BEFORE THE RÉGIE DE L'ÉNERGIE IN ... - regie-energie.qc.ca

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

28 October 2008

prepared on behalf of:

l'Association québécoise des consommateurs

industriels d'électricité (AQCIE)

Conseil de l'industrie forestière du Québec (CIFQ)

prepared evidence of:

Robert D. Knecht

Industrial Economics, Incorporated

2067 Massachusetts Avenue

Cambridge, MA 02140

Evidence of Robert D. Knecht Docket No. R-3677-2008

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My name is Robert D. Knecht. I am a Principal and the Treasurer of Industrial 1 Economics, Incorporated (“IEc”), a consulting firm located at 2067 Massachusetts 2 Avenue, Cambridge, MA 02140. As part of my consulting practice, I prepare analyses 3 and expert testimony in the field of regulatory economics. In Canada, I have 4 submitted expert evidence in regulatory proceedings in Québec, Ontario, Alberta, New 5 Brunswick, Nova Scotia, Manitoba, and Prince Edward Island. In matters regarding 6 Hydro Québec Distribution (“HQD”), I have submitted evidence or reports before the 7 Régie in dockets R-3477-2001, R-3492-2002 (Phases 1 and 2), R-3541-2004, 3563-8 2005, R-3579-2005, R-3610-2006, R-3644-2007, R-3648-2007 and R-3673-2008. I 9 obtained a B.S. degree in Economics from the Massachusetts Institute of Technology 10 in 1978, and a M.S. degree in Management from the Sloan School of Management at 11 M.I.T. in 1982, with concentrations in applied economics and finance. My curriculum 12 vitae and a schedule of my expert evidence presented to regulatory tribunals during 13 the past five years are attached as Exhibit RDK-1. 14

I was retained by l'Association québécoise des consommateurs industriels d'électricité 15 (“AQCIE”) and the Conseil de l'industrie forestière du Québec (“CIFQ”) to evaluate 16 the following aspects of HQD’s filing: 17

• Allocation of post-patrimonial generating costs, particularly the treatment of net 18 resale costs; 19

• Revenue allocation, and tracking historical cross-subsidies; 20

• Tariff design for Rate L. 21

PLEASE PROVIDE THE BACKGROUND FOR YOUR EVIDENCE IN RESPECT OF THE 22 ALLOCATION OF POST-PATRIMONIAL GENERATION COSTS. 23 In Decision D-2007-12, the Régie directed that HQD implement “the hourly method” 24 for allocating post-patrimonial generating costs in this proceeding. HQD indicates 25 that it has adopted that methodology. In Decision D-2008-024, the Régie affirmed the 26 use of the hourly method, but it directed HQD to conduct additional analysis regarding 27 the methodology for allocating HQD’s supply costs associated with the resale of 28 power. 29

In this evidence, I review the overall results of HQD’s hourly methodology to 30 demonstrate that they continue to be inconsistent with the economics of electricity 31 generation . However, I address specifically only the issue of the allocation of 32 stranded costs. In the category of stranded costs, I include both the fixed costs 33 associated with not operating the TransCanada Energy (“TCE”) Bécancour generating 34 station and the net costs associated with surplus power resales. 35

HOW DO THE RESULTS OF HQD’S ALLOCATION OF POST-PATRIMONIAL 36 GENERATING COSTS IN THIS PROCEEDING COMPARE WITH THE RESULTS 37 PRESENTED IN THE PREVIOUS TWO PROCEEDINGS IN WHICH THE “HOURLY 38 METHOD” WAS USED FOR COST ALLOCATION? 39

1. POST-PATRIMONIAL

GENERATING COST

ALLOCATION

INTRODUCTION


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A summary of the results of the hourly cost allocation methodology, applied in 2007, 1 2008 and 2009, are shown in Table IEc-1 below, for the major rate classes. Note that 2 I have made the comparison on a cents-per-kWh of energy generated, as that more 3 accurately reflects the relative costs of generation supply to each rate class, because it 4 is measured before losses. 5

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

Table IEc-1 gives rise to several observations. First, the per-kWh post-patrimonial 6 generation costs have increased substantially in 2009. This is due at least in part to 7 HQD having retained capacity in excess of its needs, resulting in the need to both 8 resell this excess capacity at a loss and to incur fixed costs associated with keeping the 9 TCE Bécancour generation facility shut down. 10

Second, the table indicates that in both 2008 and 2009 the hourly method produces 11 results that are at odds with generation economics, with traditional generation cost 12 allocation methods and with current market prices. Generation economics dictates 13 that the cost of producing power during off-peak periods is lower than the cost of 14 producing power on-peak. For that reason, both traditional cost allocation methods 15 and modern markets for electric power imply that the unit cost to serve high load 16 factor customers should be below that for lower load factor customers. 17

HQD’s method produces the reverse result, with the lowest load factor class (the 18 residential class) being assigned the lowest per-kWh generation cost. This result 19 remains unique in my experience. 20

IN THE EVIDENCE THAT YOU PRESENTED IN LAST YEAR’S PROCEEDING, YOU 21 HYPOTHESIZED THAT AT LEAST PART OF THIS UNUSUAL RESULT WAS DUE TO 22 HQD’S TREATMENT OF THE ACCOUNTING LOSSES THAT IT INCURS ON SURPLUS 23 VOLUMES. WAS YOUR HYPOTHESIS CORRECT? 24 In part it was. However, as HQD witness Mr. Coté indicated last year, the primary 25 reason why the hourly method produces the very unusual results shown above is the 26 lack of any signal for peak demand or capacity in the method, as well as the lack of 27 any differentiation in energy costs in on-peak and off-peak periods. However, based 28 on the analysis presented by HQD in this proceeding, I conclude that HQD’s treatment 29 of the losses on the resale of surplus volumes contributes to the problem. 30


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To illustrate this conclusion, Table IEc-2 below compares the results of HQD’s 1 analysis of its 2008 post-patrimonial costs using the approved hourly method and that 2 using a capacity cost signal. Note that this comparison excludes the effects to resold 3 surplus suppliers.1 I start by reviewing the 2008 analysis, because it excludes the 4 effects of the TCE stranded costs. 5

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

Table IEc-2 demonstrates that for 2008, the hourly method produces results that are 6 directionally correct, although there is virtually no differentiation among rate classes. 7 Moreover, what little differentiation that appears results primarily from differences in 8 class loss factors and not from any differentiation in actual costs. When a capacity 9 price signal is factored in, however, the results show a more traditional inter-class 10 pattern. Thus, I agree with Mr. Coté’s conclusion that the primary reason for the 11 unusual results is the absence of a capacity price signal, as well as its failure to 12 recognize any differentiation in the time-of-use cost of energy. 13

Nevertheless, HQD’s treatment of the resold volumes makes the problem worse. 14 Table IEc-3 compares the allocated 2008 unit costs both before and after the effects of 15 surplus resales are considered. 16

1 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.


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TABLE IEC-3


HOULY METHOD WITH AND WITHOUT SURPLUS RESALE EFFECTS

2008 TEST YEAR


Before Resale

Including Resale Percent

Residential 8.27 9.09 9.9%

Small and Medium General 8.14 9.23 13.4%


Total HQD 8.07 9.21 14.1%

Source: HQD-11, Document 4

Thus, it is apparent that something in HQD’s methodology is causing a 1 disproportionate increase in costs allocated to the business classes, particularly the 2 high load factor large industrial class. That is, the effect of surplus resales on the large 3 industrial class is 1.46 cents per kWh or 18.6 percent of allocated cost, compared to an 4 impact on the residential class of 0.82 cents per kWh or 9.9 percent of allocated cost. 5

Turning to the 2009 analyses, it is apparent that at least one other problem has cropped 6 up. Table IEc-4 below is similar to Table IEc-3, except that it is based on the 2009 7 test year. Because I had the hourly information for 2009, I segregated the results for 8 the small and medium general service customers, and I presented the results on a per-9 unit of energy generated basis. Additional supporting information for these 10 calculations is shown in Exhibit IEc-2 at the back of this evidence.2 11

TABLE IEC-4


HOULY METHOD WITH AND WITHOUT SURPLUS RESALE

2009 TEST YEAR

CENTS PER KWH OF ENERGY GENERATED

Before Resale

Including Resale Percent


Small General 9.83 10.49 6.7%

Medium General 9.76 10.42 6.8%


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.


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The two major changes between 2008 and 2009 are (a) the per-kWh costs of providing 1 post-patrimonial supply increased sharply from 2008 to 2009 and, (b) the allocation of 2 costs in 2009 before the effect of resale volumes is distorted. 3

While it is impossible to know for certain what causes these changes, it appears that 4 both of these results are influenced by HQD’s treatment of the fixed costs of the TCE 5 Bécancour facility.3 Rather than treating those fixed costs as stranded, HQD 6 apparently decided to include those costs as part of hourly supplies, even though there 7 will be no supplies from that facility. In effect, the hourly costs for the post-8 patrimonial energy that will actually be supplied from other generators are 9 substantially overstated. Moreover, judging by the inter-class results, it is apparent 10 that the treatment of the TCE stranded costs is further skewing the cost allocation 11 results. As shown in Table IEc-4 above, the introduction of TCE stranded costs in 12 2009 resulted in more distortion in the “before resale” results than that in 2008 (in 13 Table IEc-3). 14

BEFORE ADDRESSING THE SPECIF ICS OF HQD’S ALLOCATION METHODOLOGY 15 FOR ITS STRANDED TCE AND RESALE COSTS, PLEASE PROVIDE A LITTLE 16 BACKGROUND ON LOAD PATTERNS, HOURLY COSTS AND PRICES ASSOCIATED 17 WITH HQD’S POST-PATRIMONIAL LOAD. 18 In Exhibit IEc- 3, I attach three figures that provide an overview of HQD’s post-19 patrimonial stranded cost issues. 20

Figure IEc-1 compares the post-patrimonial load for Rate D and Rate L. Unlike past 21 years in which the load shapes were unusual, the 2009 load patterns are much more 22 consistent with overall HQD loads. In particular, the Rate D load shows the 23 pronounced winter peak that it exhibits overall. The Rate L load is much flatter, 24 though it also exhibits a winter peak. Of course, the winter peak in Rate L post-25 patrimonial load is not consistent with the overall Rate L load, which is much flatter.4 26

Nevertheless, the overall post-patrimonial load shape is beginning to look more like 27 HQD’s overall load. This is an interesting result in that (a) the overall post-28 patrimonial load remains quite thin relative to the patrimonial load, and (b) the 29 patrimonial load shape was originally designed to be more oriented toward peak hours 30 than HQD’s actual load shape. 31

It is my understanding that the shift in the patrimonial load shape is due to a number 32 of factors, including reductions in high load factor usage (including both lost industrial 33 load and successful PGEE programs such as reducing the use of inefficient 34

3 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. 4 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.


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refrigerators) and increases in winter use of electricity by weather-sensitive customers 1 as a result of increases in fossil fuel costs. 2

Figure IEc-2 compares the total post-patrimonial consumption with the resale 3 volumes. As shown, the resale volumes are much higher in the summer, due again to 4 the pronounced winter peak in the post-patrimonial load. In essence, HQD is 5 incurring more surpluses in the summer due to both reductions in overall load and 6 increases in winter peak load. 7

Figure IEc-3 compares the hourly unit cost of post-patrimonial supplies with the 8 hourly resale unit revenues, for each hour over the year. It is important to recognize 9 that the per-kWh cost reported in this figure is the “hourly method” cost developed by 10 HQD before the resale impacts are considered. However, it includes the effect of the 11 TCE stranded costs. A number of observations apply to this figure: 12

• The resale prices are consistent with generation economics and modern 13 electricity energy markets, in that they are higher on-peak than off-peak, and 14 they are higher in the peak winter and summer seasons (the US export markets 15 have pronounced summer peaks) than in the off-peak seasons. Differentials 16 between on-peak and off-peak prices are about $25 to $30 per MWh. Note that 17 these prices are energy only. Because HQD cannot resell on a firm basis, these 18 prices reflect only hourly energy differentials, and do not reflect capacity-19 related values. 20

• The hourly method costs show very little on-peak/off-peak differentiation, 21 unlike real electricity markets. The very high hourly costs in the summer 22 almost certainly result from spreading the fixed, stranded TCE costs over a 23 relatively small load in the summer. Thus, the hourly method continues to 24 produce costs that are divorced from reality. 25

• The hourly costs are considerably higher than the resale prices. From an 26 accounting perspective, this suggests that HQD is losing money on each sale, 27 which might imply that HQD should not engage in these sales. However, from 28 an economic perspective, as long as the resale values are higher than the 29 incremental cost of the supply, HQD should continue to resell the power. It is 30 therefore important to recognize that the hourly method costs are not consistent 31 with economic reality. 32

PLEASE ADDRESS HOW HQD’S COST ALLOCATION METHOD FOR BOTH TYPES OF 33 STRANDED COSTS CAUSES THE UNUSUAL RESULTS SHOWN IN TABLE IEC-4 34 ABOVE. 35 In respect of the TCE stranded costs, it is my understanding that HQD simply takes 36 the fixed costs that it continues to pay to TCE and it spreads those costs over every 37 hour of the year, with no time-of-use variation and no demand component. Because 38 post-patrimonial loads are lower in the summer than in the winter, the per-kWh 39 delivered cost of the TCE stranded costs is higher in the summer than the winter, 40 leading to the cost pattern shown in Figure IEc-3. Because the high load factor 41


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customers are disproportionately responsible for summer loads, the high load factor 1 customers are assigned a disproportionate share of the stranded costs. 2

In respect of the resale volumes, HQD assigns responsibility for the resold volumes in 3 every hour to the actual post-patrimonial consumption in every hour. In essence, the 4 more a class consumes in a particular hour, the more it is deemed to be responsible for 5 the resold power in that hour. Once HQD determines the volumetric responsibility for 6 the resold volumes, it then applies the hourly method unit cost and the resale revenue 7 to each class’s share in each hour. 8

This approach disproportionately assigns costs to the higher load factor rate classes for 9 two reasons. First, because the higher load factor customers represent a larger share 10 of the summer load, they are assigned a larger share of the resale load. For example, 11 as shown in Exhibit IEc-2, the large industrial class is responsible for 39 percent of the 12 post-patrimonial load but it gets assigned 47 percent of the resold volumes. Second, 13 because the per-kWh losses on resold power are higher in the summer than in the 14 winter (the TCE stranded cost effect), the high load factor classes are assigned a 15 disproportionate share. 16

IS HQD’S METHOD FOR TREATING THESE STRANDED COSTS CONSISTENT WITH 17 COST CAUSATION? 18 No. HQD’s treatment of both types of stranded costs relies on the assumption that 19 resale volumes are somehow proportional to post-patrimonial consumption. In effect, 20 HQD is saying that, if a class’s post-patrimonial load increases, it should be assigned 21 more of the resold volumes. 22

This approach makes little sense. Resales of power are necessary because there is not 23 enough consumption to fill up the contracts, not because there is too much 24 consumption. To the extent that there is any causative relationship between post-25 patrimonial consumption and resale volumes, HQD’s method has it exactly 26 backwards. When demand from a particular class in a particular hour increases, the 27 need to resell power in that hour goes down. 28

In addition, it may be that the need to resell power is not related to any unexpected 29 shortfall in consumption at all. For example, it is not clear that HQD’s planning did 30 not actually anticipate the need to resell power, particularly in the summer months 31 when local demand is low and export prices are more attractive. To the extent that 32 HQD ever made a planning decision based on the expectation that it would resell 33 power, there is surely no reason to charge the net accounting loss on those exports to 34 summer loads. 35

Under those conditions, there is no conceivable cost causation basis for such a cost 36 assignment. 37

CAN IT BE CREDIBLY ARGUED THAT LOSSES IN HIGH LOAD FACTOR INDUSTRIAL 38 LOADS ARE CAUSING HQD TO INCUR RESALE LOSSES, AND THEREFORE HQD 39 SHOULD ASSIGN THE COSTS FOR THE SUMMER LOSSES TO LARGE INDUSTRIAL 40 CUSTOMERS? 41


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No. Such an argument fundamentally misunderstands the economics of resold power. 1

If viewed from the narrow perspective of looking only at accounting costs and only 2 for resold volumes, the argument may appear at first blush to have some merit. 3 Relative to a base case situation, across-the-board reductions in industrial load will 4 result in the need to resell more power in the summer. 5 5

However, lost industrial load is not the only change that will cause these results. For 6 example, an across-the-board reduction in any baseload use (e.g., due to replacement 7 of inefficient refrigerators and installation of compact fluorescent lighting) will also 8 cause this kind of result. Similarly, increases in peak season load (e.g., increases in 9 electric heat due to high fossil fuel prices) will cause this effect. Based on my 10 conversations with AQCIE/CIFQ analyst M. Trahan, I understand that all of these 11 effects are occurring.6 12

In addition, the argument fails on cost causation. If losses on resale were actually 13 caused by customers leaving the system, then it would be appropriate to charge the 14 customers who have left the system for those costs. It makes little sense to assign the 15 costs for customer shutdowns to only one class of customer. The remaining customers 16 in that class are not the ones who are responsible for the shutdown. 17

However, most importantly, this argument is specious on economic grounds, because 18 it assumes that lost industrial load is actually a net cost to the system. This 19 assumption is incorrect. 20

Average large industrial revenues are about 4.6 cents per kWh, and the high load 21 factor customers within the class (particularly those taking service at high voltage) pay 22 a lower rate than that. When one of those customers shuts down, the worst case for 23 HQD is that it loses 4.6 cents per kWh in revenues and it is able to resell that power 24 for an average of 6.3 cents per kWh (ranging anywhere from 5 to 9 cents per kWh, as 25 shown in Figure IEc-3). Thus, in total, HQD will earn more revenues than it loses if a 26 large industrial customer closes, and that benefit will necessarily be passed back to 27 ratepayers in all classes. 28

The problem with the “blame-the-large-industrials” argument is that it focuses only on 29 the accounting cost of the resale volumes, and it ignores the overall economic (and 30 accounting) impact on HQD as a whole. 31

To understand this, consider what happens to overall cost allocation when large 32 industrial load declines. Because the government of Québec in its annual decrees has 33 adopted a proportional allocation for patrimonial load, when large industrial load 34 declines, the other rate classes’ share of patrimonial load increases. This, of course, 35 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. 6 See also HQD-16, Document 8, page 7, and HQD-14, Document 1, page 21.


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benefits those rate classes. However, if the focus of attention is only on the 1 accounting losses of resale, the beneficial effects of the reallocation of patrimonial 2 load will be ignored. 3

Thus, it would be extremely disingenuous, for example, for an analyst to argue that 4 residential customers should get the benefits associated with lost industrial load in the 5 form of a greater entitlement to low-cost patrimonial load, while forcing the remaining 6 large industrial customers to bear the accounting losses associated with resold power 7 supplies. 8

OVERALL, WHAT ARE YOUR CONCLUSIONS AND RECOMMENDATIONS IN THIS 9 PROCEEDING REGARDING POST-PATRIMONIAL GENERATION COST ALLOCATION? 10 As I have in the past, I conclude that the hourly method is not consistent with 11 generation economics, cost causation, or electricity markets. Because it is not an issue 12 in this proceeding, I make no recommendation regarding the allocation of non-13 stranded costs. Nevertheless, in light of the increasing winter peak demands of the 14 post-patrimonial load, I encourage the Régie to monitor whether incorporating a 15 demand component into post-patrimonial cost allocation may merit future attention. 16

In this proceeding, HQD’s stranded costs include all of the fixed costs paid to TCE for 17 the Bécancour facility that supplies no power, as well as the accounting losses on 18 resold power. I conclude that both of these stranded costs should be excluded from 19 the hourly method and allocated separately. 20

In my view, the most equitable way to allocate these costs is in proportion to total 21 generation costs. As I mentioned, the stranded costs are generated as a result of 22 consumed volumes being lower than purchased volumes. Reductions in volumes for a 23 particular class create benefits for other classes in the form of higher patrimonial 24 loads. Because the classes whose loads have not decreased benefit from the lost 25 volumes in the form of more patrimonial load, it would seem fair to assign those costs 26 proportionately. 27

WHAT IS THE IMPACT OF YOUR PROPOSAL ON OVERALL ALLOCATED 28 GENERATION COSTS? 29 Because the TCE stranded costs are confidential, I cannot evaluate the overall impact. 30 However, for illustrative purposes, I prepared an example based on the assumption 31 that the TCE stranded costs for 2009 are $120 million. (The buyout costs for TCE 32 were reported as $73 million at Docket No. R-3673-2008, and the regular TCE 33 demand charges must be added to that.) I also assumed that HQD’s hourly method 34 assigns the TCE stranded costs equally over the 8760 hours of 2009. 35

Based on those assumptions, Table IEc-5 below compares the total unit generation 36 costs based on HQD’s filing and my proposed modification to stranded cost 37 allocation. 38


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TABLE IEC-5

ALLOCATED 2009 TEST YEAR GENERATION COSTS

HQD FILED VERSUS ALTERNATIVE STRANDED COST EXAMPLE


HQD Filed Alternative Example Percent


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

PLEASE PROVIDE A BRIEF BACKGROUND OF THE REGULATORY ISSUES 1 SURROUNDING REVENUE ALLOCATION FOR THIS PROCEEDING. 2 As the parties to these proceedings are well-aware, the regulation of HQD is subject to 3 the unusual (and quite possibly unique) requirement that rates may not be adjusted in 4 order to cause changes in historical levels of cross-subsidization. How that cross-5 subsidization is measured was a matter of some debate over several rate proceedings. 6

Nevertheless, in the 2006 HQD proceeding (R-3610-2006), the Régie approved a 7 methodology proposed by HQD which measures the increase in allocated per-kWh 8 cost from proceeding to proceeding, based on a consistent cost allocation 9 methodology. That is, HQD simulates its cost allocation methodology for the prior 10 test year and for the proposed test year with the same cost allocation methodology. 11 The difference in the per-kWh allocated costs between those two simulations is 12 deemed, under this methodology, to be the necessary difference in rates that would 13 result in no change in cross-subsidies. 14

Thus, in Docket R-3610-2006, the Régie implicitly adopted a new base level of cross-15 subsidies. 16

However, in neither of the last two proceedings has the Régie applied its cross-subsidy 17 approach for revenue allocation.7 Instead, it approved across-the-board rate increases 18 for all rate classes in both cases. 19

In the current proceeding, HQD has again prepared its cross-subsidization analysis, 20 which implies differential rate increases are necessary to prevent cross-subsidies from 21 expanding. However, HQD has again proposed to apply an across-the-board rate 22

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.

2. ALLOCATION OF

TRANSMISSION

COSTS

2. REVENUE

ALLOCATION AND

CROSS-

SUBSIDIZATION


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increase of 2.2 percent. At the direction of the Régie, however, HQD has offered 1 several alternative approaches for differential rate increases. 2

WHAT ARE THE PRIMARY CONSIDERATIONS OF REGULATORS FOR EVALUATING 3 REVENUE ALLOCATION DECIS IONS? 4 As a general rule, regulators consider three primary factors when determining how a 5 rate increase is shared among the various rate classes. First, most regulators consider 6 cost to be the primary consideration, and that the objective of revenue allocation is to 7 move rates more into line with allocated costs under future rates than under prior rates. 8

This objective of “moving toward cost-based rates” is tempered by two other 9 considerations. These are the principle of “rate gradualism” (often referred to as 10 avoiding “rate shock”) and the principle of “value of service.” 11

While it is difficult to pin down exactly what the principle of gradualism requires, 12 many regulators rely on a “rule of thumb” that the rate increase for a particular class 13 be no more than 1.5 or 2.0 times the system average increase. (Generally, for smaller 14 overall increases, regulators are more comfortable with a higher multiple.) Thus, for 15 example, under a “two-times” rule, if the system average rate increase is 2.2 percent, 16 no class is assigned more than a 4.4 percent increase. 17

The principle of “value of service” is that classes who place a higher value on the 18 utility service may be assigned a larger increase than those classes that value the 19 service less highly. This criterion is generally interpreted to mean that customers 20 whose demand will be less affected by a rate increase (i.e., the demand is less price 21 elastic) may be assigned a larger increase. In practice, this criterion is often used to 22 justify lower rate increases for customers or customer classes who are likely to lose 23 load (e.g., bypass rates). 24

WHAT ALTERNATIVE APPROACHES HAS HQD OFFERED FOR REVENUE 25 ALLOCATION IN THIS PROCEEDING? 26 The cross-subsidy analysis indicates that, to maintain constant cross-subsidies, it 27 would be necessary to apply a rate increase of above average increases of 3.6 percent 28 and 2.6 percent to the residential and small general service classes respectively, and 29 below average increases of 0.2 percent and 0.7 percent to the medium general and 30 large industrial rate classes. 31

However, HQD is unwilling to suggest differentiated rate increases of that magnitude. 32 It offers several alternatives based on considerations that are consistent with the “rules 33 of thumb” that I discuss above. However, HQD is willing only to suggest maximum 34 rate increases that are 1.2 times, 1.3 times and 1.4 times the system average. Such 35 constraints are somewhat cautious compared to my experience in other jurisdictions, 36 although they presumably reflect both historical rate increase patterns and political 37 considerations in Québec. 38

DO YOU HAVE SPECIF IC RECOMMENDATIONS REGARDING REVENUE ALLOCATION 39 IN THIS PROCEEDING? 40


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While I encourage the Régie to differentiate rate increases among the various rate 1 classes to restrict or eliminate the growth in cross-subsidies, I do not have a specific 2 proposal in this proceeding. The choice of how much to temper the results of the cost 3 allocation analysis with the principle of “gradualism” is essentially one of judgement. 4 However, I do offer factors for the Régie to consider, and I evaluate whether the 5 Régie’s arguments in Decision 2008-024 justify an across-the-board rate increase in 6 this proceeding. 7

First, if HQD’s across-the-board increase is granted in this proceeding, the total 8 accumulated changes in cross-subsidies would be quite significant. in Exhibit IEc-5, I 9 have compiled the annual increases in cross-subsidies for each major rate class group 10 since the Régie’s adoption of a cross-subsidization metric in R-3610-2006. Under 11 HQD’s proposal, subsidies to the residential class will have increased by over $300 12 million (some 7.1 percent of current revenues), while the subsidies from the large 13 industrial class have increased by over $150 million (some 8.5 percent of current 14 revenues). 15

Second, all of HQD’s business classes already provide quite substantial cross-16 subsidies to the residential class, particularly the medium commercial rate class in 17 which cross-subsidies amount to more than 30 percent of allocated costs. Allowing 18 these subsidies to continue to increase would be considered inequitable in most 19 jurisdictions in my experience. 20

In addition, allowing the cross-subsidies to increase is creating rate design problems. 21 The higher cross-subsidy level for the Rate M customers is creating uneconomic 22 incentives for some customers to want to switch to Rate L, simply to get access to a 23 rate class that is subject to a lower cross-subsidy level. 24

PLEASE REVIEW THE RÉGIE’S RATIONALE IN D-2008-024 REGARDING 25 DIFFERENTIATED RATE INCREASES. 26 In that decision, the Régie identified a number of reasons for adopting an across-the-27 board increase in that proceeding. With respect, I do not agree that these reasons 28 support an across-the-board increase in this proceeding. 29

1) In R-3644-2007, there were unresolved issues regarding transmission and PGEÉ 30 cost allocation that reduced the reliability of the cost analysis. While cost 31 allocation issues may contribute some small uncertainty to HQD’s estimates of 32 impacts, it is important to recognize that HQD’s calculation of before and after 33 cross-subsidies are made using the same cost allocation methodology. Thus, 34 changing a methodology in a particular proceeding does not have a significant 35 effect on the cross-subsidy calculation. Moreover, I believe that the transmission 36 and PGEÉ cost allocation procedures have been resolved, and are therefore not an 37 issue in this proceeding. 38

2. Large industrial load reductions will have an impact on the overall costs to 39 consumers, and the allocation of stranded costs may cause inequities. As I 40 explained earlier, reductions in large industrial load tend to benefit the other 41 customer classes. To the extent that there are any inequities in HQD’s allocation 42


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of stranded costs, it is in favor of the residential class and at the expense of the 1 business classes. For that reason, considerations of equity should doubly favor the 2 differentiated rate increases implied by HQD’s cross-subsidy analysis. 3

3. The treatment of the deferred transmission expense militates against a 4 differentiated increase. As shown in HQD-16, Document 9, Table 16.1, all of the 5 Régie’s changes in last year’s proceeding had only a small net effect on allocated 6 costs. Moreover, it is my understanding that deferred transmission expense is not 7 a significant factor in this proceeding. 8

Therefore, I do not believe that the reasons presented by the Régie in its last decision 9 are applicable to this proceeding. 10

WHAT ARE THE IMPORTANT FEATURES OF THE RATE L TARIFF DESIGN FOR THIS 11 PROCEEDING?8 12 The Rate L tariff consists of demand and energy charges. In considering tariff design 13 for large industrial customers, it is reasonable for the regulator to consider both 14 embedded cost effects and marginal cost effects. As the Régie correctly recognized in 15 Decision D-2008-024, because the vast majority of generation costs assigned to the 16 Rate L class (or all rate classes for that matter) are related to the below-market 17 patrimonial pool, it will be extremely difficult to set rates for Rate L at or near 18 marginal costs. 19

WHAT ARE THE IMPLICATIONS OF AN EMBEDDED COST ALLOCATION STUDY FOR 20 DESIGNING RATES FOR LARGE INDUSTRIAL CUSTOMERS? 21 As a general rule, demand charges are designed to recover costs that are classified as 22 demand-related, and energy charges are designed to recover costs that are classified as 23 energy-related.9 It is important to recognize that, if rates are not designed in this way, 24 the tariff design will result in intra-class cross-subsidization. 25

For example, suppose HQD decided to eliminate the Rate L demand charge entirely, 26 and collect all revenue from an energy charge. Because HQD’s cost allocation 27 methodology classifies costs into demand components and energy components, the 28 cost of service per kWh is different from customer to customer. Under HQD’s 29

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.

3. TARIFF DESIGN

FOR RATE L


14

methodology (as filed in this proceeding), a customer with a 100 percent load factor 1 would cost approximate 3.7 cents per kWh to serve, while a customer with a 60 2 percent load factor would cost about 4.5 cents per kWh to serve, a 21 percent 3 difference. 4

If rates for both types of customer were set at the same average per-kWh rate, the high 5 load factor customer would cross-subsidize the low load factor customer. While this 6 is obviously an extreme example, a similar but less extreme pattern would result if 7 HQD simply over-recovered the energy-related costs in its energy charge. 8

However, over the last several rate proceedings, HQD has been following a pattern of 9 assigning disproportionate increases to the Rate L energy charges and lower increases 10 to the demand charges. This policy will necessarily result in larger rate increases for 11 high load factor rate customers than for lower load factor customers. 12

IS HQD’S RATE DESIGN PROPOSAL IN THIS PROCEEDING CONSISTENT WITH ITS 13 EMBEDDED COST ANALYSIS? 14 No, it is not. Exhibit IEc-6 shows the energy component of costs allocated to the Rate 15 L class in HQD’s cost allocation studies from 2007 through 2009. In that table, I use 16 generous assumptions about the energy component of costs, including the assumptions 17 that all post-patrimonial energy and all PGEÉ costs are energy-related. In actuality, 18 both of those cost items should have a demand-related component. 19

As shown in Exhibit IEc-6, the upper bound for energy-related costs for Rate L, even 20 including a substantial provision for cross-subsidization, is 2.95 cents per kWh. The 21 cost basis is therefore about 1.3 percent above the current Rate L energy charge of 22 2.99 cents per kWh, and about 2.1 percent below HQD’s 3.01 cents per kWh proposed 23 energy charge in this proceeding. 24

I recognize that it is HQD’s view that, for Rate L rate design purposes, all generation 25 costs are energy-related and all transmission and distribution costs are demand-related. 26 Regarding most transmission and distribution costs, as a theoretical matter, I tend to 27 agree with HQD’s all-demand approach. However, the Régie most clearly does not, 28 in that it has directed that a substantial percentage of transmission costs be classified 29 as energy-related. Thus, in HQD’s cost allocation methodology, if a rate class 30 experiences an increase in energy consumption but no increase in peak demand, its 31 allocated transmission costs will increase. Therefore, it is appropriate for rates to 32 reflect that methodology. 33

For similar reasons, I respectfully (and quite strongly) disagree with HQD that all 34 generation costs are energy-related. The patrimonial generation cost allocation 35 scheme put forward by HQD and mandated by government decree allocates 36 patrimonial generation costs using both energy and demand allocators, with a system 37 load factor weighting. Thus, if a Rate L customer can reduce its peak demand with no 38 reduction in energy consumption (i.e., leveling its load), the patrimonial costs 39 allocated to Rate L will go down. Again, this cost allocation method should be 40 reflected in the rate design. 41


15

WHAT OF MARGINAL COST CONSIDERATIONS IN TARIFF L RATE DESIGN? 1 It is my understanding that HQD believes that its approach will encourage 2 conservation, by increasing the energy charge to get it closer to the marginal energy 3 supply costs. However, this argument relies on two dubious premises. 4

First, it relies on the premise that the only price signal that industrial customers 5 consider is the short-term energy price signal. While this may be true for short-term 6 decisions, it is not correct for most serious decisions regarding longer-term investment 7 and operational planning decisions. 8

At large industrial operations, energy efficiency programs generally target loads 9 during all hours of the year, including both peak and off-peak consumption levels. 10 Shifting costs from demand charges to energy charges will likely not create any 11 meaningful additional incentives to conserve. 12

What reducing the relative demand charges will do, however, is reduce the incentive 13 for large industrial customers from maintaining a level load. That is, customers will 14 have less incentive to use energy efficiently. Under HQD’s tariff, the energy charge is 15 the same regardless of whether it is a peak period or an off-peak period, or whether it 16 applies to a customer with a very high load factor or to a customer with a more 17 temperature sensitive peak demand. The demand charge, by contrast, applies only to 18 the customer’s peak demand. Thus, by proposing disproportionate increases to the 19 energy charge, HQD encourages less efficient behavior by Rate L customers. 20

Second, the conservation premise relies on the assumption the relevant marginal cost 21 signal is energy-related. However, the shifting load pattern for post-patrimonial load 22 suggests that the need to meet winter peak demands is becoming an increasingly 23 important supply consideration. Thus, marginal supply costs will increasingly need to 24 recognize the need for capacity as well as energy. 25

WHAT IS YOUR RECOMMENDATION IN THIS PROCEEDING? 26 Based on the foregoing, I recommend that the energy charge for Rate L be set at 2.95 27 cents per kWh if HQD’s across-the-board rate increase is approved, with the balance 28 of the rate increase applied to demand charges. 29

To the extent that the Régie modifies the rate increase proposed for Rate L, I suggest 30 that the energy cost increase be adjusted proportionally. For example, an increase to 31 2.95 cents per kWh is a 1.3 percent increase, compared to HQD’s overall proposed 32 Rate L increase of 2.2 percent. If the Régie approves an overall increase for Rate L of 33 0.7 percent, the energy charge increase should be scaled back by 0.7%/2.2% * 1.3% = 34 0.4%, thereby resulting in an energy charge of 2.92 cents per kWh. 35


16

Based on my analysis completed to date, my recommendations are as follows: 1

• Correct the HQD hourly cost allocation methodology for a mis-allocation of 2 stranded costs. 3

• Assign different rate increases to the various classes to reduce the increases in 4 cross-subsidies, consistent with the Régie’s interpretation of the principles of 5 gradualism and equity. 6

• Set the energy charge for Rate L at 2.95 cents per kWh, with proportional 7 adjustments for any change in the overall Rate L class increase. 8

CONCLUSIONS AND

RECOMMENDATIONS


EXHIBIT IEc-1

CURRICULUM VITAE AND

EXPERT TESTIMONY SCHEDULE

OF

ROBERT D. KNECHT

R O B E R T D . K N E C H T

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 cross-subsidization, 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.



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

1

DOCKET # REGULATOR UTILITY DATE CLIENT TOPICS

P-2008-2044561

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-2008-2039417 et al.


UGI Utilities (Gas Division) July 2008 Pennsylvania Office of Small Business Advocate Design day demand forecast.

R-2008-2039284


UGI Penn Natural Gas July 2008 Pennsylvania Office of Small Business Advocate Revenue sharing, gas supply costs.

R-2008-2039634


PPL Gas Utilities July 2008 Pennsylvania Office of Small Business Advocate

Lost and unaccounted-for gas, gas supply costs.

A-2008-2034045


UGI Utilities, PPL Gas Utilities June 2008 Pennsylvania Office of

Small Business Advocate Public benefits of proposed sale.

R-2008-2011621


Columbia Gas of Pennsylvania May 2008 Pennsylvania Office of Small Business Advocate

Cost allocation, revenue allocation, rate design.

R-2008-2028039


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-2008-2021348


Philadelphia Gas Works April 2008 Pennsylvania Office of Small Business Advocate

Sharing mechanisms, gas supply contracts.

R-2008-2012502


National Fuel Gas Distribution Company March 2008 Pennsylvania Office of

Small Business Advocate Transportation and sales customer rate design, design day forecasts.

ROBERT D. KNECHT


2


R-2008-2013026


T.W. Phillips Gas and Oil Company March 2008 Pennsylvania Office of

Small Business Advocate Rate design treatment of capacity release revenues.

P-00072342 Pennsylvania Public Utility Commission

West Penn Power d/b/a Allegheny Power February 2008 Pennsylvania Office of

Small Business Advocate Default service electricity procurement, rate design, reconciliation.

2007-004 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.


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.


PPL Gas Utilities Corporation July 2007 Pennsylvania Office of Small Business Advocate

Design day forecasting, gas procurement.


PPL Electric Utilities Corporation July 2007 Pennsylvania Office of

Small Business Advocate Cost allocation, revenue allocation, rate design, energy efficiency.

R-00049255 (Remand)


PPL Electric Utilities Corporation May 2007 Pennsylvania Office of

Small Business Advocate Revenue allocation.


Columbia Gas of Pennsylvania, Inc. May 2007 Pennsylvania Office of

Small Business Advocate Gas procurement.



Gas procurement, margin sharing mechanisms.



Cost allocation, revenue allocation, retail gas competition.


Pike County Light & Power Company March 2007 Pennsylvania Office of

Small Business Advocate Default service procurement, rate design.

ROBERT D. KNECHT


3



National Fuel Gas Distribution Company March 2007 Pennsylvania Office of

Small Business Advocate Design day requirements.

C-20065942 Pennsylvania Public Utility Commission

Pike County Light & Power Company November 2006 Pennsylvania Office of

Small Business Advocate Wholesale power procurement by provider of last resort.

R-3610-2006 Régie de l'Énergie, Québec Hydro Québec Distribution November 2006 AQCIE/CIFQ

Post-patrimonial generation cost allocation; cross-subsidization; rate design.


Pennsylvania Power Company September 2006 Pennsylvania Office of

Small Business Advocate Affidavit: POLR rates, wholesale to retail.


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.


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.


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


Public benefits of proposed sale of PG Energy to UGI; asset management agreement.


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.


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

February 2006 New Brunswick Public Intervenor Cost allocation, rate design.

ROBERT D. KNECHT


4



Pennsylvania Power Company December 2005 Pennsylvania Office of

Small Business Advocate Cost allocation and rate design for POLR supplies.

R-3579-2005 Régie de l'Énergie, Québec Hydro Québec Distribution November 2005 AQCIE/CIFQ Generation cost allocation; cross-

subsidization; revenue allocation.

2005-002 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.


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.



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.


Pike County Light and Power (Gas Service) January 2005 Pennsylvania Office of

Small Business Advocate Fair rate of return, cost allocation, class revenue assignment.


National Fuel Gas Distribution December 2004 Pennsylvania Office of


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.


PPL Electric Utilities Corporation June 2004 Pennsylvania Office of


Transmission and distribution cost allocation, rate design, automatic distribution increases.

ROBERT D. KNECHT


5


P-042090 et al.

Pennsylvania Public Utility Commission Philadelphia Gas Works June 2004 Pennsylvania Office of

Small Business Advocate Collections and universal service cost issues.

RP-2003-0203 Ontario Energy Board Enbridge Gas Distribution May 2004 Vulnerable Energy Consumers Coalition et al.

Cost allocation, rate design for pipeline and storage costs.

R-049157 P-042090

Pennsylvania Public Utility Commission Philadelphia Gas Works April 2004 Pennsylvania Office of

Small Business Advocate Cash receipts reconciliation clause.



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



Cambridge, MA 02140 USA

617.354.0074 | 617.354.0463 fax

www.indecon.com


EXHIBIT IEc-2

EFFECTS OF RESALE COSTS AND REVENUES

ON 2009 POST-PATRIMONIAL

ALLOCATED COSTS

Workpapers of Robert D. Knecht Docket No. R-3677-2008

Unit Cost (cts/kWh)

Energy at Generator

(GWh) Energy

Share Cost ($mm) Costs Excluding Surplus Residential 9.17 1,731 35.8% 158.7 Small General 9.83 426 8.8% 41.9 Medium General 9.76 775 16.0% 75.7 Large Industrial 9.73 1,908 39.4% 185.7 Total 9.54 4,839 100.0% 461.9

Costs of Surplus Supplies Residential 11.33 107 22.9% 12.2 Small General 12.01 50 10.6% 6.0 Medium General 11.96 91 19.4% 10.9 Large Industrial 11.81 220 47.0% 26.0 Total 11.75 468 100.0% 55.0

Total Supply Cost Residential 9.29 1,838 34.6% 170.8 Small General 10.06 476 9.0% 47.9 Medium General 9.99 866 16.3% 86.6 Large Industrial 9.95 2,128 40.1% 211.6 Total 9.74 5,307 100.0% 516.9

Resale Revenues Residential 6.93 (107) 22.9% (6.8) Small General 6.91 (50) 10.6% (3.2) Medium General 6.91 (91) 19.4% (5.8) Large Industrial 6.58 (220) 47.0% (13.7) Total 6.29 (468) 100.0% (29.4)

Post-Patrimonial Supply Cost Residential 9.48 1,731 35.8% 164.1 Small General 10.49 426 8.8% 44.7 Medium General 10.42 775 16.0% 80.8 Large Industrial 10.37 1,908 39.4% 197.9 Total 10.07 4,839 100.0% 487.4

Net Effect of the Resale of Surplus Supplies

Cost Markup (cts/kWh)

Percent Markup Cost ($mm)

Residential 0.31 3.4% 5.4 Small General 0.66 6.7% 2.8 Medium General 0.66 6.7% 5.1 Large Industrial 0.64 6.6% 12.3 Total 0.53 5.5% 25.6

Source: HQD-16, Document 9, Table R-2.1

Exhibit IEc-2

Impact of Power Resales on Post-Patrimonial Generation Cost Alloca

Exhibits 3677.xls; Exhibit IEc-2 10/27/2008


EXHIBIT IEc-3

POST-PATRIMONIAL AND RESALE

LOAD, COST AND PRICE FIGURES

Figure IEc-1HQD 2009 Post-Patrimonial Loads

-

100

200

300

400

500

600

700

800

1-Jan

16-Ja

n31

-Jan

15-F

eb2-M

ar17

-Mar

1-Apr

16-A

pr1-M

ay16

-May

31-M

ay15

-Jun

30-Ju

n15

-Jul

30-Ju

l14

-Aug

29-A

ug13

-Sep

28-S

ep13

-Oct

28-O

ct12

-Nov

27-N

ov12

-Dec

27-D

ec

MW

h/ho

ur

Residential Rate L Industrial

Figure IEc-2HQD 2009 Post-Patrimonial Load and Resale Volumes

(500)

-

500

1,000

1,500

2,000

1-Jan

16-Ja

n31

-Jan

15-F

eb2-M

ar17

-Mar

1-Apr

16-A

pr1-M

ay16

-May

31-M

ay15

-Jun

30-Ju

n15

-Jul

30-Ju

l14

-Aug

29-A

ug13

-Sep

28-S

ep13

-Oct

28-O

ct12

-Nov

27-N

ov12

-Dec

27-D

ec

MW

h/ho

ur

Post-Patrimonial Load Resale Volumes

Figure IEc-3HQD Post-Patrimonial Hourly Costs and Resale Revenues

30.00

50.00

70.00

90.00

110.00

130.00

150.00

1-Jan

16-Ja

n31

-Jan

15-F

eb2-M

ar17

-Mar

1-Apr

16-A

pr1-M

ay16

-May

31-M

ay15

-Jun

30-Ju

n15

-Jul

30-Ju

l14

-Aug

29-A

ug13

-Sep

28-S

ep13

-Oct

28-O

ct12

-Nov

27-N

ov12

-Dec

27-D

ec

$/M

Wh

"Hourly Method" Cost Resale Revenue


EXHIBIT IEc-4

EXAMPLE OF ALTERNATIVE STRANDED

COST ALLOCATION


HQD Method Volumes Costs Unit Costs Volumes Costs Unit Costs Volumes Costs Unit Costs

Residential 58,643 1,850.6 3.16 1,731 164.1 9.48 60,374 2,014.7 3.34 Small General 14,430 412.9 2.86 426 44.7 10.49 14,856 457.6 3.08 Medium General 26,423 702.5 2.66 775 80.8 10.42 27,198 783.3 2.88 Large Industrial 66,885 1,637.5 2.45 1,908 197.9 10.37 68,793 1,835.4 2.67 Total 166,381 4,603.5 2.77 4,839 487.4 10.07 171,220 5,090.9 2.97

Alternative Example Patrimonial Sub-Total Stranded Total Cost Volumes Costs Unit Costs Costs Cost Volumes Costs Unit Costs

Residential 1,850.6 1,730.6 127.6 7.38 1,978.2 51.0 60,374 2,029.2 3.36 Small General 412.9 425.7 32.0 7.51 444.9 11.5 14,856 456.3 3.07 Medium General 702.5 775.1 58.0 7.48 760.5 19.6 27,198 780.1 2.87 Large Industrial 1,637.5 1,907.9 142.0 7.44 1,779.5 45.8 68,793 1,825.4 2.65 Total 4,603.5 4,839.2 359.6 7.43 4,963.1 127.8 171,220 5,090.9 2.97

Source: HQD-11, Document 3, Table 9A; IEc Workpapers.

Post-Patrimonial Consumption

Exhibit IEc-4

Example of Alternative Method for Stranded Cost Allocation

Patrimonial Consumption Post-Patrimonial Consumption Total Consumption



EXHIBIT IEc-5

ANALYSIS OF CUMULATIVE CHANGES IN

CROSS-SUBSIDIES AMONG RATE CLASSES


Increase with No Change in

Cross-Subsidy

Approved/Proposed

Increase

Increase in Cross-Subsidy

(Percent)

Base Revenues

($mm)

Increase in Cross-Subsidy

($mm)

Cumulative Increase with No Change in

Cross-Subsidy

Cumulative Approved/Proposed

Increase

Single Year Cumulative Increase in

Subsidy2007 Test YearDomestique 2.83% 1.92% -0.91% 4,050 (36.7) 2.83% 1.92% (36.67) Petite Puissance 1.73% 1.92% 0.19% 1,275 2.5 1.73% 1.92% 2.45 Moyenne Puissance 1.03% 1.92% 0.89% 1,830 16.2 1.03% 1.92% 16.23 Grande Puissance 0.97% 1.92% 0.95% 1,971 18.7 0.97% 1.92% 18.71 Total 1.92% 1.92% 0.00% 9,126 0.7 1.92% 1.92% 0.72

2008 Test YearDomestique 4.31% 2.91% -1.40% 4,165 (58.5) 7.26% 4.88% (98.93) Petite Puissance 1.32% 2.94% 1.61% 1,294 20.9 3.07% 4.91% 23.80 Moyenne Puissance 2.75% 2.87% 0.12% 1,879 2.3 3.81% 4.85% 19.44 Grande Puissance 1.06% 2.90% 1.84% 1,929 35.5 2.04% 4.88% 54.72 Total 2.90% 2.90% 0.00% 9,267 0.2 4.88% 4.88% (0.95)

2009 Test Year ProposedDomestique 3.60% 2.20% -1.40% 4,317 (60.5) 11.12% 7.19% (169.70) Petite Puissance 2.57% 2.20% -0.37% 1,362 (5.0) 5.72% 7.22% 20.47 Moyenne Puissance 0.20% 2.20% 2.01% 1,905 38.2 4.02% 7.16% 59.81 Grande Puissance 0.69% 2.20% 1.50% 1,820 27.4 2.75% 7.18% 80.68 Total 2.20% 2.20% 0.00% 9,404 0.1 7.19% 7.19% (8.74)

Cumulative Three-Year Cross-Subsidy (excluding interest)Domestique (305.30) Petite Puissance 46.72 Moyenne Puissance 95.49 Grande Puissance 154.11 Total (8.98)

EXHIBIT IEc-5

ANALYSIS OF CUMULATIVE CHANGES IN CROSS-SUBSIDIES



R-3677-2008 FilingCost Regul.

Before After 2008 2009 Change Growth Provision Total Subsidy2008 2009 2008 2009 $mm $mm % cts/kWh cts/kWh $mm 2007-08 $mm Before Proposed Cost-Based Percent Ch. $mm

Domestic 5,133.4 5,311.9 59,760 60,440 4,317 4,412 2.20% 8.59 8.79 0.20 120.10 16.10 19.31 155.51 7.14 7.30 7.40 3.60% 60.5 Small General 1,063.5 1,110.1 14,600 14,896 1,362 1,392 2.20% 7.28 7.45 0.17 25.07 3.83 6.09 34.99 9.14 9.34 9.38 2.57% 5.0 Medium General 1,505.2 1,466.3 27,331 26,811 1,905 1,947 2.20% 5.51 5.47 (0.04) (10.27) 5.54 8.52 3.79 7.11 7.26 7.12 0.20% (38.2) Large Industrial 1,736.3 1,591.7 43,569 39,948 1,820 1,860 2.20% 3.99 3.98 (0.00) (0.28) 4.79 8.14 12.65 4.56 4.66 4.59 0.69% (27.4) Total 9,438.4 9,480.0 145,261 142,095 9,404 9,611 2.20% 6.50 6.67 0.17 134.62 30.26 42.06 206.94 6.62 6.76 6.76 2.20% (0.1) Sources: HQD-11, Doc 1 Table 2 HQD-12, Doc. 3, page 3 HQD-16, Document 4, Table R-6A Calculations

Decision 2008-024 (Compliance for R-3644-2007)Cost Regul.


Domestic 4,845.8 5,133.4 59,232 59,760 4,165 4,286 2.91% 8.18 8.59 0.41 244.39 (43.87) (21.06) 179.46 6.97 7.17 7.27 4.31% 58.5 Small General 1,030.1 1,063.5 14,620 14,600 1,294 1,332 2.94% 7.05 7.28 0.24 34.78 (11.12) (6.54) 17.12 8.86 9.12 8.98 1.32% (20.9) Medium General 1,418.8 1,505.2 27,129 27,331 1,879 1,933 2.87% 5.23 5.51 0.28 75.84 (14.62) (9.50) 51.72 6.87 7.07 7.06 2.75% (2.3) Large Industrial 1,767.1 1,736.3 45,567 43,569 1,929 1,985 2.90% 3.88 3.99 0.11 46.67 (16.45) (9.75) 20.46 4.43 4.56 4.47 1.06% (35.5) Total 9,061.8 9,438.4 146,548 145,261 9,267 9,536 2.90% 6.18 6.50 0.31 401.68 (86.06) (46.85) 268.77 6.38 6.56 6.56 2.90% (0.2) Sources: Filing Filing

R-3644-2007 FilingCost Regul.


Domestic 4,845.8 5,132.7 59,232 59,760 4,165 4,286 2.91% 8.18 8.59 0.41 243.69 (43.87) (18.04) 181.78 6.97 7.17 7.27 4.36% 60.8 Small General 1,030.1 1,057.3 14,620 14,600 1,294 1,332 2.94% 7.05 7.24 0.20 28.58 (11.12) (5.61) 11.86 8.86 9.12 8.94 0.92% (26.1) Medium General 1,418.8 1,501.1 27,129 27,331 1,879 1,933 2.87% 5.23 5.49 0.26 71.74 (14.62) (8.14) 48.98 6.87 7.07 7.05 2.61% (5.0) Large Industrial 1,767.1 1,740.6 45,567 43,569 1,929 1,985 2.90% 3.88 4.00 0.12 50.97 (16.45) (8.36) 26.16 4.43 4.56 4.49 1.36% (29.8) Total 9,061.8 9,431.7 146,548 145,261 9,267 9,536 2.90% 6.18 6.49 0.31 394.98 (86.06) (40.15) 268.77 6.38 6.56 6.56 2.90% (0.2) Sources: HQD-11, Doc 1 Table 2 HQD-12, Doc. 3, page 3 HQD-15, Document 4, Table R-22(c)

D-2007-12 (Compliance R-3610-2006)Cost Regul.


Domestic 59,232 4,050 4,128 1.92% 8.40 0.06 37.00 71.00 6.43 114.43 6.84 6.97 7.03 2.83% 36.7 Small General 14,620 1,275 1,299 1.92% 7.00 0.01 2.00 18.00 2.03 22.03 8.72 8.89 8.87 1.73% (2.5) Medium General 27,129 1,830 1,865 1.92% 5.10 (0.03) (8.00) 24.00 2.91 18.91 6.75 6.88 6.82 1.03% (16.2) Large Industrial 45,567 1,971 2,009 1.92% 3.80 (0.02) (10.00) 26.00 3.13 19.13 4.33 4.41 4.37 0.97% (18.7) Total - - - 146,548 9,126 9,301 1.92% 6.20 0.01 21.00 139.00 14.50 175.50 6.23 6.35 6.35 1.92% (0.7) Sources: HQD-12, Document 1, Table 28. HQD-15, Document 4, Table R-22(d), R-3644-2007

Shaded cells represent input values

Unit RevenuesChange in Cross Subsidies

Revenues Unit Revenue Req'mt

Cost of Service Sales VolumeUnit Revenue Req'mtRevenues

Cost of Service Sales Volume Unit Revenues

Cost of Service Sales Volume Unit Revenues

Revenues Unit Revenue Req'mt Change in Cross Subsidies

Revenues Unit Revenue Req'mt Change in Cross Subsidies

Exhibit IEc-5 (Continued)

Change in Cross SubsidiesCost of Service Sales Volume Unit Revenues

Supporting Workpapers for Historical Cross-Subsidy Calculations

Filing; HQD-11, Doc 1 Table 2, R-3677-2008

Exhibits 3677.xls; Exhibit IEc-5ii 10/27/2008


EXHIBIT IEc-6

DEMAND AND ENERGY CLASSIFICATION

OF RATE L COSTS

2007 TO 2009


2007 2008 2009 2009 SourceLoad Factor Method Generation Costs 4,971.2 4,603.5 4,603.5 Table 9AEnergy Component of Generation (300 CP) 67.2% 67.1% 67.2% Table 53Energy-Related Patrimonial Costs ($mm) 3,340.6 3,088.9 3,093.6

Rate L Share of LF Method Energy 25.8% 24.8% 23.0% Table 53Rate L LF Method Energy Cost 861.6 767.5 712.6

Rate L Hourly Method Energy 141.8 115.5 Table 9A

Total Generation Energy Costs 861.6 909.3 828.1

Rate L Transmission Costs 469.5 450.1 Table 9DRate L Energy Share of Transmission 0.0% 42.9% 41.4% Table 9CRate L Transmission Energy Costs - 201.3 186.3

Total Rate L PGEÉ Costs 10.7 8.9 9.7 Table 25B

Total Rate L Energy Costs 872.3 1,119.4 1,024.1

Rate L Consumption (GWh) 45,708.0 43,623.0 40,074.0 Table 11Rate L Unit Energy Cost (cts/kWh) 1.91 2.57 2.56 Rate L Revenue/Cost Ratio 115.6% 110.0% 115.3% HQD-12, D1, Table 1Cost-Based Rate L Energy Charge (cents/kWh) 2.21 2.82 2.95 HQD Proposed Energy Charge (cents/kWh) 2.84 2.91 3.01

Exhibit IEc-6

Rate L Energy Component of Generation: 2007 to 2009


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