BEFORE THE RÉGIE DE L'ÉNERGIE
IN THE MATTER OF:
HYDRO QUÉBEC DISTRIBUTION
Demande du Distributeur relative à
l'établissement des tarifs
d'électricité pour l'année tarifaire
2008-2009
DOSSIER R-3677-2008
prepared on behalf of:
l'Association québécoise des consommateurs
industriels d'électricité (AQCIE)
28 October 2008
Conseil de l'industrie forestière du Québec (CIFQ)
prepared evidence of:
Robert D. Knecht
Industrial Economics, Incorporated
2067 Massachusetts Avenue
Cambridge, MA 02140
INTRODUCTION
1 . P O S T- PAT R I M O N I A L
G E N E R AT I N G C O S T
A L L O C AT I O N
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My name is Robert D. Knecht. I am a Principal and the Treasurer of Industrial
Economics, Incorporated (“IEc”), a consulting firm located at 2067 Massachusetts
Avenue, Cambridge, MA 02140. As part of my consulting practice, I prepare analyses
and expert testimony in the field of regulatory economics. In Canada, I have
submitted expert evidence in regulatory proceedings in Québec, Ontario, Alberta, New
Brunswick, Nova Scotia, Manitoba, and Prince Edward Island. In matters regarding
Hydro Québec Distribution (“HQD”), I have submitted evidence or reports before the
Régie in dockets R-3477-2001, R-3492-2002 (Phases 1 and 2), R-3541-2004, 35632005, R-3579-2005, R-3610-2006, R-3644-2007, R-3648-2007 and R-3673-2008. I
obtained a B.S. degree in Economics from the Massachusetts Institute of Technology
in 1978, and a M.S. degree in Management from the Sloan School of Management at
M.I.T. in 1982, with concentrations in applied economics and finance. My curriculum
vitae and a schedule of my expert evidence presented to regulatory tribunals during
the past five years are attached as Exhibit RDK-1.
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I was retained by l'Association québécoise des consommateurs industriels d'électricité
(“AQCIE”) and the Conseil de l'industrie forestière du Québec (“CIFQ”) to evaluate
the following aspects of HQD’s filing:
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Allocation of post-patrimonial generating costs, particularly the treatment of net
resale costs;
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Revenue allocation, and tracking historical cross-subsidies;
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Tariff design for Rate L.
PLEASE PROVIDE THE BACKGROUND FOR YOUR EVIDENCE IN RESPECT OF THE
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In Decision D-2007-12, the Régie directed that HQD implement “the hourly method”
for allocating post-patrimonial generating costs in this proceeding. HQD indicates
that it has adopted that methodology. In Decision D-2008-024, the Régie affirmed the
use of the hourly method, but it directed HQD to conduct additional analysis regarding
the methodology for allocating HQD’s supply costs associated with the resale of
power.
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In this evidence, I review the overall results of HQD’s hourly methodology to
demonstrate that they continue to be inconsistent with the economics of electricity
generation . However, I address specifically only the issue of the allocation of
stranded costs. In the category of stranded costs, I include both the fixed costs
associated with not operating the TransCanada Energy (“TCE”) Bécancour generating
station and the net costs associated with surplus power resales.
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H O W D O T H E R E S U LT S O F H Q D ’ S A L L O C AT I O N O F P O S T- PAT R I M O N I A L
A L L O C AT I O N O F P O S T- PAT R I M O N I A L G E N E R AT I O N C O S T S .
G E N E R AT I N G C O S T S I N T H I S P R O C E E D I N G C O M PA R E W I T H T H E R E S U LT S
P R E S E N T E D I N T H E P R E V I O U S T W O P R O C E E D I N G S I N W H I C H T H E “ H O U R LY
M E T H O D ” WA S U S E D F O R C O S T A L L O C AT I O N ?
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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A summary of the results of the hourly cost allocation methodology, applied in 2007,
2008 and 2009, are shown in Table IEc-1 below, for the major rate classes. Note that
I have made the comparison on a cents-per-kWh of energy generated, as that more
accurately reflects the relative costs of generation supply to each rate class, because it
is measured before losses.
TABLE IEC-1
POST-PATRIMONIAL SUPPLY COSTS
HOURLY METHOD
CENTS PER KWH OF ENERGY GENERATED
2007
2008
2009
Rate D
8.2
8.3
9.5
Rate G
8.3
8.5
10.5
Rate M
8.0
8.5
10.4
Rate L
8.0
8.8
10.4
Total HQD
8.1
8.6
10.1
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Table IEc-1 gives rise to several observations. First, the per-kWh post-patrimonial
generation costs have increased substantially in 2009. This is due at least in part to
HQD having retained capacity in excess of its needs, resulting in the need to both
resell this excess capacity at a loss and to incur fixed costs associated with keeping the
TCE Bécancour generation facility shut down.
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Second, the table indicates that in both 2008 and 2009 the hourly method produces
results that are at odds with generation economics, with traditional generation cost
allocation methods and with current market prices. Generation economics dictates
that the cost of producing power during off-peak periods is lower than the cost of
producing power on-peak. For that reason, both traditional cost allocation methods
and modern markets for electric power imply that the unit cost to serve high load
factor customers should be below that for lower load factor customers.
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HQD’s method produces the reverse result, with the lowest load factor class (the
residential class) being assigned the lowest per-kWh generation cost. This result
remains unique in my experience.
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I N T H E E V I D E N C E T H AT Y O U P R E S E N T E D I N L A S T Y E A R ’ S P R O C E E D I N G , Y O U
H Y P O T H E S I Z E D T H AT AT L E A S T PA RT O F T H I S U N U S U A L R E S U LT WA S D U E TO
H Q D ’ S T R E AT M E N T O F T H E A C C O U N T I N G L O S S E S T H AT I T I N C U R S O N S U R P L U S
V O L U M E S . WA S Y O U R H Y P O T H E S I S C O R R E C T ?
In part it was. However, as HQD witness Mr. Coté indicated last year, the primary
reason why the hourly method produces the very unusual results shown above is the
lack of any signal for peak demand or capacity in the method, as well as the lack of
any differentiation in energy costs in on-peak and off-peak periods. However, based
on the analysis presented by HQD in this proceeding, I conclude that HQD’s treatment
of the losses on the resale of surplus volumes contributes to the problem.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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To illustrate this conclusion, Table IEc-2 below compares the results of HQD’s
analysis of its 2008 post-patrimonial costs using the approved hourly method and that
using a capacity cost signal. Note that this comparison excludes the effects to resold
surplus suppliers.1 I start by reviewing the 2008 analysis, because it excludes the
effects of the TCE stranded costs.
TABLE IEC-2
POST-PATRIMONIAL SUPPLY COSTS EXCLUDING SURPLUS RESALE COSTS
HOULY METHOD WITH AND WITHOUT CAPACITY COST
2008 TEST YEAR
CENTS PER KWH OF ENERGY DELIVERED
Without
Capacity
Signal
With
Capacity
Signal
Percent
Difference
Residential
8.27
10.76
30.1%
Small and Medium General
8.14
9.12
12.0%
Large Industrial
7.85
8.02
2.2%
Total HQD
8.07
9.24
14.5%
Source: HQD-11, Document 4; HQD-16, Document 9, Table R-21.2
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Table IEc-2 demonstrates that for 2008, the hourly method produces results that are
directionally correct, although there is virtually no differentiation among rate classes.
Moreover, what little differentiation that appears results primarily from differences in
class loss factors and not from any differentiation in actual costs. When a capacity
price signal is factored in, however, the results show a more traditional inter-class
pattern. Thus, I agree with Mr. Coté’s conclusion that the primary reason for the
unusual results is the absence of a capacity price signal, as well as its failure to
recognize any differentiation in the time-of-use cost of energy.
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Nevertheless, HQD’s treatment of the resold volumes makes the problem worse.
Table IEc-3 compares the allocated 2008 unit costs both before and after the effects of
surplus resales are considered.
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Note that the inclusion of a capacity price signal affects the amount of costs that are deemed
to be associated with the surplus resale volumes. It appears that HQD’s “with capacity” signal
assigns no capacity costs to resold volumes, where the hourly method implicitly includes those
costs in the hourly costs assigned to resale volumes.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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TABLE IEC-3
POST-PATRIMONIAL SUPPLY COSTS
HOULY METHOD WITH AND WITHOUT SURPLUS RESALE EFFECTS
2008 TEST YEAR
CENTS PER KWH OF ENERGY DELIVERED
Before
Resale
Including
Resale
Percent
Residential
8.27
9.09
9.9%
Small and Medium General
8.14
9.23
13.4%
Large Industrial
7.85
9.31
18.6%
Total HQD
8.07
9.21
14.1%
Source: HQD-11, Document 4
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Thus, it is apparent that something in HQD’s methodology is causing a
disproportionate increase in costs allocated to the business classes, particularly the
high load factor large industrial class. That is, the effect of surplus resales on the large
industrial class is 1.46 cents per kWh or 18.6 percent of allocated cost, compared to an
impact on the residential class of 0.82 cents per kWh or 9.9 percent of allocated cost.
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Turning to the 2009 analyses, it is apparent that at least one other problem has cropped
up. Table IEc-4 below is similar to Table IEc-3, except that it is based on the 2009
test year. Because I had the hourly information for 2009, I segregated the results for
the small and medium general service customers, and I presented the results on a perunit of energy generated basis. Additional supporting information for these
calculations is shown in Exhibit IEc-2 at the back of this evidence.2
TABLE IEC-4
POST-PATRIMONIAL SUPPLY COSTS
HOULY METHOD WITH AND WITHOUT SURPLUS RESALE
2009 TEST YEAR
CENTS PER KWH OF ENERGY GENERATED
Residential
Before
Resale
Including
Resale
Percent
9.17
9.48
3.4%
Small General
9.83
10.49
6.7%
Medium General
9.76
10.42
6.8%
Large Industrial
9.73
10.37
6.6%
Total HQD
9.54
10.07
5.6%
Source: HQD-11, Document 4
2
Supporting hourly information in electronic format is available to parties to this proceeding
upon request to AQCIE/CIFQ counsel.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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The two major changes between 2008 and 2009 are (a) the per-kWh costs of providing
post-patrimonial supply increased sharply from 2008 to 2009 and, (b) the allocation of
costs in 2009 before the effect of resale volumes is distorted.
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While it is impossible to know for certain what causes these changes, it appears that
both of these results are influenced by HQD’s treatment of the fixed costs of the TCE
Bécancour facility.3 Rather than treating those fixed costs as stranded, HQD
apparently decided to include those costs as part of hourly supplies, even though there
will be no supplies from that facility. In effect, the hourly costs for the postpatrimonial energy that will actually be supplied from other generators are
substantially overstated. Moreover, judging by the inter-class results, it is apparent
that the treatment of the TCE stranded costs is further skewing the cost allocation
results. As shown in Table IEc-4 above, the introduction of TCE stranded costs in
2009 resulted in more distortion in the “before resale” results than that in 2008 (in
Table IEc-3).
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B E F O R E A D D R E S S I N G T H E S P E C I F I C S O F H Q D ’ S A L L O C AT I O N M E T H O D O L O G Y
In Exhibit IEc- 3, I attach three figures that provide an overview of HQD’s postpatrimonial stranded cost issues.
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Figure IEc-1 compares the post-patrimonial load for Rate D and Rate L. Unlike past
years in which the load shapes were unusual, the 2009 load patterns are much more
consistent with overall HQD loads. In particular, the Rate D load shows the
pronounced winter peak that it exhibits overall. The Rate L load is much flatter,
though it also exhibits a winter peak. Of course, the winter peak in Rate L postpatrimonial load is not consistent with the overall Rate L load, which is much flatter.4
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Nevertheless, the overall post-patrimonial load shape is beginning to look more like
HQD’s overall load. This is an interesting result in that (a) the overall postpatrimonial load remains quite thin relative to the patrimonial load, and (b) the
patrimonial load shape was originally designed to be more oriented toward peak hours
than HQD’s actual load shape.
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It is my understanding that the shift in the patrimonial load shape is due to a number
of factors, including reductions in high load factor usage (including both lost industrial
load and successful PGEE programs such as reducing the use of inefficient
FOR ITS STRANDED TCE AND RESALE COSTS, PLEASE PROVIDE A LITTLE
B A C K G R O U N D O N L O A D PAT T E R N S , H O U R LY C O S T S A N D P R I C E S A S S O C I AT E D
W I T H H Q D ’ S P O S T- PAT R I M O N I A L L O A D .
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The actual costs associated with the TCE facility are confidential. As such, I cannot evaluate
the exact impact of these stranded costs on the hourly method costs.
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As I have testified in the past, this counter-intuitive load shape for the large industrial rate
class results from the arbitrary allocation method used by HQD to assign the patrimonial load
among the rate classes.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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refrigerators) and increases in winter use of electricity by weather-sensitive customers
as a result of increases in fossil fuel costs.
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Figure IEc-2 compares the total post-patrimonial consumption with the resale
volumes. As shown, the resale volumes are much higher in the summer, due again to
the pronounced winter peak in the post-patrimonial load. In essence, HQD is
incurring more surpluses in the summer due to both reductions in overall load and
increases in winter peak load.
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Figure IEc-3 compares the hourly unit cost of post-patrimonial supplies with the
hourly resale unit revenues, for each hour over the year. It is important to recognize
that the per-kWh cost reported in this figure is the “hourly method” cost developed by
HQD before the resale impacts are considered. However, it includes the effect of the
TCE stranded costs. A number of observations apply to this figure:
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The resale prices are consistent with generation economics and modern
electricity energy markets, in that they are higher on-peak than off-peak, and
they are higher in the peak winter and summer seasons (the US export markets
have pronounced summer peaks) than in the off-peak seasons. Differentials
between on-peak and off-peak prices are about $25 to $30 per MWh. Note that
these prices are energy only. Because HQD cannot resell on a firm basis, these
prices reflect only hourly energy differentials, and do not reflect capacityrelated values.
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The hourly method costs show very little on-peak/off-peak differentiation,
unlike real electricity markets. The very high hourly costs in the summer
almost certainly result from spreading the fixed, stranded TCE costs over a
relatively small load in the summer. Thus, the hourly method continues to
produce costs that are divorced from reality.
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The hourly costs are considerably higher than the resale prices. From an
accounting perspective, this suggests that HQD is losing money on each sale,
which might imply that HQD should not engage in these sales. However, from
an economic perspective, as long as the resale values are higher than the
incremental cost of the supply, HQD should continue to resell the power. It is
therefore important to recognize that the hourly method costs are not consistent
with economic reality.
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P L E A S E A D D R E S S H O W H Q D ’ S C O S T A L L O C AT I O N M E T H O D F O R B O T H T Y P E S O F
S T R A N D E D C O S T S C A U S E S T H E U N U S U A L R E S U LT S S H O W N I N TA B L E I E C - 4
ABOVE.
In respect of the TCE stranded costs, it is my understanding that HQD simply takes
the fixed costs that it continues to pay to TCE and it spreads those costs over every
hour of the year, with no time-of-use variation and no demand component. Because
post-patrimonial loads are lower in the summer than in the winter, the per-kWh
delivered cost of the TCE stranded costs is higher in the summer than the winter,
leading to the cost pattern shown in Figure IEc-3. Because the high load factor
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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customers are disproportionately responsible for summer loads, the high load factor
customers are assigned a disproportionate share of the stranded costs.
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In respect of the resale volumes, HQD assigns responsibility for the resold volumes in
every hour to the actual post-patrimonial consumption in every hour. In essence, the
more a class consumes in a particular hour, the more it is deemed to be responsible for
the resold power in that hour. Once HQD determines the volumetric responsibility for
the resold volumes, it then applies the hourly method unit cost and the resale revenue
to each class’s share in each hour.
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This approach disproportionately assigns costs to the higher load factor rate classes for
two reasons. First, because the higher load factor customers represent a larger share
of the summer load, they are assigned a larger share of the resale load. For example,
as shown in Exhibit IEc-2, the large industrial class is responsible for 39 percent of the
post-patrimonial load but it gets assigned 47 percent of the resold volumes. Second,
because the per-kWh losses on resold power are higher in the summer than in the
winter (the TCE stranded cost effect), the high load factor classes are assigned a
disproportionate share.
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I S H Q D ’ S M E T H O D F O R T R E AT I N G T H E S E S T R A N D E D C O S T S C O N S I S T E N T W I T H
No. HQD’s treatment of both types of stranded costs relies on the assumption that
resale volumes are somehow proportional to post-patrimonial consumption. In effect,
HQD is saying that, if a class’s post-patrimonial load increases, it should be assigned
more of the resold volumes.
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This approach makes little sense. Resales of power are necessary because there is not
enough consumption to fill up the contracts, not because there is too much
consumption. To the extent that there is any causative relationship between postpatrimonial consumption and resale volumes, HQD’s method has it exactly
backwards. When demand from a particular class in a particular hour increases, the
need to resell power in that hour goes down.
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In addition, it may be that the need to resell power is not related to any unexpected
shortfall in consumption at all. For example, it is not clear that HQD’s planning did
not actually anticipate the need to resell power, particularly in the summer months
when local demand is low and export prices are more attractive. To the extent that
HQD ever made a planning decision based on the expectation that it would resell
power, there is surely no reason to charge the net accounting loss on those exports to
summer loads.
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Under those conditions, there is no conceivable cost causation basis for such a cost
assignment.
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C A N I T B E C R E D I B LY A R G U E D T H AT L O S S E S I N H I G H L O A D FA C TO R I N D U S T R I A L
C O S T C A U S AT I O N ?
L O A D S A R E C A U S I N G H Q D TO I N C U R R E S A L E L O S S E S , A N D T H E R E F O R E H Q D
S H O U L D A S S I G N T H E C O S T S F O R T H E S U M M E R L O S S E S TO L A R G E I N D U S T R I A L
C U S TO M E R S ?
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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No. Such an argument fundamentally misunderstands the economics of resold power.
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If viewed from the narrow perspective of looking only at accounting costs and only
for resold volumes, the argument may appear at first blush to have some merit.
Relative to a base case situation, across-the-board reductions in industrial load will
result in the need to resell more power in the summer. 5
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However, lost industrial load is not the only change that will cause these results. For
example, an across-the-board reduction in any baseload use (e.g., due to replacement
of inefficient refrigerators and installation of compact fluorescent lighting) will also
cause this kind of result. Similarly, increases in peak season load (e.g., increases in
electric heat due to high fossil fuel prices) will cause this effect. Based on my
conversations with AQCIE/CIFQ analyst M. Trahan, I understand that all of these
effects are occurring.6
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In addition, the argument fails on cost causation. If losses on resale were actually
caused by customers leaving the system, then it would be appropriate to charge the
customers who have left the system for those costs. It makes little sense to assign the
costs for customer shutdowns to only one class of customer. The remaining customers
in that class are not the ones who are responsible for the shutdown.
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However, most importantly, this argument is specious on economic grounds, because
it assumes that lost industrial load is actually a net cost to the system. This
assumption is incorrect.
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Average large industrial revenues are about 4.6 cents per kWh, and the high load
factor customers within the class (particularly those taking service at high voltage) pay
a lower rate than that. When one of those customers shuts down, the worst case for
HQD is that it loses 4.6 cents per kWh in revenues and it is able to resell that power
for an average of 6.3 cents per kWh (ranging anywhere from 5 to 9 cents per kWh, as
shown in Figure IEc-3). Thus, in total, HQD will earn more revenues than it loses if a
large industrial customer closes, and that benefit will necessarily be passed back to
ratepayers in all classes.
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The problem with the “blame-the-large-industrials” argument is that it focuses only on
the accounting cost of the resale volumes, and it ignores the overall economic (and
accounting) impact on HQD as a whole.
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To understand this, consider what happens to overall cost allocation when large
industrial load declines. Because the government of Québec in its annual decrees has
adopted a proportional allocation for patrimonial load, when large industrial load
declines, the other rate classes’ share of patrimonial load increases. This, of course,
5
I developed a simple two-period, two-class model to demonstrate that this and the rest of the
analyses presented in this section of my evidence are correct, even recognizing the proportional
allocation of patrimonial load. Electronic copies of this simple model are available upon
request to AQCIE/CIFQ counsel.
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See also HQD-16, Document 8, page 7, and HQD-14, Document 1, page 21.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
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benefits those rate classes. However, if the focus of attention is only on the
accounting losses of resale, the beneficial effects of the reallocation of patrimonial
load will be ignored.
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Thus, it would be extremely disingenuous, for example, for an analyst to argue that
residential customers should get the benefits associated with lost industrial load in the
form of a greater entitlement to low-cost patrimonial load, while forcing the remaining
large industrial customers to bear the accounting losses associated with resold power
supplies.
O V E R A L L , W H AT A R E Y O U R C O N C L U S I O N S A N D R E C O M M E N D AT I O N S I N T H I S
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As I have in the past, I conclude that the hourly method is not consistent with
generation economics, cost causation, or electricity markets. Because it is not an issue
in this proceeding, I make no recommendation regarding the allocation of nonstranded costs. Nevertheless, in light of the increasing winter peak demands of the
post-patrimonial load, I encourage the Régie to monitor whether incorporating a
demand component into post-patrimonial cost allocation may merit future attention.
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In this proceeding, HQD’s stranded costs include all of the fixed costs paid to TCE for
the Bécancour facility that supplies no power, as well as the accounting losses on
resold power. I conclude that both of these stranded costs should be excluded from
the hourly method and allocated separately.
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In my view, the most equitable way to allocate these costs is in proportion to total
generation costs. As I mentioned, the stranded costs are generated as a result of
consumed volumes being lower than purchased volumes. Reductions in volumes for a
particular class create benefits for other classes in the form of higher patrimonial
loads. Because the classes whose loads have not decreased benefit from the lost
volumes in the form of more patrimonial load, it would seem fair to assign those costs
proportionately.
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W H AT I S T H E I M PA C T O F Y O U R P R O P O S A L O N O V E R A L L A L L O C AT E D
Because the TCE stranded costs are confidential, I cannot evaluate the overall impact.
However, for illustrative purposes, I prepared an example based on the assumption
that the TCE stranded costs for 2009 are $120 million. (The buyout costs for TCE
were reported as $73 million at Docket No. R-3673-2008, and the regular TCE
demand charges must be added to that.) I also assumed that HQD’s hourly method
assigns the TCE stranded costs equally over the 8760 hours of 2009.
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Based on those assumptions, Table IEc-5 below compares the total unit generation
costs based on HQD’s filing and my proposed modification to stranded cost
allocation.
P R O C E E D I N G R E G A R D I N G P O S T- PAT R I M O N I A L G E N E R AT I O N C O S T A L L O C AT I O N ?
G E N E R AT I O N C O S T S ?
Evidence of Robert D. Knecht
Docket No. R-3677-2008
9
TABLE IEC-5
ALLOCATED 2009 TEST YEAR GENERATION COSTS
HQD FILED VERSUS ALTERNATIVE STRANDED COST EXAMPLE
CENTS PER KWH OF ENERGY DELIVERED
HQD Filed
Alternative
Example
Percent
Residential
3.34
3.36
0.7%
Small General
3.08
3.07
-0.3%
Medium General
2.88
2.87
-0.4%
Large Industrial
2.67
2.65
-0.5%
Total HQD
2.97
2.97
0.0%
Source: Exhibit IEc-4, IEc Workpapers
2. ALLOC
2 .AT R
I OEN
V EONFU E
ATLRLAONCSAT
M I SOSNI OANN D
CCORSO
TSSS U B S I D I Z AT I O N
1
2
3
4
5
6
P L E A S E P R O V I D E A B R I E F B A C K G R O U N D O F T H E R E G U L ATO RY I S S U E S
S U R R O U N D I N G R E V E N U E A L L O C AT I O N F O R T H I S P R O C E E D I N G .
As the parties to these proceedings are well-aware, the regulation of HQD is subject to
the unusual (and quite possibly unique) requirement that rates may not be adjusted in
order to cause changes in historical levels of cross-subsidization. How that crosssubsidization is measured was a matter of some debate over several rate proceedings.
7
8
9
10
11
12
13
14
Nevertheless, in the 2006 HQD proceeding (R-3610-2006), the Régie approved a
methodology proposed by HQD which measures the increase in allocated per-kWh
cost from proceeding to proceeding, based on a consistent cost allocation
methodology. That is, HQD simulates its cost allocation methodology for the prior
test year and for the proposed test year with the same cost allocation methodology.
The difference in the per-kWh allocated costs between those two simulations is
deemed, under this methodology, to be the necessary difference in rates that would
result in no change in cross-subsidies.
15
16
Thus, in Docket R-3610-2006, the Régie implicitly adopted a new base level of crosssubsidies.
17
18
19
However, in neither of the last two proceedings has the Régie applied its cross-subsidy
approach for revenue allocation.7 Instead, it approved across-the-board rate increases
for all rate classes in both cases.
20
21
22
In the current proceeding, HQD has again prepared its cross-subsidization analysis,
which implies differential rate increases are necessary to prevent cross-subsidies from
expanding. However, HQD has again proposed to apply an across-the-board rate
7
I use the term “revenue allocation” to apply to how much of the overall increase in HQD’s
revenue requirement is applied to each rate class. I use the term “rate design” to apply to how
rates are structured to recover the revenue requirement assigned to each class in the revenue
allocation process.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
10
1
2
increase of 2.2 percent. At the direction of the Régie, however, HQD has offered
several alternative approaches for differential rate increases.
3
4
5
6
7
8
W H AT A R E T H E P R I M A RY C O N S I D E R AT I O N S O F R E G U L ATO R S F O R E VA L U AT I N G
R E V E N U E A L L O C AT I O N D E C I S I O N S ?
As a general rule, regulators consider three primary factors when determining how a
rate increase is shared among the various rate classes. First, most regulators consider
cost to be the primary consideration, and that the objective of revenue allocation is to
move rates more into line with allocated costs under future rates than under prior rates.
9
10
11
This objective of “moving toward cost-based rates” is tempered by two other
considerations. These are the principle of “rate gradualism” (often referred to as
avoiding “rate shock”) and the principle of “value of service.”
12
13
14
15
16
17
While it is difficult to pin down exactly what the principle of gradualism requires,
many regulators rely on a “rule of thumb” that the rate increase for a particular class
be no more than 1.5 or 2.0 times the system average increase. (Generally, for smaller
overall increases, regulators are more comfortable with a higher multiple.) Thus, for
example, under a “two-times” rule, if the system average rate increase is 2.2 percent,
no class is assigned more than a 4.4 percent increase.
18
19
20
21
22
23
24
The principle of “value of service” is that classes who place a higher value on the
utility service may be assigned a larger increase than those classes that value the
service less highly. This criterion is generally interpreted to mean that customers
whose demand will be less affected by a rate increase (i.e., the demand is less price
elastic) may be assigned a larger increase. In practice, this criterion is often used to
justify lower rate increases for customers or customer classes who are likely to lose
load (e.g., bypass rates).
25
26
27
28
29
30
31
W H AT A LT E R N AT I V E A P P R O A C H E S H A S H Q D O F F E R E D F O R R E V E N U E
The cross-subsidy analysis indicates that, to maintain constant cross-subsidies, it
would be necessary to apply a rate increase of above average increases of 3.6 percent
and 2.6 percent to the residential and small general service classes respectively, and
below average increases of 0.2 percent and 0.7 percent to the medium general and
large industrial rate classes.
32
33
34
35
36
37
38
However, HQD is unwilling to suggest differentiated rate increases of that magnitude.
It offers several alternatives based on considerations that are consistent with the “rules
of thumb” that I discuss above. However, HQD is willing only to suggest maximum
rate increases that are 1.2 times, 1.3 times and 1.4 times the system average. Such
constraints are somewhat cautious compared to my experience in other jurisdictions,
although they presumably reflect both historical rate increase patterns and political
considerations in Québec.
39
40
D O Y O U H AV E S P E C I F I C R E C O M M E N D AT I O N S R E G A R D I N G R E V E N U E A L L O C AT I O N
A L L O C AT I O N I N T H I S P R O C E E D I N G ?
IN THIS PROCEEDING?
Evidence of Robert D. Knecht
Docket No. R-3677-2008
11
1
2
3
4
5
6
7
While I encourage the Régie to differentiate rate increases among the various rate
classes to restrict or eliminate the growth in cross-subsidies, I do not have a specific
proposal in this proceeding. The choice of how much to temper the results of the cost
allocation analysis with the principle of “gradualism” is essentially one of judgement.
However, I do offer factors for the Régie to consider, and I evaluate whether the
Régie’s arguments in Decision 2008-024 justify an across-the-board rate increase in
this proceeding.
8
9
10
11
12
13
14
15
First, if HQD’s across-the-board increase is granted in this proceeding, the total
accumulated changes in cross-subsidies would be quite significant. in Exhibit IEc-5, I
have compiled the annual increases in cross-subsidies for each major rate class group
since the Régie’s adoption of a cross-subsidization metric in R-3610-2006. Under
HQD’s proposal, subsidies to the residential class will have increased by over $300
million (some 7.1 percent of current revenues), while the subsidies from the large
industrial class have increased by over $150 million (some 8.5 percent of current
revenues).
16
17
18
19
20
Second, all of HQD’s business classes already provide quite substantial crosssubsidies to the residential class, particularly the medium commercial rate class in
which cross-subsidies amount to more than 30 percent of allocated costs. Allowing
these subsidies to continue to increase would be considered inequitable in most
jurisdictions in my experience.
21
22
23
24
In addition, allowing the cross-subsidies to increase is creating rate design problems.
The higher cross-subsidy level for the Rate M customers is creating uneconomic
incentives for some customers to want to switch to Rate L, simply to get access to a
rate class that is subject to a lower cross-subsidy level.
25
26
27
28
29
P L E A S E R E V I E W T H E R É G I E ’ S R AT I O N A L E I N D - 2 0 0 8 - 0 2 4 R E G A R D I N G
In that decision, the Régie identified a number of reasons for adopting an across-theboard increase in that proceeding. With respect, I do not agree that these reasons
support an across-the-board increase in this proceeding.
30
31
32
33
34
35
36
37
38
1) In R-3644-2007, there were unresolved issues regarding transmission and PGEÉ
cost allocation that reduced the reliability of the cost analysis. While cost
allocation issues may contribute some small uncertainty to HQD’s estimates of
impacts, it is important to recognize that HQD’s calculation of before and after
cross-subsidies are made using the same cost allocation methodology. Thus,
changing a methodology in a particular proceeding does not have a significant
effect on the cross-subsidy calculation. Moreover, I believe that the transmission
and PGEÉ cost allocation procedures have been resolved, and are therefore not an
issue in this proceeding.
39
40
41
42
2. Large industrial load reductions will have an impact on the overall costs to
consumers, and the allocation of stranded costs may cause inequities. As I
explained earlier, reductions in large industrial load tend to benefit the other
customer classes. To the extent that there are any inequities in HQD’s allocation
D I F F E R E N T I AT E D R AT E I N C R E A S E S .
Evidence of Robert D. Knecht
Docket No. R-3677-2008
12
3 . TA R I F F D E S I G N
F O R R AT E L
1
2
3
of stranded costs, it is in favor of the residential class and at the expense of the
business classes. For that reason, considerations of equity should doubly favor the
differentiated rate increases implied by HQD’s cross-subsidy analysis.
4
5
6
7
8
3. The treatment of the deferred transmission expense militates against a
differentiated increase. As shown in HQD-16, Document 9, Table 16.1, all of the
Régie’s changes in last year’s proceeding had only a small net effect on allocated
costs. Moreover, it is my understanding that deferred transmission expense is not
a significant factor in this proceeding.
9
10
Therefore, I do not believe that the reasons presented by the Régie in its last decision
are applicable to this proceeding.
11
12
13
14
15
16
17
18
19
W H AT A R E T H E I M P O RTA N T F E AT U R E S O F T H E R AT E L TA R I F F D E S I G N F O R T H I S
PROCEEDING?8
The Rate L tariff consists of demand and energy charges. In considering tariff design
for large industrial customers, it is reasonable for the regulator to consider both
embedded cost effects and marginal cost effects. As the Régie correctly recognized in
Decision D-2008-024, because the vast majority of generation costs assigned to the
Rate L class (or all rate classes for that matter) are related to the below-market
patrimonial pool, it will be extremely difficult to set rates for Rate L at or near
marginal costs.
W H AT A R E T H E I M P L I C AT I O N S O F A N E M B E D D E D C O S T A L L O C AT I O N S T U D Y F O R
20
21
22
23
24
25
As a general rule, demand charges are designed to recover costs that are classified as
demand-related, and energy charges are designed to recover costs that are classified as
energy-related.9 It is important to recognize that, if rates are not designed in this way,
the tariff design will result in intra-class cross-subsidization.
26
27
28
29
For example, suppose HQD decided to eliminate the Rate L demand charge entirely,
and collect all revenue from an energy charge. Because HQD’s cost allocation
methodology classifies costs into demand components and energy components, the
cost of service per kWh is different from customer to customer. Under HQD’s
D E S I G N I N G R AT E S F O R L A R G E I N D U S T R I A L C U S TO M E R S ?
8
Much of this section of my testimony presents the same material that I presented in last year’s
proceeding on this subject. It is included again because much of the focus of last year’s
proceeding was in respect of the “stepped rate” concept for Rate L tariff design, and the issues
I raised may not have been fully explored. I have updated the figures for the 2009 filing, and
retained much of the text. However, I have added a discussion relating to the implications of
the shifts in post-patrimonial load patterns for peak demand and off-peak price signals.
9
Some utilities will set demand charges modestly below allocated demand costs, in recognition
that the individual customer peak demands do not always match up with the coincident peak
measures used in the cost allocation study. The need for this adjustment is less appropriate for
HQD, because it already uses a broad peak for allocating the demand-related portion of
generation costs in the load factor method.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
13
1
2
3
4
methodology (as filed in this proceeding), a customer with a 100 percent load factor
would cost approximate 3.7 cents per kWh to serve, while a customer with a 60
percent load factor would cost about 4.5 cents per kWh to serve, a 21 percent
difference.
5
6
7
8
If rates for both types of customer were set at the same average per-kWh rate, the high
load factor customer would cross-subsidize the low load factor customer. While this
is obviously an extreme example, a similar but less extreme pattern would result if
HQD simply over-recovered the energy-related costs in its energy charge.
9
10
11
12
However, over the last several rate proceedings, HQD has been following a pattern of
assigning disproportionate increases to the Rate L energy charges and lower increases
to the demand charges. This policy will necessarily result in larger rate increases for
high load factor rate customers than for lower load factor customers.
13
14
15
16
17
18
19
I S H Q D ’ S R AT E D E S I G N P R O P O S A L I N T H I S P R O C E E D I N G C O N S I S T E N T W I T H I T S
No, it is not. Exhibit IEc-6 shows the energy component of costs allocated to the Rate
L class in HQD’s cost allocation studies from 2007 through 2009. In that table, I use
generous assumptions about the energy component of costs, including the assumptions
that all post-patrimonial energy and all PGEÉ costs are energy-related. In actuality,
both of those cost items should have a demand-related component.
20
21
22
23
24
As shown in Exhibit IEc-6, the upper bound for energy-related costs for Rate L, even
including a substantial provision for cross-subsidization, is 2.95 cents per kWh. The
cost basis is therefore about 1.3 percent above the current Rate L energy charge of
2.99 cents per kWh, and about 2.1 percent below HQD’s 3.01 cents per kWh proposed
energy charge in this proceeding.
25
26
27
28
29
30
31
32
33
I recognize that it is HQD’s view that, for Rate L rate design purposes, all generation
costs are energy-related and all transmission and distribution costs are demand-related.
Regarding most transmission and distribution costs, as a theoretical matter, I tend to
agree with HQD’s all-demand approach. However, the Régie most clearly does not,
in that it has directed that a substantial percentage of transmission costs be classified
as energy-related. Thus, in HQD’s cost allocation methodology, if a rate class
experiences an increase in energy consumption but no increase in peak demand, its
allocated transmission costs will increase. Therefore, it is appropriate for rates to
reflect that methodology.
34
35
36
37
38
39
40
41
For similar reasons, I respectfully (and quite strongly) disagree with HQD that all
generation costs are energy-related. The patrimonial generation cost allocation
scheme put forward by HQD and mandated by government decree allocates
patrimonial generation costs using both energy and demand allocators, with a system
load factor weighting. Thus, if a Rate L customer can reduce its peak demand with no
reduction in energy consumption (i.e., leveling its load), the patrimonial costs
allocated to Rate L will go down. Again, this cost allocation method should be
reflected in the rate design.
E M B E D D E D C O S T A N A LY S I S ?
Evidence of Robert D. Knecht
Docket No. R-3677-2008
14
1
2
3
4
W H AT O F M A R G I N A L C O S T C O N S I D E R AT I O N S I N TA R I F F L R AT E D E S I G N ?
5
6
7
8
First, it relies on the premise that the only price signal that industrial customers
consider is the short-term energy price signal. While this may be true for short-term
decisions, it is not correct for most serious decisions regarding longer-term investment
and operational planning decisions.
It is my understanding that HQD believes that its approach will encourage
conservation, by increasing the energy charge to get it closer to the marginal energy
supply costs. However, this argument relies on two dubious premises.
9
10
11
12
At large industrial operations, energy efficiency programs generally target loads
during all hours of the year, including both peak and off-peak consumption levels.
Shifting costs from demand charges to energy charges will likely not create any
meaningful additional incentives to conserve.
13
14
15
16
17
18
19
20
What reducing the relative demand charges will do, however, is reduce the incentive
for large industrial customers from maintaining a level load. That is, customers will
have less incentive to use energy efficiently. Under HQD’s tariff, the energy charge is
the same regardless of whether it is a peak period or an off-peak period, or whether it
applies to a customer with a very high load factor or to a customer with a more
temperature sensitive peak demand. The demand charge, by contrast, applies only to
the customer’s peak demand. Thus, by proposing disproportionate increases to the
energy charge, HQD encourages less efficient behavior by Rate L customers.
21
22
23
24
25
Second, the conservation premise relies on the assumption the relevant marginal cost
signal is energy-related. However, the shifting load pattern for post-patrimonial load
suggests that the need to meet winter peak demands is becoming an increasingly
important supply consideration. Thus, marginal supply costs will increasingly need to
recognize the need for capacity as well as energy.
26
27
28
29
W H AT I S Y O U R R E C O M M E N D AT I O N I N T H I S P R O C E E D I N G ?
Based on the foregoing, I recommend that the energy charge for Rate L be set at 2.95
cents per kWh if HQD’s across-the-board rate increase is approved, with the balance
of the rate increase applied to demand charges.
30
31
32
33
34
35
To the extent that the Régie modifies the rate increase proposed for Rate L, I suggest
that the energy cost increase be adjusted proportionally. For example, an increase to
2.95 cents per kWh is a 1.3 percent increase, compared to HQD’s overall proposed
Rate L increase of 2.2 percent. If the Régie approves an overall increase for Rate L of
0.7 percent, the energy charge increase should be scaled back by 0.7%/2.2% * 1.3% =
0.4%, thereby resulting in an energy charge of 2.92 cents per kWh.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
15
CONCLUSIONS AND
1
Based on my analysis completed to date, my recommendations are as follows:
R E C O M M E N D AT I O N S
2
3
•
Correct the HQD hourly cost allocation methodology for a mis-allocation of
stranded costs.
4
5
6
•
Assign different rate increases to the various classes to reduce the increases in
cross-subsidies, consistent with the Régie’s interpretation of the principles of
gradualism and equity.
7
8
•
Set the energy charge for Rate L at 2.95 cents per kWh, with proportional
adjustments for any change in the overall Rate L class increase.
Evidence of Robert D. Knecht
Docket No. R-3677-2008
16
EXHIBIT IEc-1
CURRICULUM VITAE AND
EXPERT TESTIMONY SCHEDULE
OF
ROBERT D. KNECHT
Evidence of Robert D. Knecht
Docket No. R-3677-2008
ROBERT
D.
KNECHT
Robert D. Knecht specializes in the practical application of economics, finance and management theory
to issues facing public and private sector clients. Mr. Knecht has more than twenty years of consulting
experience, focusing primarily on the energy, metals, and mining industries. He has consulted to
industry, law firms, and government clients, both in the U.S. and internationally. He has participated in
strategic and business planning studies, project evaluations, litigation and regulatory proceedings and
policy analyses. His practice currently focuses primarily on utility regulation, and he has provided
analysis and expert testimony in numerous U.S. and Canadian jurisdictions. In addition, as Treasurer of
IEc since 1995, Mr. Knecht is responsible for the firm's accounting, finance and tax planning, as well as
administration of the firm's retirement plans. Mr. Knecht's consulting assignments include the
following projects:
C For the Pennsylvania Office of Small Business Advocate, Mr. Knecht provides analysis and expert
testimony in industry restructuring, base rates and purchased energy cost proceedings involving
electric, steam and natural gas distribution utilities. Mr. Knecht has analyzed the economics and
financial issues of electric industry restructuring, stranded cost determination, fair rate of return,
claimed utility expenses, cost allocation methods and rate design issues.
C For independent power producers and industrial customers in Alberta, Mr. Knecht has provided
analysis and expert testimony in a variety of electric industry proceedings, including industry
restructuring, cost unbundling, stranded cost recovery, transmission rate design, cost allocation and rate
design.
C For industrial customers in Québec, Mr. Knecht has prepared economic analysis and expert testimony
in regulatory proceedings regarding cost allocation, compliance with legislative requirements for crosssubsidization, and rate design.
C As part of international teams of experts, Mr. Knecht has prepared the economic and financial analysis
for industry restructuring studies involving the steel and iron ore industries in Venezuela, Poland, and
Nigeria.
C For the U.S. Department of Justice and for several private sector clients, Mr. Knecht has prepared
analyses of economic damages in a variety of litigation matters, including ERISA discrimination,
breach of contract, fraudulent conveyance, natural resource damages and anti-trust cases.
C Mr. Knecht participates in numerous projects with colleagues at IEc preparing economic and
environmental analyses associated with energy and utility industries for the U.S. Environmental
Protection Agency.
Mr. Knecht holds a M.S. in Management from the Sloan School of Management at M.I.T., with
concentrations in applied economics and finance. He also holds a B.S. in Economics from M.I.T. Prior
to joining Industrial Economics as a principal in 1989, Mr. Knecht worked for seven years as an
economic and management consultant at Marshall Bartlett, Incorporated. He also worked for two years
as an economist in the Energy Group of Data Resources, Incorporated.
Industrial Economics, Incorporated
2067 Massachusetts Avenue
Cambridge, MA 02140 USA
617.354.0074 | 617.354.0463 fax
August, 2006
www.indecon.com
ROBERT D. KNECHT
EXPERT TESTIMONY SUBMITTED IN REGULATORY PROCEEDINGS: 2004 TO 2008
DOCKET #
REGULATOR
UTILITY
DATE
CLIENT
TOPICS
P-20082044561
Pennsylvania Public
Utility Commission
Pike County Light & Power
October 2008
Pennsylvania Office of
Small Business Advocate
Electric default service procurement
R-3673-2008
Régie de l’Énergie,
Québec
Hydro Québec Distribution
August 2008
AQCIE/CIFQ
Electric supply contract modifications.
1550487
Alberta Utilities
Commission
ENMAX Power Corporation
July 2008
D410 Group
Formula-based (performance-based)
ratemaking; ratepayer-supplied equity
contributions.
R-20082039417 et al.
Pennsylvania Public
Utility Commission
UGI Utilities (Gas Division)
July 2008
Pennsylvania Office of
Small Business Advocate
Design day demand forecast.
R-20082039284
Pennsylvania Public
Utility Commission
UGI Penn Natural Gas
July 2008
Pennsylvania Office of
Small Business Advocate
Revenue sharing, gas supply costs.
R-20082039634
Pennsylvania Public
Utility Commission
PPL Gas Utilities
July 2008
Pennsylvania Office of
Small Business Advocate
Lost and unaccounted-for gas, gas
supply costs.
A-20082034045
Pennsylvania Public
Utility Commission
UGI Utilities, PPL Gas
Utilities
June 2008
Pennsylvania Office of
Small Business Advocate
Public benefits of proposed sale.
R-20082011621
Pennsylvania Public
Utility Commission
Columbia Gas of Pennsylvania
May 2008
Pennsylvania Office of
Small Business Advocate
Cost allocation, revenue allocation, rate
design.
R-20082028039
Pennsylvania Public
Utility Commission
Columbia Gas of Pennsylvania
May 2008
Pennsylvania Office of
Small Business Advocate
Gas supply cost functionalization; cost
reconciliation method, sharing
mechanisms.
R-3648-2007
Régie de l’Énergie,
Québec
Hydro Québec Distribution
April 2008
AQCIE/CIFQ
Electric supply contract modifications.
R-20082021348
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
April 2008
Pennsylvania Office of
Small Business Advocate
Sharing mechanisms, gas supply
contracts.
R-20082012502
Pennsylvania Public
Utility Commission
National Fuel Gas Distribution
Company
March 2008
Pennsylvania Office of
Small Business Advocate
Transportation and sales customer rate
design, design day forecasts.
1
ROBERT D. KNECHT
EXPERT TESTIMONY SUBMITTED IN REGULATORY PROCEEDINGS: 2004 TO 2008
DOCKET #
REGULATOR
UTILITY
R-20082013026
Pennsylvania Public
Utility Commission
T.W. Phillips Gas and Oil
Company
P-00072342
Pennsylvania Public
Utility Commission
2007-004
DATE
CLIENT
TOPICS
March 2008
Pennsylvania Office of
Small Business Advocate
Rate design treatment of capacity
release revenues.
West Penn Power d/b/a
Allegheny Power
February 2008
Pennsylvania Office of
Small Business Advocate
Default service electricity procurement,
rate design, reconciliation.
New Brunswick Board
of Commissioners of
Public Utilities
New Brunswick Power
Distribution and Customer
Service Corporation
November 2007
New Brunswick Public
Intervenor
Cost allocation, revenue allocation, rate
design.
R-3644-2007
Régie de l'Énergie,
Québec
Hydro Québec Distribution
October 2007
AQCIE/CIFQ
Cost allocation, revenue allocation, rate
design.
P-00072305
Pennsylvania Public
Utility Commission
Pennsylvania Power
Corporation
July 2007
Pennsylvania Office of
Small Business Advocate
Default electric service procurement.
R-00072334
Pennsylvania Public
Utility Commission
UGI Penn Natural Gas, Inc.
July 2007
Pennsylvania Office of
Small Business Advocate
Asset management arrangement, gas
procurement.
R-00072333
Pennsylvania Public
Utility Commission
PPL Gas Utilities Corporation
July 2007
Pennsylvania Office of
Small Business Advocate
Design day forecasting, gas
procurement.
R-00072155
Pennsylvania Public
Utility Commission
PPL Electric Utilities
Corporation
July 2007
Pennsylvania Office of
Small Business Advocate
Cost allocation, revenue allocation, rate
design, energy efficiency.
R-00049255
(Remand)
Pennsylvania Public
Utility Commission
PPL Electric Utilities
Corporation
May 2007
Pennsylvania Office of
Small Business Advocate
Revenue allocation.
R-00072175
Pennsylvania Public
Utility Commission
Columbia Gas of
Pennsylvania, Inc.
May 2007
Pennsylvania Office of
Small Business Advocate
Gas procurement.
R-00072110
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
April 2007
Pennsylvania Office of
Small Business Advocate
Gas procurement, margin sharing
mechanisms.
R-00061931
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
April 2007
Pennsylvania Office of
Small Business Advocate
Cost allocation, revenue allocation,
retail gas competition.
P-00072245
Pennsylvania Public
Utility Commission
Pike County Light & Power
Company
March 2007
Pennsylvania Office of
Small Business Advocate
Default service procurement, rate
design.
2
ROBERT D. KNECHT
EXPERT TESTIMONY SUBMITTED IN REGULATORY PROCEEDINGS: 2004 TO 2008
DOCKET #
REGULATOR
UTILITY
R-00072043
Pennsylvania Public
Utility Commission
National Fuel Gas
Distribution Company
C-20065942
Pennsylvania Public
Utility Commission
R-3610-2006
DATE
CLIENT
TOPICS
March 2007
Pennsylvania Office of
Small Business Advocate
Design day requirements.
Pike County Light & Power
Company
November 2006
Pennsylvania Office of
Small Business Advocate
Wholesale power procurement by
provider of last resort.
Régie de l'Énergie,
Québec
Hydro Québec Distribution
November 2006
AQCIE/CIFQ
Post-patrimonial generation cost
allocation; cross-subsidization; rate
design.
P-00052188
Pennsylvania Public
Utility Commission
Pennsylvania Power
Company
September 2006
Pennsylvania Office of
Small Business Advocate
Affidavit: POLR rates, wholesale to
retail.
R-00061493
Pennsylvania Public
Utility Commission
National Fuel Gas
Distribution Corporation
September 2006
Pennsylvania Office of
Small Business Advocate
Rate of return, load forecasting, cost
allocation, revenue allocation, rate
design, revenue decoupling.
R-00061398
Pennsylvania Public
Utility Commission
PPL Gas Utilities Corporation
August 2006
Pennsylvania Office of
Small Business Advocate
Cost allocation, revenue allocation,
rate design.
R-00061365
Pennsylvania Public
Utility Commission
PG Energy/Southern Union
Company
July 2006
Pennsylvania Office of
Small Business Advocate
Merger savings, cost allocation,
revenue allocation, rate design.
R-00061519
Pennsylvania Public
Utility Commission
PPL Gas Utilities Corporation
July 2006
Pennsylvania Office of
Small Business Advocate
Design day weather and throughput
forecasts; gas supply hedging.
R-00061518
Pennsylvania Public
Utility Commission
PG Energy/Southern Union
Company
July 2006
Pennsylvania Office of
Small Business Advocate
Design day weather and throughput
forecasts; gas supply hedging.
A-125146
Pennsylvania Public
Utility Commission
UGI Utilities, Inc., Southern
Union Company
June 2006
Pennsylvania Office of
Small Business Advocate
Public benefits of proposed sale of PG
Energy to UGI; asset management
agreement.
R-00061355
Pennsylvania Public
Utility Commission
Columbia Gas of
Pennsylvania
May 2006
Pennsylvania Office of
Small Business Advocate
Gas supply and hedging plan;
procedural issues
R-00061296
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
April 2006
Pennsylvania Office of
Small Business Advocate
Gas procurement and procedural
issues.
R-00061246
Pennsylvania Public
Utility Commission
National Fuel Gas
Distribution
March 2006
Pennsylvania Office of
Small Business Advocate
Gas procurement; unaccounted for gas
retention rates.
2005-002
Refiling
New Brunswick Board
of Commissioners of
Public Utilities
New Brunswick Power
Distribution and Customer
Service Company
New Brunswick Public
Intervenor
Cost allocation, rate design.
February 2006
3
ROBERT D. KNECHT
EXPERT TESTIMONY SUBMITTED IN REGULATORY PROCEEDINGS: 2004 TO 2008
DOCKET #
REGULATOR
UTILITY
P-00052188
Pennsylvania Public
Utility Commission
Pennsylvania Power
Company
R-3579-2005
Régie de l'Énergie,
Québec
2005-002
DATE
CLIENT
TOPICS
December 2005
Pennsylvania Office of
Small Business Advocate
Cost allocation and rate design for
POLR supplies.
Hydro Québec Distribution
November 2005
AQCIE/CIFQ
Generation cost allocation; crosssubsidization; revenue allocation.
New Brunswick Board
of Commissioners of
Public Utilities
New Brunswick Power
Distribution and Customer
Service Company
August 2005
New Brunswick Public
Intervenor
Cost allocation, rate design.
R-00050538
Pennsylvania Public
Utility Commission
PG Energy
July 2005
Pennsylvania Office of
Small Business Advocate
Gas procurement diversification.
R-00050540
Pennsylvania Public
Utility Commission
PPL Gas Utilities Corporation
July 2005
Pennsylvania Office of
Small Business Advocate
Gas procurement, hedging, retention
rates, sharing mechanism.
R-00050340
Pennsylvania Public
Utility Commission
Columbia Gas of
Pennsylvania
May 2005
Pennsylvania Office of
Small Business Advocate
Gas procurement, hedging and
diversification.
R-3563-2005
Régie de l'Énergie,
Québec
Hydro Québec Distribution
April 2005
AQCIE/CIFQ
Generation cost allocation; industrial
demand response.
R-00050264
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
April 2005
Pennsylvania Office of
Small Business Advocate
Gas procurement, risk hedging,
financing costs in the gas cost rate.
R-00050216
Pennsylvania Public
Utility Commission
National Fuel Gas
Distribution
March 2005
Pennsylvania Office of
Small Business Advocate
Gas supply procurement and forward
pricing policies.
EB-2004-0542
Ontario Energy Board
Union Gas Limited
March 2005
Tribute Resources Inc.
Cost allocation and rate design for
service to embedded storage pools.
R-00049884
Pennsylvania Public
Utility Commission
Pike County Light and Power
(Gas Service)
January 2005
Pennsylvania Office of
Small Business Advocate
Fair rate of return, cost allocation,
class revenue assignment.
R-00049656
Pennsylvania Public
Utility Commission
National Fuel Gas
Distribution
December 2004
Pennsylvania Office of
Small Business Advocate
Fair rate of return, uncollectibles
costs, automatic rate adjustments,
cost allocation, rate design.
R-3541-2004
Régie de l'Énergie,
Québec
Hydro Québec Distribution
November 2004
AQCIE, CIFQ
Allocation of post-patrimonial
generation costs.
C-20031302
Pennsylvania Public
Utility Commission
Columbia Gas of
Pennsylvania
July 2004
Pennsylvania Office of
Small Business Advocate
Customer assistance program funding
and cost allocation.
R-049255
Pennsylvania Public
Utility Commission
PPL Electric Utilities
Corporation
June 2004
Pennsylvania Office of
Small Business Advocate
Transmission and distribution cost
allocation, rate design, automatic
distribution increases.
4
ROBERT D. KNECHT
EXPERT TESTIMONY SUBMITTED IN REGULATORY PROCEEDINGS: 2004 TO 2008
DOCKET #
REGULATOR
UTILITY
P-042090 et
al.
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
RP-2003-0203
Ontario Energy Board
R-049157
P-042090
DATE
CLIENT
TOPICS
June 2004
Pennsylvania Office of
Small Business Advocate
Collections and universal service cost
issues.
Enbridge Gas Distribution
May 2004
Vulnerable Energy
Consumers Coalition et
al.
Cost allocation, rate design for
pipeline and storage costs.
Pennsylvania Public
Utility Commission
Philadelphia Gas Works
April 2004
Pennsylvania Office of
Small Business Advocate
Cash receipts reconciliation clause.
R-049108
Pennsylvania Public
Utility Commission
National Fuel Gas
Distribution
March 2004
Pennsylvania Office of
Small Business Advocate
Uncollectible cost responsibility for
standby charges.
Application
1306819
Alberta Energy and
Utilities Board
ENMAX Power Corporation
January 2004
Calgary Industrial Group
Calgary Building Owners
T&D cost allocation, rate design,
ratepayer equity funding.
October 2008
Industrial Economics, Incorporated
2067 Massachusetts Avenue
Cambridge, MA 02140 USA
617.354.0074 | 617.354.0463 fax
www.indecon.com
5
EXHIBIT IEc-2
EFFECTS OF RESALE COSTS AND REVENUES
ON 2009 POST-PATRIMONIAL
ALLOCATED COSTS
Evidence of Robert D. Knecht
Docket No. R-3677-2008
Workpapers of Robert D. Knecht
Docket No. R-3677-2008
Exhibit IEc-2
Impact of Power Resales on Post-Patrimonial Generation Cost Alloca
Unit Cost
(cts/kWh)
Energy at
Generator
(GWh)
Energy
Share
Cost ($mm)
9.17
9.83
9.76
9.73
9.54
1,731
426
775
1,908
4,839
35.8%
8.8%
16.0%
39.4%
100.0%
158.7
41.9
75.7
185.7
461.9
Costs of Surplus Supplies
Residential
Small General
Medium General
Large Industrial
Total
11.33
12.01
11.96
11.81
11.75
107
50
91
220
468
22.9%
10.6%
19.4%
47.0%
100.0%
12.2
6.0
10.9
26.0
55.0
Total Supply Cost
Residential
Small General
Medium General
Large Industrial
Total
9.29
10.06
9.99
9.95
9.74
1,838
476
866
2,128
5,307
34.6%
9.0%
16.3%
40.1%
100.0%
170.8
47.9
86.6
211.6
516.9
Resale Revenues
Residential
Small General
Medium General
Large Industrial
Total
6.93
6.91
6.91
6.58
6.29
22.9%
10.6%
19.4%
47.0%
100.0%
(6.8)
(3.2)
(5.8)
(13.7)
(29.4)
35.8%
8.8%
16.0%
39.4%
100.0%
164.1
44.7
80.8
197.9
487.4
Costs Excluding Surplus
Residential
Small General
Medium General
Large Industrial
Total
Post-Patrimonial Supply Cost
Residential
Small General
Medium General
Large Industrial
Total
Net Effect of the Resale of
Surplus Supplies
Residential
Small General
Medium General
Large Industrial
Total
9.48
10.49
10.42
10.37
10.07
Cost Markup
(cts/kWh)
0.31
0.66
0.66
0.64
0.53
(107)
(50)
(91)
(220)
(468)
1,731
426
775
1,908
4,839
Percent
Markup
3.4%
6.7%
6.7%
6.6%
5.5%
Cost ($mm)
5.4
2.8
5.1
12.3
25.6
Source: HQD-16, Document 9, Table R-2.1
Exhibits 3677.xls; Exhibit IEc-2
10/27/2008
EXHIBIT IEc-3
POST-PATRIMONIAL AND RESALE
LOAD, COST AND PRICE FIGURES
Evidence of Robert D. Knecht
Docket No. R-3677-2008
1Ja
n
16
-J
an
31
-J
an
15
-F
eb
2M
ar
17
-M
ar
1Ap
r
16
-A
pr
1M
ay
16
-M
ay
31
-M
ay
15
-J
un
30
-J
un
15
-J
ul
30
-J
u
14 l
-A
ug
29
-A
ug
13
-S
ep
28
-S
ep
13
-O
ct
28
-O
c
12 t
-N
ov
27
-N
ov
12
-D
ec
27
-D
ec
MWh/hour
Figure IEc-1
HQD 2009 Post-Patrimonial Loads
800
700
600
500
400
300
200
100
-
Residential
Rate L Industrial
1Ja
n
16
-J
an
31
-J
an
15
-F
eb
2M
a
17 r
-M
ar
1Ap
r
16
-A
pr
1M
a
16 y
-M
a
31 y
-M
ay
15
-J
un
30
-J
un
15
-J
ul
30
-J
u
14 l
-A
ug
29
-A
ug
13
-S
ep
28
-S
ep
13
-O
ct
28
-O
c
12 t
-N
ov
27
-N
ov
12
-D
ec
27
-D
ec
MWh/hour
Figure IEc-2
HQD 2009 Post-Patrimonial Load and Resale Volumes
2,000
1,500
1,000
500
-
(500)
Post-Patrimonial Load
Resale Volumes
-A
pr
1M
a
16 y
-M
a
31 y
-M
ay
15
-J
un
30
-J
un
15
-J
ul
30
-J
u
14 l
-A
u
29 g
-A
u
13 g
-S
e
28 p
-S
ep
13
-O
c
28 t
-O
c
12 t
-N
o
27 v
-N
o
12 v
-D
e
27 c
-D
ec
16
ar
ar
Ap
r
-M
M
1-
17
eb
an
-F
-J
n
an
Ja
-J
2-
15
31
16
1-
$/MWh
Figure IEc-3
HQD Post-Patrimonial Hourly Costs and Resale Revenues
150.00
130.00
110.00
90.00
70.00
50.00
30.00
"Hourly Method" Cost
Resale Revenue
EXHIBIT IEc-4
EXAMPLE OF ALTERNATIVE STRANDED
COST ALLOCATION
Evidence of Robert D. Knecht
Docket No. R-3677-2008
Workpapers of Robert D. Knecht
Docket No. R-3677-2008
Exhibit IEc-4
Example of Alternative Method for Stranded Cost Allocation
HQD Method
Patrimonial Consumption
Volumes
Costs
Unit Costs
Residential
Small General
Medium General
Large Industrial
Total
58,643
14,430
26,423
66,885
166,381
Alternative Example
Residential
Small General
Medium General
Large Industrial
Total
Patrimonial
Cost
1,850.6
412.9
702.5
1,637.5
4,603.5
1,850.6
412.9
702.5
1,637.5
4,603.5
3.16
2.86
2.66
2.45
2.77
Post-Patrimonial Consumption
Volumes
Costs
Unit Costs
1,731
426
775
1,908
4,839
Post-Patrimonial Consumption
Volumes
Costs
Unit Costs
1,730.6
127.6
7.38
425.7
32.0
7.51
775.1
58.0
7.48
1,907.9
142.0
7.44
4,839.2
359.6
7.43
164.1
44.7
80.8
197.9
487.4
Sub-Total
Costs
1,978.2
444.9
760.5
1,779.5
4,963.1
9.48
10.49
10.42
10.37
10.07
Stranded
Cost
51.0
11.5
19.6
45.8
127.8
Total Consumption
Volumes
Costs
Unit Costs
60,374
14,856
27,198
68,793
171,220
2,014.7
457.6
783.3
1,835.4
5,090.9
Volumes
60,374
14,856
27,198
68,793
171,220
Total
Costs
2,029.2
456.3
780.1
1,825.4
5,090.9
3.34
3.08
2.88
2.67
2.97
Unit Costs
3.36
3.07
2.87
2.65
2.97
Source: HQD-11, Document 3, Table 9A; IEc Workpapers.
Exhibits 3677.xls; Exhibit IEc-4
10/27/2008
EXHIBIT IEc-5
ANALYSIS OF CUMULATIVE CHANGES IN
CROSS-SUBSIDIES AMONG RATE CLASSES
Evidence of Robert D. Knecht
Docket No. R-3677-2008
Workpapers of Robert D. Knecht
Docket No. R-3677-2008
EXHIBIT IEc-5
ANALYSIS OF CUMULATIVE CHANGES IN CROSS-SUBSIDIES
Increase with
No Change in
Cross-Subsidy
Approved/
Increase in
Proposed Cross-Subsidy
Increase
(Percent)
Cumulative
Base
Increase in Increase with
Revenues Cross-Subsidy No Change in
($mm)
($mm) Cross-Subsidy
Cumulative
Approved/
Proposed
Increase
Single Year
Cumulative
Increase in
Subsidy
2007 Test Year
Domestique
Petite Puissance
Moyenne Puissance
Grande Puissance
Total
2.83%
1.73%
1.03%
0.97%
1.92%
1.92%
1.92%
1.92%
1.92%
1.92%
-0.91%
0.19%
0.89%
0.95%
0.00%
4,050
1,275
1,830
1,971
9,126
(36.7)
2.5
16.2
18.7
0.7
2.83%
1.73%
1.03%
0.97%
1.92%
1.92%
1.92%
1.92%
1.92%
1.92%
(36.67)
2.45
16.23
18.71
0.72
2008 Test Year
Domestique
Petite Puissance
Moyenne Puissance
Grande Puissance
Total
4.31%
1.32%
2.75%
1.06%
2.90%
2.91%
2.94%
2.87%
2.90%
2.90%
-1.40%
1.61%
0.12%
1.84%
0.00%
4,165
1,294
1,879
1,929
9,267
(58.5)
20.9
2.3
35.5
0.2
7.26%
3.07%
3.81%
2.04%
4.88%
4.88%
4.91%
4.85%
4.88%
4.88%
(98.93)
23.80
19.44
54.72
(0.95)
2009 Test Year Proposed
Domestique
Petite Puissance
Moyenne Puissance
Grande Puissance
Total
3.60%
2.57%
0.20%
0.69%
2.20%
2.20%
2.20%
2.20%
2.20%
2.20%
-1.40%
-0.37%
2.01%
1.50%
0.00%
4,317
1,362
1,905
1,820
9,404
(60.5)
(5.0)
38.2
27.4
0.1
11.12%
5.72%
4.02%
2.75%
7.19%
7.19%
7.22%
7.16%
7.18%
7.19%
(169.70)
20.47
59.81
80.68
(8.74)
Cumulative Three-Year Cross-Subsidy (excluding interest)
Domestique
Petite Puissance
Moyenne Puissance
Grande Puissance
Total
Exhibits 3677.xls; Exhibit IEc-5
(305.30)
46.72
95.49
154.11
(8.98)
10/27/2008
Workpapers of Robert D. Knecht
Docket No. R-3677-2008
Exhibit IEc-5 (Continued)
Supporting Workpapers for Historical Cross-Subsidy Calculations
R-3677-2008 Filing
Cost of Service
Sales Volume
2008
2009
2008
2009
5,133.4
5,311.9
59,760
60,440
1,063.5
1,110.1
14,600
14,896
1,505.2
1,466.3
27,331
26,811
1,736.3
1,591.7
43,569
39,948
9,438.4
9,480.0
145,261
142,095
HQD-11, Doc 1 Table 2
Domestic
Small General
Medium General
Large Industrial
Total
Sources:
Revenues
Before
After
$mm
$mm
4,317
4,412
1,362
1,392
1,905
1,947
1,820
1,860
9,404
9,611
HQD-12, Doc. 3, page 3
%
2.20%
2.20%
2.20%
2.20%
2.20%
Unit Revenue Req'mt
2008
2009
Change
cts/kWh cts/kWh
8.59
8.79
0.20
7.28
7.45
0.17
5.51
5.47
(0.04)
3.99
3.98
(0.00)
6.50
6.67
0.17
HQD-16, Document 4, Table R-6A
Cost
Regul.
Growth Provision
$mm
2007-08
120.10
16.10
25.07
3.83
(10.27)
5.54
(0.28)
4.79
134.62
30.26
Unit Revenue Req'mt
2007
2008
Change
cts/kWh cts/kWh
8.18
8.59
0.41
7.05
7.28
0.24
5.23
5.51
0.28
3.88
3.99
0.11
6.18
6.50
0.31
Filing
Cost
Regul.
Growth Provision
$mm
2006-07
244.39
(43.87)
34.78
(11.12)
75.84
(14.62)
46.67
(16.45)
401.68
(86.06)
19.31
6.09
8.52
8.14
42.06
Total
$mm
155.51
34.99
3.79
12.65
206.94
(21.06)
(6.54)
(9.50)
(9.75)
(46.85)
Total
$mm
179.46
17.12
51.72
20.46
268.77
(18.04)
(5.61)
(8.14)
(8.36)
(40.15)
Total
$mm
181.78
11.86
48.98
26.16
268.77
6.43
2.03
2.91
3.13
14.50
Total
$mm
114.43
22.03
18.91
19.13
175.50
Change in Cross Subsidies
Subsidy
Unit Revenues
Before Proposed Cost-Based Percent Ch. $mm
7.14
7.30
7.40
3.60%
60.5
9.14
9.34
9.38
2.57%
5.0
7.11
7.26
7.12
0.20%
(38.2)
4.56
4.66
4.59
0.69%
(27.4)
6.62
6.76
6.76
2.20%
(0.1)
Calculations
Decision 2008-024 (Compliance for R-3644-2007)
Domestic
Small General
Medium General
Large Industrial
Total
Sources:
Cost of Service
Sales Volume
2007
2008
2007
2008
4,845.8
5,133.4
59,232
59,760
1,030.1
1,063.5
14,620
14,600
1,418.8
1,505.2
27,129
27,331
1,767.1
1,736.3
45,567
43,569
9,061.8
9,438.4
146,548
145,261
Filing; HQD-11, Doc 1 Table 2, R-3677-2008
Before
$mm
4,165
1,294
1,879
1,929
9,267
Filing
Revenues
After
$mm
4,286
1,332
1,933
1,985
9,536
%
2.91%
2.94%
2.87%
2.90%
2.90%
Before
6.97
8.86
6.87
4.43
6.38
Change in Cross Subsidies
Unit Revenues
Subsidy
Proposed Cost-Based Percent Ch. $mm
7.17
7.27
4.31%
58.5
9.12
8.98
1.32%
(20.9)
7.07
7.06
2.75%
(2.3)
4.56
4.47
1.06%
(35.5)
6.56
6.56
2.90%
(0.2)
Before
6.97
8.86
6.87
4.43
6.38
Change in Cross Subsidies
Subsidy
Unit Revenues
Proposed Cost-Based Percent Ch. $mm
7.17
7.27
4.36%
60.8
9.12
8.94
0.92%
(26.1)
7.07
7.05
2.61%
(5.0)
4.56
4.49
1.36%
(29.8)
6.56
6.56
2.90%
(0.2)
Before
6.84
8.72
6.75
4.33
6.23
Change in Cross Subsidies
Subsidy
Unit Revenues
Proposed Cost-Based Percent Ch. $mm
6.97
7.03
2.83%
36.7
8.89
8.87
1.73%
(2.5)
6.88
6.82
1.03%
(16.2)
4.41
4.37
0.97%
(18.7)
6.35
6.35
1.92%
(0.7)
R-3644-2007 Filing
Domestic
Small General
Medium General
Large Industrial
Total
Sources:
Cost of Service
Sales Volume
2007
2008
2007
2008
4,845.8
5,132.7
59,232
59,760
1,030.1
1,057.3
14,620
14,600
1,418.8
1,501.1
27,129
27,331
1,767.1
1,740.6
45,567
43,569
9,061.8
9,431.7
146,548
145,261
HQD-11, Doc 1 Table 2
Revenues
Before
After
$mm
$mm
4,165
4,286
1,294
1,332
1,879
1,933
1,929
1,985
9,267
9,536
HQD-12, Doc. 3, page 3
%
2.91%
2.94%
2.87%
2.90%
2.90%
Cost
Regul.
Unit Revenue Req'mt
2007
2008
Change
Growth Provision
cts/kWh cts/kWh
$mm
2006-07
8.18
8.59
0.41
243.69
(43.87)
7.05
7.24
0.20
28.58
(11.12)
5.23
5.49
0.26
71.74
(14.62)
3.88
4.00
0.12
50.97
(16.45)
6.18
6.49
0.31
394.98
(86.06)
HQD-15, Document 4, Table R-22(c)
D-2007-12 (Compliance R-3610-2006)
Cost of Service
2006
2007
Domestic
Small General
Medium General
Large Industrial
Total
Sources:
-
-
Sales Volume
2006
2007
59,232
14,620
27,129
45,567
146,548
Cost
Regul.
Revenues
Unit Revenue Req'mt
Before
After
2006
2007
Change
Growth Provision
$mm
$mm
%
cts/kWh cts/kWh
$mm
2006-07
4,050
4,128
1.92%
8.40
0.06
37.00
71.00
1,275
1,299
1.92%
7.00
0.01
2.00
18.00
1,830
1,865
1.92%
5.10
(0.03)
(8.00)
24.00
1,971
2,009
1.92%
3.80
(0.02)
(10.00)
26.00
9,126
9,301
1.92%
6.20
0.01
21.00
139.00
HQD-12, Document 1, Table 28. HQD-15, Document 4, Table R-22(d), R-3644-2007
Shaded cells represent input values
Exhibits 3677.xls; Exhibit IEc-5ii
10/27/2008
EXHIBIT IEc-6
DEMAND AND ENERGY CLASSIFICATION
OF RATE L COSTS
2007 TO 2009
Evidence of Robert D. Knecht
Docket No. R-3677-2008
Workpapers of Robert D. Knecht
Docket No. R-3677-2008
Exhibit IEc-6
Rate L Energy Component of Generation: 2007 to 2009
Load Factor Method Generation Costs
Energy Component of Generation (300 CP)
Energy-Related Patrimonial Costs ($mm)
Rate L Share of LF Method Energy
Rate L LF Method Energy Cost
2007
4,971.2
67.2%
3,340.6
2008
4,603.5
67.1%
3,088.9
2009
4,603.5
67.2%
3,093.6
25.8%
861.6
24.8%
767.5
23.0%
712.6
Table 53
141.8
115.5
Table 9A
909.3
828.1
469.5
42.9%
201.3
450.1
41.4%
186.3
Rate L Hourly Method Energy
Total Generation Energy Costs
861.6
Rate L Transmission Costs
Rate L Energy Share of Transmission
Rate L Transmission Energy Costs
0.0%
-
Total Rate L PGEÉ Costs
10.7
8.9
9.7
Total Rate L Energy Costs
872.3
1,119.4
1,024.1
43,623.0
2.57
110.0%
2.82
2.91
40,074.0
2.56
115.3%
2.95
3.01
Rate L Consumption (GWh)
Rate L Unit Energy Cost (cts/kWh)
Rate L Revenue/Cost Ratio
Cost-Based Rate L Energy Charge (cents/kWh)
HQD Proposed Energy Charge (cents/kWh)
Exhibits 3677.xls; Exhibit IEc-6
45,708.0
1.91
115.6%
2.21
2.84
2009 Source
Table 9A
Table 53
Table 9D
Table 9C
Table 25B
Table 11
HQD-12, D1, Table 1
10/27/2008