Proposed Reforms to Rules for Setting Electric Cooperatives’ Wheeling Rates (RSEC-WR)

Consultation Paper

Philippines Energy Regulatory Commission

December 2015

1

Acronyms and Abbreviations

ANOVA Analysis of Variance

CAPEX Capital Expenditure

CoD Cost of Debt

DSM Distribution, Supply, and Metering

DU Distribution Utility

EC Electricity Cooperative

ERC Energy Regulatory Commission

kWh Kilowatt per hour

OPEX Operating Expenditure

MWh Megawatt per hour

RSEC-WR Rules for Setting Electricity Cooperatives’ Wheeling Rates

2

Table of Contents

1 Introduction 4

2 RSEC-WR Grouping for DSM 5

2.1 Underlying Network Cost Drivers 5

2.2 Revising the RESC-WR Grouping 5

2.3 Effects of New RSEC-WR Grouping 11

2.4 Managing the DSM Transition 16

Appendices

Appendix A : Change in RSEC-WR Grouping by ECs 17

Appendix B : Transition Plan for Setting DSM Charges 19

Tables

Table 2.1: Statistical Differences in EC Groups 6

Table 2.2: Grouping Models Tested 8

Table 2.3: ECs in each grouping 10

Table 2.4: Summary Statistics of Min and Max Group Outliers 11

Table 2.5: Comparison of Median Costs for Current and New Groups 12

Table 2.6: Changes in DSM Median Costs between Current and New Groups (Option 1) 12

Table 2.7: Basis for setting New DSM Charges (2010-2014 average) 13

Table 2.8: Change in Average DSM Revenue by Region with New Grouping Approach 15

Table A.1: ECs by Current and New RSEC-WR Grouping 17

Table B.1: Transition Pathway for Setting the Real DSM Charges for each EC 19

Figures

Figure 2.1: Relationship between Grouping Criteria and Non-Power Operating Costs per kWh (2014-2010 Average) 7

Figure 2.2: Comparison of Current Grouping to Alternative Grouping Options 9

Figure 2.3: Aggregate Effect of Proposed Changes on DSM Charges using the 75th percentile of the groups 14

3

Figure 2.4: Top 5 ECs with the Largest Negative and Positive Change in the DSM Charge 15

4

1 Introduction 1 2 The Philippines Energy Regulatory Commission (ERC) regulates over 120 Electricity 3 Cooperatives (ECs). The ERC introduced the Rules for Setting Electricity Cooperatives’ Wheeling 4 Rates (RSEC-WR) in 2006 based on a benchmark grouping approach for setting EC operating 5 charges. RSEC-WR was a significant step forward but there are a number of issues with its 6 implementation: 7

The current groupings do not achieve the intended objective of grouping ECs with 8 similar underlying cost drivers; and 9

10 The initial cash flow buffer in the Distribution, Service, and Metering (DSM) allowance 11

was not transparent and has not been maintained 12 13 The ERC engaged Castalia to provide advice on a revised approach to the setting of the RSEC- 14 WR for the regulation of ECs from 2016. 15

16 In this consultation paper we detail proposed changes to the criteria for establishing the EC groups 17 including setting a transparent cash flow buffer and suitable transitional measures. 18

19 Consultation Process 20

The aim of this consultation is to get feedback on the four main issues: 21 22

Feedback on the experience of ECs with the current grouping criteria 23 24

The suitability of the proposed new grouping criteria 25 26

The setting of the DSM benchmark at the 75th percentile of the proposed groups; and 27 28

The proposed transitional measures. 29 30 All interested parties are invited to submit their comments on this consultation paper on or before 31 23rd February, 2016. Electronic copies may be sent to tariffs@erc.gov.ph. This consultation paper 32 may be downloaded at the ERC website www.erc.gov.ph or may be photocopied at cost at the 33 ERC Main Office at the Docket Section, 18th Floor, Pacific Center Building, San Miguel Avenue, 34 Pasig City. 35

5

2 RSEC-WR Grouping for DSM 1 2 Grouping the ECs with similar cost drivers has helped incentivise efficiency and has reduced the 3 regulatory burden on ERC. While RSEC-WR was an important step forward, the operating 4 conditions under which the initial groupings were established have changed significantly. Regular 5 revisions to the groups are thus needed to prevent the ECs from facing a DSM charge that does 6 not reasonably reflect their underlying cost drivers. This section summarises the: 7

8 Underlying drivers of network costs; 9

10 Proposed approach for re-grouping the ECs and for calculating the DSM allowance; 11

and 12 13

Effects that the proposed changes will have on the ECs. 14 15 2.1 Underlying Network Cost Drivers 16

Understanding network cost drivers is important for any approach to regulation, but it is especially 17 important for the RSEC-WR approach, that seeks to group ECs according to underlying costs. 18

19 The first step in the RSEC-WR methodology is to estimate required revenue per kWh for each 20 group. Therefore, the objective is to group ECs by factors that determine their costs/kWh. This 21 approach will produce groupings with less variation in costs/kWh within the group and greater 22 differences in the average cost/kWh between groups. 23

24 Evidence from first principles analysis suggest that network length/MWh sold or network 25 length/customer served could be included in the grouping criteria and the impact of other variables 26 such as transformer capacity and geography should be considered. 27

28 2.2 Revising the RESC-WR Grouping 29

In developing the proposed new groupings, we: 30 31

Used the most recent EC cost data—averaged over a five-year period from 2010 to 32 2014, and 33

34 Tested alternative models based on known drivers of DSM costs 35

36 The objective is to create EC groups that are distinct from one another. Statistical analysis can be 37 used to measure the success of the grouping by measuring the differences between groups. The 38 mean costs of each group should be significantly different from the means of each other and from 39 the mean cost of the EC population as a whole. Additionally, the variance within each group 40 should be significantly less than the variance of the population as a whole. 41

42 Failings in the current RSEC-WR grouping 43

Analysis of variance (ANOVA) testing of the current EC groups reveals they are not meaningfully 44 distinct from one another. ANOVA is a statistical technique which measures how likely a set of 45 smaller groups are actually part of a single larger group—with similar ECs. Out of four group 46 comparisons, three did not have statistically significant differences in their means. The analysis of 47 these pairs is summarized below in Table 2.1. 48

6

Table 2.1: Statistical Differences in EC Groups 1 2

Group Pairing Mean DSM Cost (Pesos per kWh)

Variance in DSM Cost

Difference in Means Statistically Significant?

Groups A and B A: 1.879

B: 1.555

A: 0.106

B: 0.131

Yes

Groups A and C A: 1.879

C: 1.654

A: 0.106

C: 0.232

No

Groups B and C B: 1.555

C: 1.654

B: 0.131

C: 0.232

No

Groups D and E D: 1.088

E: 1.054

D: 0.058

E: 0.058

No

3 Data Source: Regulatory Operations Group, Energy Regulatory Commission, March 2014. 4

5 6

The ERC is interested in feedback from ECs and other stakeholders on their experience with the 7 current groupings. For example, do they believe that their cost characteristics are similar to other 8 ECs in their current group? 9

10 Testing of Network Cost Drivers 11

We tested the grouping of ECs across a range of known network cost drivers. However we found 12 that certain cost drivers such as customers/line length, peak demand, and network losses increased 13 the variance within each group with little improvement in the separation between groups—making 14 these drivers less desirable for setting the group criteria. 15

16 The charts in Figure 2.1 show the correlation between non-power operating costs/kWh to the 17 most attractive grouping criteria—that is sales/customer and sales/network km. We also compare 18 this to customer numbers currently used for setting the groups. The charts show that: 19

20 There are economies of scale especially for low volumes of energy sold and low 21

sales/customer. This is shown by the downward sloping trend on each of the graphs, 22 with the steeper decline at lower scales (e.g. lower levels of sales or sales/customer); 23

24 The relationship with non-power operating costs is strongest for sales/customer— 25

reinforcing the inclusion of this factor in the grouping criteria; 26 27

The relationship with non-power operating costs is weakest for customer numbers— 28 questioning the inclusion of this factor in the grouping analysis; and 29

30 Sales/network km has a stronger relationship with non-power operating costs than 31

with customer numbers. 32

Figure 2.1: Relationship between Grouping Criteria and Non-Power Operating Costs per kWh (2014-2010 Average)

7

Comparing Grouping Options 1

Given the results above and the analysis of network cost drivers from other studies, we tested the 2 two alternative grouping models as set out in the table below—either entirely on the basis of 3 Sales/Customer or on the basis on Sales/Customer and Sales/Network for setting DSM charges. 4

5 Table 2.2: Grouping Models Tested 6

7 Group Current Option 1—customer

demand only Option 2—customer demand and sales per network length

Customer no. (000)

Sales per customer

Sales per customer

Sales per customer Sales per Network km

A 10 – 25 <1 MWh <0.65 MWh <0.95 MWh <23 MWh/km

B 25 – 50 <1 0.65 – 1.1 <0.95 >23

C 50 – 100 <1 1.1 – 1.5 0.95 – 1.5

D 10 – 50 1 – 2 1.5 – 1.9 1.5 – 1.9

E 50 – 100 1 – 2 1.9 – 2.3 1.9 – 2.3

F 20 – 150 1 – 3 2.3 – 3.25 2.3 – 3.25

G 30 – 150 3 – 5 > 3.25 > 3.25

8

The objective is to group ECs with similar underlying costs. This will improve the efficiency and 9 fairness of each group. With that caveat, both alternative groupings perform better than the current 10 grouping—since: 11

12 The grouping criteria better reflects network cost drivers; 13

14 There is a clearer difference in average and median values between groups; 15

16 There is less overlap between inter-quartile ranges for each group (i.e. range from 25th

17 to 75th percentiles; and 18

19 The differences in averages between the groups are consistent with expectations form 20

first principles analysis and other studies. For example, costs are lower for groups with 21 higher sales/customer, or sales/network length. 22

23 The spread for the middle 50 percent of ECs is narrower for the grouping by sales/customer only 24 (option 1) but we note that there is also a clear separation between group averages for the grouping 25 by sales/customer and sales/network km (option 2). 26

27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50

8 51

Figure 2.2: Comparison of Current Grouping to Alternative Grouping Options

Current Grouping Option 1—Sales per Customer only

Option 2—Sales per Customer & Sales per Network km

9

10

The proposed options would significantly alter the number of ECs in each group—as 1 illustrated below. Group A would see a substantial reduction, while Groups B and C would 2 see an increase in the number of ECs 3

4 Table 2.3: ECs in each grouping 5

6 Group Current Option 1 Option 2

A

B

C

D

E

F

G

11

16

5

17

28

15

7

4

33

26

15

13

5

3

3

30

30

15

13

5

3 7 8

Preferred Grouping Approach 9

Grouping by sales/customer only (option 1) is preferred because: 10 11

It is a simple and effective method that minimises the variance within the groups 12 while maximizing the variation between groups; 13

14 It is the main driver of economies of scale benefits; and 15

16 It removes the use of customer numbers which had a weaker link to scale effects 17

and is not strongly supported as a key cost driver. 18 19

The new grouping improves the efficiency and allocation of DSM revenues provided under 20 current RSEC-WR framework. We note that the only difference between option 1 and 2 21 is in the allocation of ECs in groups A to C. 22

23 While Option 2 is consistent with first principle analysis—given that networks are asset- 24

driven businesses—the separation between some of the groups is not as strong as in 25 Option 1, and the variation within groups is high, particularly in Group A. 26

27 Both options perform significantly better than the current groupings. 28

29 Assessment of Group Outliers 30

Table 2.4 summarises the key network characteristics of the minimum and maximum ECs 31 in each group. Group A and Group B have the largest variation within their grouping that 32 warrants further investigation of their outliers. 33

34 Generally, we find that the maximum outliers of each group have either lower MWh per 35 network km or a substantially smaller network size that could explain why they have higher 36 costs. For example, in Group A, IFELCO has about 1/3 the volume of electricity per 37 network km to SIARELCO, but both would receive the same DSM charge. Thus, although 38 both have similar customer consumption, there are clear differences in the relative densities 39 of their networks. While the inclusion of these scale factors does not improve the overall 40 performance of the categorisation of ECs, quantitative information on scale factors could 41 be used in assessing applications by ECs for individual price determinations if they 42 consider the group-based DSM charge is unsustainable. 43

44 Ultimately, as a longer term objective, a cost function would be the preferred option for 45 setting DSM charges, especially for the group outliers that have strong justification to 46

11

warrant higher cost. The formulation of a cost function is, however, not considered in this paper.

Table 2.4: Summary Statistics of Min and Max Group Outliers

Group Outliers Group Varianc

e

Network Length (km)

MWh/Network Length (km)

Line Loss

Load Factor

SIARELCO Min A 0.205

437 31.79 7.5% 50.7%

16.1 IFELCO Max A 985 13.17

% 53.1%

ZAMSURECO II Min B

0.104

1955 44.02 19.4 %

44.4%

CAMELCO Max B 438 34.25 12.8 %

46.0%

ALECO Min C

0.045

2171 102.45 23.5 %

38.7%

MAGELCO Max C 1758 12.84 44.2 %

24.4%

ISELCO I Min D

0.020

2292 107.93 13.7 %

48.6%

ZAMECO II Max D 925 110.40 12.4 %

53.3%

PELCO III Min E

0.021

640 197.27 17.6 %

47.8%

LASURECO Max E 893 105.28 17.7 %

35.4%

MORESCO I Min F 0.003

2006 96.58 3.6% 53.3%

SOCOTECO I Max F 1793 92.63 11.7 %

53.8%

SOCOTECO II Min G

0.025

3761 164.33 11.5 %

56.7%

CENECO Max G 2031 284.99 13.0 %

51.6%

1 2 3

2.3 Effects of New RSEC-WR Grouping 4

Without any other changes, updating of the DSM charges under the current groupings to 5 current median costs will result in significant reductions in DSM charges across all groups 6 except for Groups A and B. 7

8 Overall the net effect of updating the current groups with current cost data would reduce 9 the average median. The table below shows the changes in median costs for each of the 10 groups. 11

12 Implementation of the revised grouping (under Option 1) will result in further changes for 13 individual ECs because of changes in both the median costs of groups (due to the new 14 group composition) and switches between groups. 15

12

Table 2.5: Comparison of Median Costs for Current and New Groups 1 2

(PhP/kWh) A B C D E F G

DSM Allowance

(Current Groups ) 2.42 1.82 1.68 1.14 1.32 0.99 0.69

2014-2010 Median

(Current Groups) 2.15 1.79 1.60 1.26 1.18 0.92 0.70

2014-2010 Median

(New Groups) 2.62 1.77 1.26 1.07 0.92 0.83 0.44

3 4

Table 2.6 shows the effect on DSM charges from: 5 6

The change in median costs for each group, and 7 8

The effect of ECs switching groups. 9 10

The top number in each cell is the net change in the median DSM charge (in PhP/kWh) 11 from revising the ECs groups, compared to the up-dated median of the current groupings. 12 The bottom number is the number of ECs affected. Empty cells indicate that there are no 13 ECs that change between those groups (e.g. from current group A to new group C). 14

15 Table 2.6: Changes in DSM Median Costs between Current and New Groups 16 (Option 1) 17

18

Current Group

New Group

Total A B C D E F G

A

11 0.47

4

-0.38 7

B

16 -0.02

16

C

5 0.17

5

D

17 0.51

2 0.00

8 -0.19

6 -0.34

1

E

28 0.59

3 0.08 14

-0.11 7

-0.26 4

F

15 0.34

4 0.15

2 0.00

6 -0.09

3

G

7 0.27

2

0.18 2

-0.19 3

TOTAL 4 33 26 15 13 5 3

19

A detailed table of the ECs corresponding to this table is provided in Appendix A. 20 21

Importance of a DSM Buffer 22

We recommend that the operating revenue requirement for determining the DSM charge 23 is set at the 75th percentile of non-power operating costs for each group based on the latest 24 available data at the time of the determination. 25

26 This creates a buffer for most ECs in the recovery of non-power operating costs that is 27 transparent and predictable, so as to increase certainty in the regulatory framework and 28 help ensure the financial sustainability of the ECs. 29

13

The approach to the regulation of the ECs, and the need for the buffer, can be 1 distinguished from the approach to the regulation of the private DUs. 2

3 Regulatory risk. Under the building-block approach applied to the private 4

DUs, each DU’s costs provide the starting point for the assessment of efficient 5 costs of the DU. Benchmarks and efficiency analysis may be used, but the use 6 of current costs as the starting point and DU-specific analysis helps ensure 7 specific factors affecting the utility’s costs are taken into account. It is 8 impractical for ERC to undertake this detailed analysis for each of the ECs. The 9 approach of grouping and averaging costs under the RSEC-WR makes the 10 regulation of the ECs feasible and provides strong efficiency incentives. 11 However, it increases the risk of mis-specification of costs and limits the extent 12 to which utility-specific factors are considered. 13

14 Capacity to take-on risk. Consistent with the profit-focus of the private DUs, 15

their regulated prices provide for a return on equity. This enables the utility to 16 absorb financial risks and variations between actual costs and the estimated 17 efficient costs and remain financially viable. In contrast the ECs are 18 cooperatives and are not profit—focused. Reflecting this, the approach under 19 the RSEC-WR does not provide for a return on equity. Hence, unless the ERC 20 ‘aims high’ in the estimation of costs the ECs will have limited capacity to 21 absorb financial risks and remain viable. 22

23 Consequences of risk. There are two potential risks. Firstly, there is the risk 24

for the utility that actual costs will exceed allowed costs. As noted above the 25 ECs have more limited capacity to absorb this risk. The second risk, which 26 regulators are often particularly concerned about, is the risk that the actual 27 efficient cost for the utility will be below the allowed costs and the utility will 28 systematically earn excess returns to the earners. However, in the case of the 29 ECs the consequences of ‘aiming high’ on costs are different. The owners are 30 the customers and excess returns should, in principle, be returned to customers. 31 The key to ensuring this is good governance and regulation of the ECs can be 32 used to support good governance. 33

34 The operating revenue requirement would be translated into DSM charges in accordance 35 with the methodology set out in Article 4 of the RSEC-WR. Based on the average data 36 from 2010 to 2014, the operating revenue requirement (in PhP/kWh) for setting DSM 37 charges for the proposed new groupings would be: 38

39 Table 2.7: Basis for setting New DSM Charges (2010-2014 average) 40

41 A B C D E F G

New DSM charge =

75th percentile, 2014- 3.06 1.92 1.32 1.12 0.98 0.88 0.70 2010 Average

Comparisons:

Median, 2014-2010

Averaged 2.62 1.77 1.26 1.07 0.92 0.83 0.44

Current DSM charge 2.42 1.82 1.68 1.14 1.32 0.99 0.69 42 43

Net Effect on DSM Revenues and Tariffs 44

Setting the DSM charges with a margin substantially offsets the reduction in the DSM from 45 up-dating cost estimates. 46

14

Ad

just

men

t to

DSM

Tar

iff

(Ph

p/k

Wh

)

The chart below shows the cumulative effects on the DSM charges for each of the ECs 1 decomposed into the effects of: 2

3 Up-dating of the cost estimates based on the average data between 2010 and 4

2014—in real terms 5 6

Changing the groups; and 7 8

Setting the DSM at the 75th percentile of the groups. 9 10 Figure 2.3: Aggregate Effect of Proposed Changes on DSM Charges using the 75th

11 percentile of the groups 12

13

1.50 DSM Adjustment by Component for all ECs

Effect of updating mean of current groups Effect of change in grouping

Effect ofupdating the mean to the 75th percentile Total Change

1.00

0.50

0.00

-0.50

-1.00

For most ECs the changes are between +0.5 PhP/kWh and -0.5 PhP/kWh. Below we show the ECs that see the largest change in their DSM charge.

15

Ad

just

men

t to

DSM

Tar

iff

(Ph

p/k

Wh

)

QU

IREL

CO

AU

RE

LCO

QU

EZEL

CO

II

GU

IMEL

CO

LEYE

CO

III

KA

ELC

O

MO

PR

EC

O

SIA

REL

CO

ILEC

O I

II

NO

REC

O I

Figure 2.4: Top 5 ECs with the Largest Negative and Positive Change in the DSM 1 Charge 2

3

DSM Adjustment for ECs with the Largest Change 4 5

1.00

Effect of updating mean of current groups Effect of change in grouping

Effect ofupdating the mean to the 75th percentile Total Change

0.80

0.60

0.40

0.20

0.00

-0.20

-0.40

-0.60

-0.80

-1.00

While the DSM charge changes across the ECs (often substantially) the net effect on total DSM revenues is relatively small—plus 5.2%. This is on the assumption that all EC’s apply the new DSM immediately. However, our proposal is to adjust the current DSM to the new DSM over a three year transition period—see section 2.4 below.

Table 2.8: Change in Average DSM Revenue by Region with New Grouping Approach

Current 2014 New DSM

Percentage

Island Region Number

DSM Revenue 2014 DSM

Increase of ECs

(million pesos) Revenue

|(Decrease) (million pesos)

Luzon

I II

III

IV-A

V

CAR

6

6

14

5

8

5

1,196.9

889.3

2,135.9

943.9

965.1

513.5

1,379.5

983.4

1,996.6

1,194.5

1,076.1

549.4

+15.2%

+10.6%

(-6.5%)

+26.5%

+11.5%

+7.0%

Visayas

VI

VII

VIII

10

7

11

1,843.3

1,212.0

1,040.4

1,923.0

1,216.0

1,077.7

+4.3%

+0.3%

+3.6%

Mindanao IX

X

4

8

802.5

930.0

855.6

928.5

6.6%

(-0.1%)

16

1 XI XII

ARMM

CARAGA

3

4

2

6

658.0

911.4

90.6

751.3

607.0

981.5

123.1

773.1

(-7.8%)

7.7%

+35.9%

+2.9%

Total All 99 14,884,225 15,664,989 +5.2% 2 3

2.4 Managing the DSM Transition 4

For all EC’s it is proposed that there be a three year transition period, which would 5 incrementally adjust the DSM for each EC to its new rate. Appendix B shows the proposed 6 DSM charges over the transition period for each EC under the new RESC-WR grouping— 7 assuming implementation from 2016. 8

9 All changes to regulated DSM prices will likely require a public hearing. The proposed 10 changes would be best managed through a transition process or glide path with agreement 11 from the ECs. For ECs that see a reduction, a three year transition to the new lower level 12 would give the EC time to adjust its costs or seek special consideration from the ERC for 13 an individual higher rate. 14

15 While no explicit ‘off-ramp’ is specified for the recovery of DSM OPEX costs through the 16 DSM charges, the establishment of the RSEC-WR framework (either existing or proposed) 17 does not remove the ECs right to apply for a tariff increase through a standard rate case. 18 Four EC’s have applied for determinations outside the existing RSEC-WR regime. 19

17

Appendix A: Change in RSEC-WR Grouping by ECs

Table A.1: ECs by Current and New RSEC-WR Grouping

Current Group

New Group A B C D E F G

A IFLECO, KAELCO, MOPRECO, SIARELCO

AURELCO, BILECO, CAMELCO, GUIMELCO, LEYECO III, QUEZLCO II, QUIRELCO

B ABRECO, CASURECO I,

CASURECO IV, ESMELCO, LANECO, LEYECO I, LEYECO IV, MOELCI I, NORSAMELCO, SAMELCO I, SAMELCO II, SOELCO, SORECO I, SURSECO I, SURSECO II

C BOHECO II, CAGELCO II, CASURECO III, ISLECO II, SORECO II

D ILECO III, NORECO I ASELCO, BUSHECO,

DORMECO, FLECO, MAGELCO, NUVELCO, PANELCO I, ZAMECO I

CEBECO III, MOELCI II, MORESCO II, PRESCO, SUKELCO, ZAMECO II

SURNECO

E BOHECO I, QUEZELCO I, ZAMSURECO II

CAGELCO I, CANORECO, CAPELCO, CEBECO

AKELCO, NEECO I, NEECO II(Area II),

CEBECO II, PALECO I,DASURECO, TARLECO I

18

I, COTELCO, FIBECO, ILECO I, ILECO II, LEYECO V, LUELCO, NEECO II(Area 1), NOCECO, TARELCO I, VRESCO

F ALECO, CENPELCO, INEC, ISECO

NORECO II, PANELCO III, ZAMSURECO I, ZANECO

BATELEC I, ISLECO I

ANECO, BENECO, CASURECO II, DANECO, PELCO II, SAJELCO

MORESCO I, PENELCO, SOCOTECO I

G LASURECO, PALECO III

BATELEC II CENECO, LEYECO II, SOCOTECO II, ZAMCELCO

19

EC Current Group

New Group

Current DSM

2016 DSM

2017 DSM

2018 DSM

ABRECO B B 1.82 1.85 1.89 1.92

AKELCO E D 1.32 1.25 1.19 1.12

ALECO F C 0.99 1.10 1.21 1.32

ANECO F E 0.99 0.99 0.99 0.99

ANTECO B B 1.82 1.85 1.89 1.92

ASELCO D C 1.14 1.20 1.26 1.32

AURELCO A B 2.42 2.25 2.09 1.92

BATELEC I F D 0.99 1.03 1.08 1.12

BATELEC II G F 0.69 0.75 0.82 0.88

BENECO F E 0.99 0.99 0.99 0.99

BILECO A B 2.42 2.25 2.09 1.92

BOHECO I E B 1.32 1.52 1.72 1.92

BOHECO II C B 1.68 1.76 1.84 1.92

BUSECO D C 1.14 1.20 1.26 1.32

CAGELCO I E C 1.32 1.32 1.32 1.32

CAGELCO II C B 1.68 1.76 1.84 1.92

CAMELCO A B 2.42 2.25 2.09 1.92

CANORECO E C 1.32 1.32 1.32 1.32

CAPELCO E C 1.32 1.32 1.32 1.32

CASURECO I B B 1.82 1.85 1.89 1.92

CASURECO II F E 0.99 0.99 0.99 0.99

CASURECO III C B 1.68 1.76 1.84 1.92

CASURECO IV B B 1.82 1.85 1.89 1.92

CEBECO I E C 1.32 1.32 1.32 1.32

CEBECO II E E 1.32 1.21 1.10 0.99

CEBECO III D D 1.14 1.13 1.13 1.12

CENECO G G 0.69 0.69 0.70 0.70

CENPELCO F C 0.99 1.10 1.21 1.32

COTELCO E C 1.32 1.32 1.32 1.32

F E 0.99 0.99 0.99 0.99

Appendix B: Transition Plan for Setting DSM Charges

Table B.1 shows the proposed transition plan for setting real DSM charges for the new RESC-WR grouping. We propose that the DSM charges be adjusted each year by the TGP that would adjust for charges in inflation and efficiency.

Table B.1: Transition Pathway for Setting the Real DSM Charges for each EC

DANECO

20

E E 1.32 1.21

DORECO D C 1.14 1.20 1.26 1.32

ESAMELCO B B 1.82 1.85 1.89 1.92

FIBECO E C 1.32 1.32 1.32 1.32

FLECO D C 1.14 1.20 1.26 1.32

GUIMELCO A B 2.42 2.25 2.09 1.92

IFELCO A A 2.42 2.63 2.85 3.06

ILECO I E C 1.32 1.32 1.32 1.32

ILECO II E C 1.32 1.32 1.32 1.32

ILECO III D B 1.14 1.40 1.66 1.92

INEC F C 0.99 1.10 1.21 1.32

ISECO F C 0.99 1.10 1.21 1.32

ISELCO I F D 0.99 1.03 1.08 1.12

ISELCO II C B 1.68 1.76 1.84 1.92

KAELCO A A 2.42 2.63 2.85 3.06

LANECO B B 1.82 1.85 1.89 1.92

LASURECO G E 0.69 0.79 0.89 0.99

LEYECO I B B 1.82 1.85 1.89 1.92

LEYECO II G G 0.69 0.75 0.82 0.88

LEYECO III A B 2.42 2.25 2.09 1.92

LEYECO IV B B 1.82 1.85 1.89 1.92

LEYECO V E C 1.32 1.32 1.32 1.32

LUELCO E C 1.32 1.32 1.32 1.32

MAGELCO D C 1.14 1.20 1.26 1.32

MOELCI I B B 1.82 1.85 1.89 1.92

MOELCI II D D 1.14 1.13 1.13 1.12

MOPRECO A A 2.42 2.63 2.85 3.06

MORESCO I F F 0.99 0.95 0.92 0.88

MORESCO II D D 1.14 1.13 1.13 1.12

NEECO I E D 1.32 1.25 1.19 1.12

NEECO II-A1 E C 1.32 1.32 1.32 1.32

NEECO II-A2 E D 1.32 1.25 1.19 1.12

NOCECO E C 1.32 1.32 1.32 1.32

NORECO I D B 1.14 1.40 1.66 1.92

NORECO II E D 1.32 1.25 1.19 1.12

NORSAMELCO B B 1.82 1.85 1.89 1.92

D C 1.14 1.20 1.26 1.32

DASURECO

1.10 0.99

NUVELCO

21

D C 1.14 1.20

PANELCO III E D 1.32 1.25 1.19 1.12

PELCO I E E 1.32 1.21 1.10 0.99

PELCO II F E 0.99 0.99 0.99 0.99

PELCO III G E 0.69 0.79 0.89 0.99

PENELCO F F 0.99 0.95 0.92 0.88

PRESCO D D 1.14 1.13 1.13 1.12

QUEZELCO I E B 1.32 1.52 1.72 1.92

QUEZELCO II A B 2.42 2.25 2.09 1.92

QUIRELCO A B 2.42 2.25 2.09 1.92

SAJELCO F E 0.99 0.99 0.99 0.99

SAMELCO I B B 1.82 1.85 1.89 1.92

SAMELCO II B B 1.82 1.85 1.89 1.92

SIARELCO A A 2.42 2.63 2.85 3.06

SOCOTECO I F F 0.99 0.95 0.92 0.88

SOCOTECO II G G 0.69 0.69 0.70 0.70

SOLECO B B 1.82 1.85 1.89 1.92

SORECO I B B 1.82 1.85 1.89 1.92

SORECO II C B 1.68 1.76 1.84 1.92

SUKELCO D D 1.14 1.13 1.13 1.12

SURNECO D E 1.14 1.09 1.04 0.99

SURSECO I B B 1.82 1.85 1.89 1.92

SURSECO II B B 1.82 1.85 1.89 1.92

TARELCO I E C 1.32 1.32 1.32 1.32

TARELCO II E E 1.32 1.21 1.10 0.99

VRESCO E C 1.32 1.32 1.32 1.32

ZAMCELCO G G 0.69 0.69 0.70 0.70

ZAMECO I D C 1.14 1.20 1.26 1.32

ZAMECO II D D 1.14 1.13 1.13 1.12

ZAMSURECO I E D 1.32 1.25 1.19 1.12

ZAMSURECO II E B 1.32 1.52 1.72 1.92

E D 1.32 1.25 1.19 1.12

PANELCO I

1.26 1.32

ZANECO

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