicknesses in the range of 40 to 60 percent, implying
8
that their equity investors face lower financial risk than do equity investors in Gaz Métro.
14.00%
Figure 17
Gaz Métro's Authorized ROE and Equity Thickness
Compared to Authorized ROE and Equity Thickness for US LDCs
Jan 1999-Oct 2008
13.00%
Authorized ROE
for US LDCs
Authorized ROE
12.00%
11.00%
10.00%
9.00%
Gaz Métro's Authorized ROE
8.00%
30.00%
40.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Common Equity % Capital
9
Source: "Regulatory Focus", Regulatory Research Associates, RoE Public Utilities Fortnightly 2006, 2007 and 2008 Surveys, Brattle research.
41
100.00%
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q45. Given the differences in the regulation of local distribution companies between
2
Canada and the U.S., why should the Régie consider comparisons of allowed returns
3
across the two jurisdictions?
4
A45.
First, while there are some differences in regulatory procedure between Canada and the
5
U.S., the differences are not so great as to make comparisons in Canadian and U.S.
6
allowed returns irrelevant. When it comes to the element of risk that matters most to
7
investors (i.e., long-term earnings and capital cost recovery), the regulatory regimes on
8
both sides of the border have fundamentally the same design. Under traditional cost of
9
service regulation in both Canada and the U.S., utilities are permitted to recover their
10
invested capital (which is measured as depreciated original cost) plus a reasonable return
11
on their investment. This allowed return should meet three standards. It should be
12
equivalent to returns available for investments of comparable risk, it should be adequate
13
to maintain the utility’s financial integrity, and it should allow the utility to attract capital
14
on reasonable terms. These fundamental similarities between the economics of U.S. and
15
Canadian utilities operating under traditional cost of service, and the way they are
16
regulated, make comparisons of allowed returns between the two jurisdictions highly
17
meaningful.
18
While there are differences in regulatory context between the two countries, these
19
differences primarily affect earnings variability risk and not fundamental capital recovery
20
risks. Canadian utilities are generally subject to annual determinations of their cost of
21
service, and utilize deferral accounts to adjust for differences between forecast and actual
22
revenues and costs between annual rate cases. In the U.S., utility rate cases are relatively
23
infrequent, and utilities typically do not utilize deferral accounts to adjust for deviations
24
in revenues and costs. These differences can cause year-to-year returns on U.S. utilities to
25
be more variable relative to allowed returns than year-to-year returns on Canadian
26
utilities. While U.S. utilities may have higher variability risk because of these differences,
27
undue emphasis should not be placed on variability risk because it is fundamental risk
28
that matters most to investors. This difference in earnings variability risk does not make
29
comparisons between U.S. and Canadian utilities inappropriate. Rather, the similarities in
42
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
fundamental risks and capital recovery make comparisons between U.S. and Canadian
2
utilities appropriate.29
3
Q46. You’ve stated that it is appropriate to compare utilities that operate under
4
traditional cost of service regulation in Canada and the U.S., but Gaz Métro
5
operates under a performance incentive mechanism, not traditional cost of service
6
regulation. How does Gaz Métro’s risk under its Performance Incentive Mechanism
7
compare to the risk of U.S. utilities operating under traditional cost of service
8
regulation?
9
A46.
In general, Gaz Métro’s Performance Incentive Mechanism exposes equity investors to
10
greater business risks than would traditional cost of service regulation. This is primarily
11
due to the productivity gains and overearnings sharing and service performance threshold
29
The NEB recently found that U.S. comparisons were highly relevant for determining the allowed return for
the TQM pipeline, which serves Québec. The NEB stated:
In the Board’s view, global financial markets have evolved significantly since 1994. Canada has
witnessed increased flows of capital and implemented tax policy changes that facilitate these
flows. As a result, the Board is of the view that Canadian firms are increasingly competing for
capital on a global basis. The Board notes that Canada has been diversifying its business partners
such that there is currently proportionally less Canadian foreign direct investment in the United
States than there was in the 1990’s. Nonetheless, the evidence is also clear that the United States
is the single most important recipient of Canadian investments.
A fair return on capital should, among other things, be comparable to the return available from the
application of the invested capital to other enterprises of like risk and permit incremental capital
to be attracted to the regulated company on reasonable terms and conditions. TQM needs to
compete for capital in the global market place. The Board has to ensure that TQM is allowed a
return that enables TQM to do so. Comparisons to returns in other countries would be useful, but
challenging, in terms of differences in business risks and business environment. As a result, the
Board is of the view that pipeline companies operating in the U.S. have the potential to act as a
useful proxy for the investment opportunities available in the global market place.
******
Overall, the Board finds that the risks resulting from the regulatory environment are higher for
U.S. pipelines than for Canadian pipelines, and finds that this was also true in 1994. However, the
Board is of the view that the risks faced by TQM and those faced by U.S. pipelines are not so
different as to make them inappropriate comparators. The Board accepts that there are many
similarities between the risks faced by pipelines in the two countries. This is due to the two
regulatory models sharing, to a large extent, the same fundamental principles. Moreover,
Canadian and U.S. pipelines operate in what the Board views as an integrated North American
natural gas market, which informs the choices made by regulators in the different jurisdictions.
See National Energy Board, RH-1-2008, pp. 66-68.
43
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
features of the Performance Incentive Mechanism. How much greater the risk is depends
2
on the particular form of cost of service regulation to which it is being compared. In the
3
U.S., most cost of service regimes do not make extensive use of deferral accounts, and
4
many do not require utilities to file frequent rate cases. Under this approach the regulator
5
is making use of “regulatory lag” (the time between cost-of-service rate cases) as an
6
incentive mechanism, i.e., to the extent the utility is able to reduce costs or increase
7
productivity between rate cases, its earned returns will vary between rate cases because
8
rates do not change between cases. As a result, this approach to cost of service regulation
9
exposes utilities to somewhat greater business risks than does traditional cost of service
10
regulation with “true ups” as often practiced in Canada.
11
Gaz Métro’s Performance Incentive Mechanism exhibits some of the characteristics of
12
cost of service regulation with regulatory lag. However, it is a riskier regime than US-
13
style regulatory lag because the revenue cap includes the effect of projected productivity
14
gains that must be shared with Gaz Métro’s customers before any gains or overearnings
15
accrue to Gaz Métro’s shareholders. As a result, if Gaz Métro performs well under its
16
performance incentive scheme, most of the out-performance is passed on to its customers
17
immediately as reduced rates. Furthermore, when the performance incentive mechanism
18
ends Gaz Métro could be in a position of having to pay off accrued underperformance
19
under the mechanism.
20
Q47. Would it also be meaningful to compare the allowed returns of local distribution
21
22
companies such as Gaz Métro with those of transmission pipelines?
A47.
Yes. Local distribution companies and transmission pipelines are all asset-intensive,
23
regulated enterprises that are in sufficiently similar businesses that comparing their
24
allowed returns is meaningful. The differences between LDCs and transmission pipelines
25
from a business risk perspective largely involve the level of competition that they face in
26
the markets they serve. Many pipelines face market risk due to competitive bypass
27
because they own transmission or storage assets that serve third parties in competition
28
with other facilities. While most LDCs do not face bypass risk in their franchised service
44
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
territories, some LDCs do face significant market risk, either due to competition from
2
alternative fuels or from the loss of industrial load due to economic conditions, and thus
3
they may face market risk similar to that of transmission pipelines. Gaz Métro certainly
4
falls within that category.
5
Q48. Is there a difference between the allowed returns required for new and existing
6
7
natural gas infrastructure?
A48.
No there is not. To create a dichotomy between new and existing infrastructure with
8
respect to the allowed return on capital is bad policy and would be economically
9
inefficient. As long as new and existing investments face the same risks over their
10
lifetimes, there is no difference in the market’s required return on capital for such
11
investments. To treat them differently would create a “vintaging” problem, where new
12
investment would be encouraged at the expense of upgrading or expanding existing
13
infrastructure. Such a policy would be inefficient because it will create incentives for
14
suboptimal investment decisions.
15
B.
16
Q49. How does Gaz Métro’s business environment compare to other LDCs in Canada
17
18
GAZ MÉTRO’S UNIQUE BUSINESS ENVIRONMENT
and the U.S.?
A49.
Gaz Métro’s business environment is unique compared to other LDCs in Canada and the
19
U.S. in at least three respects: (1) natural gas has a significantly lower penetration rate in
20
Québec, in Gaz Métro’s service territory, than in the service territories of typical LDCs in
21
Canada and the U.S.; (2) Gaz Métro faces significantly stronger competition from
22
electricity than other LDCs in Canada and the U.S.; and (3) Gaz Métro has a large
23
industrial customer load, an industrial customer load that is larger than the LDCs in Dr.
24
Vilbert’s U.S. LDC sample.
45
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
2
1.
Q50. How does natural gas penetration in Québec compare to natural gas penetration in
3
4
Natural Gas Penetration in Québec
other Canadian provinces?
A50.
Natural gas usage for home heating is significantly lower in Québec than in all Canadian
5
provinces except the Atlantic provinces. See Figure 18 below, which was compiled using
6
data from Natural Resource Canada for 2006. Natural gas represents 9% of the energy
7
used for home heating in Québec, compared to an average of over 75% of the energy
8
used for home heating in Manitoba, British Columbia, Ontario, Saskatchewan and
9
Alberta.
Figure 18
Fuel Mix for Home Heating in Canadian Provinces in 2006
100%
90%
Other
Wood
% of Energy Use for Heating
80%
70%
Heating
Oil
60%
50%
40%
30%
Electricity
20%
10%
0%
Natural
Gas
Quebec
Atlantic
Manitoba
British
Columbia and
Territories
Ontario
Saskatchewan
Alberta
Source: Natural Resources Canada, "Comprehensive Energy Use Database"
Notes: "Other" includes propane and coal; Atlantic Region is comprised of Newfoundland, Prince Edward Island, Nova Scotia, and New Brunswick
10
11
Total natural gas usage is also significantly lower in Québec than in all other Canadian
12
provinces except for the Atlantic provinces. Figure 19 shows primary natural gas and
13
other fuel usage for the Canadian provinces in 2007. It shows that natural gas usage as a
46
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
percentage of total primary fuel usage gas is significantly lower in Québec than in
2
Ontario, Manitoba, British Columbia, Saskatchewan and Alberta.
Figure 19
Fuel Mix in Canadian Provinces in 2007
100%
90%
Primary
Electricity
% of Energy Consumption
80%
70%
60%
50%
Petroleum
40%
30%
20%
Coal
10%
Natural
Gas
0%
Quebec
Atlantic
Ontario
Manitoba
British
Columbia &
Territories
Saskachewan
Alberta
Source: Statistics Canada
Notes: Primary electricity is hydro and nuclear electricity. Atlantic provinces are Newfoundland, Prince Edward Island, Nova Scotia and New
Brunswick.
3
4
Q51. How does natural gas penetration in Québec compare to natural gas penetration in
5
6
the U.S.?
A51.
Natural gas usage for home heating is significantly higher in the U.S. than in Québec. See
7
Figure 20 below, which was compiled using the most recently available survey of
8
Residential Energy Consumption compiled by the U.S. Energy Information
9
Administration, for 2005. Natural gas represents 55% or more of the energy used for
10
home heating in the Northeast, South, West and Midwest census regions of the U.S.
47
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 20
Fuel Mix for Home Heating in US in 2005
100%
Kerosene
LPG
90%
% of Energy Use for Heating
80%
Heating Oil
70%
60%
Electricity
50%
40%
30%
Natural Gas
20%
10%
0%
Northeast
South
West
Midwest
Source: EIA, "Residential Energy Consumption Survey 2005"
1
2
Total natural gas usage is also greater in the U.S. than in Québec. Figure 21 shows
3
natural gas and other fuel usage by census region in the U.S in 2006. It shows that natural
4
gas usage as a percentage of total primary fuel usage in Québec (see Figure 19) is
5
significantly lower than natural gas usage in the U.S., where natural gas usage is at least
6
20% of total fuel usage in every census region.
48
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 21
Fuel Mix in US Census Regions in 2006
100%
Other
Biomass
Nuclear
Hydro
90%
% of Energy Consumption
80%
70%
Petroleum
60%
50%
40%
Coal
30%
20%
Natural Gas
10%
0%
Midwest
Northeast
South
West
Source: EIA
Notes: Natural Gas excludes supplemental gaseous fuels; "Other" includes geothermal, wind, photovoltaic, solar, thermal energy and net imports of
electricity.
1
2
3
2.
Q52. How competitive is natural gas with electricity in other Canadian provinces and in
4
5
Competition from Electricity
the U.S.?
A52.
Electricity rates are significantly higher in most other major cities in Canada and the U.S.
6
than in Québec. Therefore, electricity has a greater competitive advantage compared to
7
natural gas in Québec than in most other major cities in Canada and the U.S. Figure 18
8
uses data from Hydro-Québec to compare residential electricity rates in major North
9
American cities as of April 2008. Figure 22 shows that only residential rates in Winnipeg
10
and Seattle were lower than residential rates in Québec as of April 2008. The pattern is
11
similar for larger commercial and industrial customers.
49
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 22
Average Residential Electricity Rates for Major North American Cities
for Monthly Consumption of 1000 KWh
(April 1, 2008)
25
21.3
20
19.1
14.8
14.9
Houston, TX3
(Reliant Energy)
15
Charlottetown, PE
(Maritime Electric)
18.1
11.8
Halifax, NS
(Nova Scotia Power)
Vancouver, BC
(BC Hydro)
11.6
Detroit, MI3
(Detroit Edison)
Seattle, WA
(Seattle City Light)
11.5
Moncton, NB
(NB Power)
Winnipeg, MB
(Manitoba Hydro)
11.2
Chicago, IL3
(Commonwealth Edison)
7.0
11.2
Toronto, ON
(Toronto Hydro)
6.8
10.9
Regina, SK
(SaskPower)
6.4
9.5
10.6
Ottawa, ON
(Ottawa Hydro)
6.8
Montréal, QC
(Hydro-Québec)
8.7
10.4
St. John’s, NL2
(Newfoundland Power)
10
10.3
Miami, FL3
(Florida Power and Light)
¢/kWh
13.5
New York, NY3
(Consolidated Edison)
Boston, MA
(Boston Edison)
San Francisco, CA3
(Pacific Gas and Electric)
Q53. What is the impact of the new Green Fund levy on natural gas versus electricity
3
4
Edmonton, AB
(EPCOR)
Source: "Comparison of Electricity Prices in Major North American Cities, 2008", Hydro Québec.
Notes: Rates are in Canadian dollars and exclude taxes.
1
2
Nashville, TN
(Nashville Electric Service)
0
Portland, OR
(Pacific Power and Light)
5
competition?
A53.
The Green Fund levy is paid by energy distributors, including Gaz Métro, and in Gaz
5
Métro’s case the levy is passed through directly to customers. The effect of the levy is to
6
increase the delivered natural gas cost paid by consumers. In particular, the cost of
7
natural gas is increased relative to the cost of electricity. It therefore further increases the
8
pressure on natural gas from competition with electricity.
9
Q54. How does Gaz Métro’s growth rate in the home-heating market compare to other
10
11
jurisdictions?
A54.
Gaz Métro’s penetration rate in housing starts in Québec is significantly lower than the
12
penetration rate for natural gas in new, single-family homes in the U.S. Gaz Métro
13
supplied natural gas to 12.3% of all housing starts in Québec in 2008 and 8.9% of all
50
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
housing starts in Québec in 2007, while natural gas was used to heat 60% of newly
2
constructed single family homes in the U.S. in 2007.30 Gaz Métro had a lower penetration
3
rate in new residential housing despite its significant spending on advertising and other
4
market initiatives.
5
Despite any success Gaz Métro has had supplying new housing with natural gas,
6
electricity remains the dominant fuel for home heating in Québec. See Figure 18 above
7
(which looks at the fuel mix for home heating in Québec and other Canadian provinces in
8
2006) and Figure 23 below, which looks at the percentage of homes in Québec heated by
9
natural gas during 1997-2007. The share of homes in Québec heated by electricity has
10
been over 70% in recent years, while the share of homes in Québec heated by natural gas
11
has remained fairly steady at only 5-6%. This is in stark contrast to the situation in
12
Ontario, where natural gas is the dominant fuel, or Canada as a whole, where around half
13
of all homes are use gas. See Figure 24.
30
Gaz Métro Limited Partnership, Annual Information Form, Fiscal Year Ended September 30, 2008, p.26.
American Gas Association, Table 10-4, “Market Share Of Private Housing Completions By Heating Fuel,
1990-2007, (Percent)”, from U.S. Bureau of the Census, Characteristics of New Housing 2007
51
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 23
Space Heating by Fuel type in Québec
80
Fuel Oil & Other Liquid
Natural Gas (piped gas)
Electricity
Wood
70
% of households
60
50
40
30
20
10
0
1997
1998
1999
2000
2001
2002
Source: Statistics Canada, Table 203-0019: Survey of Household Spending; Dwelling characteristics
1
52
2003
2004
2005
2006
2007
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
Figure 24
Space Heating by Natural Gas in Quebec, Canada, and Ontario
80.0
Quebec
Canada
Ontario
70.0
% of households
60.0
50.0
40.0
30.0
20.0
10.0
0.0
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
Source: Statistics Canada, Table 203-0019: Survey of Household Spending; Dwelling characteristics
1
2
3
3.
Q55. What portion of Gaz Métro’s load is represented by deliveries to industrial
4
5
Gaz Métro’s Industrial Customer Load
customers?
A55.
In fiscal year 2008, approximately 52% of Gaz Métro’s load (measured on a normalized
6
basis) was deliveries to industrial customers.31 In fiscal year 2007, approximately 57% of
7
Gaz Métro’s load (measured on a normalized basis) was deliveries to industrial
8
customers.
31
Gaz Métro Limited Partnership Annual Information Form, Fiscal Year Ended September 30, 2008, p. 21.
53
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q56. How does Gaz Métro’s industrial load compare to that of other LDCs in the U.S.?
2
A56.
Figure 25 below compares Gaz Métro’s industrial load in fiscal year 2007 to the
3
industrial load in calendar year 2007 of the U.S. LDCs in Dr. Vilbert’s pure play U.S.
4
LDC sub sample.32 It shows that Gaz Métro’s industrial load was higher than each of the
5
U.S. LDCs in Dr. Vilbert’s sub sample.
Figure 25
Gaz Métro Industrial Load Compared to Dr. Vilbert's Pure Play U.S. LDC Sub Sample (2007)
60%
50%
% of Total Throughput
40%
30%
20%
10%
0%
Gaz Métro
NICOR GAS
South Jersey
Industries Inc.
AGL Resources
Northwest
Natural Gas Co.
Southwest Gas Piedmont Natural
Corp.
Gas Co
Q57. What does Gaz Métro’s relatively large industrial load suggest for Gaz Métro’s
8
9
Laclede Group
Inc.
Sources: EIA Form 176 data for 2007. Gaz Métro.
Notes: Gaz Métro's Industrial Load Factor is calculated using actual, non-normalized deliveries to customers on tariffs D4 and D5 for the 2007 calendar
year so that it is comparable with the industrial throughput calculated for the U.S. LDCs in Dr. Vilbert's sub sample.
6
7
WGL Holdings
Inc.
business risk?
A57.
Gaz Métro’s relatively large industrial load increases its business risk. Industrial
10
customers tend to have loads that are more variable and unpredictable than other
11
customer classes. They tend to have a greater ability to switch from natural gas to
32
Attachment B to my testimony describes the LDCs in Dr. Vilbert’s pure play U.S. LDC sub sample in
greater detail.
54
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
competing fuels (particularly fuel oil) when natural gas commodity prices rise relative to
2
the prices of competing fuels. Moreover, in recent years many industrial customers have
3
decreased the size of their operations or have shut down in response to macroeconomic
4
conditions and fuel costs. This greater variability in industrial customers’ load is
5
particularly striking when compared to load variations for residential and commercial
6
customers (SML customers). SML customers’ load varies due to changes in weather and
7
to increased energy conservation. However, these more predictable variations can be at
8
least partially addressed through weather normalization mechanisms and through
9
mechanisms like that recently incorporated into Gaz Métro’s Performance Incentive
10
Mechanism that is meant to account for declining customer usage.
11
The 2009 performance incentive mechanism results illustrate how Gaz Métro is exposed
12
to business risk through exposure to declining volumes for industrial customers.
13
14
C.
15
Q58. How does Gaz Métro’s risk compare with the U.S. LDCs included in Dr. Vilbert’s
16
17
GAZ MÉTRO’S LONG-TERM RISK IS GREATER THAN THAT OF THE U.S.
LDCS IN DR. VILBERT’S PURE PLAY SUB SAMPLE
pure play U.S. LDC sub sample?
A58.
In my opinion, the eight companies in Dr. Vilbert’s pure play U.S. LDC sub sample are
18
of lower risk than Gaz Métro. The eight companies in this sub sample were selected
19
because they represent relatively “pure play” U.S. LDCs, with operations concentrated in
20
regulated gas distribution and assets largely devoted to traditional LDC service. The
21
fundamental long-term risk of the companies in Dr. Vilbert’s sub sample are lower than
22
Gaz Métro’s because the companies in Dr. Vilbert’s sub sample have smaller industrial
23
load, face less competition and have lower regulatory risk (since their rates are
24
determined using traditional cost of service methodologies and many employ
25
mechanisms like rate decoupling that reduce their short-term revenue variability).
26
I have included a table as Attachment B to this evidence that presents information useful
27
in assessing the risk of the eight U.S. LDCs included in Dr. Vilbert’s sub sample relative
55
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
to Gaz Métro’s risk. The table presents information on business activities by segment
2
(distribution, transmission and storage), distribution service customer mix, and bypass
3
risk for distribution customers. It also presents information on how rates are determined,
4
including the use of decoupling or margin stabilization mechanisms, weather
5
normalization and gas cost adjustment mechanisms. Finally, the table presents
6
information on the diversified (unregulated) activities of the holding companies in Dr.
7
Vilbert’s pure play U.S. LDC sub sample.
8
Q59. Please explain with reference to Attachment B how you reached the conclusion that
9
10
Dr. Vilbert’s U.S. LDC sub sample is a relatively “pure play” LDC sample.
A59.
The eight companies in Dr. Vilbert’s sub sample have operations concentrated in
11
regulated gas distribution. I base this conclusion on two factors. First, the companies in
12
Dr. Vilbert’s sub sample derive most of their income from regulated gas distribution
13
services. Please refer to the rows labelled “LDC Net Income as a Percentage of the
14
Company’s Net Income in 2008” on pages 2 and 4 of Attachment B. The companies in
15
Dr. Vilbert’s sample derived from 51 percent - 98 percent of their net income from
16
regulated distribution activities in 2008. Similarly, between 76 percent - 97 percent of
17
these companies’ assets were committed to regulated distribution activities in 2008.
18
Second, while six of the eight companies in Dr. Vilbert’s sub sample have lines of
19
business that involve the provision of competitive storage and transportation service,
20
these lines of business represent an insignificant portion of these companies’ overall
21
activities. Please refer to the rows labelled “Interstate Storage and Transportation” on
22
pages 1 and 3 of Attachment B. Finally, unregulated activities make up a small portion of
23
the business activities of the companies in Dr. Vilbert’s sub sample. Please refer to the
24
rows labelled “Diversified Activities” on pages 2 and 4 of Attachment B. Therefore, I
25
conclude that Dr. Vilbert’s U.S. LDC sample represents a “pure play” LDC sample.
56
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q60. Please explain with reference to Attachment B how you reached the conclusion that
2
the companies in Dr. Vilbert’s U.S. LDC sample are exposed to lower fundamental
3
risk than Gaz Métro.
4
A60.
I conclude that the companies in Dr. Vilbert’s U.S. pure play LDC sub sample have lower
5
fundamental risk than Gaz Métro because the companies in Dr. Vilbert’s sub sample have
6
smaller industrial load and face a lesser degree of competition than Gaz Métro. The
7
companies in Dr. Vilbert’s sub sample appear to face weaker competition from electricity
8
than Gaz Métro. See the rows labelled “Competition with Electricity” on pages 1 and 3 of
9
Attachment B. In 2007, average residential electric rates in the states in which these
10
companies operate were higher than Hydro-Quebec’s average residential rate. Moreover,
11
their distribution services do not face a great degree of bypass risk. Three of the eight
12
companies in Dr. Vilbert’s sub sample (Laclede Group, Nicor Inc. and WGL Holdings)
13
serve customer bases that largely consist of residential and commercial customers that are
14
not at risk of bypass. Please refer to the rows labeled “Customer Mix” on pages 1 and 3
15
of Attachment B. One additional company (South Jersey Industries) has higher industrial
16
and electric generator throughput, but does not appear to face significant bypass risk;
17
South Jersey does not discuss bypass as one of its risk factors in its annual reports to
18
investors (the SEC Form 10-K). Three of the remaining four companies, (NICOR, Inc.,
19
Northwest Natural Gas, Piedmont Natural Gas and Southwest Gas) serve significant
20
industrial and electric generation load. According to their 10-K’s, these companies have
21
been successful at using negotiated rates to prevent bypass of their systems.33 Please refer
22
to the rows labeled “Bypass Risk” on pages 2 and 4 of Attachment B. Thus, I conclude
23
that the companies in Dr. Vilbert’s sample face lower fundamental risk than Gaz Métro
24
since the companies in Dr. Vilbert’s sample are not exposed to competition to the same
25
degree as Gaz Métro.
33
The remaining company, AGL Resources, states in its 2008 SEC Form 10-K that it faces bypass risk, and
does not discuss whether it can mitigate this risk through the use of negotiated agreements.
57
WRITTEN EVIDENCE OF
PAUL R. CARPENTER
1
Q61. Please explain with reference to Attachment B to your evidence how regulatory risk
2
3
of the companies in Dr. Vilbert’s sample compare to Gaz Métro’s regulatory risk?
A61.
The LDCs owned by the companies in Dr. Vilbert’s pure play U.S. LDC sub sample tend
4
to have rates set by traditional cost of service methodologies. Many of them (all but
5
Laclede Group and NICOR Inc.) also have decoupling or margin stabilization
6
mechanisms that reduce the short-term variability of their earnings for some of their
7
utility subsidiaries. Please refer to the rows labeled “Decoupling Mechanism” on pages 2
8
and 4 of Attachment B. As I have discussed, Gaz Metro’s Performance Incentive
9
Mechanism is a riskier regime than traditional cost of service regulation as it is employed
10
in the U.S. Thus, Gaz Metro’s regulatory risk is somewhat higher than that of the
11
companies in Dr. Vilbert’s pure play U.S. LDC sub sample.
12
Q62. Please summarize your conclusion regarding the risk of Gaz Métro compared to the
13
14
risk of Dr. Vilbert’s pure play U.S. LDC sub sample.
A62.
I conclude that Gaz Métro faces more risk than the companies in Dr. Vilbert’s pure play
15
U.S. LDC sub sample. Gaz Métro faces more fundamental risk and somewhat higher
16
regulatory risk than the companies in Dr. Vilbert’s sub sample.
17
Q63. Does this complete your written evidence?
18
A63.
Yes.
58