VI. Determination of Cap Levels

A. Overview of Positions of Parties

B. Discussion

1. Cap Criteria for Assuring Bundled Customer Indifference

2. Evaluation of Forecast DA CRS Payback Period Scenarios

 

Scenario

Cap

Interest

Maximum

Years to

     

Rate

Undercoll.

Payoff

PG&E

13

2.7

9%

223

9

 

14

2.7

4%

211

8

 

15

4

9%

217

4

 

16

4

4%

211

4

           

SCE

       
 

Scenario

Cap

Interest

Maximum

Years to

     

Rate

Undercoll.

Payoff

 

13

2.7

9%

208

6

 

14

2.7

4%

201

5

 

15

4

9%

208

4

 

16

4

4%

201

3

           

SDG&E

         
 

Scenario

Cap

Interest

Maximum

Years to

     

Rate

Undercoll.

Payoff

 

13

2.7

9%

30.8

4

 

14

2.7

4%

30

3

 

15

4

9%

30.8

2

 

16

4

4%

30

2

           

3. Determination of the 2001-2002 Undercollection

   

Exhibit 151

May 15, 2003 DWR Letter

 
 

Scenario

Assumed Undercollection

(millions)

2001-2002 Method

Estimated Undercollection

(millions)

Variance

(millions)

PG&E

13

$216

2

$311

$95

   

$216

3

$292

$76

   

$216

4

$304

$88

 

14

$210

2

$311

$101

   

$210

3

$292

$82

   

$210

4

$304

$94

 

15

$216

2

$311

$95

   

$216

3

$292

$76

   

$216

4

$304

$88

 

16

$210

2

$311

$101

   

$210

3

$292

$82

   

$210

4

$304

$94

           

   

Exhibit 151

May 15, 2003 DWR Letter

 
 

Scenario

Assumed Undercollection

(millions)

2001-2002 Method

Estimated Undercollection

(millions)

Variance

(millions)

SCE

13

$208

2

$264

$56

   

$208

3

$255

$47

   

$208

4

$260

$52

 

14

$201

2

$264

$63

   

$201

3

$255

$54

   

$201

4

$260

$59

 

15

$208

2

$264

$56

   

$208

3

$255

$47

   

$208

4

$260

$52

 

16

$201

2

$264

$63

   

$201

3

$255

$54

   

$201

4

$260

$59

           

   

Exhibit 151

May 15, 2003 DWR Letter

 
 

Scenario

Assumed Undercollection

(millions)

2001-2002 Method

Estimated Undercollection

(millions)

Variance

(millions)

SDG&E

13

$31

2

$34

$3

   

$31

3

$19

($12)

   

$31

4

$23

($8)

 

14

$30

2

$34

$4

   

$30

3

$19

($11)

   

$30

4

$23

($7)

 

15

$31

2

$34

$3

   

$31

3

$19

($12)

   

$31

4

$23

($8)

 

16

$30

2

$34

$4

   

$30

3

$19

($11)

   

$30

4

$23

($7)

4. Disposition of DWR Operating Reserves

5. Analysis of Key Variables Underlying DA CRS Cap Evaluation

a) Natural Gas Prices

b) New Generation Capacity Additions

c) Levels of DA Load

d) Utility Retained Generation and CTC Costs

e) Off-System Sales (OSS) Prices

6. Interest Rate Assumed as a Source of Financing

a) Parties' Positions

b) Discussion

7. Avoiding Making DA Uneconomic to Customers

a) Parties' Positions

b) Discussion

8. Allocation of the DA CRS Undercollection to Bundled Customer Groups

a) Parties' Positions

b) Discussion

8 The scenario modeling for SDG&E was initially done on a dual basis showing alternate results due to uncertainty as to whether 80 MW of United States Navy load was deemed to be exempt from the DWR components of the DA CRS. The Commission subsequently issued D.03-05-036 on May 9, 2003, affirming that the 80 MW of Navy load is indeed subject to the DWR charges. Accordingly, the treatment adopted in D.03-05-036 is incorporated into the modeling runs relied upon for purposes of analysis of the appropriate cap in this decision. 9 Competition Transition Cost (CTC) was identified in D.02-11-022 as the URG-related component of the DA CRS. 10 Barkovich, CLECA, Ex. 167, p. 10. 11 AreM/WPTF, Ex. 181, at 16. 12 CMTA, Ex. 172 at 5:8-3 13 RT pp. 2054-2055, (McDonald/DWR). 14 RT p. 2056 (McDonald/DWR); RT p. 2073 (McMahon/DWR). 15 RT p. 2058 (McDonald/DWR). 16 CMTA/McGuire, Ex. 172, pp. 7-8 (Table 1). 17 Barkovich, CLECA, Ex. 167, p. 10. 18 SCE/Collette, Ex.160, pp. 4-5. 19 PG&E/Rifas, Ex. 155, p. 1-5. 20 All statutory references are to the Public Utilities Code. 21 Ex. 167, p. 9. 22 D.02-11-022, p. 77 (slip op.). 23 DWR, Ex. 150, p. 7. 24 RT p. 2046 (McDonald/DWR). 25 RT pp. 2138-2140 (Burns/PG&E). 26 Collette, Edison, Ex. 160, p. 10. 27 RT p. 2228. 28 RT pp. 2136-2137 (PG&E/Burns). 29 Currently, the simple average authorized cost of capital is 9.25%. Pursuant to D.02-11-027, the authorized costs of capital of the three utilities are 9.24% (PG&E), 9.75% (SCE), and 8.77% (SDG&E). 30 See ORA Ex. 162, Attach. A. 31 ORA cites to the ALJ ruling of October 25, 2000 in A.99-09-049. 32 See D.02-11-074 33 RT p. 2300 (Hansen/SDG&E). 34 Barkovich, CLECA, Ex. 167, at pp. 13-17. The 4 cent figure was used by DWR in its scenario analysis. 35 SCE/Collette, Ex. 160, pp. 6-8. 36 RT pp. 2114-2117 (Rifas/PG&E); Exs. 157 and 158. 37 CLECA/Barkovich, Ex. 167, p. 26. 38 CLECA/Barkovich, Ex. 168, p. 6. 39 CMTA/McGuire, Ex. 173, p. 9. 40 D.02-11-022, p. 108 (slip op.); RT pp. 2370-2371 (CMTA/McGuire). 41 Strategic Energy/Lacey, Ex. 171, Attachment SEL-2; UC/CSU/CCLC, Ex. 176. 42 D.02-11-022, p. 117 (slip op.). 43 Barkovich, CLECA, Ex. 167, p. 21. 44 Barkovich, CLECA, Ex. 167, p. 23. 45 This figure is simply 1.7¢ times the ratio of $211 million to $505 million. 46 Ex. 155, p. 1-4. 47 Ex. 155, p. 1-4. 48 See D.02-11-022, p. 110 (slip op.). 49 The penetration of direct access among agricultural customers below 20 kW in load is extremely low. But it is not particularly high among agricultural customers over 20 kW in load either. ORA is not opposed to including the entire agricultural class as well as streetlighting customers in the "core class." 50 ORA, Ex. 162, pp. 10-11.

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