(U 338-E) 2018 General Rate Case A Workpapers REVISED. RO- Rate Base SCE-09 Volume 02, Chapter IV, Book A

Transcription

1 (U 338-E) 2018 General Rate Case A Workpapers REVISED RO- Rate Base SCE-09 Volume 02, Chapter IV, Book A September 2016

2 1 SCE-9, VOLUME 2, CHAPTER IV Rate Base Overview Witness: David Gunn Adjustments & Working Capital Witness: John McCarson Customer Deposits: Paul Hunt

3 2 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: David Gunn Rate Base Overview

4 3 RATE BASE NOTES TO WORKING PAPERS Rate Base is the net investment value on which the Company s return is determined. This represents the depreciated asset value of our properties used to provide service to the public. The major components of Rate Base are Fixed Capital, Adjustments, Working Capital, and Deductions for Reserves. This information is drawn from Chapter IV of SCE-9, Volume 2. Rate Base is shown as Total Company and also cost separated by CPUC and FERC jurisdictions.

5 4 Southern California Edison Summary of Electric Rate Base - Total Company (nominal $000) SCE-9, Volume 2 Line Recorded Estimated No. Item FIXED CAPITAL 1. Electric Plant in Service 38,341,915 40,815,020 43,814,513 46,745,415 50,120,052 53,536, Capitalized Software 1,522,330 1,435,897 1,342,969 1,197,161 1,239,704 1,563, Other Intangibles 196, , , , , , Total Fixed Capital 40,060,520 42,463,041 45,380,893 48,170,019 51,596,896 55,339,572 ADJUSTMENTS 5. Customer Advances for Construction (67,223) (68,035) (65,041) (68,805) (75,604) (81,907) 6. Customer Deposits Total Adjustments (67,223) (68,035) (65,041) (68,805) (75,604) (81,907) WORKING CAPITAL 8. Materials & Supplies 209, , , , , , Mountainview Emission Credits 4,013 3,345 2,708 2,105 1, Working Cash 369, , , , , , Total Working Capital 582, , , , , ,836 DEDUCTIONS FOR RESERVES 12. Accumulated Depreciation Reserve (12,148,795) (12,072,578) (12,618,656) (13,232,867) (13,917,607) (14,750,580) 13. Accumulated Amortization (986,054) (885,695) (753,550) (664,026) (659,380) (790,387) 14. Accum. Def. Taxes - Plant (4,895,300) (5,208,015) (5,556,234) (5,906,069) (6,199,190) (6,430,974) 15. Accum. Def. Taxes - Uniform Capitalization Accum. Def. Taxes - CIAC 99, , , , , , Accum. Def. Taxes - Vacation Accrual 20,236 18,876 17,476 16,035 14,555 13, Unfunded Pension Reserve (66,221) (80,833) (76,060) (75,390) (78,536) (81,026) 19. Total Deductions for Reserves (17,976,651) (18,123,754) (18,871,796) (19,735,432) (20,694,461) (21,868,215) 20. RATE BASE 22,599,453 24,834,567 27,027,261 29,006,412 31,556,675 34,182, DEPR'N & AMORT EXPENSE 1,655,532 1,742,006 1,840,653 2,003,455 2,140,408 2,340,484

6 5 Southern California Edison Summary of Electric Rate Base - CPUC Basis (nominal $000) Line Recorded Estimated No. Item FIXED CAPITAL 1 Plant in Service 30,818,827 32,837,956 35,201,920 37,600,616 40,350,528 43,121,665 2 Capitalized Software 1,427,012 1,345,991 1,258,882 1,122,202 1,162,082 1,465,756 3 Other Intangibles 183, , , , , ,242 4 Total Fixed Capital 32,429,825 34,382,790 36,670,223 38,936,020 41,734,901 44,811,663 ADJUSTMENTS 5 Customer Advances for Construction (67,223) (68,035) (65,041) (68,805) (75,604) (81,907) 6 Customer Deposits (67,223) (68,035) (65,041) (68,805) (75,604) (81,907) WORKING CAPITAL 6 Materials & Supplies 196, , , , , ,207 7 Mountainview Emission Credits 4,013 3,345 2,708 2,105 1, Working Cash 345, , , , , ,056 9 Total Working Capital 546, , , , , ,257 DEDUCTIONS FOR RESERVES 10 Accumulated Depreciation Reserve (10,723,587) (10,627,897) (11,023,543) (11,484,951) (12,007,996) (12,660,356) 11 Accumulated Amortization (924,314) (830,238) (706,368) (622,449) (618,094) (740,898) 12 Accum. Def. Taxes - Plant (3,598,422) (3,745,187) (3,934,432) (4,139,318) (4,315,066) (4,431,267) 13 Accum. Def. Taxes - Capitalized Interest Accum. Def. Taxes - CIAC 99, , , , , , Accum. Def. Taxes - Vacation Accrual 18,969 17,694 16,382 15,031 13,644 12, Unfunded Pension Reserve (62,075) (75,771) (71,297) (70,670) (73,618) (75,952) 17 Total Deductions for Reserves (15,189,946) (15,156,909) (15,604,029) (16,175,471) (16,855,433) (17,724,538) 18 RATE BASE 17,719,222 19,686,099 21,548,011 23,292,395 25,488,107 27,748, DEPR'N & AMORT EXPENSE 1,438,477 1,512,015 1,594,466 1,745,313 1,865,733 2,044,825

7 6 Southern California Edison Summary of Electric Rate Base - ISO (nominal $000) Line Recorded Estimated No. Item FIXED CAPITAL 1 Plant in Service 7,523,088 7,977,063 8,612,593 9,144,799 9,769,525 10,415,024 2 Capitalized Software 95,318 89,906 84,088 74,958 77,622 97,906 3 Other Intangibles 12,289 13,282 13,988 14,241 14,848 14,978 4 Total Fixed Capital 7,630,695 8,080,251 8,710,670 9,233,998 9,861,995 10,527,909 ADJUSTMENTS 5 Customer Advances for Construction Customer Deposits WORKING CAPITAL 6 Materials & Supplies 13,132 12,278 13,057 14,241 15,297 15,844 7 Mountainview Emission Credits Working Cash 23,108 22,784 23,290 25,739 30,305 33,736 9 Total Working Capital 36,240 35,062 36,347 39,980 45,602 49,580 DEDUCTIONS FOR RESERVES 10 Accumulated Depreciation Reserve (1,425,208) (1,444,680) (1,595,114) (1,747,916) (1,909,611) (2,090,224) 11 Accumulated Amortization (61,740) (55,456) (47,182) (41,577) (41,286) (49,489) 12 Accum. Def. Taxes - Plant (1,296,878) (1,462,829) (1,621,803) (1,766,751) (1,884,124) (1,999,707) 13 Accum. Def. Taxes - Capitalized Interest Accum. Def. Taxes - CIAC Accum. Def. Taxes - Vacation Accrual 1,267 1,182 1,094 1, Unfunded Pension Reserve (4,146) (5,061) (4,762) (4,720) (4,917) (5,073) 17 Total Deductions for Reserves (2,786,705) (2,966,845) (3,267,767) (3,559,961) (3,839,028) (4,143,677) 18 RATE BASE 4,880,230 5,148,468 5,479,250 5,714,018 6,068,569 6,433, DEPR'N & AMORT EXPENSE 217, , , , , ,658

8 7 SCE-9, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Customer Advances for Construction

9 8 CUSTOMER ADVANCES FOR CONSTRUCTION NOTES TO WORKPAPERS Customer Advances for Construction represent refundable amounts provided by applicants (generally developers) in advance of constructing new distribution facilities that will later be served by SCE. Developers are required to advance the construction costs that exceed a Commission specified allowance formula pursuant to Distribution Line Extension rules in Tariff Rule 15. These funds are a liability to SCE until reimbursed to the developers. Consistent with Commission rules, SCE does not pay the developers interest for holding these monies. As an interest free source of funds, the Customer Advances for Construction are a proper offset to rate base.

10 9 Average Customer Advances for Construction ($000, Nominal Average Balances) Line Recorded Forecast No. Item Electric Construction 59,500 59,152 60,146 65,631 72,385 77,759 2 Temporary Services 6,080 5,979 5,970 6,095 6,236 6,378 3 CIAC 3,910 3,958 1, Total 69,490 69,089 67,745 72,308 79,137 84,762 EOY Customer Advances for Construction ($000, Nominal EOY Balances) Line Recorded Forecast No. Item Electric Construction 59,974 58,329 61,963 69,299 75,471 80,048 2 Temporary Services 6,043 5,914 6,026 6,163 6,309 6,447 3 CIAC* 5,417 2, Total 71,434 66,744 68,746 75,870 82,404 87,119 *CIAC represents the forfeited advances in the Electric Contruction balance in each year.

11 Recorded Forecast Customer Advances ($ millions) Meter Sets (Thousands) CUSTOMER ADVANCES Customer Advances (EOY- Nominal) Customer Advances (AVG- Nominal) Meter Sets EOY Customer Advances (mil.) AVG Customer Advances (mil.) Meter Sets (Thousands) Dec ,115, ,234,301 46, $102 $ Dec-09 92,477,961 96,649,171 32, $92 $97 32 Dec-10 77,332,367 83,869,416 25, $77 $84 26 Dec-11 74,884,032 75,911,546 19, $75 $76 20 Dec-12 61,146,506 67,223,249 22, $61 $67 23 Dec-13 57,184,292 59,165,399 27, $57 $59 27 Dec-14 62,470,118 59,827,205 29, $62 $60 30 Dec-15 66,017,400 65,580,118 31, $66 $66 32 Dec-16 64,243,539 65,130,469 36, $64 $65 36 Dec-17 67,988,741 66,116,140 40, $68 $66 41 Dec-18 75,462,195 71,725,468 48, $75 $72 49 Dec-19 81,779,756 78,620,975 51, $82 $79 51 Dec-20 86,494,402 84,137,079 51, $86 $84 51

12 11 Southern California Edison Company Rate Base Adjustments Customer Advances Month Total December-14 (62,470,118) January-15 (62,393,871) February-15 (63,121,293) March-15 (64,100,539) April-15 (64,746,762) May-15 (65,840,053) June-15 (67,351,722) July-15 (66,493,941) August-15 (67,689,922) September-15 (68,042,406) October-15 (66,303,218) November-15 (66,633,929) December-15 (66,017,400) 13 Month Total (851,205,174) Less 1/2 First Month (31,235,059) Less 1/2 Last Month (33,008,700) 12 Month Total (786,961,415) Weighted Average (65,580,118)

13 12 Southern California Edison Company Rate Base Deductions for Reserve Customer Advances Recorded 2015 Balances Account Account Description December-14 January-15 February-15 March-15 April-15 May-15 June-15 July-15 August-15 September-15 October-15 November-15 December-15 Average CUSTOMER ADVANCES FOR CONST (140,567) (212,832) (69,797) (53,098) (47,318) (49,503) (144,888) (28,727) (22,792) (85,476) (131,504) (231,843) (257,832) (106,415) CUST ADVANCES FOR CONST-ELEC (55,191,592) (55,028,930) (55,900,570) (56,853,166) (57,500,903) (58,375,231) (59,647,634) (59,010,245) (60,011,805) (60,425,462) (58,686,985) (59,141,534) (58,717,532) (58,128,085) ADVANCES FOR TEMP SERVICES (1,276,518) (1,217,483) (1,131,208) (1,144,171) (1,124,422) (1,065,899) (1,138,762) (1,078,281) (1,069,388) (998,004) (1,050,148) (901,445) (798,291) (1,079,718) CUST ADVANCES FOR TEMP SERVICE (4,432,646) (4,505,831) (4,591,352) (4,621,738) (4,653,484) (4,928,784) (5,047,998) (5,005,650) (5,214,897) (5,222,609) (5,123,725) (5,102,506) (4,987,148) (4,894,039) CUST ADVANCES UNECONOMIC LINE EXT (1,428,795) (1,428,795) (1,428,366) (1,428,366) (1,420,635) (1,420,635) (1,372,440) (1,371,039) (1,371,039) (1,310,856) (1,310,856) (1,256,601) (1,256,597) (1,371,860) Total (62,470,118) (62,393,871) (63,121,293) (64,100,539) (64,746,762) (65,840,053) (67,351,722) (66,493,941) (67,689,922) (68,042,406) (66,303,218) (66,633,929) (66,017,400) (65,580,118)

14 13 CUSTOMER ADVANCES Ending Balances Recorded Forecast Customer Advances - Electr. Constr. 68,526,206 55,099,144 51,909,901 56,620,386 59,974,129 58,329,062 61,962,675 69,298,789 75,470,979 80,047,873 Customer Advances - Temp. Serv. 6,357,826 6,047,361 5,274,391 5,849,732 6,043,271 5,914,477 6,026,066 6,163,405 6,308,777 6,446,530 Total 74,884,032 61,146,506 57,184,292 62,470,118 66,017,400 64,243,539 67,988,741 75,462,195 81,779,756 86,494,402 Total ($000) (74,884) (61,147) (57,184) (62,470) (66,017) (64,244) (67,989) (75,462) (81,780) (86,494) Average Balances Recorded Forecast Customer Advances - Electr. Constr. 69,965,450 61,035,087 53,504,523 54,265,144 59,499,946 59,151,595 60,145,869 65,630,732 72,384,884 77,759,426 Customer Advances - Temp. Serv. 5,946,096 6,188,162 5,660,876 5,562,061 6,080,172 5,978,874 5,970,271 6,094,735 6,236,091 6,377,653 Total 75,911,546 67,223,249 59,165,399 59,827,205 65,580,118 65,130,469 66,116,140 71,725,468 78,620,975 84,137,079 Total ($000) (75,912) (67,223) (59,165) (59,827) (65,580) (65,130) (66,116) (71,725) (78,621) (84,137)

15 14 CUSTOMER ADVANCES FORECAST Account and * Customer Advances for Const-Elec By Component Recorded Forecast Meters 19,829 22,866 27,370 29,879 31,653 36,336 40,519 48,848 51,424 51,310 Beginning Balance 71,640,566 68,526,206 55,099,144 51,909,901 56,620,386 59,974,129 58,329,062 61,962,675 69,298,789 75,470,979 Customer Advances 8,221,600 6,602,137 12,820,281 19,879,234 25,379,327 20,167,071 22,912,999 28,252,501 30,443,908 31,039,689 Refunded Advances (11,335,960) (20,029,199) (13,943,578) (12,765,260) (16,608,611) (19,312,140) (18,522,257) (20,508,801) (23,646,989) (25,838,163) CIAC (2,065,947) (2,403,488) (5,416,973) (2,499,998) (757,128) (407,586) (624,729) (624,632) Ending Balance 68,526,206 55,099,144 51,909,901 56,620,386 59,974,129 58,329,062 61,962,675 69,298,789 75,470,979 80,047,873 Simple Average Balance 70,083,386 61,812,675 53,504,523 54,265,144 58,297,258 59,151,595 60,145,869 65,630,732 72,384,884 77,759,426 * - Broken out of in June 2012 due to a system change

16 15 Calculations - Advance Forecast Meter Sets Cash Advance (Nominal) Transfer Voucher (Nominal) Total Refundable (Nominal) Inflation Adjustment Total (2015$) ,829 5,649,200 2,572,400 8,221, % 8,472, ,866 4,935,838 1,666,299 6,602, % 6,648, ,370 7,217,381 5,602,901 12,820, % 12,807, ,879 8,547,045 11,332,189 19,879, % 19,730, ,653 12,474,196 12,905,131 25,379, % 25,379,327 5-Year Average ( ) 26,319 7,764,732 6,815,784 14,580,516 14,607,792 Average Advance Per Meter (2015$) 555 Escalated Unescalated ,336 20,167, % 20,167, ,519 22,912, % 22,488, ,848 28,252, % 27,111, ,424 30,443, % 28,541, ,310 31,039, % 28,478,074

17 16 Calculations - Refunds Forecast RTS Year Cash Advance Transfer Voucher Total 12/31/15 Refunded Advances 12/31/15 Remaining Advances ,496,553 19,846,244 36,342, % 9.0% 9.0% 3,270, % - 0.0% - 0.0% - 0.0% ,471,308 6,900,997 10,372, % 13.0% 5.6% 583, % 764, % - 0.0% - 0.0% ,283,598 2,763,900 5,047, % 25.0% 7.8% 391, % 376, % 493, % - 0.0% ,484,600 2,937,400 8,422, % 35.0% 9.2% 778, % 673, % 647, % 848, % ,649,200 2,572,400 8,221, % 37.0% 7.4% 609, % 642, % 555, % 534, % 700, ,935,838 1,666,299 6,602, % 26.0% 6.4% 425, % 258, % 272, % 235, % 226, ,217,381 5,602,901 12,820, % 27.0% 9.0% 1,158, % 571, % 347, % 365, % 316, ,547,045 11,332,189 19,879, % 30.0% 11.5% 2,277, % 1,233, % 608, % 369, % 389, ,474,196 12,905,131 25,379, % 79.0% 31.2% 7,930, % 4,627, % 2,507, % 1,235, % 751, ,167, % 9.3% 1,884, % 7,231, % 4,219, % 2,286, % 1,126, ,912, % 9.3% 2,141, % 8,216, % 4,794, % 2,597, ,252, % 9.3% 2,640, % 10,131, % 5,911, ,443, % 9.3% 2,845, % 10,916, ,039, % 9.3% 2,901,197 Total 19,312,140 18,522,257 20,508,801 23,646,989 25,838,163 Average Distribution Year Annual Future % 99.5% % 90.2% % 54.5% % 33.7% % 22.4% % 16.9% % 13.5% % 9.9% % 6.8% % 3.9% 99.5%

18 17 Weighted Average of Historical Refund Data by Prior GRC Weight 20% 20% 60% Year 2009 GRC 2012 GRC 2015 GRC Average 1 7.7% 11.2% 9.2% 9.3% % 36.4% 37.1% 35.7% % 20.0% 18.2% 20.8% % 11.0% 8.9% 11.3% 5 6.2% 4.8% 5.6% 5.6% 6 3.8% 2.6% 3.5% 3.4% 7 1.9% 2.7% 4.4% 3.6% 8 0.7% 3.0% 3.9% 3.1% 9 0.3% 4.6% 3.3% 3.0% % 3.8% 5.1% 3.9% 99.8% 100.1% 99.2% 99.5% Most recent history is best indicator of near term expected amounts absorbed. 35.7% 20.8% 9.3% 11.3% 5.6% 3.4% 3.6% 3.1% 3.0% 3.9%

19 18 Calculations - Temporary Services Advance Forecast (Nominal) (Nominal) (Nominal) Total (Nominal) , ,254 5,782,246 6,357, , ,025 5,578,841 6,047, , ,303 4,498,228 5,274, ,567 1,276,518 4,432,646 5,849, , ,291 4,987,148 6,043,271 5 Year Average ( ) 5,914,516 5 Year Avg ( ) Inflation Adjustments Forecast ,914, % 5,914, ,914, % 6,026, ,914, % 6,163, ,914, % 6,308, ,914, % 6,446,530 Summary Of Ending Balances By Account GENERAL LEDGER RECORDED AMOUNTS Customer Advances for Const 338, , , , , Advances for Temp Services 237, , ,303 1,276, , Customer Advances for Temp Services 5,782,246 5,578,841 4,498,228 4,432,646 4,987,148 Total 6,357,826 6,047,361 5,274,391 5,849,732 6,043,271

20 19 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Materials and Supplies

21 20 MATERIALS & SUPPLIES NOTES TO WORKPAPERS Materials and Supplies (M&S) Inventory (Account 154) is maintained for new plant construction and O&M activities required to operate existing plant. The inventory is required to meet the demands of both planned projects and emergency situations. To maintain the balance between material needs and client response time, SCE has M&S inventory located at numerous sites throughout our 50,000-plus square mile service area. The inventories were analyzed as (1) Transmission and Distribution-related, (2) Generation-related, and (3) Info Technology/Transportation Services-related amounts. SCE makes a rate base adjustment for certain accounting requirements associated with the M&S investment unpaid sales tax liabilities and unpaid invoices.

22 21 Southern California Edison Cash Working Capital Materials & Supplies Summary ($000, Nominal Average Balances, SCE Share) Line Recorded Forecast 5-Year No. Item Growth 1. Transm. & Distribution 162, , , , , , % 2. PVNGS 30,236 30,605 30,114 30,193 29,021 28, % 3. Hydro 3,459 3,459 3,459 3,459 3,459 3, % 4. Mountainview 4,732 4,962 4,962 4,962 4,962 4, % 5. Peaker Project 935 1,073 1,073 1,073 1,073 1, % 6. Solar PV % 7. Subtotal - Generation 39,435 40,188 39,696 39,776 38,604 38, % 8. Info Tech. (Excl. Nonutility) 8,110 8,345 8,580 8,821 9,069 9, % 9. Transportation Services % 10. Subtotal - General 8,513 8,822 9,070 9,317 9,571 9, % 11. Total M&S 210, , , , , , % 12. Less: Accounting Adjustments (19,231) (19,055) (18,833) (20,660) (22,352) (23,166) 3.8% 13. Total Adjusted M&S 190, , , , , , %

23 22 Southern California Edison Cash Working Capital Recorded Materials & Supplies ($000, Nominal Average Balances, SCE Share) Line Recorded 5-Year No. Item Growth 1. Transm. & Distribution 119, , , , , , % 2. PVNGS 22,061 22,642 24,578 26,612 27,881 30, % 3. Hydro 2,668 2,830 2,934 3,194 3,402 3, % 5. Mountainview 4,419 4,632 4,577 4,605 4,552 4, % 6. Peaker Project % 7. Solar N/A 8. Subtotal - Generation 29,924 30,915 32,961 35,338 36,806 39, % 9. Info Tech. (Excl. Nonutility) 6,455 6,880 6,914 7,684 7,598 8, % 10. Transportation Services % 11. Subtotal - General 7,220 7,392 7,370 7,972 7,934 8, % 12. Total M&S 156, , , , , , % 13. Accounting Adjustments (16,223) (12,798) (14,215) (13,826) (15,790) (19,231) 3.5% 14. Total Adjusted M&S 140, , , , , , %

24 23 Transmission & Distribution M&S 6.3% CAGR 6.8% CAGR $ $ $ $ $ $ $ $ $ $ Generation M&S 5.7% CAGR -0.7 % CAGR $30.91 $32.96 $35.34 $36.81 $39.43 $40.19 $39.70 $39.78 $38.60 $38.15 Information Technology and Transportation Services-Related M&S 3.3% CAGR 2.9% CAGR $7.39 $7.37 $7.97 $7.93 $8.51 $8.82 $9.07 $9.32 $9.57 $9.83

25 24 Southern California Edison Cash Working Capital Recorded Materials & Supplies ($000, Nominal EOY Balances, SCE Share) Line Recorded 5-Year No. Item Growth 1. Transm. & Distribution 119, , , , , , % 2. PVNGS 22,248 23,170 25,287 26,926 28,699 32, % 3. Hydro 2,683 2,925 3,028 3,380 3,425 3, % 5. Mountainview 4,511 4,613 4,618 4,520 4,593 4, % 6. Peaker Project , % 7. Solar N/A 8. Subtotal - Generation 30,250 31,539 33,844 35,776 37,672 41, % 9. Info Tech. (Excl. Nonutility) 6,913 6,459 7,573 7,860 7,937 8, % 10. Transportation Services % 11. Subtotal - General 7,454 7,000 7,856 8,158 8,303 8, % 12. Total M&S 156, , , , , , % 13. Accounting Adjustments (19,575) (21,865) (14,785) (17,038) (20,362) (20,102) 0.5% 14. Total Adjusted M&S 137, , , , , , %

26 25 Southern California Edison Cash Working Capital Recorded Materials & Supplies ($000, Nominal EOY Balances, SCE Share) Line Recorded Forecast 5-Year No. Item Growth 1. Transm. & Distribution 162, , , , , , % 2. PVNGS 32,121 29,090 31,137 29,249 28,794 28, % 3. Hydro 3,459 3,459 3,459 3,459 3,459 3, % 5. Mountainview 4,962 4,962 4,962 4,962 4,962 4, % 6. Peaker Project 1,073 1,073 1,073 1,073 1,073 1, % 7. Solar PV % 8. Subtotal - Generation 41,703 38,673 40,720 38,832 38,376 37, % 9. Info Tech. (Excl. Nonutility) 8,229 8,461 8,699 8,943 9,194 9, % 10. Transportation Services % 11. Subtotal - General 8,697 8,948 9,192 9,442 9,700 9, % 12. Total M&S 212, , , , , , % 13. Accounting Adjustments (20,102) (18,008) (19,659) (21,660) (23,043) (23,289) 3.0% 14. Total Adjusted M&S 192, , , , , , %

27 26 Southern California Edison Cash Working Capital Recorded Materials & Supplies ($ Nominal Monthly Balances, SCE Share) Line No. Item 1. Transm. & Distribution 2. Palo Verde 3. Hydro 5. Mountainview 6. Peakers 7. Solar 8. Subtotal - Generation 9. Info Tech. (Excl. Nonutility) 10. Transportation Services 11. Subtotal - General 12. Total M&S 13. Accounting Adjustments 14. Total Adjusted M&S Recorded Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun ,678, ,686, ,524, ,565, ,362, ,901, ,486,503 28,699,358 29,469,961 29,494,113 29,320,191 29,793,444 28,942,898 29,350,912 3,425,210 3,422,623 3,429,823 3,433,936 3,452,615 3,467,221 3,470,954 4,592,551 4,584,944 4,573,226 4,581,627 4,599,373 4,607,945 4,613, , , , , , , ,613 67,093 66,483 66,483 66,483 66,483 66,042 66,042 37,671,932 38,428,985 38,443,114 38,289,698 38,807,065 37,989,512 38,403,599 7,936,914 8,280,791 8,225,872 8,154,674 8,097,089 8,050,527 7,966, , , , , , , ,152 8,303,471 8,629,293 8,577,183 8,533,100 8,478,091 8,453,118 8,354, ,653, ,745, ,544, ,388, ,647, ,343, ,244,232 (20,361,720) (16,093,547) (17,009,991) (20,694,453) (19,447,367) (19,421,129) (20,759,187) 179,292, ,651, ,534, ,693, ,200, ,922, ,485,046

28 27 Southern California Edison Cash Working Capital Recorded Materials & Supplies ($ Nominal Monthly Balances, SCE Share) Line No. Item 1. Transm. & Distribution 2. Palo Verde 3. Hydro 5. Mountainview 6. Peakers 7. Solar 8. Subtotal - Generation 9. Info Tech. (Excl. Nonutility) 10. Transportation Services 11. Subtotal - General 12. Total M&S 13. Accounting Adjustments 14. Total Adjusted M&S Recorded Weighted Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Average 166,704, ,811, ,025, ,922, ,975, ,449, ,085,909 29,420,023 29,609,444 32,369,971 32,793,367 31,857,876 32,120,503 30,236,011 3,469,641 3,481,405 3,482,041 3,473,203 3,479,240 3,459,004 3,458,734 4,797,014 4,914,594 4,881,778 4,888,986 4,963,510 4,962,432 4,731, , ,909 1,006,032 1,007,243 1,062,798 1,072, ,483 65,923 65,753 82,215 82, ,894 88,729 72,764 38,661,184 38,977,105 41,822,037 42,245,256 41,464,319 41,703,274 39,434,956 8,089,954 8,085,785 8,062,375 8,114,490 8,104,936 8,229,398 8,109, , , , , , , ,863 8,499,505 8,509,337 8,506,588 8,561,546 8,548,965 8,696,779 8,512, ,865, ,297, ,354, ,729, ,988, ,849, ,033,447 (19,046,289) (19,240,471) (19,966,811) (19,444,658) (19,416,119) (20,101,827) (19,230,983) 194,819, ,057, ,387, ,284, ,572, ,747, ,802,464

29 28 Southern California Edison Cash Working Capital Recorded Materials & Supplies Compound Annual Growth Rates ($ Nominal Average Balances, SCE Share) Line Recorded Compound Annual Growth Rate No. Item Year 4-Year 3-Year 2-Year 1. Transm. & Distribution 119,324, ,319, ,519, ,933, ,235, ,085, % 8.2% 12.6% 14.4% 2. PVNGS 22,061,119 22,641,937 24,577,509 26,612,074 27,881,053 30,236, % 7.5% 7.2% 6.6% 3. Hydro 2,667,775 2,830,163 2,933,820 3,194,293 3,402,447 3,458, % 5.1% 5.6% 4.1% 5. Mountainview 4,419,073 4,632,492 4,577,246 4,604,806 4,552,145 4,731, % 0.5% 1.1% 1.4% 6. Peaker Project 776, , , , , , % 3.8% 4.6% 5.0% 7. Solar PV - 3,309 54,687 79,411 79,890 72,764 N/A 116.6% 10.0% -4.3% 8. Subtotal - Generation 29,924,465 30,914,670 32,961,046 35,338,477 36,805,738 39,434, % 6.3% 6.2% 5.6% 9. Info Tech. (Excl. Nonutility) 6,454,683 6,879,633 6,913,650 7,684,430 7,598,047 8,109, % 4.2% 5.5% 2.7% 10. Transportation Services 765, , , , , , % -5.9% -4.1% 18.4% 11. Subtotal - General 7,219,795 7,392,443 7,370,016 7,971,647 7,933,697 8,512, % 3.6% 4.9% 3.3% 12. Total M&S 156,468, ,626, ,850, ,243, ,974, ,033, % 7.6% 10.9% 12.1%

30 29 Southern California Edison Cash Working Capital - T&D Materials and Supplies Forecast ($M Nominal Balances, SCE Share) Analysis of Materials & Supplies to Capital Expenditures Regression of 3-Year Rolling Average M&S to T&D Capital Expenditures Transmission and Distribution Activity Annual Activity/Balance 3-Year Average Activity Unadjsuted Less: Capital Required M&S Inc. Change EOY Capital Incr. Capital Materials Period Year CapEx Inc. Projects Expenditures Per $1 Cap Ex in M&S M&S Expenditures Expenditures & Supplies A B C D E=C+D F G=F*J H I J K 1998 $ $0.00 $ $ $ $0.00 $ $47.26 $ $ $ $0.00 $ $51.33 $ $ $ $0.00 $ $44.62 $ $ $ $0.00 $ $51.79 $ $ $ $0.00 $ $55.93 $ $ $1, $0.00 $1, $58.78 $1, $ $1, $0.00 $1, $72.55 $1, $ $1, $0.00 $1, $82.27 $1, $ $1, ($34.14) $1, $93.10 $1, $ $1, ($136.27) $1, $97.76 $1, $ $1, ($243.26) $1, $ $1, $ $2, ($481.22) $1, $ $1, $ $2, ($657.19) $1, $ $1, $ $2, ($710.10) $2, $ $1, $ $2, ($474.33) $2, $ $2, $ $3, ($472.74) $2, $ $2, $ Recorded 2015 $3, ($275.39) $2, $ $2, $ Forecast 2016 $2, ($173.00) $2, $7.90 $ $2, $ $ $3, ($383.05) $3, $17.22 $ $3, $ $ $4, ($190.49) $3, $21.93 $ $3, $ $ $4, ($200.85) $4, $14.87 $ $3, $ $ $4, ($159.48) $3, $2.51 $ $3, $45.77 $ $54,787 per $1M of Capital Expenditures

31 30 Materials & Supplies: T&D Forecast Analysis of Materials & Supplies to Capital Expenditures Regression of 3-Year Rolling Average M&S to T&D Capital Expenditures Transmission & Distribution (Excluding Incentive Projects) SUMMARY OUTPUT Regression Statistics Multiple R R Square Adjusted R Square Standard Error Observations 17 ANOVA df SS MS F Significance F Regression E-12 Residual Total Coefficients Standard Error t Stat P-value Lower 95% Upper 95% Lower 95.0% Upper 95.0% Intercept CapEx E ,591 2,785 2,317 1,998 1,806 1, , , , , , M&S 3-Year Avg. Capital Expenditures 3-Year Avg.

32 31 Southern California Edison Cash Working Capital - T&D Materials and Supplies Forecast ($ Nominal Balances, SCE Share) Sales Tax Unpaid Total GL Month Payable** Invoices Adjustments A B C D=B+C Dec-14 (6,248,250) (14,113,470) (20,361,720) Jan-15 (1,761,551) (14,331,996) (16,093,547) Feb-15 (2,550,793) (14,459,198) (17,009,991) Mar-15 (6,034,257) (14,660,196) (20,694,453) Apr-15 (4,698,137) (14,749,230) (19,447,367) May-15 (4,622,673) (14,798,455) (19,421,129) Jun-15 (5,755,712) (15,003,474) (20,759,187) Jul-15 (3,928,194) (15,118,094) (19,046,289) Aug-15 (4,233,202) (15,007,269) (19,240,471) Sep-15 (4,743,473) (15,223,338) (19,966,811) Oct-15 (4,265,531) (15,179,127) (19,444,658) Nov-15 (4,360,024) (15,056,095) (19,416,119) Dec-15 (5,055,571) (15,046,255) (20,101,827) 13 Month Total (58,257,369) (192,746,198) (251,003,567) Less 1/2 First Month (3,124,125) (7,056,735) (10,180,860) Less 1/2 Last Month (2,527,786) (7,523,128) (10,050,913) 12 Month Total (52,605,458) (178,166,336) (230,771,794) Weighted Average (4,383,788) (14,847,195) (19,230,983) **Adjusted to exclude SONGS

33 32 Material & Supplies Inventory: Unpaid Invoices** Recorded (Jan 2015 Dec 2015)* Weighted Average Inventory 190,948,496 Monthly Average Inventory Receipts 13,040,070 Average Payment Lag (in Months) 1.04 Average Unpaid Inventory** 13,498,086 Average Recorded Unpaid Inventory % 7.07% *Excludes Rate Base and Participant Adjustments **Adjusted to exclude SONGS

34 33 Material & Supplies Inventory: Unpaid Invoices** Month Inventory Payments Payment Lag Days Weighting Monthly Lag Dec-14 15,588, ,204, Jan-15 11,910, ,193, Feb-15 12,026, ,635, Mar-15 14,406, ,733, Apr-15 12,560, ,240, May-15 13,125, ,364, Jun-15 13,875, ,572, Jul-15 12,380, ,659, Aug-15 14,527, ,516, Sep-15 12,247, ,386, Oct-15 12,718, ,354, Nov-15 10,276, ,491, Dec-15 12,282, ,834, **Adjusted to exclude SONGS Total Dec 14-Dec ,927, ,287,187,

35 34 Material & Supplies Inventory: Sales Tax Liabilities Month Sales Tax Payable** M&S Inventory* % of Inventory A B C D=-B/C Dec-14 (6,248,250) 199,653, % Jan-15 (1,761,551) 202,745, % Feb-15 (2,550,793) 204,544, % Mar-15 (6,034,257) 207,388, % Apr-15 (4,698,137) 208,647, % May-15 (4,622,673) 209,343, % Jun-15 (5,755,712) 212,244, % Jul-15 (3,928,194) 213,865, % Aug-15 (4,233,202) 212,297, % Sep-15 (4,743,473) 215,354, % Oct-15 (4,265,531) 214,729, % Nov-15 (4,360,024) 212,988, % Dec-15 (5,055,571) 212,849, % Average 2.1% *Excludes Rate Base Adjustments ** Adjusted to exclude SONGS

36 35 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Mountainview Emission Credits

37 36 MOUNTAINVIEW EMISSION CREDITS NOTES TO WORKPAPERS Mountainview Emission Credits represent RECLAIM Trading Credits that are required by the South Coast Air Quality Management District (SCAQMD) to operate the plant. The total RTC emission credits, available to Mountainview at acquisition, were originally valued at $18.8 million. The total Mountainview RTC emission credits are based upon the associated pounds of NOx credits per year and projected annual value of those credits, annually through In D , the Commission authorized the transfer of the Mountainvew Emission Credits Inventory to SCE s utility rate base.

38 37 Mountainview Emission Credits Inventory ($000, Nominal Average Balances) Line Item Recorded Forecast No Emission Credits 6,774 6,106 5,468 4,861 4,284 3,734

39 38 Mountainview Emissions Credits RECLAIM Trade Credits and Volatile Organic Compounds Nominal $ Line Recorded Forecast No. Item RTCs Beg. Year 8,256,078 7,522,430 6,793,664 6,127,099 5,488,381 4,881,598 4,305,155 3,757,534 Add: 2. RTC's Purchased , , , , ,978 Less: 3. RTC's Consumed (563,069) (602,861) (546,437) (753,031) (723,277) (695,734) (669,798) (645,218) 4. Fair Market Value Adjustment (139,577) (83,582) (98,849) 5. Write-Off (30,968) (39,683) (21,130) 6. Transfers Prior Period True-Up (35) (2,640) (149) 8. YE RTC Balance 7,522,430 6,793,664 6,127,099 5,488,381 4,881,598 4,305,155 3,757,534 3,237, VOCs Beg. Year 351, , , , , , , , Less amort. (15,294) (15,294) (15,294) (15,294) (15,294) (15,294) (15,294) (15,294) 11. Bal. VOCs Year-End 336, , , , , , , , Total Year-End 7,858,889 7,114,830 6,432,972 5,778,960 5,156,884 4,565,147 4,002,232 3,466, Average Balance 8,233,361 7,486,860 6,773,901 6,105,966 5,467,922 4,861,015 4,283,689 3,734,465

40 39 WORKING CAPITAL NOTES TO WORKPAPERS Working Cash This section presents the Working Cash component of Rate Base. Working Cash is included in Rate Base to compensate Edison's investors for the funds provided by them. These funds are used for paying operating expenses in advance of receiving customer revenues and for working funds for day-to-day operational requirements. If these funds are not recognized through a Working Cash allowance, investors are not compensated for their use. The amounts of Working Cash required is the sum of Edison's Operational Cash Requirement and a Working Cash Capital requirement resulting from the difference in the average number days' lag between the collection of revenues and the payment of expenses. From this amount, estimates of vacation accrued by Edison employees but not yet taken and estimates of Working Cash Capital not supplied by investors are deducted. The net amount represents the Working Cash supplied by Edison's investors and is shown in SCE-09, Volume 2, Chapter 4.

41 40 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT

42 41 WORKING CASH OPERATIONAL CASH REQUIREMENTS NOTES TO WORKPAPERS Operational Cash is the average balance of funds SCE investors have furnished for the utility to meet its daily operational needs. Balance sheet accounts consisting of amounts supplied by investors for operational needs were included, provided that the amounts: (1) are necessary to maintain minimum balances, (2) are recoverable from ratepayers, (3) are non-interest bearing, and (4) whose carrying costs are not recovered from ratepayers elsewhere. The Workpapers detailing the development of Operational Cash Requirements are separated into the following sections: Cash Bank Balances Special Deposits Working Funds Prepayments Other Accounts Receivable & Reserve for Uncollectibles Paid Absence Long Term Incentive Plans (LTIP) Works Compensation and Injuries & Damage Claims Reserves User Taxes and Other Fees Unfunded Pension Reserves

43 42 Southern California Edison Company Working Cash Capital Operational Cash Requirement Escalation Rates Used To Forecast Opeational Cash Components SCE COMPOSITE O&M ESCALATION INDEXES WITHOUT HEALTH CARE Year Index (Year 2015=100) Annual Percentage Change F % 2017F % 2018F % 2019F % 2020F % SCE COMPOSITE LABOR O&M ESCALATION INDEX Year Index (Year 2015=100) Annual Percentage Change F % 2017F % 2018F % 2019F % 2020F % SCE MEDICAL ESCALATION RATES Year Annual Percentage Change F 0.00% 2017F 7.00% 2018F 7.00% 2019F 7.00% 2020F 7.00%

44 43 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Cash Bank Balances

45 44 WORKING CASH Operational Cash Requirements CASH BANK BALANCES NOTES TO WORKPAPERS The diverse nature of SCE s cash transactions requires the use of multiple banks and 67 separate bank accounts to provide various services including balance reporting, check processing, electronic funds transfers and depository services. Due to operational constraints and standard banking practice, SCE must maintain the minimum bank balances requested to operate effectively.

46 45 SCE Average Available Bank Balances 2011 through Bank Actual Actual Actual Actual Actual Estimate City National 178, , , , , , JPMorgan 1,555, ,459, ,926, ,598, ,949, ,200, Mellon 2,227, , , , , , Union 19,745, ,178, ,259, ,656, ,427, ,400, Wells Fargo 20,829, ,443, ,980, ,112, ,200, ,100, Total 44,536, ,431, ,456, ,596, ,854, ,900,000.00

47 46 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Special Deposits

48 47 WORKING CASH Operational Cash Requirements SPECIAL DEPOSITS NOTES TO WORKPAPERS FERC Account Special Deposits represents funds managed by outside parties on SCE s behalf. This account includes a wide range of trust accounts set up to manage funds for Nuclear Decommissioning, and employee pensions and savings. Most special deposit accounts, however, are either interest bearing or recovered in other ratemaking mechanisms elsewhere so are not included in Rate Base for GRC purposes. The two accounts included as Working Cash in this GRC are Relocation Plan Deposits and Special Funds-Relocation Escrow. Accounts included in Special Deposits: Account Account Description Relocation Plan Deposit Special Funds-Relocation Escrow

49 48 Southern California Edison Company Working Cash Capital Operational Cash Requirement Special Deposits Month Total December ,019 January ,019 February ,019 March ,019 April ,019 May ,019 June ,019 July ,019 August ,019 September ,019 October ,000 November ,000 December , Month Total 5,260,190 Less 1/2 First Month 135,009 Less 1/2 Last Month 360, Month Total 4,765,180 Weighted Average 397,098 SPECIAL DEPOSITS Year % Change Recorded Forecasted % % % % % 435

50 49 Southern California Edison Company Working Cash Capital Operational Cash Requirement Special Deposits Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec Relocation Plan Deposit Special Funds - Relocation Escrow 270, , , , , , , , , , , , ,000 Total 270, , , , , , , , , , , , ,000

51 50 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Working Funds

52 51 WORKING CASH Operational Cash Requirements WORKING FUNDS NOTES TO WORKPAPERS FERC Account Working Funds represents cash advanced to officers, agents, or employees that are supplied by investors for operational needs.

53 52 Southern California Edison Company Working Cash Capital Operational Cash Requirement Working Funds Month Total December ,800 January ,791 February ,791 March ,791 April ,600 May ,600 June ,600 July ,600 August ,600 September ,600 October ,095 November ,095 December , Month Total 1,603,063 Less 1/2 First Month 62,400 Less 1/2 Last Month 61, Month Total 1,479,613 Weighted Average 123,301 Forecasted WORKING FUNDS Year % Change Recorded Forecasted % % % % % 123

54 53 Southern California Edison Company Working Cash Capital Operational Cash Requirement Working Funds Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec Contingent Funds 124, , , , , , , , , , , , ,100

55 54 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Prepayments

56 55 WORKING CASH Operational Cash Requirements PREPAYMENTS NOTES TO WORKPAPERS FERC Accounts 165 Prepayments include prepaid rent insurance, software license fees, and other miscellaneous prepayments and reflects an average balance that has not yet been accrued to operating expenses. The prepayment amount is the balance sheet related operational cash requirement that encompasses the time from initially recording the prepayment until such time as it is accrued to operating expenses. Because SCE has advanced these funds, the average balance is includable in working cash. Accounts included in Prepayments: Account Account Description Prepaid Rent Prepaid Insurance Prepaid Miscellaneous TDBU Expenses Prepaid Software License Expense

57 56 Southern California Edison Company Working Cash Capital Operational Cash Requirement Prepayments Month Total December-14 34,645,515 January-15 34,032,698 February-15 30,704,043 March-15 27,674,619 April-15 23,669,120 May-15 18,317,161 June-15 36,465,883 July-15 35,295,879 August-15 29,667,255 September-15 29,714,965 October-15 24,703,291 November-15 29,477,096 December-15 40,269, Month Total 394,637,519 Less 1/2 First Month 17,322,757 Less 1/2 Last Month 20,134, Month Total 357,179,765 Weighted Average 29,764,980

58 57 Southern California Edison Company Working Cash Capital Operational Cash Requirement Account Account Description December-14 January-15 February-15 March-15 April-15 May-15 June-15 July-15 August-15 September-15 October-15 November-15 December-15 Average Prepaid Rent - ST 2,095,794 4,165,544 2,088,841 2,153,634 1,864,085 1,811,398 1,736,727 1,894,111 1,740,857 1,787,092 1,807,373 1,659,737 1,750,344 2,052, Prepaid Insurance 19,768,493 16,022,161 13,200,651 10,805,737 7,525,806 3,390,133 23,200,262 23,207,002 19,232,422 20,037,547 16,551,381 21,385,661 19,129,819 16,167, Miscellaneous Prepaid TDBU expenses 11,832,885 13,017,953 13,671,715 13,137,755 12,763,173 11,298,643 9,830,815 8,615,595 7,212,856 6,507,254 5,059,516 5,218,627 15,798,138 10,012, Prepaid Software License Expense-LT 948, ,040 1,742,836 1,577,494 1,516,058 1,816,988 1,698,080 1,579,171 1,481,121 1,383,071 1,285,021 1,213,071 3,591,692 1,532,497 Total 34,645,515 34,032,698 30,704,043 27,674,619 23,669,120 18,317,161 36,465,883 35,295,879 29,667,255 29,714,965 24,703,291 29,477,096 40,269,993 29,764,980 Prepaid Insurance Adjustment Prepaid Insurance 39,536,987 32,044,321 26,401,303 21,611,475 15,051,611 6,780,266 46,400,523 46,414,004 38,464,844 40,075,095 33,102,763 42,771,321 38,259,637 32,334,653 Prepaid Insurance - 50% Reduction (19,768,493) (16,022,161) (13,200,651) (10,805,737) (7,525,806) (3,390,133) (23,200,262) (23,207,002) (19,232,422) (20,037,547) (16,551,381) (21,385,661) (19,129,819) (16,167,327) 19,768,493 16,022,161 13,200,651 10,805,737 7,525,806 3,390,133 23,200,262 23,207,002 19,232,422 20,037,547 16,551,381 21,385,661 19,129,819 16,167,327

59 58 Southern California Edison Working Cash Capital Operational Cash Requirement Prepayments - Nominal Average Balance Recorded Forecast Account Account Description Forecast Methodology Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec Prepaid Rent - ST Non-Labor Composite 2,052,705 2,070,047 2,111,413 2,156,592 2,202,289 2,248, Prepaid Insurance Non-Labor Composite 16,167,327 16,303,910 16,629,711 16,985,548 17,345,462 17,706, Miscellaneous Prepaid TDBU expenses TDBU Forecast 10,012,451 17,451,656 17,869,598 18,435,487 19,004,401 19,053, Prepaid Software License Expense-LT Non-Labor Composite 1,532,497 1,545,444 1,576,327 1,610,056 1,644,172 1,678,416 Total 29,764,980 37,371,057 38,187,048 39,187,684 40,196,324 40,686,682 Average ($000) 29,765 37,371 38,187 39,188 40,196 40,687

60 59 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Other Accounts Receivables

61 60 WORKING CASH Operational Cash Requirements Other Accounts Receivable & Accum Provision for Uncollectibles NOTES TO WORKPAPERS FERC Account 143- Other Accounts Receivable represents miscellaneous receivables unrelated to utility customer accounts. FERC Account 144- Accumulated Provision for Uncollectibles represents the balance of accruals for estimated uncollectibles that have not yet been written off. There are 17 Other Accounts Receivables & Accumulated Provision for Uncollectibles accounts that were incorporated into Working Cash. Accounts included in Other Accounts Receivable & Uncollectible Reserve Account Account Description Other Accounts Receivable A/R Damage Claims Recon Cal CDP Trust Receivable HCRA Trust Receivable PY DCRA Trust Receivable PY PBOP Trust Reimbursement Receivable Employee Tools Safety Receivable Medicare RX Reimbursements Pension Plan Trustee OAR Northern Trust VEBA Accum Prov Uncollectible Acct - CRE Accum Prov Uncollectible Acct - PWRD Accum Prov Uncollectible Acct - PMO Accum Prov Uncollectible Acct - Catalina Island Accum Prov Uncollectible Acct- Damage Claims Accum Prov Uncollectible Acct- Accruals Accum Prov Uncollectible Acct- Write Off

62 61 Southern California Edison Company Working Cash Capital Operational Cash Requirement Other Accounts Receivable & Accumulated Provision for Uncollectibles Month Total December-14 75,792,464 January-15 93,937,782 February-15 98,077,286 March ,076,789 April ,071,726 May-15 52,292,849 June-15 42,558,951 July-15 65,648,654 August-15 67,699,031 September-15 67,029,714 October-15 55,808,094 November-15 43,926,267 December-15 44,012, Month Total 935,932,468 Less 1/2 First Month 37,896,232 Less 1/2 Last Month 22,006, Month Total 876,029,806 Weighted Average 73,002,484

63 62 Southern California Edison Company Working Cash Capital Operational Cash Requirement Other Accounts Receivable Account Account Description Forecast December-14 January-15 February-15 March-15 April-15 May-15 June-15 July-15 August-15 September-15 October-15 November-15 December-15 Average Other Accounts Receivable - Reconciliation Account Non-Labor Composite 34,177,297 43,769,336 40,626,639 51,580,114 41,265,472 39,915,769 39,248,661 43,683,699 39,777,271 32,640,805 29,431,392 30,150,238 21,603,226 38,331, Accounts Receivable - Damage Claims Recon Non-Labor Composite 13,363,304 14,374,952 15,150,453 15,541,432 16,127,736 16,464,169 16,378,146 15,886,758 15,573,661 14,815,221 14,124,645 12,846,786 11,702,608 14,984, Cal CDP Trust Receivable Non-Labor Composite (1,698,629) 86,202 1,138,015 1,833,510 (1,377,228) (459,318) (952,823) (333,314) (213,942) 351, ,824 (1,252,757) 153,138 (92,876) HCRA Trust Receivable - Prior Year Medical (1,245) 242,646 33,884 90, , ,450 (1,381) (1,125) (607) (2,458) (2,640) (2,765) 257,904 60, DCRA Trust Receivable - Prior Year Non-Labor Composite - 244, , ,545 78,775 79, ,146 64, PBOP Trust Reimbursement Receivable* Medical 66,012,948 71,562,948 77,112,948 84,600,000 91,500,000 31,957,208 24,590,457 44,160,000 50,340,000 56,520,000 48,123,511 39,298,107 45,478,107 56,292, Employee Tools/Safety Receivable Non-Labor Composite (23,688) (26,282) (25,171) (27,202) (25,048) (28,396) (29,377) (30,078) (30,625) (117,765) (119,047) (120,639) (122,984) (54,414) Medicare RX Reimbursements Medical 242, , , , , , , , , , Pension Plan Trustee Non-Labor Composite 1,329,373 1,356,906 1,397,863 1,378, , ,015 1,002, ,208 1,101,885 1,283,902 1,580,089 1,094, ,711 1,111, OAR - Northern Trust - VEBA Non-Labor Composite 920, , , , , , , , , , , , , ,227 Total Other Accounts Receivable 114,322, ,778, ,740, ,115, ,616,684 89,240,946 80,926, ,714, ,369, ,172,546 94,841,936 82,581,949 80,705, ,467,700 Allowance for Uncollectibles Provision for Doubtful Accounts - CRE Non-Labor Composite (5,426,066) (5,426,066) (5,426,066) (5,770,935) (5,768,887) (5,768,887) (8,137,000) (8,126,228) (8,126,090) (8,690,294) (8,677,983) (8,645,405) (6,330,738) (7,036,854) Provision for Doubtful Accounts - PWRD Non-Labor Composite (951,904) (951,904) (951,904) (951,904) (951,904) (951,904) (951,904) (951,904) (941,467) (659,858) (659,858) (659,858) (642,049) (865,112) Provision for Doubtful Accounts - PMO Non-Labor Composite (1,871,198) (1,871,198) (1,871,198) (1,871,198) (1,871,198) (1,871,198) (1,871,198) (1,871,198) (1,871,198) (690,576) (690,576) (690,576) (488,224) (1,518,419) Provision for Doubtful Accounts - Catalina Island Non-Labor Composite (1,728) (1,728) (1,728) (1,728) (1,728) (1,728) (1,728) (1,728) (1,728) (344) (1,238) Provision for Doubtful Accounts - Damage Claims Non-Labor Composite (5,078,055) (5,462,482) (5,757,172) (5,905,744) (6,128,540) (6,256,384) (6,223,696) (6,036,968) (5,917,991) (5,629,784) (5,367,365) (4,881,779) (4,446,991) (5,694,202) Provision for Doubtful Accounts - Accruals Non-Labor Composite (230,732,172) (232,847,301) (234,574,116) (236,585,976) (238,292,596) (240,131,149) (242,464,625) (245,541,975) (248,573,828) (250,798,126) (252,552,948) (253,818,965) (50,015,593) (234,712,957) Provision for Doubtful Accounts - Write Off Non-Labor Composite 179,036, ,011, ,332, ,891, ,652, ,625, ,898, ,601, ,482, ,409, ,073, ,459, ,912,968 Tax Adjustment (40.746%) 26,494,911 26,708,685 26,586,749 26,157,450 25,817,782 25,407,351 26,383,580 26,863,426 27,279,186 26,916,560 26,841,612 26,581,571 25,231,528 26,450,598 Total Allowance for Uncollectibles (38,529,658) (38,840,535) (38,663,211) (38,038,913) (37,544,958) (36,948,097) (38,367,758) (39,065,564) (39,670,173) (39,142,832) (39,033,841) (38,655,682) (36,692,411) (38,465,216) Grand Total 75,792,464 93,937,782 98,077, ,076, ,071,726 52,292,849 42,558,951 65,648,654 67,699,031 67,029,714 55,808,094 43,926,267 44,012,859 73,002,484 *PBOP Trust Reimbursement Adjustment PBOP Trust Reimbursement Receivable 66,600,000 72,150,000 77,700,000 84,600,000 91,500,000 31,957,208 24,590,457 44,160,000 50,340,000 56,520,000 48,123,511 39,298,107 45,478,107 56,414,861 Cumulative Adjustment (587,052) (587,052) (587,052) (122,302) Adjusted PBOP Trust Reimbursement 66,012,948 71,562,948 77,112,948 84,600,000 91,500,000 31,957,208 24,590,457 44,160,000 50,340,000 56,520,000 48,123,511 39,298,107 45,478,107 56,292,559

64 63 Recorded Average Forecast Averages Account Account Description Forecast Methodology Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec Other Accounts Receivable - Reconciliation Account Non-Labor Composite 38,331,638 38,655,469 39,427,920 40,271,587 41,124,917 41,981, Accounts Receivable - Damage Claims Recon Non-Labor Composite 14,984,743 15,111,336 15,413,306 15,743,115 16,076,702 16,411, Cal CDP Trust Receivable Non-Labor Composite (92,876) (93,660) (95,532) (97,576) (99,644) (101,719) HCRA Trust Receivable - Prior Year Medical 60,218 60,218 64,434 68,944 73,770 78, DCRA Trust Receivable - Prior Year Non-Labor Composite 64,037 64,578 65,868 67,277 68,703 70, PBOP Trust Reimbursement Receivable* Medical 56,292,559 56,292,559 60,233,038 64,449,351 68,960,805 73,788, Employee Tools/Safety Receivable Non-Labor Composite (54,414) (54,874) (55,970) (57,168) (58,379) (59,595) Medicare RX Reimbursements Medical 171, , , , , , Pension Plan Trustee Non-Labor Composite 1,111,781 1,121,173 1,143,578 1,168,048 1,192,798 1,217, OAR - Northern Trust - VEBA Non-Labor Composite 598, , , , , ,188 Total Other Accounts Receivable 111,467, ,931, ,995, ,438, ,191, ,266, Provision for Doubtful Accounts - CRE Non-Labor Composite (7,036,854) (7,096,302) (7,238,107) (7,392,986) (7,549,639) (7,706,876) Provision for Doubtful Accounts - PWRD Non-Labor Composite (865,112) (872,420) (889,854) (908,895) (928,154) (947,485) Provision for Doubtful Accounts - PMO Non-Labor Composite (1,518,419) (1,531,246) (1,561,845) (1,595,265) (1,629,068) (1,662,997) Provision for Doubtful Accounts - Catalina Island Non-Labor Composite (1,238) (1,249) (1,274) (1,301) (1,328) (1,356) Provision for Doubtful Accounts - Damage Claims Non-Labor Composite (5,694,202) (5,742,308) (5,857,056) (5,982,384) (6,109,147) (6,236,383) Provision for Doubtful Accounts - Accruals Non-Labor Composite (234,712,957) (236,695,844) (241,425,733) (246,591,684) (251,816,811) (257,061,433) Provision for Doubtful Accounts - Write Off Non-Labor Composite 184,912, ,475, ,201, ,271, ,387, ,519,678 Tax Adjustment (40.746%) 26,450,598 26,674,056 27,207,083 27,789,252 28,378,089 28,969,123 Total Provision for Doubtful Accounts (38,465,216) (38,790,176) (39,565,319) (40,411,925) (41,268,229) (42,127,728) Grand Total 73,002,484 73,141,692 77,430,471 82,026,834 86,923,710 92,139,058 Average ($000) 73,002 73,142 77,430 82,027 86,924 92,139

65 64 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Paid Absence

66 65 WORKING CASH Operational Cash Requirements PAID ABSENCE NOTES TO WORKPAPERS Paid Absence includes the value of vacation and sick days earned, but not yet taken by employees. These amounts are a reduction to Rate Base, since they represent a liability to SCE until the employees take the time off. Accounts Include: Account Account Description Paid Absence

67 66 Southern California Edison Company Working Cash Capital Operational Cash Requirement Paid Absence Month Total Dec-14 65,630,092 Jan-15 56,405,904 Feb-15 58,022,618 Mar-15 77,676,834 Apr-15 82,002,512 May-15 82,720,025 Jun-15 79,024,081 Jul-15 75,252,768 Aug-15 78,909,327 Sep-15 73,969,596 Oct-15 75,475,885 Nov-15 58,175,746 Dec-15 60,532, Month Total 923,798,358 Less 1/2 First Month 32,815,046 Less 1/2 Last Month 30,266, Month Total 860,716,827 Weighted Average 71,726,402 Year % Change Recorded Forecast* , % 77, % 76, % 76, % 76, % 76,940 *Based on labor headcount forecast

68 67 Southern California Edison Company Working Cash Capital Operational Cash Requirement Paid Absence Account Account Description December-14 January-15 February-15 March-15 April-15 May-15 June-15 July-15 August-15 September-15 October-15 November-15 December Paid Absence (65,630,092) (56,405,904) (58,022,618) (77,676,834) (82,002,512) (82,720,025) (79,024,081) (75,252,768) (78,909,327) (73,969,596) (75,475,885) (58,175,746) (60,532,972)

69 68 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Long Term Incentive Plan

70 69 WORKING CASH Operational Cash Requirements LONG TERM INCENTIVE PLAN NOTES TO WORKPAPERS FAS 123 Long Term Incentive Plans (LTIP) are SCE liabilities that include Stock Options, Restricted Stock Units, and Performance Shares. Recovery for the associated expenses are being requested beginning in the 2018 Test Year. Since expenses will be accrued and recovered in advance of payments, the accumulated liability associated with the Post-2018 LTIP expenses is included as a reduction to rate base.

71 70 Southern California Edison Working Cash Capital Long Term Incentives ($000 Nominal Weighted Average Balances) Performance Shares (1,614) (3,632) (4,550) Restricted Stock Units (1,612) (3,629) (4,545) Stock Options (4,056) (10,947) (16,852) Total (7,282) (18,208) (25,948) Tax Adjustment* ( ) 2,967 7,419 10,573 After-Tax Total (4,315) (10,789) (15,375) *See IRC Sections 83 & 404

72 71 Southern California Edison Working Cash Capital Long Term Incentives ($000 Nominal) Total Performance Shares Expense 3, ,120 3,120 9,360 Payments - 1,101 2,202 3,304 Restricted Stock Units Expense 3,117 3,117 3,117 9,350 Payments - 1,100 2,200 3,300 Stock Options Expense 7,489 7,489 7,489 22,466 Payments - 1,105 1,988 3,093 Total LTIP Expense 13,726 13,726 2,202 41,177 Payments - 3,306 6,391 9,696

73 72 Southern California Edison Working Cash Capital Long Term Incentives Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Performance Shares Expense 2016 PS 91, ,768 91,768 91,768 91, ,768 91,768 91,768 91,768 91,768 91,768 91, PS 91, ,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91, PS 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91, PS 2020 PS Total Expense 183, , , , , , , , , , , ,303 Performance Shares Cash Payments 2016 PS 2017 PS 2018 PS 2019 PS 2020 PS Total Payments PS Cumulative Balance (183,535) (367,070) (642,373) (917,676) (1,192,978) (1,468,281) (1,743,584) (2,018,887) (2,294,189) (2,569,492) (2,844,795) (3,120,098) Restricted Stock Units Expense 2016 RSU 91, ,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91, RSU 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91, RSU 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91, RSU 2020 RSU Total Expense 183, , , , , , , , , , , ,012 Restricted Stock Units Cash Payments 2010 RSU 2011 RSU 2012 RSU 2013 RSU 2014 RSU Total Payments RSU Cumulative Balance (183,342) (366,683) (641,695) (916,708) (1,191,720) (1,466,732) (1,741,745) (2,016,757) (2,291,770) (2,566,782) (2,841,794) (3,116,807)

74 73 Southern California Edison Working Cash Capital Long Term Incentives Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Stock Options Expense 2015 Tranche IV 156, , , , , , , , , , , , Tranche III 156, , , , , , , , , , , , Tranche IV 2017 Tranche II 156, , , , , , , , , , , , Tranche III 2017 Tranche IV 2018 Tranche I 156, , , , , , , , , , , , Tranche II 2018 Tranche III 2019 Tranche I 2019 Tranche II 2020 Tranche I Total Expense 624, , , , , , , , , , , ,055 Stock Options Cash Payments 2012 Tranche IV Tranche III Tranche IV Tranche II Tranche III Tranche IV Tranche I Tranche II Tranche III Tranche I Tranche II Tranche I Total Cash Payments Stock Option Cumulative Balance (624,055) (1,248,110) (1,872,164) (2,496,219) (3,120,274) (3,744,329) (4,368,383) (4,992,438) (5,616,493) (6,240,548) (6,864,602) (7,488,657)

75 74 Southern California Edison Working Cash Capital Long Term Incentives Performance Shares Expense 2016 PS 2017 PS 2018 PS 2019 PS 2020 PS Total Expense Performance Shares Cash Payments 2016 PS 2017 PS 2018 PS 2019 PS 2020 PS Total Payments PS Cumulative Balance Restricted Stock Units Expense 2016 RSU 2017 RSU 2018 RSU 2019 RSU 2020 RSU Total Expense Restricted Stock Units Cash Payments 2010 RSU 2011 RSU 2012 RSU 2013 RSU 2014 RSU Total Payments RSU Cumulative Balance Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91, , , , , , , , , , , , ,303 1,101,211 1,101, (2,202,422) (2,385,957) (2,661,260) (2,936,562) (3,211,865) (3,487,168) (3,762,471) (4,037,773) (4,313,076) (4,588,379) (4,863,681) (5,138,984) 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91, , , , , , , , , , , , ,012 1,100,049 1,100, (2,200,099) (2,383,440) (2,658,453) (2,933,465) (3,208,477) (3,483,490) (3,758,502) (4,033,514) (4,308,527) (4,583,539) (4,858,551) (5,133,564)

76 75 Southern California Edison Working Cash Capital Long Term Incentives Stock Options Expense 2015 Tranche IV 2016 Tranche III 2016 Tranche IV 2017 Tranche II 2017 Tranche III 2017 Tranche IV 2018 Tranche I 2018 Tranche II 2018 Tranche III 2019 Tranche I 2019 Tranche II 2020 Tranche I Total Expense Stock Options Cash Payments 2012 Tranche IV 2013 Tranche III 2013 Tranche IV 2014 Tranche II 2014 Tranche III 2014 Tranche IV 2015 Tranche I 2015 Tranche II 2015 Tranche III 2016 Tranche I 2016 Tranche II 2017 Tranche I Total Cash Payments Stock Option Cumulative Balance Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,055 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24, ,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25, ,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22, ,049 92,049 92,049 92,049 92,049 92,049 92,049 92,049 92,049 92,049 92,049 92,049 (8,020,662) (8,552,668) (9,084,673) (9,616,678) (10,148,683) (10,680,689) (11,212,694) (11,744,699) (12,276,704) (12,808,710) (13,340,715) (13,872,720)

77 76 Southern California Edison Working Cash Capital Long Term Incentives Performance Shares Expense 2016 PS 2017 PS 2018 PS 2019 PS 2020 PS Total Expense Performance Shares Cash Payments 2016 PS 2017 PS 2018 PS 2019 PS 2020 PS Total Payments PS Cumulative Balance Restricted Stock Units Expense 2016 RSU 2017 RSU 2018 RSU 2019 RSU 2020 RSU Total Expense Restricted Stock Units Cash Payments 2010 RSU 2011 RSU 2012 RSU 2013 RSU 2014 RSU Total Payments RSU Cumulative Balance Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91,768 91, , , , , , , , , , , , ,303 2,202,422 2,202, (3,120,098) (3,303,633) (3,578,935) (3,854,238) (4,129,541) (4,404,844) (4,680,146) (4,955,449) (5,230,752) (5,506,054) (5,781,357) (6,056,660) 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91,671 91, , , , , , , , , , , , ,012 2,200,099 2,200, (3,116,807) (3,300,148) (3,575,160) (3,850,173) (4,125,185) (4,400,197) (4,675,210) (4,950,222) (5,225,234) (5,500,247) (5,775,259) (6,050,271)

78 77 Southern California Edison Working Cash Capital Long Term Incentives Stock Options Expense 2015 Tranche IV 2016 Tranche III 2016 Tranche IV 2017 Tranche II 2017 Tranche III 2017 Tranche IV 2018 Tranche I 2018 Tranche II 2018 Tranche III 2019 Tranche I 2019 Tranche II 2020 Tranche I Total Expense Stock Options Cash Payments 2012 Tranche IV 2013 Tranche III 2013 Tranche IV 2014 Tranche II 2014 Tranche III 2014 Tranche IV 2015 Tranche I 2015 Tranche II 2015 Tranche III 2016 Tranche I 2016 Tranche II 2017 Tranche I Total Cash Payments Stock Option Cumulative Balance Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,055 14,770 14,770 14,770 14,770 14,770 14,770 14,770 14,770 14,770 14,770 14,770 14,770 16,094 16,094 16,094 16,094 16,094 16,094 16,094 16,094 16,094 16,094 16,094 16,094 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 19,107 20,503 20,503 20,503 20,503 20,503 20,503 20,503 20,503 20,503 20,503 20,503 20,503 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24,600 24, ,600 24, ,257 22,257 22,257 22,257 22,257 22,257 22,257 22,257 22,257 22,257 22,257 22,257 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25,981 25, ,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22,362 22, , , , , , , , , , , , ,674 (14,331,100) (14,789,481) (15,247,861) (15,706,242) (16,164,622) (16,623,002) (17,081,383) (17,539,763) (17,998,144) (18,456,524) (18,914,904) (19,373,285)

79 78 Southern California Edison Operational Cash Long Term Incentives Historical Exercise Pattern - Stock Options Grant Year Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Total % 0% 2% 5% 9% 0% 3% 12% 5% 26% 0% 62% % 0% 4% 3% 0% 2% 7% 11% 4% 28% 0% 60% % 2% 0% 0% 2% 17% 7% 5% 1% 7% 0% 41% % 0% 0% 0% 0% 17% 2% 2% 3% 0% 0% 25% % 0% 0% 0% 5% 10% 0% 2% 0% 0% 0% 18% % 0% 0% 5% 13% 4% 1% 0% 0% 25% 1% 49% % 1% 3% 17% 3% 2% 0% 0% 2% 25% 2% 56% % 1% 4% 11% 5% 0% 0% 2% 24% 8% 3% 58% % 1% 2% 6% 0% 0% 0% 26% 12% 4% 2% 53% % 0% 0% 0% 0% 0% 1% 12% 20% 22% 2% 58% % 0% 0% 0% 0% 3% 26% 10% 10% 8% 2% 59% % 0% 1% 12% 8% 4% 1% 1% 0% 1% 0% 27% % 0% 7% 13% 9% 7% 1% 0% 0% 7% 0% 44% % 3% 9% 0% 12% 1% 1% 1% 4% 12% 0% 43% % 4% 7% 0% 4% 1% 1% 9% 17% 9% 0% 53% % 4% 8% 0% 0% 1% 16% 18% 6% 24% 0% 77% % 3% 1% 0% 0% 0% 9% 19% 25% 27% 84% % 0% 0% 0% 0% 0% 19% 19% 20% 58% % 0% 0% 1% 0% 10% 18% 11% 40% % 1% 13% 18% 20% 10% 2% 63% % 8% 13% 18% 27% 4% 70% % 7% 13% 22% 11% 54% % 9% 17% 9% 35% % 7% 8% 15% % 5% 5% % 0% 0% Average 0% 2% 5% 6% 6% 4% 6% 8% 9% 14% 1% 60%

80 79 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT Workers Compensation and Injuries & Damages

81 80 WORKING CASH Operational Cash Requirements WORKER S COMP AND INJURIES & DAMAGES NOTES TO WORKPAPERS To the extent that Workers Compensation and Injuries & Damage Claim Reserves represent funds provided by ratepayers exceeding SCE s payment of these claims, they should be a reduction to rate base. In the case of Workers Compensation and Injuries & Damage Claim Reserves, this ratepayer pre-funding is represented by the amounts associated with the Commission authorized levels of Account 925 Workers Compensation Reserve and Injuries and Damage Claims Accruals, not the recorded amounts required by the Generally Accepted Accounting Principles (GAAP). Since these revenues are subject to income tax, the amount available as a rate base offset is the aftertax amount.

82 81 Forecast Workers Compensation and Injuries & Damages Reserves Year Authorized/ Proposed 925 Expense Payments* Net Authorized/ Proposed Expense Pre-Tax Accum Balance Accum. Net Balance*** Average Accum. Balance** 2015 (118,324,807) (70,112,181) (52,886,637) ,909,321 (30,318,906) 4,590,415 (122,915,222) (72,832,186) (71,472,183) ,757,532 (51,373,886) (15,616,353) (107,298,869) (63,578,872) (68,205,529) ,060,772 (54,897,180) (23,836,408) (83,462,460) (49,454,846) (56,516,859) ,794,012 (56,311,253) (24,517,241) (58,945,219) (34,927,400) (42,191,123) ,522,451 (36,434,505) (3,912,055) (55,033,165) (32,609,351) (33,768,376) * Based upon average 5.1-year turnover applied to Authorized Accruals ** 2015 Average Balance based on D ***Tax Rate %

83 82 Authorized Workers Compensation and Injuries & Damages Reserve Accruals Authorized Acct 925 Plus: MIP Transferred to SONGS Year 925 Authorized / Proposed Adjusted GRC Authorized ,674,388 9,674, ,674,388 9,674, ,851,430 9,851, ,878,029 9,878, ,912,602 9,912, ,954,235 9,954, ,088,617 10,088, ,266,176 10,266, ,467,136 21,467, ,490,434 30,490, ,490,434 30,490, ,245,372 4,079,806 46,325, ,095,796 4,168,315 47,264, ,611,174 4,236,540 48,847, ,435,438 1,213,995 28,649, ,313,372 1,226,708 29,540, ,162,774 1,242,668 30,405, ,458,636 1,245,077 53,703, ,758,916 1,270,871 55,029, ,160,165 1,293,473 56,453, ,879, ,331 34,210, ,570, ,858 34,909, ,410, ,766 35,757,532 Authorized ,060, ,060,772 Proposed ,794, ,794, ,522, ,522,451

84 83 Workers Compensation and Injuries & Damages Reserves Recorded Debits / Payments / Balances Recorded Recorded Debits Payments Y-E Balance ,787,082 (21,986,005) 90,366, ,333,349 (38,546,849) 81,152, ,404,900 (23,097,869) 78,459, ,434,943 (22,645,611) 73,248, ,451,955 (26,040,469) 68,660, ,641,093 (25,443,411) 62,858, ,073,896 (25,862,101) 73,069, ,792,717 (30,839,136) 89,023, ,661,722 (27,832,225) 132,852, ,264,385 (22,416,477) 139,700, ,947,536 (28,710,786) 186,937, ,032,681 (23,063,934) 187,906, ,359,748 (24,261,180) 210,004, ,659,049 (25,929,942) 210,733, ,352,247 (29,369,478) 231,716, ,017,946 (34,864,451) 227,870, ,249,180 (79,446,407) 330,673, (115,838,696) (43,528,622) 171,305, ,122,782 (38,767,479) 184,661, ,296,488 (33,815,959) 199,141, (14,762,977) (36,043,144) 148,335,417 Total 731,282,029 (662,511,534) Authorized Accruals / Recorded Payments Authorized Accruals Recorded Payments Difference ,674,388 (21,986,005) (12,311,617) ,674,388 (38,546,849) (28,872,461) ,851,430 (23,097,869) (13,246,439) ,878,029 (22,645,611) (12,767,582) ,912,602 (26,040,469) (16,127,868) ,954,235 (25,443,411) (15,489,176) ,088,617 (25,862,101) (15,773,484) ,266,176 (30,839,136) (20,572,960) ,467,136 (27,832,225) (6,365,089) ,490,434 (22,416,477) 8,073, ,490,434 (28,710,786) 1,779, ,325,178 (23,063,934) 23,261, ,264,111 (24,261,180) 23,002, ,847,714 (25,929,942) 22,917, ,649,433 (29,369,478) (720,045) ,540,080 (34,864,451) (5,324,371) ,405,442 (79,446,407) (49,040,965) ,703,713 (43,528,622) 10,175, ,029,787 (38,767,479) 16,262, ,453,638 (33,815,959) 22,637, ,210,157 (36,043,144) (1,832,987) Total 592,177,122 (662,511,534) (70,334,412)

85 84 Workers Compensation and Injuries & Damages Reserves Account Turnover -- Five Year Rolling Averages Reserve Balance Rolling Five-Year Average Avg Mo. Accruals Avg Mo. Payments Y-E Balance Avg Mo. Rec'd Accruals Avg Mo. Payments Y-E Balance Cumulative Payments Jan-06 2,002,723 (1,921,994) 187,018,293 4,312,280 (2,257,126) 114,998,101 Feb-06 2,002,723 (1,921,994) 187,099,022 4,295,556 (2,253,239) 117,040,418 Mar-06 2,002,723 (1,921,994) 187,179,751 4,278,833 (2,249,353) 119,069,898 Apr-06 2,002,723 (1,921,994) 187,260,480 4,262,109 (2,245,467) 121,086,540 May-06 2,002,723 (1,921,994) 187,341,209 4,245,385 (2,241,580) 123,090,344 Jun-06 2,002,723 (1,921,994) 187,421,938 4,228,661 (2,237,694) 125,081,311 Jul-06 2,002,723 (1,921,994) 187,502,667 4,211,937 (2,233,808) 127,059,440 Aug-06 2,002,723 (1,921,994) 187,583,396 4,195,213 (2,229,921) 129,024,732 Sep-06 2,002,723 (1,921,994) 187,664,124 4,178,489 (2,226,035) 130,977,186 Oct-06 2,002,723 (1,921,994) 187,744,853 4,161,765 (2,222,149) 132,916,802 Nov-06 2,002,723 (1,921,994) 187,825,582 4,145,041 (2,218,262) 134,843,581 Dec-06 2,002,723 (1,921,994) 187,906,311 4,128,317 (2,214,376) 136,757,523 (139,294,430) Jan-07 3,863,312 (2,021,765) 189,747,859 4,127,716 (2,205,240) 138,679,999 (137,080,054) Feb-07 3,863,312 (2,021,765) 191,589,406 4,127,115 (2,196,104) 140,611,010 (134,874,814) Mar-07 3,863,312 (2,021,765) 193,430,953 4,126,513 (2,186,968) 142,550,555 (132,678,710) Apr-07 3,863,312 (2,021,765) 195,272,501 4,125,912 (2,177,832) 144,498,635 (130,491,743) May-07 3,863,312 (2,021,765) 197,114,048 4,125,311 (2,168,696) 146,455,250 (128,313,911) Jun-07 3,863,312 (2,021,765) 198,955,595 4,124,709 (2,159,560) 148,420,400 (126,145,215) Jul-07 3,863,312 (2,021,765) 200,797,143 4,124,108 (2,150,424) 150,394,084 (123,985,655) Aug-07 3,863,312 (2,021,765) 202,638,690 4,123,507 (2,141,288) 152,376,303 (121,835,232) Sep-07 3,863,312 (2,021,765) 204,480,237 4,122,905 (2,132,152) 154,367,057 (119,693,944) Oct-07 3,863,312 (2,021,765) 206,321,785 4,122,304 (2,123,015) 156,366,345 (158,423,391) (117,561,793) Nov-07 3,863,312 (2,021,765) 208,163,332 4,121,703 (2,113,879) 158,374,169 (156,300,375) (115,438,777) Dec-07 3,863,312 (2,021,765) 210,004,880 4,121,101 (2,104,743) 160,390,526 (154,186,496) (113,324,898) Jan-08 2,221,587 (2,160,828) 210,065,638 4,058,598 (2,102,101) 162,347,023 (152,081,752) (111,220,154) Feb-08 2,221,587 (2,160,828) 210,126,397 3,996,094 (2,099,459) 164,243,657 (149,979,651) (109,118,053) Mar-08 2,221,587 (2,160,828) 210,187,156 3,933,590 (2,096,817) 166,080,430 (147,880,192) (107,018,594) Apr-08 2,221,587 (2,160,828) 210,247,915 3,871,086 (2,094,175) 167,857,341 (145,783,375) (104,921,777) May-08 2,221,587 (2,160,828) 210,308,674 3,808,583 (2,091,533) 169,574,391 (143,689,199) (102,827,602) Jun-08 2,221,587 (2,160,828) 210,369,433 3,746,079 (2,088,891) 171,231,579 (141,597,666) (100,736,069) Jul-08 2,221,587 (2,160,828) 210,430,192 3,683,575 (2,086,249) 172,828,905 (139,508,775) (98,647,178) Aug-08 2,221,587 (2,160,828) 210,490,951 3,621,072 (2,083,607) 174,366,370 (137,422,526) (96,560,929) Sep-08 2,221,587 (2,160,828) 210,551,710 3,558,568 (2,080,965) 175,843,973 (135,338,920) (94,477,322) Oct-08 2,221,587 (2,160,828) 210,612,469 3,496,064 (2,078,323) 177,261,714 (177,276,468) (133,257,955) (92,396,357) Nov-08 2,221,587 (2,160,828) 210,673,228 3,433,560 (2,075,681) 178,619,594 (175,198,145) (131,179,632) (90,318,034) Dec-08 2,221,587 (2,160,828) 210,733,987 3,371,057 (2,073,039) 179,917,612 (173,122,464) (129,103,951) (88,242,353) Jan-09 4,196,021 (2,447,456) 212,482,551 3,400,345 (2,082,696) 181,235,262 (171,049,426) (127,030,913) (86,169,315) Feb-09 4,196,021 (2,447,456) 214,231,115 3,429,634 (2,092,353) 182,572,543 (168,966,730) (124,948,217) (84,086,619) Mar-09 4,196,021 (2,447,456) 215,979,679 3,458,923 (2,102,009) 183,929,456 (166,874,378) (122,855,864) (81,994,267) Apr-09 4,196,021 (2,447,456) 217,728,243 3,488,211 (2,111,666) 185,306,001 (164,772,368) (120,753,855) (79,892,257) May-09 4,196,021 (2,447,456) 219,476,807 3,517,500 (2,121,323) 186,702,178 (162,660,702) (118,642,189) (77,780,591) Jun-09 4,196,021 (2,447,456) 221,225,371 3,546,789 (2,130,980) 188,117,987 (160,539,378) (116,520,865) (75,659,267) Jul-09 4,196,021 (2,447,456) 222,973,935 3,576,078 (2,140,637) 189,553,427 (158,408,398) (114,389,885) (73,528,287) Aug-09 4,196,021 (2,447,456) 224,722,499 3,605,366 (2,150,294) 191,008,499 (156,267,761) (112,249,248) (71,387,650) Sep-09 4,196,021 (2,447,456) 226,471,063 3,634,655 (2,159,951) 192,483,203 (154,117,467) (110,098,953) (69,237,356) Oct-09 4,196,021 (2,447,456) 228,219,627 3,663,944 (2,169,608) 193,977,538 (197,634,505) (151,957,515) (107,939,002) (67,077,404) Nov-09 4,196,021 (2,447,456) 229,968,191 3,693,232 (2,179,265) 195,491,506 (195,464,897) (149,787,907) (105,769,394) (64,907,796) Dec-09 4,196,021 (2,447,456) 231,716,755 3,722,521 (2,188,922) 197,025,105 (193,285,632) (147,608,642) (103,590,129) (62,728,531) Jan-10 2,584,829 (2,905,371) 231,396,213 3,660,119 (2,197,469) 198,487,755 (191,096,710) (145,419,720) (101,401,207) (60,539,609) Feb-10 2,584,829 (2,905,371) 231,075,671 3,597,717 (2,206,016) 199,879,456 (188,899,241) (143,222,252) (99,203,738) (58,342,141) Mar-10 2,584,829 (2,905,371) 230,755,129 3,535,314 (2,214,562) 201,200,208 (186,693,226) (141,016,236) (96,997,723) (56,136,125) Apr-10 2,584,829 (2,905,371) 230,434,587 3,472,912 (2,223,109) 202,450,011 (184,478,663) (138,801,674) (94,783,161) (53,921,563) May-10 2,584,829 (2,905,371) 230,114,045 3,410,510 (2,231,656) 203,628,865 (182,255,554) (136,578,565) (92,560,052) (51,698,454) Jun-10 2,584,829 (2,905,371) 229,793,503 3,348,108 (2,240,203) 204,736,771 (180,023,899) (134,346,909) (90,328,396) (49,466,798) Jul-10 2,584,829 (2,905,371) 229,472,961 3,285,706 (2,248,749) 205,773,727 (177,783,696) (132,106,706) (88,088,193) (47,226,595) Aug-10 2,584,829 (2,905,371) 229,152,419 3,223,303 (2,257,296) 206,739,734 (175,534,947) (129,857,957) (85,839,444) (44,977,846) Sep-10 2,584,829 (2,905,371) 228,831,876 3,160,901 (2,265,843) 207,634,793 (173,277,651) (127,600,661) (83,582,148) (42,720,550) Oct-10 2,584,829 (2,905,371) 228,511,334 3,098,499 (2,274,390) 208,458,902 (171,011,808) (125,334,818) (81,316,305) (40,454,707) Nov-10 2,584,829 (2,905,371) 228,190,792 3,036,097 (2,282,936) 209,212,062 (168,737,418) (123,060,429) (79,041,916) (38,180,318) Dec-10 2,584,829 (2,905,371) 227,870,250 2,973,695 (2,291,483) 209,894,274 (212,666,757) (166,454,482) (120,777,492) (76,758,979) (35,897,381) Jan-11 15,187,432 (6,620,534) 236,437,148 3,193,440 (2,369,792) 210,717,921 (210,375,274) (164,162,999) (118,486,009) (74,467,496) (33,605,898) Feb-11 15,187,432 (6,620,534) 245,004,046 3,413,185 (2,448,101) 211,683,005 (208,005,482) (161,793,207) (116,116,217) (72,097,704) (31,236,106) Mar-11 15,187,432 (6,620,534) 253,570,943 3,632,930 (2,526,410) 212,789,525 (205,557,381) (159,345,106) (113,668,116) (69,649,603) (28,788,005) Apr-11 15,187,432 (6,620,534) 262,137,841 3,852,675 (2,604,719) 214,037,481 (203,030,971) (156,818,696) (111,141,706) (67,123,193) (26,261,595) May-11 15,187,432 (6,620,534) 270,704,739 4,072,420 (2,683,028) 215,426,873 (200,426,252) (154,213,977) (108,536,987) (64,518,474) (23,656,876) Jun-11 15,187,432 (6,620,534) 279,271,637 4,292,165 (2,761,337) 216,957,701 (197,743,224) (151,530,949) (105,853,959) (61,835,446) (20,973,848) Jul-11 15,187,432 (6,620,534) 287,838,534 4,511,910 (2,839,646) 218,629,966 (194,981,887) (148,769,612) (103,092,622) (59,074,109) (18,212,511) Aug-11 15,187,432 (6,620,534) 296,405,432 4,731,656 (2,917,955) 220,443,667 (192,142,241) (145,929,966) (100,252,976) (56,234,463) (15,372,865) Sep-11 15,187,432 (6,620,534) 304,972,330 4,951,401 (2,996,264) 222,398,803 (189,224,286) (143,012,011) (97,335,021) (53,316,508) (12,454,910) Oct-11 15,187,432 (6,620,534) 313,539,228 5,171,146 (3,074,573) 224,495,376 (186,228,022) (140,015,747) (94,338,757) (50,320,244) (9,458,646) Nov-11 15,187,432 (6,620,534) 322,106,125 5,390,891 (3,152,882) 226,733,385 (183,153,449) (136,941,174) (91,264,184) (47,245,671) (6,384,073) Dec-11 15,187,432 (6,620,534) 330,673,023 5,610,636 (3,231,191) 229,112,830 (180,000,567) (133,788,292) (88,111,302) (44,092,789) (3,231,191)

86 85 Workers Compensation and Injuries & Damages Reserves Account Turnover -- Five Year Rolling Averages Reserve Balance Rolling Five-Year Average Avg Mo. Accruals Avg Mo. Payments Avg Mo. Rec'd Accruals Avg Mo. Payments Y-E Balance Y-E Balance Cumulative Payments Jan-12 (9,653,225) (3,627,385) 317,392,413 5,385,361 (3,257,951) 231,240,240 (176,769,376) (130,557,101) (84,880,111) (40,861,598) Feb-12 (9,653,225) (3,627,385) 304,111,804 5,160,085 (3,284,712) 233,115,613 (173,511,425) (127,299,149) (81,622,160) (37,603,647) Mar-12 (9,653,225) (3,627,385) 290,831,194 4,934,809 (3,311,472) 234,738,950 (170,226,713) (124,014,438) (78,337,448) (34,318,935) Apr-12 (9,653,225) (3,627,385) 277,550,584 4,709,534 (3,338,232) 236,110,252 (166,915,241) (120,702,966) (75,025,976) (31,007,463) May-12 (9,653,225) (3,627,385) 264,269,974 4,484,258 (3,364,993) 237,229,517 (163,577,009) (117,364,733) (71,687,744) (27,669,231) Jun-12 (9,653,225) (3,627,385) 250,989,364 4,258,982 (3,391,753) 238,096,747 (160,212,016) (113,999,741) (68,322,751) (24,304,238) Jul-12 (9,653,225) (3,627,385) 237,708,755 4,033,707 (3,418,513) 238,711,940 (156,820,263) (110,607,988) (64,930,998) (20,912,485) Aug-12 (9,653,225) (3,627,385) 224,428,145 3,808,431 (3,445,274) 239,075,098 (153,401,750) (107,189,474) (61,512,485) (17,493,972) Sep-12 (9,653,225) (3,627,385) 211,147,535 3,583,156 (3,472,034) 239,186,219 (149,956,476) (103,744,201) (58,067,211) (14,048,698) Oct-12 (9,653,225) (3,627,385) 197,866,925 3,357,880 (3,498,794) 239,045,305 (146,484,442) (100,272,167) (54,595,177) (10,576,664) Nov-12 (9,653,225) (3,627,385) 184,586,315 3,132,604 (3,525,555) 238,652,355 (142,985,648) (96,773,372) (51,096,383) (7,077,870) Dec-12 (9,653,225) (3,627,385) 171,305,705 2,907,329 (3,552,315) 238,007,369 (139,460,093) (93,247,818) (47,570,828) (3,552,315) Jan-13 4,343,565 (3,230,623) 172,418,647 2,942,695 (3,570,145) 237,379,919 (135,907,778) (89,695,503) (44,018,513) Feb-13 4,343,565 (3,230,623) 173,531,589 2,978,061 (3,587,975) 236,770,005 (132,337,633) (86,125,358) (40,448,368) Mar-13 4,343,565 (3,230,623) 174,644,531 3,013,428 (3,605,805) 236,177,628 (128,749,658) (82,537,383) (36,860,393) Apr-13 4,343,565 (3,230,623) 175,757,473 3,048,794 (3,623,635) 235,602,787 (125,143,854) (78,931,578) (33,254,589) May-13 4,343,565 (3,230,623) 176,870,415 3,084,160 (3,641,465) 235,045,483 (121,520,219) (75,307,944) (29,630,954) Jun-13 4,343,565 (3,230,623) 177,983,357 3,119,527 (3,659,294) 234,505,715 (117,878,754) (71,666,479) (25,989,490) Jul-13 4,343,565 (3,230,623) 179,096,299 3,154,893 (3,677,124) 233,983,484 (114,219,460) (68,007,185) (22,330,195) Aug-13 4,343,565 (3,230,623) 180,209,241 3,190,259 (3,694,954) 233,478,788 (110,542,336) (64,330,060) (18,653,071) Sep-13 4,343,565 (3,230,623) 181,322,183 3,225,625 (3,712,784) 232,991,630 (106,847,381) (60,635,106) (14,958,116) Oct-13 4,343,565 (3,230,623) 182,435,125 3,260,992 (3,730,614) 232,522,007 (103,134,597) (56,922,322) (11,245,332) Nov-13 4,343,565 (3,230,623) 183,548,067 3,296,358 (3,748,444) 232,069,921 (99,403,983) (53,191,708) (7,514,718) Dec-13 4,343,565 (3,230,623) 184,661,009 3,331,724 (3,766,274) 231,635,372 (95,655,539) (49,443,264) (3,766,274) Jan-14 4,024,707 (2,817,997) 185,867,720 3,328,869 (3,772,450) 231,191,791 (91,889,265) (45,676,990) Feb-14 4,024,707 (2,817,997) 187,074,430 3,326,014 (3,778,625) 230,739,180 (88,116,815) (41,904,540) Mar-14 4,024,707 (2,817,997) 188,281,141 3,323,159 (3,784,801) 230,277,537 (84,338,190) (38,125,915) Apr-14 4,024,707 (2,817,997) 189,487,852 3,320,303 (3,790,977) 229,806,864 (80,553,389) (34,341,114) May-14 4,024,707 (2,817,997) 190,694,563 3,317,448 (3,797,152) 229,327,160 (76,762,412) (30,550,137) Jun-14 4,024,707 (2,817,997) 191,901,273 3,314,593 (3,803,328) 228,838,425 (72,965,260) (26,752,985) Jul-14 4,024,707 (2,817,997) 193,107,984 3,311,738 (3,809,504) 228,340,659 (69,161,932) (22,949,657) Aug-14 4,024,707 (2,817,997) 194,314,695 3,308,883 (3,815,679) 227,833,863 (65,352,429) (19,140,153) Sep-14 4,024,707 (2,817,997) 195,521,406 3,306,027 (3,821,855) 227,318,035 (61,536,749) (15,324,474) Oct-14 4,024,707 (2,817,997) 196,728,116 3,303,172 (3,828,031) 226,793,176 (57,714,894) (11,502,619) Nov-14 4,024,707 (2,817,997) 197,934,827 3,300,317 (3,834,206) 226,259,287 (53,886,864) (7,674,588) Dec-14 4,024,707 (2,817,997) 199,141,538 3,297,462 (3,840,382) 225,716,367 (50,052,657) (3,840,382) Jan-15 (1,230,248) (3,003,595) 194,907,694 3,233,877 (3,842,019) 225,108,225 (46,212,275) Feb-15 (1,230,248) (3,003,595) 190,673,851 3,170,292 (3,843,656) 224,434,861 (42,370,256) Mar-15 (1,230,248) (3,003,595) 186,440,008 3,106,708 (3,845,293) 223,696,276 (38,526,600) Apr-15 (1,230,248) (3,003,595) 182,206,164 3,043,123 (3,846,930) 222,892,469 (34,681,307) May-15 (1,230,248) (3,003,595) 177,972,321 2,979,539 (3,848,567) 222,023,440 (30,834,377) Jun-15 (1,230,248) (3,003,595) 173,738,478 2,915,954 (3,850,204) 221,089,189 (26,985,809) Jul-15 (1,230,248) (3,003,595) 169,504,634 2,852,369 (3,851,841) 220,089,717 (23,135,605) Aug-15 (1,230,248) (3,003,595) 165,270,791 2,788,785 (3,853,479) 219,025,024 (19,283,764) Sep-15 (1,230,248) (3,003,595) 161,036,948 2,725,200 (3,855,116) 217,895,108 (15,430,285) Oct-15 (1,230,248) (3,003,595) 156,803,104 2,661,616 (3,856,753) 216,699,971 (11,575,169) Nov-15 (1,230,248) (3,003,595) 152,569,261 2,598,031 (3,858,390) 215,439,612 (7,718,417) Dec-15 (1,230,248) (3,003,595) 148,335,417 2,534,446 (3,860,027) 214,114,032 (3,860,027) Partial Month (1.2) (1.7) (0.0) (1.0) (1.1) Months Years yr Avg Months 61.2 Years 5.1

87 86 SCE-09, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital OPERATIONAL CASH REQUIREMENT User Taxes

88 87 WORKING CASH Operational Cash Requirements USER TAXES & OTHER FEES NOTES TO WORKPAPERS User Taxes and Other Fees are amounts collected from utility customers on behalf of city and state authorities. These funds are available to the utility until they get paid to the proper taxing authority and therefore represent a reduction to Rate Base. SCE includes the average balances collected for City Utility Taxes, California Energy Resources Surcharges, Santa Barbara City Surcharges, Ventura Franchise Surcharges, and CPUC Reimbursement Fees. Accounts included in User Taxes: Account Account Description Santa Barbara Surcharge Ventura Franchise Surcharge PUC Reimbursement Fee-Electric City Utility Tax Energy Resources Surcharge-California

89 88 Southern California Edison Company Working Cash Capital Operational Cash Requirement User Taxes and Other Fees Month Total December-14 (29,648,156) January-15 (21,623,896) February-15 (41,053,582) March-15 (27,534,931) April-15 (19,363,166) May-15 (21,510,312) June-15 (27,279,120) July-15 (26,626,457) August-15 (32,832,244) September-15 (38,972,533) October-15 (31,527,177) November-15 (27,725,610) December-15 (30,606,089) 13 Month Total (376,303,271) Less 1/2 First Month (14,824,078) Less 1/2 Last Month (15,303,044) 12 Month Total (346,176,149) Weighted Average (28,848,012) Forecasted User Taxes and Other Fees Year %Change Recorded Forecasted 2015 (28,848) % (29,092) % (29,673) % (30,308) % (30,950) % (31,595)

90 89 Southern California Edison Company Working Cash Capital Operational Cash Requirement User Taxes and Other Fees Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec Santa Barbara Surcharge Collected (113,236.41) (109,122.50) (103,512.58) (109,615.32) (101,476.85) (101,942.58) (103,822.36) (63,597.03) (70,275.51) (69,059.92) (78,175.35) (56,884.92) 10, Ventura Franchise Surcharge Collected (18,208.79) (17,093.39) (13,821.23) (16,569.16) (8,745.53) (2,352.93) (10,230.23) (77,397.80) (81,504.68) (86,490.18) (89,824.05) (69,183.97) (139,067.03) PUC Reimbursemt Fee - Electric (5,088,438.32) (1,587,372.14) (2,958,018.24) (4,546,496.47) (1,589,558.83) (3,070,557.78) (4,766,724.17) (1,983,452.79) (3,878,447.47) (5,955,790.86) (1,979,684.76) (3,505,170.41) (5,206,974.36) UUT - Collected (19,137,510.84) (18,259,153.64) (34,920,887.52) (18,147,156.13) (16,029,813.34) (15,168,903.43) (17,463,631.63) (22,417,805.74) (24,707,681.57) (26,545,238.86) (27,300,391.64) (20,445,885.42) (19,846,186.29) Energy Resources Surcharge - California (5,290,761.33) (1,651,154.05) (3,057,342.76) (4,715,093.61) (1,633,570.96) (3,166,554.78) (4,934,711.38) (2,084,203.37) (4,094,334.60) (6,315,953.57) (2,079,101.25) (3,648,485.58) (5,424,115.00) Total (29,648,155.69) (21,623,895.72) (41,053,582.33) (27,534,930.69) (19,363,165.51) (21,510,311.50) (27,279,119.77) (26,626,456.73) (32,832,243.83) (38,972,533.39) (31,527,177.05) (27,725,610.30) (30,606,088.74)

91 90 SCE-9, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Overview

92 91 WORKING CASH LEAD-LAG STUDY Overview NOTES TO WORK PAPERS SCE s lead-lag study determines the funds required from investors to cover the timing difference between when operating expenses are paid and when revenues are received. A Net Working Cash requirement results from the utility paying operating expenses in advance of collecting revenues covering those expenses in the course of serving utility customers. The analysis determines the weighted-average revenue lag days and the weighted-average lag days for expenses. Multiplying the net lead days by the average daily expense results in the average lead-lag working cash requirement.

93 92 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Revenue Lags

94 93 WORKING CASH LEAD-LAG STUDY REVENUE LAGS NOTES TO WORKPAPERS Revenue Lag is defined as the number of days from the time service is delivered to the time the customer payment is made available in SCE s bank account. The Revenue Lag is measured from the midpoint of the service period to the point that the payment has cleared the bank. Consistent with Standard Practice U-16, SCE has determined the revenue lag using the Ratio of Accounts Receivable to Sales Method and the Bank Lag. SCE has determined a day lag based on twelve months of recent revenue data.

95 94 Southern California Edison Lead-Lag Study Revenue Lag - Accounts Receivable to Sales Method ($M) Average Billed & Unbilled Accounts Receivable $1, CDWR, UUT and Other Adj. $58.33 = Net Average Billed & Unbilled Accounts Receivable $1, / Daily Billed Revenues $31.92 = AR to Sales Lag + Bank Lag = Total Revenue Lag days 0.94 days days

96 95 Southern California Edison Lead-Lag Study - Average Billed and Unbilled Accounts Receivabl Nominal $ GL Account Description Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec Average Billed & Unbilled Accounts Receivable Customer Accounts Receivable- Non-Recon Account 659,739, ,017, ,897, ,258, ,564, ,274, ,683, ,896, ,808,341 1,113,046, ,036, ,180, ,614, ,320, Accrued/Unbilled Revenue 649,526, ,274, ,515, ,485, ,474, ,543, ,382, ,069,000 1,087,387,000 1,045,168, ,403, ,792, ,083, ,691,375 Total 1,309,265,230 1,335,291,058 1,254,412,601 1,259,743,347 1,138,038,492 1,182,817,731 1,575,065,328 1,758,965,860 2,052,195,341 2,158,214,311 1,600,439,779 1,349,972,358 1,240,697,715 1,495,011,473 Adjustments DA CRS - DWR Power 117, , , , , , , , , , , , , , DWR Power (2,075,953) (1,992,155) (1,915,397) (1,971,065) (2,005,840) (1,986,678) (1,967,374) (1,882,217) (1,838,932) (1,802,946) (1,768,425) (1,741,656) (1,731,397) (1,898,030) DWR Customer Return Credit 5,876, ,316 (1,161,257) (1,806,458) (2,551,355) (3,945,027) (3,902,994) (2,046,568) (628,679) 2,031,335 3,863,764 2,718,346 2,793,986 (180,768) DWR - CCA - CRS Bond (31,703) (28,914) (30,078) (32,919) (30,151) (32,111) (20,541) (56,951) (33,047) (16,294) (18,222) 13,546 3,168 (24,996) DA CRS - DWR Bond (2,329,749) (2,235,438) (2,213,628) (2,309,989) (2,819,857) (2,377,387) (2,729,444) (2,555,170) (2,512,575) (2,805,453) (3,078,819) 412,393 (2,923,296) (2,320,991) DWR Bond (21,819,046) (22,926,680) (21,978,340) (22,082,271) (22,510,002) (22,018,670) (23,562,822) (26,631,802) (27,558,234) (30,168,576) (28,613,307) (1,821,308) (23,208,233) (22,698,804) DWR / UUT AR Conversion (11,424,629) (12,372,405) (11,302,084) (10,707,603) (9,014,724) (9,374,969) (11,629,087) (15,007,448) (17,116,048) (19,087,438) (15,672,395) (12,820,332) (12,589,552) (13,009,302) CDWR - Unbilled Conversion (17,821,000) (14,646,000) (12,784,000) (13,167,000) (12,126,000) (12,733,000) (15,913,000) (17,038,000) (21,335,000) (20,256,000) (17,786,000) (16,656,000) (13,934,000) (15,859,792) Santa Barbara City Surcharge (31,161) (35,231) (33,295) (31,366) (27,285) (25,894) (32,150) (39,234) (37,925) (45,520) (32,598) (27,762) (31,404) (33,295) PUC Reimbursemt Fee - Electric* (1,696,146) (529,124) (986,006) (1,515,499) (529,853) (1,023,519) (1,588,908) (661,151) (1,292,816) (1,985,264) (659,895) (1,168,390) (1,735,658) (1,138,027) Ventura Franchise Surcharge Collected (18,209) (17,093) (13,821) (16,569) (8,746) (2,353) (10,230) (77,398) (81,505) (86,490) (89,824) (69,184) (139,067) (45,988) Ventura Franchise Surcharge (47,425) (50,767) (44,756) (44,199) (37,541) (37,177) (48,211) (58,452) (60,269) (63,287) (50,835) (40,472) (46,550) (48,579) Energy Resources Surcharge - California* (1,763,587) (550,385) (1,019,114) (1,571,698) (544,524) (1,055,518) (1,644,904) (694,734) (1,364,778) (2,105,318) (693,034) (1,216,162) (1,808,038) (1,187,165) Total (53,064,413) (54,342,593) (53,364,686) (55,139,737) (52,089,166) (54,495,777) (62,933,337) (66,632,878) (73,743,854) (76,275,620) (64,484,257) (32,301,859) (55,235,090) (58,329,460) Net Average Billed & Unbilled Accounts Receivable 1,256,200,817 1,280,948,465 1,201,047,915 1,204,603,610 1,085,949,326 1,128,321,954 1,512,131,991 1,692,332,981 1,978,451,487 2,081,938,690 1,535,955,522 1,317,670,499 1,185,462,625 1,436,682,014 *PUC Reimbursement Fees and Energy Resource Surcharge are collected throughout the month, and liabilities are paid quarterly. This requires the weighted average adjustment to be divided by 3.

97 96 Southern California Edison Lead-Lag Study - Revenue Lag - Recorded Revenue Nominal $ GL Account Description Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec Total Recorded Revenue Residential Sales (426,237,693) (444,474,655) (333,191,743) (388,180,924) (248,067,849) (337,023,015) (422,994,728) (545,014,806) (533,001,323) (614,906,146) (426,603,455) (368,606,851) (445,610,676) (5,107,676,172) Agricultural Sales (13,221,461) (10,913,747) (11,599,381) (16,499,311) (19,247,471) (18,555,713) (25,561,331) (35,784,725) (32,045,257) (31,106,408) (25,598,844) (12,893,114) (13,423,076) (253,228,377) Commercial Sales (426,660,995) (377,315,487) (345,460,891) (404,532,584) (408,414,384) (379,963,829) (492,017,120) (640,441,492) (619,003,706) (662,513,316) (567,547,075) (378,895,569) (411,883,783) (5,687,989,235) Industrial Sales (58,583,336) (51,362,430) (49,514,087) (53,960,195) (52,036,389) (50,926,905) (57,217,638) (69,406,629) (68,788,154) (70,697,419) (68,408,539) (52,059,541) (51,503,753) (695,881,680) Commercial Sales-Other Public Authorities (39,898,741) (33,370,799) (31,212,952) (37,035,046) (37,064,562) (35,015,815) (46,308,197) (57,385,402) (57,480,920) (66,995,541) (57,159,842) (34,739,028) (38,009,764) (531,777,868) Public Street & Highway Lighting (9,908,034) (9,592,888) (9,480,917) (9,887,458) (9,497,213) (9,609,455) (9,494,161) (9,547,775) (9,482,376) (9,495,475) (9,647,790) (9,260,046) (9,769,077) (114,764,632) Public Auth Special Contracts (969,695) (1,026,895) (1,018,575) (956,141) (878,108) (881,843) (885,968) (1,047,954) (1,084,538) (1,080,155) (997,206) (1,165,413) (969,363) (11,992,158) Interdepartmental Sales (12,273) (13,081) (10,381) (11,682) (11,963) (9,407) (12,286) (13,004) (11,445) (15,972) (14,123) (10,072) (13,838) (147,254) Sales to Railroads & Railways (1,506,193) (828,002) (146,958) (1,400,382) (840,906) (216,164) (1,862,000) (1,475,599) (1,470,416) (1,439,079) (952,751) (62,384) (1,385,329) (12,079,970) Late Payment Charge- Comm & Ind (607,383) (656,011) (472,911) (441,412) (479,402) (319,199) (422,015) (536,686) (642,841) (656,861) (754,635) (621,644) (588,373) (6,591,990) Residential Late Payment (988,919) (920,996) (841,286) (812,254) (726,977) (550,860) (686,121) (801,620) (983,378) (1,179,628) (1,385,514) (1,095,615) (1,101,336) (11,085,586) Returned Check Charges (130,672) (109,051) (139,292) (126,944) (120,299) (103,049) (98,341) (126,718) (111,973) (146,808) (145,451) (134,176) (148,076) (1,510,178) Service Reconnection Charges (2,485) (2,021) (2,006) (2,261) (2,542) (2,073) (2,006) (1,199) (1,935) (1,595) (1,211) (626) (977) (20,452) Service Establishment Charge (127) (44) (77) (95) (162) (152) (57) 65 (18) 5 (25) (143) (33) (736) Field Collection Charges (6) - (6) (6) (111) (17) (36) - (108) Quickcheck Revenue (10) (6) (6) (16) (16) (24) - (10) 3 - (50) Meter Leasing Revenue Company Financed Added Facilities (848,723) (985,850) (896,930) (877,859) (900,622) (931,246) (904,232) (909,628) (905,364) (904,222) (987,578) (685,717) (911,067) (10,800,314) Company Financed Interconnect Facilities (42,397) (41,285) (40,418) (38,942) (38,942) (38,942) (28,772) (37,299) (37,299) (37,299) (37,299) (37,299) (37,299) (451,095) Customer Financed Added/Interconnect Facility SCE Financed Added Faclty (1,856,280) (1,929,717) (1,929,565) (1,940,829) (1,929,929) (1,929,929) (1,827,618) (1,922,178) (1,922,178) (1,922,178) (1,922,178) (1,915,288) (1,915,288) (23,006,876) Interconnect Facility Finance Charge (1,281,546) (1,281,564) (1,281,846) (1,281,560) (1,281,560) (1,281,560) (856,714) (1,213,037) (1,213,037) (1,213,037) (1,213,037) (1,213,037) (1,213,037) (14,543,025) DA Revenue (14,971) (16,292) (17,301) (17,757) (18,757) (13,414) (55,166) (16,197) (27,973) (31,928) (17,767) (27,539) (22,524) (282,615) Direct Access Monthly Customer Charges EDBL Customer Finance Added Facilities (311,709) (306,457) (311,391) (357,219) (322,945) 556,095 (1,222,889) (292,068) (342,593) (361,225) (367,239) (412,519) (281,856) (4,022,307) SCE Energy Manager Fee Based Services (18,940) (16,180) (13,420) (11,720) (11,260) (11,860) (13,020) (12,966) (10,820) (10,580) (10,400) (9,770) (13,400) (145,396) SCE Energy Manager Fee Based Services Adj Off Grid Photo Voltaic Revenues Interconnect Facilities Charges-Customer Financed (157,234) (129,099) (218,806) (191,894) (173,218) (207,238) (184,558) (173,218) (195,898) (173,218) (175,960) (207,238) (177,167) (2,207,512) Interconnect Facilities Charges - SCE Financed (1,289,626) (558,191) (8,587) (1,112,051) (1,107,467) (1,119,986) (134,058) (1,049,195) (1,135,230) (1,506,286) (1,535,302) (1,154,725) (1,329,952) (11,751,029) DMS Service Fees (183) (207) (162) (172) (206) (268) (290) (215) (221) (170) (283) (142) (244) (2,579) Transmission of Elec of Others (3,274,309) (3,747,281) (3,773,561) (3,773,561) (3,773,561) (3,773,561) (3,423,311) (3,296,769) (3,227,171) (3,227,171) (3,227,171) (3,227,171) (3,227,171) (41,697,458) WDAT (412,837) (421,288) (433,424) (423,667) (430,457) (432,918) (430,311) (455,351) (449,784) (466,867) (460,634) (449,647) (428,878) (5,283,226) Radial Line Rev-Base Cost - Reliant Coolwater (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (32,885) (394,622) Radial Line Rev-Base Cost - Reliant Ormond Beach (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (90,079) (1,080,948) Radial Line Rev-O&M - AES Huntington Beach (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (33,512) (402,148) Radial Line Rev-O&M - Reliant Mandalay (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (17,476) (209,706) Radial Line Rev-O&M - Reliant Coolwater (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (45,917) (551,002) Radial Line Rev-O&M - Ormond Beach (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (54,278) (651,331) High Desert Tie-Line Rental Rev (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (22,011) (264,133) Scheduling/Dispatch Revenues (CSS) Inland Empire CRT Tie-Line EX (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (3,541) (42,492) Reliability Service Revenue - Non-PTO's (15,935) (18,432) (17,764) (22,703) (17,202) (14,947) (22,172) (23,228) (23,404) (20,933) (23,350) (22,642) (20,195) (246,974) Opt Out Res CARE - Initial Fee (270) (930) (370) (260) (210) (160) (210) (170) (70) (140) (120) (220) (180) (3,040) Opt Out Res CARE - Monthly Fee (28,285) (26,215) (23,495) (24,925) (25,750) (23,075) (25,765) (24,195) (18,935) (16,035) (14,770) (10,360) (9,300) (242,820) Opt Out Res Non-CARE - Initial Fee (6,225) (22,800) (6,450) (7,050) (7,500) (5,925) (5,625) (5,850) (5,400) (5,475) (5,550) (3,750) (4,125) (85,500) Opt Out Res Non-CARE - Monthly Fee (187,050) (180,105) (161,745) (174,085) (182,095) (167,595) (182,740) (169,725) (127,055) (95,575) (83,625) (62,325) (60,745) (1,647,415) Service Connection Charge - Residential (560,644) (444,484) (469,494) (584,444) (569,930) (520,616) (594,695) (624,083) (603,449) (594,290) (584,739) (545,136) (648,903) (6,784,262) Service Connection Charge - Non-Residential (262,332) (249,195) (258,384) (304,265) (298,344) (268,936) (285,705) (283,563) (265,146) (284,732) (279,482) (256,701) (277,770) (3,312,223) Service Connection Charge - At Pole (974) (825) (1,474) (1,640) (1,851) (1,566) (786) (976) (1,338) (1,050) (970) (362) (1,204) (14,042) Total Revenue (989,598,192) (941,262,198) (793,255,729) (925,292,998) (788,779,850) (843,664,761) (1,068,060,310) (1,372,393,168) (1,334,920,365) (1,471,406,507) (1,170,463,641) (870,085,542) (985,287,459) (12,564,872,529) Service Billed Revenue Adj 43,130,853 43,017,526 46,464,501 60,817,464 70,107,806 82,244,709 99,164, ,678, ,754,169 92,329,132 70,979,683 68,310, ,999,490 Customer Billed Revenues (898,131,345) (750,238,203) (878,828,497) (727,962,386) (773,556,954) (985,815,601) (1,273,228,886) (1,219,241,732) (1,349,652,338) (1,078,134,510) (799,105,859) (916,976,729) (11,650,873,039) Daily Billed Revenues (365 Days) (31,920,200)

98 97 Southern California Edison Lead-Lag Study - Revenue Lag Nominal $ Service Billed Revenue Adjustment Total Service Billed Service Billed DWR Service Billed Revenue Pending Month Pending Customer Bill Pending Customer Bill Customer Bill A B C D=B+C Jan-15 ($44,543,884) $1,413,031 ($43,130,853) Feb-15 ($44,461,097) $1,443,570 ($43,017,526) Mar-15 ($48,060,688) $1,596,187 ($46,464,501) Apr-15 ($63,386,600) $2,569,136 ($60,817,464) May-15 ($72,763,345) $2,655,539 ($70,107,806) Jun-15 ($84,978,261) $2,733,552 ($82,244,709) Jul-15 ($101,984,026) $2,819,744 ($99,164,283) Aug-15 ($118,765,268) $3,086,634 ($115,678,633) Sep-15 ($125,387,631) $3,633,462 ($121,754,169) Oct-15 ($95,505,900) $3,176,769 ($92,329,132) Nov-15 ($73,659,939) $2,680,255 ($70,979,683) Dec-15 ($70,840,670) $2,529,941 ($68,310,729) Total Service Billed Revenue Adjustment ($913,999,490)

99 98 Southern California Edison Lead-Lag Study - Revenue Lag - Bank Lag Nominal $ Payment Type Revenue Lag Days Dollar Day Lags A B C D=B x C Authorized Payment Agency & Credit Card $1,026,624, $192,652,723 Direct Payment $1,302,855, $2,901,148,601 SCE.Com $1,313,836, $1,925,448,961 Quick Check $509,309, $745,261,356 Electronic Funds Transfer $1,546,092, ($37,153,976) Electronic Data Interchange $1,290,721, ($35,609,124) Montebello Local Office $3,200, $7,725,550 Other Local Offices Checks $25,730, $102,648,585 Other Local Offices Cash $13,093, $60,428,296 Union Bank Same Day Next Day $6,525,002, $6,908,229,489 Total $13,556,467, $12,770,780,462 Study Period: 1/1/ /31/2015

100 99 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS NOTES TO WORKPAPERS Expense Lags represent the average time from recording the various operating costs to render service advanced by third party vendors and suppliers, investors, employees, and taxing agencies to the date of payment for those expenses. The expense lags were developed based on recorded information. The lags are determined by calculating the average number of days from the date (or midpoint of a service period) that SCE records an expense until the time SCE s payment to the vendor or payee clears the bank. The Workpapers which detail the development of the Expense Lag Study are separated into the following sections: Fuel Purchased Power - CONFIDENTIAL Company Labor STIP Goods & Services Materials Issued From Stores Insurance Provisions & Line Rents Injuries & Damages Provisions Funded Pension Provisions Benefits & Unfunded Pension Provisions P.B.O.P. Franchise Requirements Provision for Uncollectibles Depreciation Nuclear Decommissioning Taxes Other Than Income Taxes Based on Income Other Labor & Non-Labor

101 100 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Fuel

102 101 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS FUEL NOTES TO WORKPAPERS Fuel costs represent the natural gas, nuclear fuel, diesel, and propane amounts used by SCE s generating stations. The overall average lag days are calculated by weighting the fuel types individually. The nuclear fuel lag days are set at zero because the nuclear fuel investment is amortized uniformly over the service period. The Workpapers which detail the development of the expense lag days for Fuel are separated into the following sections: Natural Gas Mountainview, Peakers, and Fuel Cells Nuclear Amortization and Waste Disposal Diesel Catalina Fuel & Transportation Propane

103 102 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FUEL LAG DAYS (In Thousands) Fuel Type 2015 Lag Days Dollar Days Lag Natural Gas 132, ,352,383 Nuclear Fuel Amortization 39, Nuclear Fuel - Waste Disposal/Dry Cask 1, ,812 Diesel Fuel (Catalina) 5, ,451 Propane ,897 Total Fuel (2015 Recorded) 178, ,528,543 Fuel Type 2018 Forecast Lag Days Dollar Days Lag Natural Gas 189, ,677,672 Nuclear Fuel Amortization 40, Nuclear Fuel - Waste Disposal/Dry Cask ,079 Diesel Fuel (Catalina) 10, ,077 Propane ,180 Total Fuel (2018 Forecast) 241, ,017,007

104 103 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY NATURAL GAS Mountainview, Peakers and Fuel Cells Period Amount Lag Days Lag $ January ,186, ,902,926 February ,649, ,876,723 March ,951, ,895,437 April ,848, ,189,066 May ,117, ,989,922 June ,892, ,892,383 July ,083, ,283,725 August ,109, ,794,474 September ,323, ,336,906 October ,824, ,022,582 November ,801, ,019,405 December ,363, ,179,907 Grand Total 132,152, ,352,383,456

105 104 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FUEL - NUCLEAR OTHER Summary Location Name Amount Paid Lag Days Dollar Days Lag Waste Disposal, PVNGS* Dry Cask, PVNGS 1,818, ,811,768 Nuclear - Total 1,818, ,811,768 Nuclear Fuel Amortization 39,482, * Palo Verde NGS Waste Disposal is projected to be $0 for the GRC period. Dry Cask, PVNGS Period Beginning Period Ending Mid-Point Payment Date Amount Paid Lag Days Dollar Days Lag 1/1/2015 1/31/ /16/15 1/28/ , ,613,076 2/1/2015 2/28/ /14/15 2/25/ , ,827,368 3/1/2015 3/31/ /16/15 3/25/ , ,127 4/1/2015 4/30/ /15/15 4/22/ , ,829 5/1/2015 5/31/ /16/15 5/27/ , ,708 6/1/2015 6/30/ /15/15 6/24/ , ,319 7/1/2015 7/31/ /16/15 7/22/ , ,793,024 8/1/2015 8/31/ /16/15 8/26/ , ,920 9/1/2015 9/30/ /15/15 9/23/ , ,298 10/1/ /31/ /16/15 10/28/ , ,257,632 11/1/ /30/ /15/15 11/25/2015 (17,806) 9.5 (169,157) 12/1/ /31/ /16/15 12/23/2015 (1,757) 7.0 (12,299) 1,818, ,811,768 Nuclear Fuel Amortization Period Beginning Period Ending Unit Amount Paid Lag Days Dollar Days Lag 1/1/ /31/2015 PVNGS 39,482,591 39,482,

106 105 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FUEL CATALINA DIESEL, TRANSPORTATION Amount Lag Days Lag $ SC Fuels 4,004, ,658,496 Seaway Company 1,076, ,792,372 Total 5,081, ,450,868 Catalina Diesel Purchases SC Fuels Amount Lag Days Lag $ January , ,946,861 February , ,526,490 March , ,120,096 April , ,551,799 May , ,642,420 June , ,509,644 July , ,274,307 August , ,883,800 September , ,534,326 October , ,260,869 November , ,550,208 December , ,857,678 Grand Total 4,004, ,658,496 Fuel Transportation Seaway Company Amount Lag Days Lag $ January , ,005 February , ,600 March , ,207 April , ,022 May , ,856 June , ,430 July , ,593 August , ,831 September , ,056,902 October , ,687 November , ,383 December , ,014,856 Grand Total 1,076, ,792,372

107 106 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY Propane Period Amount Lag Days Lag $ January , ,625 February , ,193 March , ,987 April , ,757 May , ,353 June , ,929 July , ,270 August , ,352 September , ,805 October , ,466 November , ,489 December , ,143 Grand Total 149, ,896,563

108 107 Southern California Edison Company Working Cash Capital Fuel Forecast (In Thousands) Recorded Forecasted Fuel Type Natural Gas 132, , , , , ,874 Nuclear Fuel - Amortization 39,483 38,393 38,685 40,606 42,311 43,537 Nuclear Fuel - Other Waste Disposal 1, Diesel Fuel 5,081 10,408 10,544 10,682 10,824 10,968 Propane Fuel Total 178, , , , , ,612

109 108 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Purchased Power

110 109 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS PURCHASED POWER NOTES TO WORKPAPERS Purchased power costs represent the largest single expense affecting SCE s working cash needs. SCE s purchased power costs can be categorized as (1) Qualifying Facilities (QF) paid by United States Postal Service (USPS), (2) Qualifying Facilities (QF) paid by Electronic Fund Transfer (EFT), and (3) Non-QF Bilateral and Firm agreements, Power Exchange, and other energy related costs (Non-QF). The purchased power lag days reflect the average time from the service period when SCE receives the energy to the dates when the payments for the energy clear the bank. The purchased power expense lags were developed using the recorded payments for year 2015 for each type of agreement. The composite lags were developed using 2018 forecasted expense to ensure forecasted shifts between the different types of agreements were captured in the overall weighting. See Confidential Workpapers, SCE-9, Vol. 2, Chapter IV

111 110 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Company Labor

112 111 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS COMPANY LABOR NOTES TO WORKPAPERS SCE determined an average expense lag for labor based on its biweekly payroll calendar. The lag is the average number of days between the time SCE receives service from employees to the day when the paychecks are deposited and clear the bank. The weighted lag day is computed as a percentage of the following payroll categories: (1) employees participating in direct deposit, (2) employees receiving negotiable checks (3) the immediate payment of payroll tax, (4) a composite of other withholdings, and (5) paid absence. Company labor also includes accruals for paid absence and long term incentives. These accruals have a zero day lag since they represent an immediate offset to rate base in Operational Cash.

113 112 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY LABOR 2015 Amount Percentage of Payroll Percentage of Labor Total Lag Days Base Labor Lag Day Add'l Lag Days Wtd Lag Days Direct Deposit 603,694, % 38.92% Negotiable Checks 19,828, % 1.28% Paid Absence 108,311, % 6.98% Tax Withholding 498,652, % 32.15% Other Withholdings 307,015, % 19.79% Subtotal 1,537,502, % LTIP 13,725, % Total 1,551,228, % Negotiable Check Clearing Lag Check Issue Date Amount Lag Days Weighted Lag 1/2/2015 3,132, ,767,947 1/16/2015 1,886, ,456,422 1/30/2015 8,621, ,028,232 2/13/2015 1,278, ,536,835 2/27/2015 3,877, ,219,046 3/13/2015 7,919, ,491,290 3/27/2015 2,042, ,376,977 4/10/2015 1,001, ,966,447 4/24/ , ,343,968 5/8/2015 1,078, ,112,310 5/22/ , ,113,558 6/5/ , ,074,463 6/19/ , ,814,655 7/2/2015 3,027, ,532,860 7/17/2015 1,000, ,163,077 7/31/2015 1,531, ,978,849 8/14/2015 1,219, ,958,905 8/28/2015 1,374, ,872,309 9/11/ , ,249,677 9/25/2015 2,336, ,871,529 10/9/2015 3,115, ,884,409 10/23/2015 1,082, ,275,093 11/6/2015 1,158, ,662,852 11/20/ , ,085,254 12/4/ , ,364,172 12/18/2015 1,024, ,360,203 Weighted Lag 54,263, ,561,339

114 113 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags STIP

115 114 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS STIP NOTES TO WORKPAPERS STIP is accrued during the calendar year and paid first quarter of the following year. The associated FICA taxes are included in the estimated expense and the longer STIP expense lag is applied to these taxes. The lag is the average number of days between the time SCE receives service from employees to the day when the paychecks are deposited and clear the bank.

116 115 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY Short Term Incentive Plan (STIP) Composite Lag Calculation 2015 STIP & Executive Incentive Compensation (EIC) Accrual Date of Weighted Lag Percentage of Total STIP Type Mid-Point Payment Lag Days Days STIP 06/30/14 03/16/ % EIC 06/30/14 03/03/15 8.0% Total 100% 258.0

117 116 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Goods and Services

118 117 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS GOODS & SERVICES NOTES TO WORKPAPERS The expense lag for Goods & Services represents the time lag between invoice received date and the payment of such costs. The determination was based on the review of Goods & Services invoices paid from January 2015 through December 2015.

119 118 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY GOODS & SERVICES Summary of Payments (January December 2015) Period Amount Lag Days Dollar Days Lag PO 3,791,332, ,070,872,712 Non-PO 368,212, ,585,915,413 Total 4,159,545, ,656,788,125 PO Goods & Services Period Amount Lag Days Dollar Days Lag January ,523, ,354,387,020 February ,283, ,364,375,261 March ,491, ,635,949,870 April ,671, ,082,556,375 May ,080, ,270,958,002 June ,820, ,297,891,562 July ,074, ,350,266,839 August ,663, ,417,342,944 September ,009, ,567,566,661 October ,704, ,061,280,793 November ,044, ,065,508,222 December ,964, ,602,789,164 Total 3,791,332, ,070,872,712 NON-PO Goods & Services Period Amount Lag Days Dollar Days Lag January-15 20,569, ,747,385 February-15 20,199, ,853,951 March-15 42,878, ,106,486 April-15 38,954, ,131,508 May-15 29,909, ,369,553 June-15 25,316, ,614,698 July-15 31,860, ,451,532 August-15 25,937, ,616,438 September-15 29,237, ,615,846 October-15 25,458, ,800,634 November-15 26,713, ,687,058 December-15 51,178, ,920,325 Total 368,212, ,585,915,413

120 119 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Materials Issued From Stores

121 120 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS MATERIALS ISSUED FROM STORES NOTES TO WORKPAPERS Materials Issued from Stores are those materials that are charged to maintenance expense on a daily basis. Therefore, the lag days are set to zero.

122 121 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY MATERIALS ISSUED FROM STORES Dollar Month Materials Expense Lag Days Days Lag Jan-15 2,564, Feb , Mar-15 (2,004,953) 0 0 Apr , May-15 73, Jun , Jul-15 87, Aug , Sep , Oct , Nov , Dec , Total 4,748,

123 122 SCE-9, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Insurance Provisions & Line Rents

124 123 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS INSURANCE PROVISIONS & LINE RENTS NOTES TO WORKPAPERS Insurance Provisions & Line Rents represent accrued expenses which are prepaid for property insurance and for right-of-way facilities located on public or federal lands. Since these accrued expenses are offset in rate base, the lag days are zero.

125 124 SCE-9, Volume 2, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Injuries & Damages Provisions

126 125 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS INJURIES & DAMAGES PROVISIONS NOTES TO WORKPAPERS Injuries and Damages Provisions represent accruals to cover losses incurred through claims and suits of injuries and damages to persons and property. Since these accrued expenses are offset in rate base, the lag days are zero.

127 126 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Funded Pension Provisions

128 127 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS FUNDED PENSION PROVISIONS NOTES TO WORKPAPERS The expense lag for Funded Pension Provisions utilizes an accrual pattern based upon the monthly distribution percentage for base revenues and the timing of payments made to the trust accounts.

129 128 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FUNDED PENSION PROVISIONS Funded Pension General Ledger Account Contribution Date Period Period Period Date of Beginning Ending Mid-Point Payment Payments Lag Days Dollar Lag Days 1/1/ /31/2015 7/13/2015 4/13/ ,486,000 (91.0) (3,229,226,000) 1/1/ /31/2015 7/13/2015 7/10/ ,486,000 (3.0) (106,458,000) 1/1/ /31/2015 7/13/2015 9/14/ ,619, ,613,997,000 96,591,000 (17.8) (1,721,687,000)

130 129 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FUNDED PENSION PROVISIONS (In Thousands) Recorded Forecast Item Funded Pension 87,739 91,431 94,666 97, , ,895

131 130 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Benefits & Unfunded Pension Provisions

132 131 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS BENEFITS & UNFUNDED PENSION PROVISIONS NOTES TO WORKPAPERS Benefits and Unfunded Pension Provisions are included in the lead lag study to compensate investors for the lag between when the expenses are accrued and the revenues are collected. The expense lag for Benefits represents the period from when the expenses are accrued to the time they are paid. Unfunded provision expense is accrued monthly and the accumulated provision is an immediate offset to rate base since it represents a liability to SCE until the funds are paid out. Because the provision is accrued uniformly on a daily basis the associated expense lag is zero days. This results in an overall composite lag of 3.12 day for Benefits and Unfunded Pensions Provisions.

133 132 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY BENEFITS AND UNFUNDED PENSION PROVISIONS Benefits Lag by Benefit Benefit Amount Lag Days Dollar Days Lag 401K Benefits 72,701, ,869,501 Life Insurance Benefits 10,595, ,262,112 Medical Benefits 271,277, ,491,662 Dental Benefits 26,404, ,608,792 Vision Benefits 3,992, ,088, ,972, ,246,320,372 Unfunded Pension Amount Lag Days Dollar Days Lag 15,007, ,979, ,246,320,372

134 133 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags P.B.O.P. Provision

135 134 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS P.B.O.P. PROVISIONS NOTES TO WORKPAPERS The expense lag for PBOPs utilizes an accrual pattern based upon the monthly distribution percentage for base revenues and the timing of payments made to the trust accounts. Various PBOP payments were made in December The composite PBOP lag also includes the Pay As You Go portion which assumes a zero day lag.

136 135 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY Post Retirement Benefits Other than Pensions General Ledger Account Contribution Date Period Period Period Date of Dollar Beginning Ending Mid-Point Payment Amount Lag Days Days Lag 1/1/ /31/2015 7/13/2015 Various 8,947, ,413,735,652 Paid throughout the month 14,830, ,777, ,413,735,652

137 136 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY PBOP Forecast (In Thousands) Recorded Forecast Item PBOP 22,477 32,236 34,533 36,823 39,371 42,098

138 137 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Franchise Requirements

139 138 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS FRANCHISE REQUIREMENTS NOTES TO WORKPAPERS Franchise Fees are amounts billed to SCE by municipalities for service within their jurisdictions. Each municipality has different franchise requirements based on a formula that incorporates line miles in each service area and the revenues received from utility customers. Payments vary depending on the Franchise Requirements for each city/county. The lead lag for Franchise Requirements is the time between SCE incurring the expense and the time the fees are paid. The development of the lag days was based on 2015 payments made for the service agreements in year 2014 and estimated payments for 2015.

140 139 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS Summary of Payments Made for 2014 Dollar Schedule No. Description Amount Lag Days Days Lag 2 Broughton Act - Counties 4,217, ,210,498,598 3 Broughton Act - Cities 104, ,764, Act - 1% Municipalities 94,287, ,360,230, Act -.5% Municipalities 18,213, ,227,145,702 6 City of Long Beach 7,030, ,589,433 7 City of Los Angeles - Ordinance No , ,406,161 8 City of Avalon - Nos. 434 & , ,508,456 9 Miscellaneous 6, ,776,704 TOTAL 124,166, ,657,920,900

141 140 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS SCHEDULE 2 Broughton Act - Counties Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Imperial County 01/01/14 12/31/14 07/02/14 04/15/15 4, ,409,256 Kings County 01/01/14 12/31/14 07/02/14 04/15/15 260, ,875,370 Madera County 01/01/14 12/31/14 07/02/14 04/15/15 1, ,078 Mono County 01/01/14 12/31/14 07/02/14 04/15/15 163, ,853,511 Orange County 01/01/14 12/31/14 07/02/14 04/15/15 471, ,305,108 Tulare County 01/01/14 12/31/14 07/02/14 04/15/15 3,316, ,704,275 Total 4,217, ,210,498,598 SCHEDULE 3 Broughton Act - Cities Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Anaheim 01/01/14 12/31/14 07/02/14 04/15/15 87, ,035,300 Pasadena 01/01/14 12/31/14 07/02/14 03/31/15 17, ,729,577 Total 104, ,764,877

142 141 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS SCHEDULE Act - 1% Municipalities Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Adelanto 01/01/14 12/31/14 07/02/14 04/15/15 246, ,641,092 Agoura Hills 01/01/14 12/31/14 07/02/14 04/15/15 283, ,354,693 Aliso Viejo 01/01/14 12/31/14 07/02/14 04/15/15 400, ,806,567 Apple Valley 01/01/14 12/31/14 07/02/14 04/15/15 529, ,051,558 Artesia 01/01/14 12/31/14 07/02/14 04/15/15 138, ,662,941 Avalon 01/01/14 12/31/14 07/02/14 04/15/15 40, ,483,714 Azusa 01/01/14 12/31/14 07/02/14 04/15/15 57, ,494,668 Baldwin Park 01/01/14 12/31/14 07/02/14 04/15/15 455, ,821,158 Banning 01/01/14 12/31/14 07/02/14 04/15/15 13, ,866,800 Barstow 01/01/14 12/31/14 07/02/14 04/15/15 251, ,112,513 Beaumont 01/01/14 12/31/14 07/02/14 04/15/15 290, ,260,267 Bell 01/01/14 12/31/14 07/02/14 04/15/15 168, ,262,465 Bell Gardens 01/01/14 12/31/14 07/02/14 04/15/15 181, ,085,124 Bellflower 01/01/14 12/31/14 07/02/14 04/15/15 365, ,997,047 Beverly Hills 01/01/14 12/31/14 07/02/14 04/15/15 1,054, ,535,012 Bishop 01/01/14 12/31/14 07/02/14 04/15/15 47, ,501,154 Blythe 01/01/14 12/31/14 07/02/14 04/15/15 163, ,935,859 Bradbury 01/01/14 12/31/14 07/02/14 04/15/15 20, ,017,357 Brea 01/01/14 12/31/14 07/02/14 04/15/15 775, ,616,831 Buena Park 01/01/14 12/31/14 07/02/14 4/15/ , ,312,590 Burbank 01/01/14 12/31/14 07/02/14 4/15/ , ,945,914 Calabasas 01/01/14 12/31/14 07/02/14 4/15/ , ,941,430 California City 01/01/14 12/31/14 07/02/14 4/15/ , ,113,762 Calimesa 01/01/14 12/31/14 07/02/14 04/15/15 74, ,300,431 Camarillo 01/01/14 12/31/14 07/02/14 04/15/15 741, ,888,900 Canyon Lake 01/01/14 12/31/14 07/02/14 04/15/15 112, ,207,019 Carpinteria 01/01/14 12/31/14 07/02/14 04/15/15 118, ,111,431 Carson 01/01/14 12/31/14 07/02/14 04/15/15 1,715, ,420,399 Cathedral City 01/01/14 12/31/14 07/02/14 04/15/15 514, ,637,992 Cerritos 01/01/14 12/31/14 07/02/14 04/15/15 655, ,031,351 Chino Hills 01/01/14 12/31/14 07/02/14 04/15/15 538, ,655,506 Colton 01/01/14 12/31/14 07/02/14 04/15/15 63, ,329,226 Commerce 01/01/14 12/31/14 07/02/14 04/15/15 908, ,656,988 Costa Mesa 01/01/14 12/31/14 07/02/14 04/15/15 1,359, ,206,058 Cudahy 01/01/14 12/31/14 07/02/14 04/15/15 78, ,577,874 Culver City 01/01/14 12/31/14 07/02/14 04/15/15 636, ,785,295 Cypress 01/01/14 12/31/14 07/02/14 04/15/15 481, ,237,686 Desert Hot Springs 01/01/14 12/31/14 07/02/14 04/15/15 203, ,524,291 Diamond Bar 01/01/14 12/31/14 07/02/14 04/15/15 429, ,339,780 Downey 01/01/14 12/31/14 07/02/14 04/15/15 896, ,172,960 Duarte 01/01/14 12/31/14 07/02/14 04/15/15 236, ,923,756 Eastvale 01/01/15 03/31/15 02/14/15 03/31/15 127, ,687,506 Eastvale 04/01/15 06/30/15 05/16/15 06/30/15 95, ,301,924 Eastvale 07/01/15 09/30/15 08/15/15 09/30/15 95, ,349,723 Eastvale 10/01/15 12/31/15 11/15/15 12/31/ , ,349,723 El Monte 01/01/14 12/31/14 07/02/14 4/15/ , ,594,982 El Segundo 01/01/14 12/31/14 07/02/14 4/15/2015 1,176, ,741,023 Farmersville 01/01/14 12/31/14 07/02/14 4/15/ , ,144,741 Fillmore 01/01/14 12/31/14 07/02/14 04/15/15 82, ,704,642 Fontana 01/01/14 12/31/14 07/02/14 04/15/15 1,490, ,712,065 Fountain Valley 01/01/14 12/31/14 07/02/14 04/15/15 651, ,009,453 Fresno County 01/01/14 12/31/14 07/02/14 04/15/15 35, ,303,314 Garden Grove 01/01/14 12/31/14 07/02/14 04/15/15 1,211, ,627,682 Gardena 01/01/14 12/31/14 07/02/14 04/15/15 498, ,166,724 Glendale 01/01/14 12/31/14 07/02/14 03/31/15 10, ,907,628 Glendora 01/01/14 12/31/14 07/02/14 04/15/15 489, ,608,486 Goleta 01/01/14 12/31/14 07/02/14 04/15/15 450, ,194,408 Grand Terrace 01/01/14 12/31/14 07/02/14 04/15/15 102, ,316,686 Hawaiian Gardens 01/01/14 12/31/14 07/02/14 04/15/15 68, ,601,822 Hawthorne 01/01/14 12/31/14 07/02/14 04/15/15 567, ,819,896 Hesperia 01/01/14 12/31/14 07/02/14 04/15/15 843, ,975,067 Highland 01/01/14 12/31/14 07/02/14 04/15/15 313, ,045,139 Indian Wells 01/01/14 12/31/14 07/02/14 04/15/15 306, ,077,439 Industry 01/01/14 12/31/14 07/02/14 04/15/15 1,312, ,666,560 Inyo County 01/01/14 12/31/14 07/02/14 04/15/15 97, ,897,841 Irvine 01/01/14 12/31/14 07/02/14 04/15/15 3,975, ,140,911,961 Irwindale 01/01/14 12/31/14 07/02/14 04/15/15 360, ,494,286 Jurupa Valley 01/01/15 03/31/15 02/14/15 03/31/15 248, ,054,875 Jurupa Valley 04/01/15 06/30/15 05/16/15 06/30/15 192, ,644,046 Jurupa Valley 07/01/15 09/30/15 08/15/15 09/30/15 192, ,740,091 Jurupa Valley 10/01/15 12/31/15 11/15/15 12/31/ , ,740,091 Kern County 01/01/14 12/31/14 07/02/14 4/10/2015 1,742, ,515,868 La Canada Flintridge 01/01/14 12/31/14 07/02/14 4/15/ , ,673,853 La Habra 01/01/14 12/31/14 07/02/14 4/15/ , ,399,851 La Habra Heights 01/01/14 12/31/14 07/02/14 04/15/15 65, ,671,402 La Mirada 01/01/14 12/31/14 07/02/14 04/15/15 441, ,594,750 La Palma 01/01/14 12/31/14 07/02/14 04/15/15 137, ,437,006 La Puente 01/01/14 12/31/14 07/02/14 04/15/15 178, ,142,169 Laguna Beach 01/01/14 12/31/14 07/02/14 04/15/15 246, ,730,275 Laguna Hills 01/01/15 03/31/15 02/14/15 03/31/15 70, ,135,187 Laguna Hills 04/01/15 06/30/15 05/16/15 06/30/15 54, ,446,622 Laguna Hills 07/01/15 09/30/15 08/15/15 09/30/15 54, ,473,807 Laguna Hills 10/01/15 12/31/15 11/15/15 12/31/ , ,473,807 Laguna Niguel 01/01/15 03/31/15 02/14/15 3/31/ , ,773,501 Laguna Niguel 04/01/15 06/30/15 05/16/15 6/30/ , ,593,328 Laguna Niguel 07/01/15 09/30/15 08/15/15 9/30/ , ,611,032 Laguna Niguel 10/01/15 12/31/15 11/15/15 12/31/ , ,611,032 Laguna Woods 01/01/14 12/31/14 07/02/14 4/15/ , ,049,925 Lake Forest 01/01/15 03/31/15 02/14/15 3/31/ , ,590,615 Lake Forest 04/01/15 06/30/15 05/16/15 6/30/ , ,250,121 Lake Forest 07/01/15 09/30/15 08/15/15 09/30/15 227, ,364,011 Lake Forest 10/01/15 12/31/15 11/15/15 12/31/ , ,364,011 Lakewood 01/01/14 12/31/14 07/02/14 4/15/ , ,587,085 Lancaster 01/01/14 12/31/14 07/02/14 4/15/2015 1,123, ,568,475 Lawndale 01/01/14 12/31/14 07/02/14 4/15/ , ,552,438 Loma Linda 01/01/14 12/31/14 07/02/14 04/15/15 221, ,447,971 Lomita 01/01/14 12/31/14 07/02/14 04/15/15 111, ,986,563 Los Alamitos 01/01/14 12/31/14 07/02/14 04/15/15 231, ,481,067 Los Angeles County 01/01/14 12/31/14 07/02/14 03/31/15 6,885, ,872,940,440 Lynwood 01/01/14 12/31/14 07/02/14 04/15/15 324, ,233,124 Malibu 01/01/14 12/31/14 07/02/14 04/15/15 344, ,823,089 Mammoth Lakes 01/01/14 12/31/14 07/02/14 04/15/15 195, ,045,613 Manhattan Beach 01/01/14 12/31/14 07/02/14 04/15/15 453, ,282,697 Maywood 01/01/14 12/31/14 07/02/14 04/15/15 91, ,330,981

143 142 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS SCHEDULE Act - 1% Municipalities Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag McFarland 01/01/14 12/31/14 07/02/14 04/15/15 10, ,905,993 Menifee 01/01/14 12/31/14 07/02/14 04/15/15 666, ,405,036 Mission Viejo 01/01/15 03/31/15 02/14/15 03/31/15 154, ,895,068 Mission Viejo 04/01/15 06/30/15 05/16/15 06/30/15 127, ,729,416 Mission Viejo 07/01/15 09/30/15 08/15/15 09/30/15 127, ,793,076 Mission Viejo 10/01/15 12/31/15 11/15/15 12/31/ , ,793,076 Montclair 01/01/14 12/31/14 07/02/14 4/15/ , ,407,202 Montebello 01/01/14 12/31/14 07/02/14 4/15/ , ,872,695 Monterey Park 01/01/14 12/31/14 07/02/14 4/15/ , ,531,090 Moorpark 01/01/14 12/31/14 07/02/14 04/15/15 313, ,855,685 Moreno Valley 01/01/14 12/31/14 07/02/14 04/15/15 1,057, ,409,498 Murrieta 01/01/14 12/31/14 07/02/14 04/15/15 840, ,258,003 Norco 01/01/14 12/31/14 07/02/14 04/15/15 280, ,598,902 Norwalk 01/01/14 12/31/14 07/02/14 04/15/15 540, ,156,453 Ojai 01/01/14 12/31/14 07/02/14 04/15/15 91, ,233,792 Palm Desert 01/01/14 12/31/14 07/02/14 04/15/15 1,183, ,691,762 Palm Springs 01/01/14 12/31/14 07/02/14 04/15/15 1,024, ,133,953 Palmdale 01/01/14 12/31/14 07/02/14 04/15/15 1,138, ,610,853 Palos Verdes Estates 01/01/14 12/31/14 07/02/14 04/15/15 130, ,324,648 Paramount 01/01/14 12/31/14 07/02/14 04/15/15 418, ,134,773 Perris 01/01/14 12/31/14 07/02/14 04/15/15 483, ,778,066 Pico Rivera 01/01/14 12/31/14 07/02/14 04/15/15 408, ,169,914 Placentia 01/01/14 12/31/14 07/02/14 04/15/15 441, ,728,208 Port Hueneme 01/01/14 12/31/14 07/02/14 04/15/15 140, ,325,985 Rancho Cucamonga 01/01/14 12/31/14 07/02/14 04/15/15 2,190, ,587,216 Rancho Mirage 01/01/14 12/31/14 07/02/14 04/15/15 628, ,414,520 Rancho Palos Verdes 01/01/14 12/31/14 07/02/14 04/15/15 338, ,072,469 Rancho Santa Margarita 01/01/14 12/31/14 07/02/14 04/15/15 432, ,001,031 Rialto 01/01/14 12/31/14 07/02/14 04/15/15 752, ,070,613 Ridgecrest 01/01/14 12/31/14 07/02/14 04/15/15 303, ,085,704 Riverside City 01/01/14 12/31/14 07/02/14 04/15/15 41, ,918,120 Riverside County 01/01/14 12/31/14 07/02/14 04/15/15 3,384, ,487,225 Rolling Hills Estates 01/01/14 12/31/14 07/02/14 04/15/15 113, ,582,791 Rosemead 01/01/14 12/31/14 07/02/14 04/15/15 285, ,805,765 San Bernardino County 01/01/14 12/31/14 07/02/14 04/15/15 3,724, ,068,925,203 San Buenaventura 01/01/15 03/31/15 02/14/15 03/31/15 247, ,034,935 San Buenaventura 04/01/15 06/30/15 05/16/15 06/30/15 224, ,096,619 San Buenaventura 07/01/15 09/30/15 08/15/15 9/30/ , ,208,804 San Buenaventura 10/01/15 12/31/15 11/15/15 12/31/ , ,208,804 San Dimas 01/01/14 12/31/14 07/02/14 4/15/ , ,046,717 San Gabriel 01/01/14 12/31/14 07/02/14 4/15/ , ,991,937 San Jacinto 01/01/14 12/31/14 07/02/14 04/15/15 338, ,242,101 San Marino 01/01/14 12/31/14 07/02/14 04/15/15 161, ,375,268 Santa Barbara (CITY) 10/01/14 12/31/14 11/15/14 02/21/15 190, ,565,140 Santa Barbara (CITY) 01/01/15 03/31/15 02/14/15 05/18/15 190, ,613,081 Santa Barbara (CITY) 04/01/15 06/30/15 05/16/15 08/13/15 190, ,946,640 Santa Barbara (CITY) 07/01/15 09/30/15 08/15/15 11/14/ , ,232,258 Santa Barbara (COUNTY) 01/01/15 03/31/15 02/14/15 3/31/ , ,437,386 Santa Barbara (COUNTY) 04/01/15 06/30/15 05/16/15 6/30/ , ,801,942 Santa Barbara (COUNTY) 07/01/15 09/30/15 08/15/15 9/30/ , ,899,742 Santa Barbara (COUNTY) 10/01/15 12/31/15 11/15/15 12/31/15 195, ,899,742 Santa Clarita 01/01/14 12/31/14 07/02/14 04/15/15 2,146, ,942,895 Santa Fe Springs 01/01/14 12/31/14 07/02/14 04/15/15 1,216, ,169,449 Seal Beach 01/01/14 12/31/14 07/02/14 04/15/15 278, ,799,730 Signal Hill 01/01/14 12/31/14 07/02/14 04/15/15 207, ,654,193 Simi Valley 01/01/14 12/31/14 07/02/14 04/15/15 1,124, ,712,865 South El Monte 01/01/14 12/31/14 07/02/14 04/15/15 272, ,238,413 South Gate 01/01/14 12/31/14 07/02/14 04/15/15 600, ,254,100 Stanton 01/01/14 12/31/14 07/02/14 04/15/15 198, ,848,412 Tehachapi 01/01/14 12/31/14 07/02/14 04/15/15 88, ,423,493 Temecula 01/01/15 03/31/15 02/14/15 3/31/ , ,544,808 Temecula 04/01/15 06/30/15 05/16/15 6/30/ , ,752,982 Temecula 07/01/15 09/30/15 08/15/15 9/30/ , ,883,570 Temecula 10/01/15 12/31/15 11/15/15 12/31/ , ,883,570 Temple City 01/01/14 12/31/14 07/02/14 04/15/15 190, ,797,622 Thousand Oaks 01/01/14 12/31/14 07/02/14 04/15/15 1,610, ,118,543 Torrance 01/01/14 12/31/14 07/02/14 04/15/15 2,325, ,388,649 Tustin 01/01/14 12/31/14 07/02/14 04/15/15 809, ,328,403 Twentynine Palms 01/01/14 12/31/14 07/02/14 04/15/15 126, ,224,311 Ventura (COUNTY) 01/01/14 12/31/14 07/02/14 04/15/15 1,521, ,792,458 Vernon 01/01/14 12/31/14 07/02/14 04/15/15 15, ,316,773 Victorville 01/01/14 12/31/14 07/02/14 04/15/15 1,166, ,714,301 Villa Park 01/01/14 12/31/14 07/02/14 04/15/15 86, ,776,810 Walnut 01/01/14 12/31/14 07/02/14 04/15/15 231, ,309,447 West Covina 01/01/14 12/31/14 07/02/14 04/15/15 799, ,324,486 West Hollywood 01/01/14 12/31/14 07/02/14 04/15/15 506, ,286,185 Westlake Village 01/01/14 12/31/14 07/02/14 04/15/15 207, ,427,047 Westminster 01/01/14 12/31/14 07/02/14 04/15/15 583, ,562,697 Wildomar 01/01/14 12/31/14 07/02/14 04/15/15 307, ,376,229 Woodlake 01/01/14 12/31/14 07/02/14 04/15/15 36, ,518,972 Yorba Linda 01/01/14 12/31/14 07/02/14 04/15/15 695, ,716,690 Yucaipa 01/01/14 12/31/14 07/02/14 04/15/15 347, ,731,085 Yucca Valley 01/01/14 12/31/14 07/02/14 04/15/15 180, ,717,862 Total 94,287, ,360,230,969

144 143 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS SCHEDULE Act -.5% Municipalities Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Alhambra 01/01/14 12/31/14 07/02/14 4/15/ , ,422,153 Arcadia 01/01/14 12/31/14 07/02/14 4/15/ , ,985,101 Chino 01/01/14 12/31/14 07/02/14 4/15/ , ,775,661 Claremont 01/01/14 12/31/14 07/02/14 4/15/ , ,184,929 Compton 01/01/14 12/31/14 07/02/14 4/15/ , ,173,330 Corona 01/01/14 12/31/14 07/02/14 4/15/ , ,091,568 Covina 01/01/14 12/31/14 07/02/14 4/15/ , ,705,759 Delano 01/01/14 12/31/14 07/02/14 4/15/ , ,333,704 Exeter 01/01/14 12/31/14 07/02/14 4/15/ , ,272,022 Fullerton 01/01/14 12/31/14 07/02/14 4/15/ , ,173,060 Hanford 01/01/14 12/31/14 07/02/14 4/15/ , ,056,534 Hemet 01/01/14 12/31/14 07/02/14 4/15/ , ,962,347 Hermosa Beach 01/01/14 12/31/14 07/02/14 4/15/ , ,489,297 Huntington Beach 01/01/14 12/31/14 07/02/14 4/15/ , ,914,303 Huntington Park 01/01/14 12/31/14 07/02/14 4/15/ , ,736,351 Inglewood 01/01/14 12/31/14 07/02/14 4/15/ , ,948,758 La Verne 01/01/14 12/31/14 07/02/14 4/15/ , ,744,686 Lake Elsinore 01/01/14 12/31/14 07/02/14 4/15/ , ,056,838 Lindsay 01/01/14 12/31/14 07/02/14 4/15/ , ,819,239 Monrovia 01/01/14 12/31/14 07/02/14 4/15/ , ,534,295 Newport Beach 01/01/14 12/31/14 07/02/14 4/15/ , ,344,548 Ontario 01/01/14 12/31/14 07/02/14 4/15/2015 1,288, ,697,311 Orange 01/01/14 12/31/14 07/02/14 4/15/ , ,363,857 Oxnard 01/01/14 12/31/14 07/02/14 4/15/ , ,555,912 Pomona 01/01/14 12/31/14 07/02/14 4/15/ , ,858,614 Porterville 01/01/14 12/31/14 07/02/14 4/15/ , ,146,101 Redlands 01/01/14 12/31/14 07/02/14 4/15/ , ,397,009 Redondo Beach 01/01/14 12/31/14 07/02/14 4/15/ , ,502,124 San Bernardino 01/01/14 12/31/14 07/02/14 4/15/2015 1,032, ,305,435 San Fernando 01/01/14 12/31/14 07/02/14 4/15/ , ,724,091 Santa Ana 01/01/14 12/31/14 07/02/14 4/15/2015 1,345, ,053,048 Santa Monica 01/01/14 12/31/14 07/02/14 4/15/ , ,168,392 Santa Paula 01/01/14 12/31/14 07/02/14 4/15/ , ,735,087 Sierra Madre 01/01/14 12/31/14 07/02/14 4/15/ , ,463,649 South Pasadena 01/01/14 12/31/14 07/02/14 4/15/ , ,163,459 Tulare 01/01/14 12/31/14 07/02/14 4/15/ , ,895,064 Upland 01/01/14 12/31/14 07/02/14 4/15/ , ,148,873 Visalia 01/01/14 12/31/14 07/02/14 4/15/ , ,935,040 Whittier 01/01/14 12/31/14 07/02/14 4/15/ , ,308,153 Total 18,213, ,227,145,702

145 144 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS SCHEDULE 6 City of Long Beach Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Long Beach 01/01/15 03/31/15 02/14/15 05/31/15 1,531, ,567,489 Long Beach 04/01/15 06/30/15 05/16/15 08/31/15 1,547, ,544,394 Long Beach 07/01/15 09/30/15 08/15/15 11/30/15 2,248, ,475,729 Long Beach 10/01/14 12/31/14 11/15/ /28/15 1,703, ,001,821 Total 7,030, ,589,433 SCHEDULE 7 City of Los Angeles - Ordinance No Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Los Angeles 01/01/14 12/31/14 07/02/14 03/31/15 262, ,406,161

146 145 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FRANCHISE REQUIREMENTS SCHEDULE 8 City of Avalon - Gas & Water Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Avalon 01/01/14 12/31/14 07/02/14 04/15/15 43, ,508,456 SCHEDULE 9 Miscellaneous Period Period Period Date of Dollar Location Beginning Ending Mid-Point Payment Amount Lag Days Days Lag Los Angeles County - New Mains Laid 01/01/14 12/31/14 07/02/14 03/31/15 1, ,040 Los Angeles County - Application Fee 01/01/14 12/31/14 07/02/14 03/31/15 5, ,360,000 County of San Bernardino - Ordinance Fee 01/01/14 12/31/14 07/02/14 03/31/ ,664 6, ,776,704

147 146 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Provision for Uncollectibles

148 147 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS PROVISIONS FOR UNCOLLECTIBLES NOTES TO WORKPAPERS Provision for non-grc uncollectibles represent accruals for customer receivables that will not be collected and will eventually be written off. The amount is estimated by adding fuel, purchased power and other non-labor expense, and multiplying the sum by the uncollectible rate. Since these accrued expenses are offset in rate base (allowance for doubtful accounts), the expense lag days are zero.

149 148 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Depreciation

150 149 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS DEPRECIATION NOTES TO WORKPAPERS Depreciation expense is included in the lead-lag study to compensate investors for the lag between when the expenses are accrued and the revenues are collected. The provision expense is accrued monthly and the accumulated provision is an immediate offset to Rate Base. Because the monthly depreciation expense is accrued uniformly on a daily basis the associated expense lag days are zero.

151 150 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Decommissioning

152 151 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS DECOMMISSIONING NOTES TO WORKPAPERS The expense lag for decommissioning is the average time between the date SCE has the funds available from the accrued decommissioning contributions and the date the funds are deposited in the nuclear decommissioning trust funds. SCE is not seeking new contributions for SONGS or Palo Verde because the trust funds are sufficient to meet the future costs of decommissioning based on the current forecast. Therefore, the expense lag for nuclear decommissioning contributions is zero days

153 152 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Taxes (Other than Income)

154 153 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS TAXES - OTHER THAN INCOME NOTES TO WORKPAPERS The Workpapers detailing the development of the Expense Lag for Taxes - Other Than Income are separated into the following sections: Ad Valorem Taxes Property Taxes based on the assessed valuation of Company property. Federal Insurance Contributions Act (F.I.C.A.) Taxes based on Taxable Wages to cover Social Security and Medicare for the Company's employees. Results Sharing FICA expenses are included in the Results Sharing expenses. Federal Unemployment Taxes Act (F.U.T.A.) Taxes based on Taxable Wages to cover Federal Unemployment for the Company's employees. State Unemployment Insurance Taxes (S.U.I.) Taxes based on Taxable Wages to cover State Unemployment for the Company's employees. State Employment Training Taxes Taxes based on Taxable Wages to cover State Employment Training for the Company's employees. Miscellaneous Taxes include miscellaneous state taxes not provided for elsewhere such as Nevada and Arizona franchise tax, sales tax permits, sales tax breakage, and gross operating revenue tax. Miscellaneous Local Taxes include amounts paid to operators of shared-cost projects for Edison's share of local taxes other than income, city licenses, city use tax, city sales tax permits, city business licenses and credits for operating taxes charged to non-utility or utility affiliates.

155 154 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY TAXES - OTHER THAN INCOME Amount Lag Days Lag $ Ad Valorem - Arizona 9,383, ,722,385 Ad Valorem - California 268,321, ,978,056,616 Ad Valorem - Nevada 1,268,465 (38.5) (48,781,816) Total Ad Valorem 278,973, ,236,997,185 Federal Insurance Contribution Act (F.I.C.A.) 119,296, ,793,860,798 Federal Unemployment Taxes Act (F.U.T.A.) 2,040, ,647,781 State Unemployment Insurance Act (S.U.I.) 6,507, ,780,694 Total Taxable Wage Taxes 127,843, ,408,289,272 Total Weighted 406,817, ,645,286,457

156 155 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY TAXES - OTHER THAN INCOME AD VALOREM TAXES California General Ledger Account Type of Period Period Period Date of Dollar Payment Beginning Ending Mid-Point Payment Amount Lag Days Days Lag 1st 7/1/2014 6/30/ /30/2014 4/10/ ,549, ,973,488,996 2nd 7/1/2015 6/30/ /30/ /10/ ,771,619 (20.0) (2,995,432,380) 268,321, ,978,056,616 Arizona General Ledger Account Type of Period Period Period Date of Dollar Payment Beginning Ending Mid-Point Payment Amount Lag Days Days Lag 1st 7/1/2014 6/30/ /30/2014 5/1/2015 4,758, ,595,438 2nd 7/1/2015 6/30/ /30/ /1/2015 4,624,967 (59.0) (272,873,053) 9,383, ,722,385 Nevada General Ledger Account Type of Period Period Period Date of Dollar Payment Beginning Ending Mid-Point Payment Amount Lag Days Days Lag 1st 7/1/2014 6/30/ /30/2014 1/2/ , ,024 2nd 7/1/2014 6/30/ /30/2014 3/5/ , ,627,177 3rd 7/1/2015 6/30/ /30/2015 8/20/ ,156 (132.0) (41,864,653) 4th 7/1/2015 6/30/ /30/ /1/ ,626 (90.0) (28,496,364) 1,268,465 (38.5) (48,781,816) Total Weighted Average 278,973, ,236,997,185

157 156 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH LEAD-LAG STUDY 2018 GRC TAXES - OTHER THAN INCOME F.I.C.A. Payroll Cycle Period Beginning Period Ending Period Mid-Point Date of Payment Amount Lag Days Dollar Days Lag STIP Amount 12/15/14 12/28/14 12/21/14 01/05/15 5,489, ,340,647 12/29/14 01/11/15 01/04/15 01/20/15 5,156, ,496,473 01/12/15 01/25/15 01/18/15 02/02/15 6,295, ,438,785 01/26/15 02/08/15 02/01/15 02/17/15 5,024, ,397,467 02/09/15 02/22/15 02/15/15 03/02/15 5,321, ,817,531 02/23/15 03/08/15 03/01/15 03/16/15 6,312, ,693,887 13,347,380 03/09/15 03/22/15 03/15/15 03/30/15 5,070, ,054,510 03/23/15 04/05/15 03/29/15 04/13/15 4,902, ,537,144 04/06/15 04/19/15 04/12/15 04/27/15 4,958, ,383,449 04/20/15 05/03/15 04/26/15 05/11/15 4,875, ,129,917 05/04/15 05/17/15 05/10/15 05/26/15 4,836, ,391,131 05/18/15 05/31/15 05/24/15 06/08/15 4,753, ,307,216 06/01/15 06/14/15 06/07/15 06/22/15 4,701, ,519,330 06/15/15 06/28/15 06/21/15 07/03/15 4,815, ,786,574 06/29/15 07/12/15 07/05/15 07/20/15 4,502, ,535,321 07/13/15 07/26/15 07/19/15 08/03/15 4,806, ,103,956 07/27/15 08/09/15 08/02/15 08/17/15 4,322, ,844,546 08/10/15 08/23/15 08/16/15 08/31/15 4,214, ,213,903 08/24/15 09/06/15 08/30/15 09/14/15 3,936, ,051,095 09/07/15 09/20/15 09/13/15 09/28/15 4,028, ,420,773 09/21/15 10/04/15 09/27/15 10/13/15 3,848, ,577,191 10/05/15 10/18/15 10/11/15 10/26/15 3,707, ,615,442 10/19/15 11/01/15 10/25/15 11/09/15 3,486, ,296,213 11/02/15 11/15/15 11/08/15 11/23/15 3,419, ,288,287 11/16/15 11/29/15 11/22/15 12/07/15 3,353, ,300,615 11/30/15 12/13/15 12/06/15 12/21/15 3,154, ,319, ,296, ,793,860,798

158 157 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY 2018 GRC TAXES - OTHER THAN INCOME Federal Unemployment Insurance Tax General Ledger Account Period Beginning Period Ending Period Mid- Point Date of Payment Amount Lag Days Dollar Days Lag 10/01/14 12/31/14 11/15/14 01/27/15 1,419, ,648,351 01/01/15 03/31/15 02/14/15 04/28/15 600, ,566,279 04/01/15 06/30/15 05/16/15 07/23/15 8, ,547 07/01/15 09/30/15 08/15/15 10/29/15 11, ,604 2,040, ,647,781 State Unemployment Insurance Tax California (Including Training Tax) General Ledger Account Period Beginning Period Ending Period Mid- Point Date of Payment Amount Lag Days Dollar Days Lag 10/01/14 12/31/14 11/15/14 01/27/15 103, ,540,147 01/01/15 03/31/15 02/14/15 04/27/15 6,203, ,520,151 04/01/15 06/30/15 05/16/15 07/27/15 82, ,956,546 07/01/15 09/30/15 08/15/15 10/29/15 116, ,663,650 6,505, ,680,495 DC General Ledger Account Period Beginning Period Ending Period Mid- Point Date of Payment Amount Lag Days Dollar Days Lag 01/01/15 03/31/15 02/14/15 04/17/ , ,052 Nevada General Ledger Account Period Beginning Period Ending Period Mid- Point Date of Payment Amount Lag Days Dollar Days Lag 10/01/14 12/31/14 11/15/14 01/19/ ,978 01/01/15 03/31/15 02/14/15 04/17/15 1, ,283 04/01/15 06/30/15 05/16/15 07/16/ ,304 07/01/15 09/30/15 08/15/15 10/07/ ,583 1, ,148 State Unemployment Insurance Tax Summary General Ledger Account General Ledger Account Description Amount Lag Days Dollar Days Lag California SUI Tax(Including Training Tax) 6,505, ,680, DC SUI TAX , Nevada SUI Tax 1, ,148 6,507, ,780,694

159 158 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Taxes (Income)

160 159 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS TAXES - BASED ON INCOME NOTES TO WORKPAPERS The expense lag for Income Taxes represents the period from when the current tax expenses are accrued to the time they are due under the law. The Workpapers detailing the development of the Expense Lag for Taxes Based on Income are separated into the following sections: Federal Income Tax California State Corporation Franchise Tax The Income Tax Deferred lag is zero for utilities that use accelerated depreciation to reduce income taxes because accumulated deferred taxes are an offset to Rate Base.

161 160 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY FEDERAL INCOME TAX LAG DAYS ANALYSIS Accrual Midpoint 4/15/15 6/15/15 9/15/15 12/15/15 7/13/2015 (89) (28) Required %'s 25% 25% 25% 25% (22.25) (7.00) Proposed Lag (Days) 25.50

162 161 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY CALIFORNIA INCOME TAX LAG DAYS ANALYSIS Accrual Midpoint 4/15/15 6/15/15 9/15/15 12/15/15 7/13/2015 (89) (28) Required %'s 30% 40% 0% 30% (26.70) (11.20) PROPOSED LAG 8.60

163 162 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Working Capital Lead-Lag Study Expense Lags Other O&M Expenses

164 163 WORKING CASH LEAD-LAG STUDY EXPENSE LAGS Other O&M Expenses NOTES TO WORKPAPERS Other O&M expenses represent non-labor expenses associated with balancing accounts. The purpose of this item is to include the balancing accounts expense lag to compensate investors for the time between the recording of utility costs and payment of those costs. We determined the associated working cash requirement using a three-year average of recorded expenses.

165 164 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY NON GRC EXPENSES Average Amount O&M EXPENSE NON ISO RELATED CHARGES: LABOR NON-LABOR TOTAL Public Purpose Programs Adjustment Mechanism - Intervenor Compensation - 2,579 2,579 Public Purpose Programs Adjustment Mechanism - Cool Center California Solar Initiative 1, , ,340 California Solar Initiative M&E Memorandum Account - (262) (262) CARE 1,763 3,114 4,876 Demand Response 9,106 32,649 41,755 Demand Response Capacity Contracts (BRRBA) - 9,260 9,260 Demand Response Capacity Energy (BRRBA) Demand Response Audit Demand Response Audit Demand Response Audit Demand Response Audit - 3,792 3,792 Demand Response Audit Department of Energy Litigation Memorandum Account Electric Program Investment Charge 1,241 4,027 5,268 Energy Efficiency Program Energy Settlement - 37,893 37,893 Hazardous Waste (9) 2,941 2,932 Hydrogen Energy California Memorandum Account Long Term Procurement Plan Technical Assistance Memorandum Account Low Income Energy Efficiency Program Adjustment Mechanism 2,449 51,885 54,333 New System Generation - 399, ,218 Procurement Energy Efficiency 42, , ,474 Purchase Agreement Admin Costs 970 (692) 278 Renewable Portfolio Standard Costs Memorandum Account Self-Generation Program Incremental Cost MA ,873 17,214 Smart Grid "American Recovery & Reinvestment Act" Memo Acct 341 1,996 2,337 Greenhouse Gas Customer Outreach & Education Memo Account (P9144) Greenhouse Gas Admin Cost Memo Account (P9145) Statewide Marketing, Education & Outreach Balancing Account (9147) 50 9,534 9,584 Agricultural Account Aggregation Study Memo Account (P9148) On-Bill Financing Balancing Account Research, Development and Design 124 2,247 2,371 RSDMA Mobilehome Park Master Meter Balancing Account MMMBA Net Energy Metering Aggregation Billing Service Memorandum Account Fire Hazard Program Memorandum Account (0) NEM Online Application System Memorandum Account 3-3 Green Tariff Marketing, Education & Outreach Memorandum Acct Green Tariff Shared Renewables Administrative Costs Memo Acct Residential Rate Implementation Memo (Tracking) CEMA - Drought 6 2,647 2,653 Aggregator Managed Portfolio Program Energy 408 (352) 56 CEMA - Bark Beetle 26 4,439 4,465 TOTAL NON ISO EXPENSE $ 61,826 $ 956,063 $ 1,017,889 ISO CHARGES: Reliability Services Balancing Account - (20,518) (20,518) Transmission Access Charge Balancing Account (2) 51,857 51,855 Transmission Revenue Balancing Account - 7,256 7,256 TOTAL ISO EXPENSE $ (2) $ 38,595 $ 38,593

166 165 SOUTHERN CALIFORNIA EDISON COMPANY WORKING CASH CAPITAL LEAD-LAG STUDY Other O&M Expenses Recorded Forecasted Non-GRC Expenses Non-ISO Expenses Labor 61,826 63,545 65,473 67,322 69,202 71,095 Non-Labor 956, , ,406 1,004,449 1,025,732 1,047,096 Total Non-ISO 1,017,889 1,027,685 1,048,879 1,071,771 1,094,935 1,118,190 ISO Expenses Labor Non-Labor 38,595 38,594 39,323 40,219 41,167 42,066 Total ISO 38,595 38,594 39,323 40,219 41,167 42,066 Total Non-GRC Expense 1,056,484 1,066,279 1,088,202 1,111,990 1,136,102 1,160,257

167 166 SCE-09 Results of Operations - Vol.02, Results of Operations Plant, Taxes, Depreciation Expense and Reserve, & Rate Base Chapter IV: Rate Base Witness: John McCarson Deductions for Reserves Unfunded Pension Reserve

168 167 WORKING CASH Deductions for Reserves Unfunded Pensions Reserves NOTES TO WORKPAPERS SCE does not have the use of most of SCE s pension reserves as they are held in external trust funds. The Unfunded Pension Reserve represents the unfunded portion of accumulated provision for employee retirement benefits. The balance is a liability to SCE until paid out. It consists of several accounts representing ongoing pension reserves. A forecast for 2016 through 2020 was made based upon actuarial determinations of pension accruals and payouts. A portion of these pension reserves are for shared EIX officers. In the case of the shared officers, utility customers are only responsible for 75 percent of the pension accruals, with the balance being recorded to nonutility operations. Removing these portions of the reserves, not recovered from customers, leaves 98.9 percent of the total unfunded pension reserves as a rate base offset. However, since for tax purposes, the revenues for Unfunded Pension Reserve accruals are taxed immediately upon receipt, whereas a tax deduction is taken only when payment is made, the full amount is unavailable to the company. As a result of this timing difference, SCE only holds about 60 percent of the accrual amount (i.e. it has been reduced for taxes paid). The after tax rate base offset for Unfunded Pension Reserve is shown in SCE-9, Volume 2, Chapter IV.

169 168 Southern California Edison Unfunded Pension Reserves End of Year Balances ($000's) Line Recorded Forecast No. Item Pre-Tax 139, , , , , ,162 2 Less: Taxes (56,058) (49,974) (50,974) (53,826) (55,711) (55,888) 3 After-Tax 83,012 72,674 74,128 78,275 81,016 81,274 Average Balances ($000's) Line Recorded Forecast No. Item Pre-Tax 142, , , , , ,944 2 Less: Tax (56,058) (53,016) (50,474) (52,400) (54,768) (55,799) 3 After-Tax 85,229 77,843 73,401 76,201 79,645 81,145

170 169 Southern California Edison Company Rate Base Deductions for Reserve Unfunded Pension Reserve (Adjusted for Income Tax) Month Total December-14 (83,419,973) January-15 (83,994,043) February-15 (84,658,438) March-15 (85,439,674) April-15 (86,104,072) May-15 (86,768,473) June-15 (85,226,511) July-15 (85,821,270) August-15 (86,555,327) September-15 (84,960,581) October-15 (85,555,357) November-15 (84,442,484) December-15 (83,012,079) 13 Month Total (1,105,958,281) Less 1/2 First Month (41,709,986) Less 1/2 Last Month (41,506,039) 12 Month Total (1,022,742,255) Weighted Average (85,228,521) (85,228.52)

171 170 Unfunded Pension Reserve Recorded 2015 Balance RECORDED: ACCOUNT ACCOUNT TITLE EXECUTIVE RETIREMENT PLAN SPECIAL PENSION PROV-ACCRUAL EMPLMT AGRMT SURV BNFT SPECIAL PEN PROV-SURV BEN-JFD EXEC SURVIVOR BENEFIT SURVIVOR INCOME CONTINUATION EXEC 1985 DEF COMP DEATH BNFT SUPPL SURV INC/RETIR INC SUPPLEMENTAL LTD Grand Total RECORDED ADJUSTED FOR EIX FUNDED SHARE: ACCOUNT ACCOUNT TITLE SCE Forecast Share EXECUTIVE RETIREMENT PLAN 98.8% SPECIAL PENSION PROV-ACCRUAL 100% EMPLMT AGRMT SURV BNFT 100% SPECIAL PEN PROV-SURV BEN-JFD 100% EXEC SURVIVOR BENEFIT 0.0% SURVIVOR INCOME CONTINUATION 100% EXEC 1985 DEF COMP DEATH BNFT 99.5% SUPPL SURV INC/RETIR INC 100% SUPPLEMENTAL LTD 100% Grand Total 98.7% RECORDED ADJUSTED FOR EIX SHARE & DEFERRED TAXES ACCOUNT ACCOUNT TITLE Tax Rate EXECUTIVE RETIREMENT PLAN % SPECIAL PENSION PROV-ACCRUAL % EMPLMT AGRMT SURV BNFT % SPECIAL PEN PROV-SURV BEN-JFD % EXEC SURVIVOR BENEFIT % SURVIVOR INCOME CONTINUATION % EXEC 1985 DEF COMP DEATH BNFT % SUPPL SURV INC/RETIR INC % SUPPLEMENTAL LTD % Grand Total Grand Total EOP (000) Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 (122,511,763) (123,700,204) (124,888,645) (126,157,178) (127,345,619) (128,534,060) (125,976,984) (61,853) (61,853) (61,853) (61,853) (61,853) (61,853) (61,853) (26,357) (24,346) (23,834) (24,801) (24,293) (23,790) (23,292) (993) (993) (993) (993) (993) (993) (993) 1,088,421 1,086,951 1,085,481 1,084,011 1,082,541 1,081,071 1,079,601 (7,929,228) (7,897,832) (7,893,479) (7,916,171) (7,911,819) (7,907,467) (7,903,115) (7,795,311) (7,734,622) (7,710,849) (7,723,991) (7,700,218) (7,676,444) (7,652,671) (4,147,448) (4,028,753) (3,996,069) (4,014,794) (3,982,109) (3,949,424) (3,916,739) (141,384,532) (142,361,652) (143,490,241) (144,815,769) (145,944,363) (147,072,960) (144,456,046) Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 (120,902,293) (122,075,121) (123,247,949) (124,499,816) (125,672,644) (126,845,473) (124,321,990) (61,853) (61,853) (61,853) (61,853) (61,853) (61,853) (61,853) (26,357) (24,346) (23,834) (24,801) (24,293) (23,790) (23,292) (993) (993) (993) (993) (993) (993) (993) 1,079,560 1,078,102 1,076,644 1,075,186 1,073,728 1,072,270 1,070,812 (7,929,228) (7,897,832) (7,893,479) (7,916,171) (7,911,819) (7,907,467) (7,903,115) (7,764,405) (7,703,957) (7,680,278) (7,693,368) (7,669,689) (7,646,010) (7,622,331) (4,147,448) (4,028,753) (3,996,069) (4,014,794) (3,982,109) (3,949,424) (3,916,739) (139,753,016) (140,714,752) (141,827,810) (143,136,610) (144,249,672) (145,362,739) (142,779,500) Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 (72,167,788) (72,867,860) (73,567,933) (74,315,185) (75,015,258) (75,715,331) (74,209,039) (36,920) (36,920) (36,920) (36,920) (36,920) (36,920) (36,920) (15,733) (14,532) (14,227) (14,804) (14,501) (14,201) (13,903) (593) (593) (593) (593) (593) (593) (593) 644, , , , , , ,179 (4,733,035) (4,714,295) (4,711,697) (4,725,242) (4,722,644) (4,720,046) (4,717,448) (4,634,651) (4,598,569) (4,584,435) (4,592,248) (4,578,114) (4,563,980) (4,549,846) (2,475,653) (2,404,803) (2,385,293) (2,396,470) (2,376,961) (2,357,451) (2,337,941) (83,419,973) (83,994,043) (84,658,438) (85,439,674) (86,104,072) (86,768,473) (85,226,511) (83,420.0) (83,994.0) (84,658.4) (85,439.7) (86,104.1) (86,768.5) (85,226.5)

172 171 Unfunded Pension Reserve Recorded 2015 Balance RECORDED: ACCOUNT ACCOUNT TITLE EXECUTIVE RETIREMENT PLAN SPECIAL PENSION PROV-ACCRUAL EMPLMT AGRMT SURV BNFT SPECIAL PEN PROV-SURV BEN-JFD EXEC SURVIVOR BENEFIT SURVIVOR INCOME CONTINUATION EXEC 1985 DEF COMP DEATH BNFT SUPPL SURV INC/RETIR INC SUPPLEMENTAL LTD Grand Total RECORDED ADJUSTED FOR EIX FUNDED SHARE: ACCOUNT ACCOUNT TITLE SCE Forecast Share EXECUTIVE RETIREMENT PLAN 98.8% SPECIAL PENSION PROV-ACCRUAL 100% EMPLMT AGRMT SURV BNFT 100% SPECIAL PEN PROV-SURV BEN-JFD 100% EXEC SURVIVOR BENEFIT 0.0% SURVIVOR INCOME CONTINUATION 100% EXEC 1985 DEF COMP DEATH BNFT 99.5% SUPPL SURV INC/RETIR INC 100% SUPPLEMENTAL LTD 100% Grand Total 98.7% RECORDED ADJUSTED FOR EIX SHARE & DEFERRED TAXES ACCOUNT ACCOUNT TITLE Tax Rate EXECUTIVE RETIREMENT PLAN % SPECIAL PENSION PROV-ACCRUAL % EMPLMT AGRMT SURV BNFT % SPECIAL PEN PROV-SURV BEN-JFD % EXEC SURVIVOR BENEFIT % SURVIVOR INCOME CONTINUATION % EXEC 1985 DEF COMP DEATH BNFT % SUPPL SURV INC/RETIR INC % SUPPLEMENTAL LTD % Grand Total Grand Total EOP (000) Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Average (127,165,425) (128,353,866) (125,707,170) (126,895,611) (125,011,389) (122,460,802) (126,018,536) (61,853) (61,853) (61,853) (61,853) 0 0 (54,121) (21,341) (22,308) (21,824) (19,901) (20,868) (20,704) (22,844) (993) (993) (993) (993) (993) (993) (993) 1,078,131 1,076,661 1,075,191 1,073,721 1,072,251 1,070,781 1,079,601 (7,871,719) (7,894,411) (7,890,059) (7,858,662) (7,881,354) (7,900,915) (7,895,097) (7,591,982) (7,605,124) (7,581,351) (7,520,663) (7,533,805) (7,545,726) (7,641,853) (3,832,644) (3,851,369) (3,818,684) (3,734,590) (3,753,315) (3,841,314) (3,906,073) (145,467,826) (146,713,263) (144,006,742) (145,018,551) (143,129,472) (140,699,673) (144,459,916) Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Average (125,494,818) (126,667,646) (124,055,720) (125,228,548) (123,369,080) (120,852,001) (124,362,996) (61,853) (61,853) (61,853) (61,853) 0 0 (54,121) (21,341) (22,308) (21,824) (19,901) (20,868) (20,704) (22,844) (993) (993) (993) (993) (993) (993) (993) 1,069,354 1,067,896 1,066,438 1,064,980 1,063,522 1,062,064 1,070,812 (7,871,719) (7,894,411) (7,890,059) (7,858,662) (7,881,354) (7,900,915) (7,895,097) (7,561,883) (7,574,973) (7,551,294) (7,490,846) (7,503,936) (7,515,810) (7,611,556) (3,832,644) (3,851,369) (3,818,684) (3,734,590) (3,753,315) (3,841,314) (3,906,073) (143,775,897) (145,005,657) (142,333,988) (143,330,413) (141,466,024) (139,069,673) (142,782,867) Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Average (74,909,112) (75,609,185) (74,050,100) (74,750,173) (73,640,238) (72,137,768) (74,233,516) (36,920) (36,920) (36,920) (36,920) 0 0 (32,305) (12,739) (13,316) (13,027) (11,879) (12,456) (12,358) (13,636) (593) (593) (593) (593) (593) (593) (593) 638, , , , , , ,179 (4,698,708) (4,712,253) (4,709,655) (4,690,914) (4,704,459) (4,716,135) (4,712,662) (4,513,764) (4,521,577) (4,507,443) (4,471,361) (4,479,174) (4,486,262) (4,543,414) (2,287,744) (2,298,921) (2,279,411) (2,229,214) (2,240,391) (2,292,919) (2,331,574) (85,821,270) (86,555,327) (84,960,581) (85,555,357) (84,442,484) (83,012,079) (85,228,521) (85,821.3) (86,555.3) (84,960.6) (85,555.4) (84,442.5) (83,012.1)

173 172 Unfunded Pension Reserve Recorded 2015 Balance RECORDED: ACCOUNT ACCOUNT TITLE EXECUTIVE RETIREMENT PLAN SPECIAL PENSION PROV-ACCRUAL EMPLMT AGRMT SURV BNFT SPECIAL PEN PROV-SURV BEN-JFD EXEC SURVIVOR BENEFIT SURVIVOR INCOME CONTINUATION EXEC 1985 DEF COMP DEATH BNFT SUPPL SURV INC/RETIR INC SUPPLEMENTAL LTD Grand Total RECORDED ADJUSTED FOR EIX FUNDED SHARE: ACCOUNT ACCOUNT TITLE SCE Forecast Share EXECUTIVE RETIREMENT PLAN 98.8% SPECIAL PENSION PROV-ACCRUAL 100% EMPLMT AGRMT SURV BNFT 100% SPECIAL PEN PROV-SURV BEN-JFD 100% EXEC SURVIVOR BENEFIT 0.0% SURVIVOR INCOME CONTINUATION 100% EXEC 1985 DEF COMP DEATH BNFT 99.5% SUPPL SURV INC/RETIR INC 100% SUPPLEMENTAL LTD 100% Grand Total 98.7% RECORDED ADJUSTED FOR EIX SHARE & DEFERRED TAXES ACCOUNT ACCOUNT TITLE Tax Rate EXECUTIVE RETIREMENT PLAN % SPECIAL PENSION PROV-ACCRUAL % EMPLMT AGRMT SURV BNFT % SPECIAL PEN PROV-SURV BEN-JFD % EXEC SURVIVOR BENEFIT % SURVIVOR INCOME CONTINUATION % EXEC 1985 DEF COMP DEATH BNFT % SUPPL SURV INC/RETIR INC % SUPPLEMENTAL LTD % Grand Total Grand Total EOP (000) ACTUARY FORECAST: Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec-20 (122,460,802) (105,996,000) (109,899,000) (117,949,000) (123,505,000) (124,835,000) (20,704) (14,000) (993) ,070, (7,900,915) (7,552,000) (7,189,000) (6,786,000) (6,497,000) (6,189,000) (7,545,726) (7,051,000) (6,545,000) (6,352,000) (6,163,000) (6,001,000) (3,841,314) (3,354,000) (2,832,000) (2,473,000) (2,088,000) (1,678,000) (140,699,673) (123,967,000) (126,465,000) (133,560,000) (138,253,000) (138,703,000) FORECAST ADJUSTED FOR EIX FUNDED SHARE: Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec-20 (120,852,001) (104,712,500) (108,568,239) (116,520,762) (122,009,484) (123,323,380) (20,704) (14,000) (993) ,062, (7,900,915) (7,552,000) (7,189,000) (6,786,000) (6,497,000) (6,189,000) (7,515,810) (7,016,000) (6,512,512) (6,320,470) (6,132,408) (5,971,212) (3,841,314) (3,354,000) (2,832,000) (2,473,000) (2,088,000) (1,678,000) (139,069,673) (122,648,500) (125,101,750) (132,100,231) (136,726,892) (137,161,592) 98.9% FORECAST ADJUSTED FOR EIX SHARE & DEFERRED TAXES Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec-20 (72,137,768) (62,046,345) (64,331,024) (69,043,212) (72,295,500) (73,074,035) (12,358) (8,296) (593) , (4,716,135) (4,474,862) (4,259,770) (4,020,976) (3,849,732) (3,667,230) (4,486,262) (4,157,261) (3,858,924) (3,745,131) (3,633,697) (3,538,182) (2,292,919) (1,987,379) (1,678,073) (1,465,351) (1,237,224) (994,282) (83,012,079) (72,674,142) (74,127,791) (78,274,671) (81,016,153) (81,273,729) (83,012.1) (72,674.1) (74,127.8) (78,274.7) (81,016.2) (81,273.7)

174 173 Projected Accrued Liability for Executive Benefits (per Hewitt Associates projections) SCE Share Executive Benefit Plan Account SCE Shared Total % SCE Shared Total Shared Officer Rate: 100% 75% 100% 75% SCE Share % Executive Retirement Plan ,076,000 6,438, ,514, % 100,862,000 5,134, ,996, % 1963 Employment Agreement , , % 14, , % Survivor Benefit Plan ,842,000 62,000 1,904, % % Survivor Income Continuation Plan ,022, ,022, % 7,552, ,552, % 1985 DCP Survivor Benefit ,571, ,000 7,693, % 6,911, ,000 7,051, % Supplemental Survivor Income/Retirement Income Plan ,202, ,202, % 3,354, ,354, % 135,735,000 6,622, ,357, % 118,693,000 5,274, ,967, %

175 174 Projected Accrued Liability for Executive Benefits (per Hewitt Associates projections) Executive Benefit Plan Account Shared Officer Rate: Executive Retirement Plan Employment Agreement Survivor Benefit Plan Survivor Income Continuation Plan DCP Survivor Benefit Supplemental Survivor Income/Retirement Income Plan SCE Share SCE Shared Total % SCE Shared Total 100% 75% 100% 75% SCE Share % 104,576,000 5,323, ,899, % 112,236,000 5,713, ,949, % % % % % 7,189, ,189, % 6,786, ,786, % 6,415, ,000 6,545, % 6,226, ,000 6,352, % 2,832, ,832, % 2,473, ,473, % 121,012,000 5,453, ,465, % 127,721,000 5,839, ,560, %

176 175 Projected Accrued Liability for Executive Benefits (per Hewitt Associates projections) Executive Benefit Plan Account Shared Officer Rate: Executive Retirement Plan Employment Agreement Survivor Benefit Plan Survivor Income Continuation Plan DCP Survivor Benefit Supplemental Survivor Income/Retirement Income Plan SCE Share SCE Shared Total % SCE Shared Total 100% 75% 100% 75% SCE Share % 117,523,000 5,982, ,505, % 118,789,000 6,046, ,835, % % % % % 6,497, ,497, % 6,189, ,189, % 6,041, ,000 6,163, % 5,882, ,000 6,001, % 2,088, ,088, % 1,678, ,678, % 132,149,000 6,104, ,253, % 132,538,000 6,165, ,703, %

177 176 EXHIBIT SCE-09 VOLUME 2, CHAPTER IV, SECTION C CUSTOMER DEPOSITS WORKPAPERS WITNESS: PAUL T. HUNT, JR.

178 177 PROPOSED REVENUE REQUIREMENT REDUCTION

179 178 CALCULATION OF CUSTOMER DEPOSITS REVENUE REQUIREMENT ADJUSTMENT 2015 Customer Deposits Customer Deposits Year/Month ($) 2014 December 220,326, January 222,483, February 224,683, March 227,789, April 229,690, May 232,302, June 233,544, July 235,564, August 236,710, September 234,198, October 236,769, November 239,167, December 241,489, month average 231,901, percent 208,711,367 Interest Rate Adjustment SCE Embedded Cost of Debt (D ) 5.49% Projected Day Commercial Paper Rate (IHS Global Insight) 1.88% << Difference 3.61% Revenue Requirement Reduction ($) >> 7,534,480

180 179 ADJUSTMENT TO COST OF LONG-TERM DEBT IN RESULTS OF OPERATIONS MODEL Category Amount ($ Millions) Cost Weighted Cost Rate Base Debt Portion of Rate Base Customer Deposits % 0.04% Long-Term Debt % 5.37% 5.41% Adjustment to Cost of Long-Term Debt -0.08%

181 180 IMPACT OF THE RATE BASE OFFSET

182 181 Impact of Customer Deposits and Nuclear Fuel on Ratemaking Capital Structure Assumptions: ($millions) 2015 Recorded Rate Base Customer Deposits (2015 authorized RB offset) Nuclear Fuel (at amortized cost) 131 Sources: Rate Base: Edison International 2015 Financial and Statistical Report, p. 2 Customer Deposits: D , p. 473 Nuclear Fuel: SCE 2015 FERC Form 1, p. 110, 13c (Note: nuclear fuel is for Palo Verde only) Ratemaking Financing With No Customer Deposits Adjustment: Authorized Equivalent Cap Structure Ratebase $ Common Equity 48% Preferred Equity 9% 2214 Long Term Debt 43% Total 100% Ratemaking Financing With Customer Deposits Adjustment: Ratebase less Customer Deposits Authorized Equivalent Adj Ratemaking Difference Cap Structure Ratebase $ Cap Structure Common Equity 48% % -0.35% Preferred Equity 9% % -0.07% Long Term Debt 43% % -0.32% Subtotal 100% Customer Deposits % Total Debt (LTD + Deposits) 43.4% 0.42% Total Ratemaking Financing Ratemaking Financing With Nuclear Fuel Adjustment Ratebase less Nuclear Fuel Authorized Equivalent Adj Ratemaking Difference Cap Structure Ratebase $ Cap Structure Common Equity 48% % -0.26% Preferred Equity 9% % -0.05% Long Term Debt 43% % -0.23% Subtotal 100% Nuclear Fuel (Palo Verde Only) % Total Debt (LTD + Nuclear Fuel) 43.3% 0.35% Total Ratemaking Financing Ratemaking Financing With Both Customer Deposits and Nuclear Fuel Adjustment Ratebase less N Fuel & Cust Dep Authorized Equivalent Adj Ratemaking Difference Cap Structure Ratebase $ Cap Structure Common Equity 48% % -0.61% Preferred Equity 9% % -0.11% Long Term Debt 43% % -0.55% Subtotal 100% Nuclear Fuel + Cust Dep % Total Debt (LTD + Nuclear Fuel) 43.7% 0.72% Total Ratemaking Financing 24596

183 Earnings Impact of Customer Deposits Offset Reduced Equity Earnings from Lower Rate Base in 2015: ($millions) Common Equity Preferred Equity Total Customer Deposits offset (authorized) times common equity ratio 48% 9% equity reduction due to offset: Times equity return: 10.45% 5.79% After Tax earnings impact Customer Deposits Offset from D Cost of Capital Components from D Customer Rate of Return from Rate Base Offset 2013 Authorized Cost of Capital* Including Gross-up Assumed Tax Rate: 40% Grossed-up Auth Cap Rate of Weighted Tax Weighted Structure Return Cost Gross-up Cost Equity 48% % % preferred 9% % % debt 43% % % 7.90% 11.59% *D

184 183 STANDARD PRACTICE U-16

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225 224 STANDARD PRACTICE U-16-W

226 225 CALIFORNIA PUBLIC UTILITIES COMMISSION Water Division DETERMINATION OF WORKING CASH ALLOWANCE Standard Practice U-16-W San Francisco, California March, 2006

227 226 DETERMINATION OF WORKING CASH ALLOWANCE TABLE OF CONTENTS Chart Table Page No. No. Title No. CHAPTER 1 - INTRODUCTION 1-1 CHAPTER 2 - WORKING CASH ALLOWANCE - SIMPLIFIED BASIS 2-A Determination of Working Cash Allowance - Utilities Operated by Individuals or Partnerships B Determination of Working Cash Allowance - Incorporated Telephone Company C Determination of Working Cash Allowance - An Incorporated Company CHAPTER 3 - WORKING CASH ALLOWANCE - DETAILED BASIS 3-A Graphical Comparison of cost and Retail Methods of Determining Average Cash Available for Use as Working Cash Allowance A Sheet 1 - Determination of Average Amount of Working Cash Supplied by Investors Sheet 2 - Development of Average Lag in Payment of Expenses Sheet 3 - Development of Average Lag in Collection of Revenues - Ratio of Accounts Receivable (Not Including Unbilled Sales) to Credit Sales Method Sheet 4 - Development of Average Lag in Collection of Revenues - Ratio of Accounts Receivable (Including Unbilled Sales) to Credit Sales Method Sheet 5 - Development of Average Lag in Collection of Revenues - Statistical Sampling Method i

228 227 3-B Effect of Changes in Working Cash Items on 3-26 Working Cash Allowance CHAPTER 4 - PREPARATION OF STAFF REPORT 4-1 Appendix I Derivation of Basis for Calculating Federal Income Tax Applicable to Increase in Net Revenue for Incorporated Companies * Follows page indicated ii

229 228 Chapter A INTRODUCTION B PURPOSE C NEED FOR WORKING CASH ALLOWANCE D WORKING CASH COMPONENT OF RATE BASE E WORKING CASH ALLOWANCE - SIMPLIFIED BASIS Chapter WORKING CASH ALLOWANCE SIMPLIFIED BASIS Determination of Operational Cash Requirement Deduction from Operational Cash Requirement Determination of Appropriate Federal Income Tax Accrual to Use in Working Cash Determination TABLE 2-A TABLE 2-B TABLE 2-C Chapter WORKING CASH ALLOWANCE - DETAILED BASIS A HISTORICAL BACKGROUND B DETERMINATION OF OPERATIONAL CASH REQUIREMENT Cash It should be recognized that not all of the utility's bank deposit transactions involve funds for operations. Some banks require compensatory balances of about 20% of a revolving credit. This credit is ordinarily used to finance construction before completion. The amounts in the revolving credit will fluctuate until such time as management considers it favorable to convert short-term debts into long-term financing. The cost of these construction monies is more properly considered in arriving at an allowable rate of return and should not be included in cash balances considered in the operational cash requirement.special Deposits Working Funds Notes Receivable Prepayments Other Deferred Debits C DEDUCTIONS FROM THE OPERATIONAL CASH REQUIREMENT Customers' Deposits Insurance Reserves Deferred Credits Accrued Vacation and Sick Leave Amounts Withheld from Employees Taxes Accrued Accounts Payable Revenue Lags and Expense Lags D COST METHOD VS. RETAIL METHOD E DETERMINATION OF LAG DAYS FOR REVENUES F DETERMINATION OF EXPENSE LAG DAYS Federal Income and State Corporation Franchise Taxes G MULTI-DEPARTMENT AND/OR DISTRICT UTILITIES - DETAILED BASIS TABLE 3-A TABLE 3-B i

230 229 Chapter PREPARATION OF STAFF REPORT APPENDIX I... i ii

231 230 Chapter 1 A HISTORY 1. This Standard Practice was originally prepared under Utilities Division Work Order No. S-1181 by engineers of the Valuation Section under the supervision of Mr. Clarence Unnevehr, Valuation Engineer. This practice was accepted for use by the Utilities Division at the Division Conference on February 28, 1956 (Doc. Mgmt. #271137). B -INTRODUCTION 2. This report describes present staff practices and serves as a guide to the staff engineer or analyst (analyst) in determining the working cash allowance. B PURPOSE 3. The purpose of this Standard Practice is to assist staff engineers in analyzing and determining a proper working cash for use in the rate base portion of results of operation reports. 4. This report covers the suggested procedures the analyst should be familiar with before undertaking a working cash allowance study. Two methods are set forth: A simplified basis, and a detailed basis. Deviations to this standard practice are acceptable but must be approved by the Project Manager. C NEED FOR WORKING CASH ALLOWANCE 5. The need for working cash was first recognized in Smyth vs. Ames, 169 US , in Mr. Justice Harlan stated that among the matters to be considered in determining the value of property used was "the sum required to meet operating expenses." Therefore, from the beginning of the "property devoted to public use " 1-1

232 231 doctrine as a basis for fixing rates, working cash has generally been recognized as a proper item to be included in the base on which the utility is entitled to earn a return. D WORKING CASH COMPONENT OF RATE BASE 6. The working cash allowance is a component of rate base. It can be positive or negative. 1 Its purpose is to compensate investors for funds provided by them which are permanently committed to the business for the purpose of paying operating expenses in advance of receipt of offsetting revenues from its customers and in order to maintain minimum bank balances. Cash held for construction, for purchases of stock, for payment of dividends and interest on funded debt, and link purposes does not qualify for inclusion in cash working capital The analyst should recognize that management policies may affect working cash, and these policies should be considered when arriving at conclusions as to the reasonable allowance. The actual operating conditions of the utility in procurement of, and payment for, services, receipt of revenues, and accounting procedures are easily ascertained. Changes in operating conditions in the near future may be considered in the development of the working cash allowance, such as changes in tax rates and payment schedules which may affect the amount of working cash available to the utility. 2. First, determine the operational cash requirement and then subtract from the operational cash requirement such amounts as are available to this utility in forms 1 The Pacific Telephone and Telegraph Company Decision No Cal. PUC 775, 821 (1964) upheld by the California Supreme Court in S.F ,April 28, 1965 shere the Commission disallowed $6,800,000 (which Pacific termed negative working cash ) from Pacific s claimed rate base for the test year. The Commission found that where the funds supplied to Pacific by others than investors are greater than the amount required for working cash, the excess amount should be deducted from rate base. The Court commented This view appears sound and fair, the decision sets forth detailed findings on the subject, and no error is shown. Cited in Subj. Ref. H-9, June 9, see also: The Pacific Lighting Gas Supply Company Decision No Cal. PUC 610, 625 (1962) D , February 16, 1984, In the Matter of the Application of SAN GABRIEL VALLEY WATER COMPANY, a California corporation, for authorization to issue and sell not exceeding $4,737, 500 aggregate principal amount of its First Mortgage Series M, 12-1/2% Bonds Due February 1, 1999, to execute and deliver an Eighteenth Supplemental Trust Indenture and to purchase and retire all of its outstanding Preferred Stock at AT&T Co., et al (Private Line Cases) 34 FCC 244, 271 (1961) 1-2

233 232 of tax accruals or other funds not supplied by the investors. 3 The operational requirement is made up of working funds in the form of cash, special deposits and other current assets which the investor is required to supply to the utility in order for it to perform its day-to-day operational requirements efficiently and economically. On the other hand, the amount subtracted from the operational cash requirement represents a source of interest-free working funds available to the utility due to the fact that revenues are collected prior to the payment of employees' wages, taxes and the utility's creditors. The net amount then represents the allowance for funds supplied by the investors. 3. For practical reasons, the method of determining the working cash allowance varies with the size, nature and the operation of the utility. For utilities not large enough to justify a detailed study, or when a detailed study would be impractical from a work-time viewpoint, a simplified basis may be used to develop a working cash allowance. For major utilities, a detailed method is used based upon the socalled "weighted-average or lead-lag" study. In the final analysis the amount of working cash to be included in the rate base must rest upon the analyst's judgment. The amount of working cash allowance in the end result is essentially a judgment amount based upon what the analyst believes to be fair and reasonable for the operations of the utility but within limitations dictated by the size of the utility and staff policy. 4. This regulatory concept of working capital must be distinguished from the accounting definition of working capital. Accountants define working capital as the difference between current assets and current liabilities. The regulatory concept, on the other hand, defines working capital as an allowance for the amount of money which the utility has furnished from its own funds for the 3 If through the availability and use of tax accrual moneys or other funds supplied by the subscribers, the investors are required to supply a smaller sum, their compensation should be proportionately less. T.P.T. and T. Co., Decision No , 48 CPUC 1, 22 (1948) 1-3

234 233 purpose of enabling it to satisfy ordinary requirements for minimum bank balances and to bridge the gap between the time expenses of rendering utility service are paid and the time revenues from the same service are collected. This definition includes both materials and supplies and working cash in working capital. Since the category of materials and supplies is already included in rate base, this Standard Practice is concerned only with the working cash allowance to be included in the rate base for rate-fixing purposes. E WORKING CASH ALLOWANCE - SIMPLIFIED BASIS 10. The Working Cash Allowance for small utilities as developed for results of operation studies has generally been derived on a simplified basis. The method provides that working cash "requirement" be based upon a certain number of months' expenses for fuel and/or commodity purchases, and a certain number of months of operating expenses, excluding taxes, depreciation and uncollectibles. The number of months usually depends on the type of billing and rate schedules by which the utility collects its revenues. The selection of the number of months of operating expenses used in the simplified method is based upon earlier Commission decisions commencing with Decision No. 2947, dated November 30, 1915, wherein the Commission stated that "The Commission ordinarily allows for working capital an allowance equivalent to cover two months operating expenses." 4 In later decisions the Commission, in ruling on working capital, separated the working capital into working cash allowance and materials and supplies, and also deducted from the working cash capital an amount equivalent to a percentage of certain tax accruals which were held by the company for tax payments to be made in the future. 5 4 Pacific Gas and Electric Company, Case Nos. 477 and 550, Decision No. 2947, 8 CRC 566, 569 (1915). 5 Great Western Power Company of California, Application No. 5585, Decision No , 22 CRC 814, 830 (1923). 1-4

235 234 Chapter 2 WORKING CASH ALLOWANCE SIMPLIFIED BASIS 1. The working cash allowance for small utilities as developed by staff engineers for results of operation studies has generally been derived on a simplified basis. The method provides that working cash requirement be based upon a certain number of months expenses for fuel and/or commodity purchases, and a certain number of months of operating expenses, excluding taxes, depreciation and uncollectibles. The number of months usually depends on the type of billing and rate schedules by which the utility collects its revenues. The selection of the number of months of operating expenses used in the simplified method is based upon earlier Commission decisions commencing with Decision No. 2947, dated November 30, 1915, wherein the Commission stated that The Commission ordinarily allows for working capital an allowance equivalent to cover two months operating expenses. 1 In later decisions the Commission, in ruling on working capital, separated the working capital into working cash allowance and materials and supplies, and also deducted from the working cash capital an amount equivalent to a percentage of certain tax accruals which were held by the company for tax payments to be made in the future. 2 Determination of Operational Cash Requirement 2. The first step in calculating a working cash allowance on the simplified basis is to obtain the operational cash requirement for the operation of the utility. It should be noted that the operational cash requirement should be for operation 1 Pacific Gas and Electric Company, Case Nos. 477 and 550, Decision No. 2947, 8 CRC 566 (1915). 2 Great Western Power Company of California, Application No. 5585, Decision No , 22 CRC 814, 830 (1923). 2-3

236 235 and not for new construction or replacement of plant. 3 The procedure to develop the operational cash requirement is as follows: a. For electric, gas, and water utilities: Operational cash = Average monthly operating expenses, excluding taxes, depreciation and uncollectibles, multiplied by a certain number of months. Less: One month's average purchased power expense and/or commodity of water and/or gas and/or electricity billed after receipt. The number of months used as the foregoing multiplier is determined from the utility's billing practice as follows: No. of Months Description Average Expenses Monthly billing at meter rates 2 Monthly billing at flat rates 1 Bimonthly billing at meter rates 2 1/2 Bimonthly billing at flat rates 1/2 Annual or seasonal billings in lump Judgment sums - gross requirement is determined by special study Where utilities have more than one billing procedure, expenses should be allocated to each type of billing and service in proportion to total operating revenues received under each. 3 "Any construction cash capital needed is an element of a cost of capital and is not includible in rate base." Pacific Gas and Electric Company, Decision No , 49 Cal. PUC 107, 117 (1949). 2-3

237 236 In determining expenses for purchased power and/or commodity, the following accounts should be considered: Electric Class A and B 501, 518, 536, 547 and 555 Class C 501, 531, 539 and 545 Class D 501, 521, 531 and 540 Gas Class A and B 717, 723, 728 and 807 Class C 701, 730 and 731 Class D 701 and 730 Water Class A, B and C 704, 723 and 726 Class D 704 and 726 b. For telephone utilities, the requirement is equal to the average monthly operating expenses, exclusive of taxes and depreciation, multiplied by a certain number of months. Expenses should be allocated to toll service and local and miscellaneous service in proportion to total operating revenues received under each. Since exchange service is normally billed in advance and toll service is generally billed in arrears, the number of months used for monthly billing as the foregoing multiplier is set forth as follows: No. of Months Monthly Billing Average Expenses Toll Service 2 Local and Miscellaneous Service 1 3. In the selection of the number of months for electric, gas and water utilities where annual or seasonal billing is made by lump sum, an evaluation should be made of the extent to which revenues are received in advance of payment of operating expenses. In many instances, the revenues so collected in advance of payment of expense may result in a zero working cash requirement. 4 Deduction from Operational Cash Requirement 4. The second step in the development of working cash allowance on a simplified basis is to deduct from the operational cash requirement an amount 4 Inverness Water Company, A-44221, Exhibit 8, Staff Report No. S-1653, Chapter 10, Paragraphs

238 237 which is available to the utility in the form of tax accruals or other funds not supplied by the investor. Normally for small utilities "other funds not supplied by the investors" are not large enough to be significant and therefore are not considered in the study. Tax monies available to the utility as a source of working funds are normally federal income tax accruals. State income taxes are not considered primarily because they do not appreciably affect working cash requirement. If ad valorem taxes are accrued on a calendar-year basis, that is, preceding the local government's fiscal year, one half of the annual amount should be included in the tax accruals available to meet working cash requirements. Determination of Appropriate Federal Income Tax Accrual to Use in Working Cash Determination 5. In determining the deduction from the operational cash requirement, it is necessary to determine an approximate level of earnings on which the federal income tax accrual will be developed. In most rate proceedings, the net taxable income at present rates is obviously on the low side. Often it is found that the taxable income at rates proposed by the applicant is on the high side. Since the rates the Commission will authorize are not known at the time the engineer is preparing the report, it will be necessary that he exercise judgment as to the level of earnings to be used in computing the federal income tax accrual available to meet working cash requirements. The level of earnings may be arrived at by applying a rate of return, recommended by the staff rate of return expert, to the rate base (excluding working cash allowance) which will give an approximate level of earnings after taxes. With the developed earnings after taxes, the amount of federal income taxes may be determined. Table 2-C sets forth the procedure in developing the income tax calculations for an incorporated utility. 2-3

239 For utilities operated by individuals or partnerships, a deduction for income tax accrual is not appropriate, inasmuch as the individuals or partners must pay income taxes on substantially a current basis. Therefore, for such utilities the operational cash requirement is acceptable as the working cash allowance. A sample calculation for this type of utility is shown in Table 2-A. 7. For utilities operating as corporations, the practice in the past has been to deduct from the operational cash requirement one half of the adjusted total annual federal income tax accrual because of the availability of these funds due to the lag in payment of the taxes. Where the tax accrual was greater than the operational cash requirement, the deduction has been limited to one half of the operational cash requirement. This deduction was made because the tax accrual was available for working cash as a result of the lag in the payment of the first $100,000 of estimated taxes. 8. In 1968, changes were made to the federal income tax code as it related to estimated income tax payments for corporations. 1 It eliminated, over a 10-year period, the exemption of the first $100,000 of corporate tax liability from the requirement of payment on a quarterly estimated basis. Formerly, the Code allowed the payment of the first $100,000 of estimated taxes to be made in equal installments on March 15 and June 15 of the following tax year. The Code's new estimated payment schedule altered the previous estimated tax payment schedule so as to phase out the $100,000 exemption from the quarterly estimated tax payment over two 5-year transitional periods. At the end of the first of these periods ( ), corporations will be paying current installments on all of their estimated taxes with the exception of the first $5,500. The $5,500 exemption will remain in effect only in 1972, and then will be phased out over the next 5-year transitional period ( ). The new system will require small utility 1 See Subject Reference N62, dated July 8, 1968, "Computation of Federal Income Taxes for Incorporated Utilities." 2-4

240 239 corporations with less than $100,000 of estimated federal income taxes to pay estimated taxes on the current basis program. 9. The change in the estimated tax payment schedule results in reduced tax accruals available for working cash. Therefore, it is recommended, that commencing with the test year 1968 through 1974 and subsequent years thereafter, the percent deduction from operational cash requirement for utilities having various tax liabilities be as follows: Percent Deduction from Operational Cash Requirement Test Years Tax Liability $ 0 - $ 5,500 50% 50% 50% 50% 50% 30% 0% 5,501-10, ,001-30, , , The deductions recommended in the above tabulation are based on the average availability of federal tax accruals for the test year and two future years. 10. Tables 2-B and 2-C set forth the suggested procedure for the development of working cash allowance. For utilities paying more than $200,000 in federal income taxes, it is recommended that the detailed basis covered in Chapter 3 be used in the determination of the working cash allowance. 2-5

241 240 TABLE 2-A SIMPLIFIED BASIS DETERMINATION OF WORKING CASH ALLOWANCE (A utility operating as an individual or partnership using monthly billing at meter rates) Estimated Test Year Operating Expenses, Excluding Taxes and Depreciation $ 6, Purchased Power and/or Purchased Commodity for Resale* 1, Two Months' Average Operating Expenses (1/6 x Line 1) 1, One Month's Average Purchased Power and/or Purchased Commodity* (1/12 x Line 2) Average Tax Accruals Available Working Cash Allowance (Line 3 - Line 4 - Line 5) Use 850 * Electric power, gas or other fuel purchased for pumping and or purchased water or gas or electricity for resale billed after receipt (metered). 2A-1

242 241 TABLE 2-B SIMPLIFIED BASIS DETERMINATION OF WORKING CASH ALLOWANCE (An incorporated telephone company) Estimated Test Year 1969 Determination of Operational Cash Requirement 1. Annual O&M Expenses $120, Toll Revenues 128, Local Revenues 79, Miscellaneous Revenues 4, Total Revenues 211, Ratio - Toll Revenues to Total Rev. (L.2 + L.5) 60.6% 7. 1/6 x Line 1 x Line 6 12, /24 - Line 1 x (100% - Line 6) 1, Operational Cash Requirement (L.7 + L.8) 14,172 Estimation of Federal Income Tax 10. Federal Income Tax at Present Rates Federal Income Tax at Proposed Rates 4, Federal Income Tax, Judgment Basis 3,800 Determination of Working Cash Allowance 13. Deduction to be made from Operational Requirement # 1, Working Cash Allowance (Line 9 - Line 13) 12, Use 12,300 # Since Federal Income Tax Accrual, Judgment Basis (line 12), does not exceed the Operational Cash Requirement (line 9), the deduction from the Operational Cash Requirement (line 13) for the test year 1969 is 50% of the Judgment Basis Federal Income Tax Accrual (line 12) rather than 50% of the Operational Cash Requirement. (See paragraph 9 for percent deductions to be used for subsequent test years.) 2B-1

243 242 TABLE 2-C SIMPLIFIED BASIS DETERMINATION OF WORKING CASH ALLOWANCE (An incorporated company) Estimate Test Year 1969 Determination of Operational Cash Requirement 1. Operating Expenses, Excl. Taxes, Depr. & Uncollect. $290, Purchased Power and Purchased Commodity for Resale* 143, Meter Revenues - Bimonthly Billing 325, Other Revenues - Flat Rate Monthly Billing 198, Total Revenues (3 + 4) 524, Ratio - Flat Rate to Total Revenues (4 / 5) 37.9% 7. 5/24 x Line 1 x (100% - Line 6) $ 37, /24 x Line 1 x Line 6 4, /12 x Line 2 11, Operational Cash Requirement ( ) 29,984 Estimation of Federal Income Tax 11. Rate Base Excluding Working Cash 1,396, Judgment Factor to be Applied to Line % 13. Result of Applying Judgment Factor to Line 11 (11x12) $ 97, Net Revenue at Present Rates 22, Increase in Net Revenue Needed to Give Result of Applying Judgement Factor (13-14) 75, Federal Income Tax at Present Rates 17, FIT Applicable to Increase in Net Revenue x (15)** 69, FIT Resulting from Applying Judgment Factor ( ) 86,866 Determination of Working Cash Allowance 19. Deduction to be made from Operational Requirement # Working Cash Allowance (Line 10 - Line 19) 29, Use 30,000 * Electric power, gas or other fuel purchased for pumping and/or purchased commodity for resale billed after receipt (metered). ** Basis of calculating Line 17. (See Appendix I, page i, for derivation.) 2C-2

244 243 (a) If Line 16 is less than $5,500, use x Line 15. (b) If Line 16 is less than $5,500, but result of step (a) is greater than $5,500, use ($5, Line 16) (Line 15 - $19,500). (c) If Line 16 exceeds $5,500, use x Line 15. # Since Federal Income Tax Accrual (Line 18) is greater than $30,000, no deduction from the Operational Cash Requirement (Line 10) is made. (See paragraphs 8 and 9).. 2C-2

245 244 Chapter 3 WORKING CASH ALLOWANCE - DETAILED BASIS A HISTORICAL BACKGROUND 1. The detailed basis of determining working cash allowance is normally referred to as the "weighted average or lead-lag days" method. Fundamentally, the same principles apply for the detailed basis as for the simplified basis, that is, first the operational cash requirement is determined and then amounts of monies available through tax accruals and other funds not supplied by the investor are deducted from the operational requirement. The term investor as used herein is defined as one who invests (to lay out money or capital) in business with the view of obtaining an income or profit; to convert into some form of wealth other than money, as securities or real estate, with the expectation of deriving income 1. Basically, the procedure is to determine, by analyzing certain current assets balance sheet accounts, the operational cash required by the utility and then deducting from this amount the average working cash available as the result of collecting revenues in advance of paying expenses. 2. The detailed basis is a modification of a study first developed and introduced in evidence in 1928 before the Interstate Commerce Commission by Arthur S. Field, Ph.D. 2 Dr. Field's study generally outlined a method which was applicable in determining both materials and supplies and working cash. The method consisted essentially of the determination of allowances by consideration of average weighted periods of time during which a company has money invested in the business for the purpose of paying operating expenses. Dr. Field's method was used primarily in connection with railroad valuations. 1 Webster's New Collegiate Dictionary : (G & C Merriam Co., 1959) 2 North Hampton and Bath Railroad Company, 149 ICC 244,

246 In 1933, F. T. Mylott, consulting accountant and later commissioner for the New York Public Service Commission, broadened the application of the weighted average or dollar days "lead or lag" method for general utility companies' use. The detailed basis was first introduced before the California Commission in 1947 in a staff exhibit wherein the staff determined the working cash required by the American Telephone and Telegraph Company for the furnishing of services to license companies. 3 Since 1947 numerous working cash allowance studies using the detailed basis have been introduced in evidence before the California Commission for electric, gas, water, and telephone utilities The working cash allowance included in the rate base for major utilities is normally developed by the detailed basis. The following are the most recent detailed studies prepared by the staff for major utilities' rate proceedings: Study Application Exhibit Company Number or Case No. No. California Water Service Company J-1196 A General Telephone Company of J-1215 California Pacific Gas & Electric Company S-1545 A Pacific Lighting Gas Supply Company S-1612 A San Diego Gas & Electric Company S-1572 A San Jose Water Works J-1147 A Southern California Edison Company S-1342 A Southern California Gas Company S-1524 A-41860(Amd) 50 Southern Counties Gas Company of S-1523 A-41859(Amd) 51 California Southern California Water Company J-1195 A , 8 The Pacific Telephone and Telegraph J-1177 A , 77 Company S-1660 C Before commencing a study using the detailed method, the engineer should familiarize himself with the operations of the utility, its accounting procedures for accruing expenses, payment procedures and schedule, and management's 3 The Pacific Telephone and Telegraph Company, A-28211, D-41416, 48 Cal. PUC 1, 22 (1948). 1-2

247 246 viewpoint of working cash needs. Without this information, the engineer would not be knowledgeable enough to be able to request the pertinent facts from the utility in the preparation of the data to complete a detailed study of working cash allowance. 6. Table 3-A, Sheets 1 through 5, illustrates the technique and format to be used in developing a detailed study. B DETERMINATION OF OPERATIONAL CASH REQUIREMENT 7. The operational cash requirement for working cash capital is evidenced by amounts included in certain current asset accounts in the balance sheets. These accounts are: a. Cash b. Special Deposits c. Working Funds d. Notes Receivable e. Prepayments f. Other Deferred Debits 8. The amounts included in most of these accounts are dependent on management's judgment as to the level of working capital required by a particular utility. Therefore, the appropriate working cash capital will vary not only between different types of utilities, but between different utilities of the same type. The fact that the amounts appear on the books of the utilities is not necessarily a satisfactory indication that the funds are used economically and efficiently to serve the customers. Therefore, analysis and evaluation of the reasonableness of these current asset accounts are required of the engineer to be able to develop the reasonable amounts to be included in the operational cash requirement. 9. Except for cash, the amounts used in determining operational cash requirements for a given period are the average of month-end balances. Cash should be the average required minimum bank deposit. Table 3-A, Sheet 1 of 5, 4 For more detailed early history see unpublished paper "The Determination of Working Cash Capital Allowance for Public Utility Regulatory Purposes" by Carol Towers Coffey, July 29, 1950, Univ. of California Library, Berkeley 1-3

248 247 illustrates the recommended format in the development of the operational cash requirement. Included therein are some of the selected balance sheet accounts which make up the operational cash requirement, as well as the deductions therefrom to obtain the working cash allowance. Some of the factors to consider in the analysis and evaluation of the reasonableness of the current assets accounts are discussed in the following paragraphs. Cash 10. This balance sheet account includes the utility's current cash monies on hand and bank deposits except those classed as petty cash or other working funds. The largest portion in this account will generally be actually working, such as cash on hand to pay expenses prior to the receipt of payments from consumers. Other amounts of each may be on hand to pay dividends, debt interest or costs for construction purposes. The account fluctuates with regular frequency depending upon anticipated large cash outlays such as accrued taxes, bond interest, dividends, and construction expenditures. The problem, therefore, is to separate cash items which should not be included in the working cash from those amounts which are necessary for the utility "to operate economically and efficiently". 11. In determining the cash requirement, the only amounts which should be considered are the required minimum bank deposits that must be maintained and reasonable amounts of working funds. The determination of the amount of money required to pay expenses in advance of receipt of revenues is made by the lag study. If funds were to be allowed in the cash requirement, over and above the minimum bank deposits for payment of certain operating expenses, it would have the effect of providing for payments of the same cost twice, once as determined in the lag study and once again in determining the operational requirement. It must be remembered that the cash requirement is not a measure of funds that the utility maintains for all purposes, such as for construction or for payment of dividends and interest. It is the amount that must be maintained for day-to-day operations. When the ratepayer pays his bill, he has compensated the investor 1-4

249 248 for the interest on construction funds and a return on the investor's capital; therefore construction cash, interest and dividends are not included in the cash requirement. 12. In previous staff studies, the determination of the working cash portion of the operational cash requirement started with the "cash" balance sheet account with deductions made therefrom for construction funds, bond interest and other adjustments. The Commission has ruled that both construction funds and bond interest should be excluded from the "cash" balance sheet account. 13. In most recent staff studies, both before the California Commission 5 and the Federal Communications Commission 6, the staff has adopted the procedure of "building up" the operational cash requirement which, therefore, does not require adjusting for construction funds or bond interest. This procedure includes only those cash items, furnished by investors, which are actually needed for operations and consist of minimum bank deposits and working funds. 14. Commercial banks normally require utilities to maintain a minimum balance on deposit in commercial accounts. If this minimum is not maintained, the banks will charge a fee. The minimum balance and the cost for such other services rendered by the banks are usually negotiated between the banks and the utilities. The procedure to determine the reasonable level or average daily bank balances has been explained in detail in an exhibit presented in a rate proceeding before the Commission. 7 There are other published papers which may also be of assistance. 8 It should be recognized that not all of the utility's bank deposit transactions involve funds for operations. Some banks require compensatory balances of about 20% of a revolving credit. This credit is ordinarily used to finance construction before completion. The amounts in the 5 TPT&T Company, A-49142, Exhibit Nos. 61 and 77, dated July 13, 1967 and August 8, AT&T Company, Docket No , Cal. PUC Exhibit No. 2, dated October 17, Exhibit No. 11, Southern California Gas Company, Application No (1950). 8 Pacific Coast Gas Association Proceedings - Vol S. M. Gilliland, So. Counties Gas Co. - "Looking Ahead - Short term Phase". W. D. Morningstar, Pac. Lighting Gas Supply Co. - "Looking Ahead - Long Term Phase". A. E. Mason, So. Calif. Gas Co. - "Bank Balances, How Much is Enough". Vol W. Karns, San Diego Gas & Electric Co. - "Keeping Your Money at Work". 1-5

250 249 revolving credit will fluctuate until such time as management considers it favorable to convert short-term debts into long-term financing. The cost of these construction monies is more properly considered in arriving at an allowable rate of return and should not be included in cash balances considered in the operational cash requirement. 9 9 PG and E Company, Decision No , 49 Cal. PUC 107, 117 (1949). See also 51 Cal. PUC 130, 137 (1951). 1-6

251 250 Special Deposits 16. Special deposits may include cash items that have not been reflected in operating expenses but which nevertheless are required for the operation of the utility. These include items such as encroachment permits, street repair and repavement permits, and deposits for Workmen's Compensation Insurance. They may also include items associated with the initial construction of plant (viz., deposits with realtors for purchase of land or architect's fees) that have not been included in rate base or in interest-bearing construction work in progress. All of those deposits represent cash supplied by the investor needed in the day-to-day operations and for which he should be compensated. Working Funds 17. This account includes cash advanced to officers, agents and/or employees of the utility for petty cash purchases or advances for expenses. These funds are recognized in most instances as investors' funds necessary for the economical and efficient operation of the utility. Notes Receivable 18. The amounts of notes receivable that should be included in the requirements will depend upon the extent to which they are interest bearing. Those notes resulting from utility operations that do not bear interest may be included in the requirement. Prepayments 19. This account includes prepayments for rents, insurance, taxes, group annuity premiums for pensions, and other items where the actual expense has not been accrued to operating expenses. Analysis should be made of this account to determine those items that are to be included in the lag study. The remainder (e.g., an unaccrued balance of a prepaid triennial premium of an insurance policy) are funds that are supplied by the investors and should be considered in the operational cash requirement. 1-7

252 251 Other Deferred Debits 20. This account includes those debits that are in the process of amortization and which are not included in the other current asset accounts. These expenses may include abnormal expenses which are being amortized to operating expenses and uncleared amounts from the clearing accounts. C DEDUCTIONS FROM THE OPERATIONAL CASH REQUIREMENT 21. As indicated on the lower portion of Table 3-A, there is deducted from the amount of current assets accounts certain current liabilities which represent monies provided from sources other than the investors for the operation of the utility. These accounts may include monies already derived through rates to offset a future liability which the company has not incurred, monies received from customers for the procurement of services, and amounts withheld from employees. These amounts are intermingled in the cash balances or invested in the plant accounts. Therefore, if these amounts are not excluded, the investors in effect would be compensated for funds which they have not supplied. The following current liabilities accounts should be considered as deductions from the operational requirement. Customers' Deposits 22. This account represents monies advanced by the customer as security for the payment of utility bills. Only noninterest-bearing customer deposits are to be considered. Insurance Reserves 23. This account included funds allowed by the Commission to be accumulated through charges to operating expenses in anticipation of some future or deferred liability. The adjustment may be either made in the working cash determination or deducted from rate base proper Southern Counties Gas Co. of Calif., Decision No , 52 Cal. PUC 645, 652 (1953). See also Exhibit No. 19, San Diego Gas & Electric Company, Table 14-B, page

253 252 Deferred Credits 24. This account represents monies which will be spent in the future, and for which provision has been made through charges to operating expense in prior years or which represents funds and receipts slated to be used to reduce expenses. Accrued Vacation and Sick Leave 25. These amounts represent monies accrued through operating expenses for future liabilities which the utility has available until payments to employees for vacation and sick leave are made. Amounts Withheld from Employees 26. This amount includes monies withheld from the employees and which are available to the utility until such time as payments are required. They include withholdings for income taxes, U.S. Savings Bonds, other state and federal payroll taxes, premiums for group insurance, and contributions to pension plans. Taxes Accrued 27. The available working cash of the unpaid operating taxes accrued and credited to this balance sheet account has been considered in the expense lag study. The amounts of accrued but unpaid "excise" and/or "service users" taxes, associated with telephone service and collected from the ratepayers, are also credited to this account. These latter amounts represent a source of interest-free working cash supplied by the ratepayers and therefore should be deducted from the operational cash requirement. Accounts Payable 28. The expense lag study includes a determination of the availability of unpaid operating expenses for working cash that are credited to this account. This account also includes amounts currently due for materials and supplies and equipment received but not paid for. The lag study considers the voucher items included in operating expenses that are credited to this account. The balance of these amounts is accounted for either as a debit to materials and supplies, as interest-bearing construction work in progress, or as a plant account. These 1-9

254 253 amounts are a credit extended by the suppliers, and provide capital from a source other than that of the investors. Since these amounts are included in rate base or are receiving interest during construction, they also should be deducted from the operational requirement. This adjustment is consistent with the staff's most recent working cash allowance study before the California Commission and the Federal Communications Commission Revenue Lags and Expense Lags 29. Revenue lags arise when the utility has extended credit to customers and, under accrual accounting, that credit is shown on the balance sheet as accounts receivable. Similarly, expense lags arise when the utility has received credit and, under accrual accounting, that credit is shown on the balance sheet as accounts payable. Also under accrual accounting, operating taxes which have not yet been paid are included in the balance sheet as accrued taxes rather than accounts payable. 30. The detailed basis first measures, from the midpoint of the month, the weighted average days of lead or lag of payment of expenses by analyzing each expense component to determine how many days on the average before or after a reference point the payment is made. This procedure measures, on the average, the number of days the utility has available the amount of the expense before its payment. A similar analysis of weighted average days is made of revenues by classes of customers to determine the average number of days that the utility has extended credit to its customers for the cost of service supplied by the utility. D COST METHOD VS. RETAIL METHOD 31. The Commission in a 1930 decision stated, "the allowance for working cash capital differs from the company's claim in this case principally in that it is based upon the cost rather than the retail value of the service which at all times has been rendered, but on account of the lag in monthly meter readings and 11 And 1-10

255 254 collections has not been paid for by the consumers." 13 The cost method has been used consistently since this decision and it assumes that the utility advances the operating expenses incurred in rendering service to the customer the instant the service is rendered. The utility must wait until the customer pays his bill before it is reimbursed for the cost of this service plus a profit. In turn, the cost of rendering service is advanced to the utility by the utility's suppliers and employees and by taxing agencies. As the average lag in payment of a utility's expenses is generally longer than the lag in receiving revenues, the utility has funds which are not supplied by its investors available for its use. 32. The retail method assumes that the utility advances to the customer both the expenses incurred in rendering service and the return the utility will earn as a result of rendering service. Since the return is considered to be advanced by the investor to the customer, it follows that it should be deducted from the amount of cash available as a result of collecting revenues in advance of paying expenses. 33. To counter the argument that profit is advanced by the investor to the customer, it is proposed that it is the customer who actually pays the profit. To deduct the profit in determining cash available would have the compounding effect of requiring the customer to pay an additional return on the portion of his payment that constitutes the return. The only out-of-pocket expense required of the utility is the cost of rendering the service. The only amount which the utility has advanced in supplying service to the customer is the "cost" of service to the company, not the "price" at which it is billed to the customer. 14 Chart 3-A shows a graphical comparison and explanation in support of the cost method. E DETERMINATION OF LAG DAYS FOR REVENUES 34. Lag days of revenues measure the length of time that the utility has extended credit for the cost of service rendered to its customers. There are two techniques to measure the time lag of payment of the cost of service as measured 12 See footnote 4 on page 3-2 and footnote 5 on page Los Angeles Gas and Electric Company, Case No. 2747, Decision No , 35 CRC 443, 453 (1930). 14 See footnote 13 on page

256 255 by receipts of revenues. One is the "statistical sampling" method, and the other is the "ratio of accounts receivable to credit sales" method. The "statistical sampling" method takes a representative sample of customers by classes and geographical locations and measures the time from the midpoint of the period during which the service is rendered to the date that the revenue is received for the service. 1-12

257 256 (insert Chart 3-A here) 1-13

258 For the "ratio of accounts receivable to credit sales" method, the engineer must first ascertain from the utility whether or not the accounts receivable include unbilled sales to customers. If accounts receivable do not include unbilled sales, the revenue lag days are determined by dividing the total annual sales into the sum of: (1) the unbilled sales, i.e., the product of customer sales to the period of time measured from the midpoint of service rendered to the date of billing; and (2) the accumulation for the full year of each daily accounts receivable - billed customers which reflects the dollar days lag measured from the date of billing to date of payment. The quotient thus arrived at results in a composite revenue lag days. But, if accounts receivable include unbilled sales, the "accounts receivable" method of developing revenue lag days is obtained by dividing the total annual sales into the accumulation for the full year of each daily accounts receivables for all customers. This method was used by the staff in a recent rate proceeding If appropriate accounting records are maintained and readily available from large utilities, the "accounts receivable" method should be used in preference to the "statistical sampling" method for the development of lag days in future working cash studies. The "accounts receivable" method will yield a more representative lag experienced by the utility for the entire year which will not be subjected to any sampling variability. However, if appropriate accounting records are unavailable, the "statistical sampling" method may be used. 37. Table 3-A, Sheets 3 through 5, illustrates the two methods of determining revenue lag days. The "accounts receivable method, depending on whether accounts receivable exclude or include unbilled sales, is set forth in Sheets 3 and 4, respectively. For illustrative purposes, the "accounts receivable" method shown was developed to result in the same number of lag days as the "sampling" method on Sheet 5. This may not be true in an actual study. 38. It should be noted that accounts receivable of certain types of utilities may include charges for flat rate water service or telephone exchange service which 15 The Pacific Telephone and Telegraph Company, C-7409, Exh. No. 2, S-1660, January 11, 1963, Chapter 15, Table 15-B, Sheet 4a of

259 258 are normally billed in advance of rendering service. In the case of a telephone billing to a customer, both exchange service (billed in advance) and message tolls (billed in arrears) are credited to accounts receivable. In determining a composite revenue lag under the "accounts receivable" method, all advance billings should be deducted from accounts receivable. F DETERMINATION OF EXPENSE LAG DAYS 39. Expense lag arises when the utility receives credit for the various costs of rendering service which have been advanced to the utility by its suppliers, employees, and taxing agencies. The total cost of rendering service reflected in operating expenses, taxes and book depreciation, from which the average day lag of credit is determined, is that amount set out in the summary of earnings chapter. The expenses used to develop lag days are separated into their basic components, such as purchased commodities, company labor expensed, types of employee benefits, types of taxes, depreciation, materials, goods and services. 40. The methods of accruing expenses and dates of payment of expenses can be ascertained by the engineer in the review of the company's accounting techniques and practices. For purchased commodities, the number of lag days is the time from the midpoint of the monthly expense accrual to the date of the payment. For company labor, the number of lag days is the time from the midpoint of the pay period to the date of payment. For taxes, the number of lag days is the time from the midpoint of the monthly expense accrual to the date of the payment. Utility-contributed employees' benefits are ordinarily prepaid amounts and may be reflected in the operational cash requirement portion of the study as the average amount of the prepayment account. In that case, the expense lag will be zero lag days. If, on the other hand, prepaid employees' benefits are to be included in the lag study, the number of lead days is the time from the midpoint of the expense accrual date to the date of payment. Since book depreciation expense is occurring uniformly day by day and accumulated depreciation is deducted from the rate base, the practice is to include depreciation provisions at zero lag days. 1-15

260 Some companies pay their employees and some of their suppliers by commercial drafts rather than by a bank check. When a draft is used, no entry is made in the balance sheet accounts until the draft is returned to the utility to be exchanged for cash. Therefore, when a company used draft for remittances, the draft lag should be taken into account in the lag study. 42. There are instances where payments for expenses, such as state automobile licenses and state corporation franchise taxes, exceed the amounts that had been accrued to operating expense as of the date of payments. In such cases, the computation of lag days taken from the midpoint of the monthly accrual to the date of payment would be a negative lag day, or a "lead" day. Until such time as the accrued expense clears the deficit in the particular account, the days will be "lead" days. 43. The dollar amounts of goods and services (sometimes called "voucher items") are obtained by subtracting from total operating expenses all items of purchased commodities, company labor and benefits, taxes, depreciation and materials. The net balancing amount is taken as the goods and services. The determination of the lag days for this amount is determined by analyzing the disbursement journal for payments for the goods and services received. 44. The summation of the product of each operating expense and its respective number of lag or lead days equals the total dollar-day lag. Dividing the summation obtained above by the total expenses will result in the weighted average days of lead or lag of credit for the cost of service rendered and advanced by the utility's suppliers, employees, and taxing agencies. Table 3-A, Sheet 2 of 5, illustrates the proper format in the development of the lag days. Federal Income and State Corporation Franchise Taxes 45. For utilities which have used accelerated amortization to reduce income taxes, the Commission, in fixing rates, has permitted normalization of the income tax expense, thereby offsetting the reduction in the tax, but has deducted from the rate base the average accumulated deferred taxes due to accelerated amortization. Therefore, for those utilities where rates have been set on this 1-16

261 260 procedure, the lag days for the offsetting amount due to accelerated amortization should be zero. The reason for this is that the adjustment is already included in the rate base, and to assign the same lag days as for the actual income taxes would in effect be doubling the deduction from working cash. 46. As stated in Chapter 1, Paragraph 7, one working cash allowance at both present and proposed rates should be used in the test year. The state and federal corporation income taxes should be the estimated tax accruals that would result based upon the rate of return recommended by the staff's rate or return expert. 47. Table 3-A, Sheets 3 through 5, illustrates the procedure in developing amounts available to the investor as a result of collecting revenues in advance of paying expenses. This procedure, based on the "cost method" explained in Chart 3-A, results in monies being available on a daily average basis. This amount is then deducted from the operational cash requirement as shown in Table 3-A, Sheet 1 of 5. Should the end result indicate that there are excess funds not supplied by the investor, this amount should be deducted from the rate base Table 3-B has been included to assist the engineer in evaluating the effect of changes in working cash items on the working cash allowance. G MULTI-DEPARTMENT AND/OR DISTRICT UTILITIES - DETAILED BASIS 49. The procedure to determine the working cash allowance for multidepartment and/or district utilities is basically the same as that for a single company. First, the operational cash requirement is developed, and then the amount of monies resulting from the collection of revenues in advance of paying expenses and taxes and accruing depreciation is deducted from the operational requirement. 50. The operational cash requirement is analyzed for those items such as working funds and special deposits which can be assigned directly to the 16 "In an application for an increase in gas rates, it is equitable both to applicant's stockholders and to the ratepayers to deduct from rate base the average amount of working cash applicant has on hand not supplied by stockholders." Pacific Lighting Gas Supply Company, A-43670, D-63706, 59 Cal. PUC 610, 625 (1962). 1-17

262 261 particular department and/or district. The remainder of the items not directly assignable are then allocated to the respective departments and/or districts on the four-factor basis. 51. For multi-departmental utilities, the amount deducted from the allocated operational cash requirement as a result of collecting revenues in advance of paying expenses and taxes and accruing depreciation, is developed by analyzing the experienced lag or lead of revenues and expenses of the particular department. 52. Multi-district utilities pose a problem because of the different makeup in operating expenses and the different types of billing procedures followed by the various districts of a utility. For instance, not all districts incur a water replenishment assessment or purchase water for resale. The billing procedure of one district may be completely on a flat rate schedule while another district may be on a bimonthly metered basis. The following steps set out the recommended procedure to determine the working cash allowance for a particular district: a. Develop the average lag in payment of expenses and taxes and accrual of depreciation for the total company or department as shown in Table 3-A, Sheet 2 of 5 b. Group the total company or department expense items in the above table to correspond with classifications used in the summary of earnings chapter of the district results of operations report and determine the expense lags for the grouped items as illustrated in the following tabulation: (Refer to Table 3-A, Sheet 2 of 5) Expense Days Lag (Composite) Item Nos. Purchased Power or Commodity 33 1, 23 Franchise Requirements Federal Income Tax Income Taxes Deferred Due to Accelerated Amortization 0 11 Federal Insurance Contribution Act (10) 12 Federal Unemployment Insurance Tax Miscellaneous Federal Taxes 0 14 State Corp. Franch. Tax (275) 15 Also, The Pacific Telephone and Telegraph Company, C-7409, C-67369, 62 Cal. PUC 775, 821 (1964). 1-18

263 262 State Unemployment Ins. Tax State Use Tax-Paid Directly State Use Tax-Paid to Vendors State Auto. License Fees (150) 19 Miscellaneous State Taxes 0 20 Ad Valorem Taxes Miscellaneous Local Taxes 0 22 Depreciation 0 24 Other Operating Expenses* 19 2 to 8 (Lead) * Includes operation and maintenance expenses, administrative and general and miscellaneous expenses but excludes purchased power or commodity. c. Determine the composite expense lag for the district, using the district's operating expenses as set out in the summary of earnings chapter and the corresponding grouped lag days as developed in the preceding subparagraph. d. Develop the composite revenue lag based on the district's revenue collection experience. e. Apply the excess of expense lag over revenue lag to the total district's operating expenses and divide by 365 days to obtain the average amount of working cash capital available as a result of collecting revenues in advance of paying expenses and accruing depreciation. f. Deduct the amount derived in the above step from the operational cash requirement as allocated to the particular district on the direct and four-factor bases to obtain the working cash allowance. 1-19

264 263 TABLE 3-A Sheet 1 of 5 Detailed Basis California Light, Power, Gas & Water, Inc. Electric Department DETERMINATION OF AVERAGE AMOUNT OF WORKING CASH SUPPLIED BY INVESTORS Item Test Year Amount Operational Cash Requirement Total Electronic Indicated by Certain Balance Sheet Accounts Company Department 1. Average Minimum Bank Deposit $15,000,000 $ 7,500,000** Average Month-End Balances 2. Miscellaneous Special Deposits 1,700, ,000** 3. Working Funds - 250, Miscellaneous Receivables 220, ,000** 5. Prepayments 360, ,000** 6. Deferred Debits 900, ,000** 7. Total Operational Cash Requirement 18,180,000 9,340,000 Deductions from Operational Requirement - Average Amounts Not Supplied by Investors 8. Amounts Withheld, Primarily Employees' Income Taxes, Social Security Taxes, And Disability Insurance Contributions - 600, Deferred Credits 1,800, ,000** 10. User Taxes * - 373, Average Amount Available as Result of Collecting Revenues in Advance of Paying 1-20

265 264 Expenses and Taxes, and Accruing Depreciation * - (6,568,000) 12. Deduction from Operational Requirement (4,695,000) 13. Working Cash Allowance (7-12) 14,035, USE 14,035,000 (Red Figure) * Based on an assumed 7.0% rate of return for the Electric Department operation. ** Allocated by four-factor percentage. 1-21

266 265 TABLE 3-A Sheet 2 of 5 Detailed Basis California Light, Power, Gas & Water Inc. Electric Department DEVELOPMENT OF AVERAGE LAG IN PAYMENT OF EXPENSES AND TAXES AND ACCRUING DEPRECIATION Test Year Expenses, Avg. No. Thousands Taxes and of of Dollar- Item Depreciation Days Lag Days Lag (1) (2) (3) = (1) x (2) 1 Purchased Power or Commodity $ 2,500, ,500 2 Company Labor 24,100, ,500 3 Goods and Services 8,200, ,400 4 Materials Issued from Stores 1,500, Pension Provisions 500, ,500 6 Group Life Insurance 300, ,400 7 Injuries & Damage & Other 350, Insur. Provisions 8 Provisions for Uncollectibles a/ 175, Franchise Requirements a/ 750, , Federal Income Tax a/ 18,300, , Income Taxes Deferred Due to Accelerated Amortization 1,100, Federal Insurance Contribution Act 300,000 (10) (3,000) 13 Federal Unemployment Ins. Tax 50, , Miscellaneous Federal Taxes 1, State Corporations Franchise Tax 1,650,000 (275) (453,750) a/ 16 State Unemployment Ins. Tax 250, , State Use Tax - Paid Directly 40, , State Use Tax - Paid to 200, ,800 Vendors 19 State Automobile License Fees 120,000 (150) (18,000) 1-22

267 Miscellaneous State Taxes 1, Ad Valorem Taxes 13,000, , Miscellaneous Local Taxes 5, Fuel 9,500, , Depreciation 13,000, Total 95,892,000 1,536,640 (Lead) 1,536,640,000 95,892,000 = 16.0 Days a/ Based upon an assumed rate of return of 7.0% for the Electric Department operations. 1-23

268 267 TABLE 3-A Sheet 3 of 5 Detailed Basis California Light, Power, Gas & Water, Inc. Electric Department DEVELOPMENT OF AVERAGE LAG IN COLLECTION OF REVENUES RATIO OF ACCOUNTS RECEIVABLE (NOT INCLUDING UNBILLED SALES) TO CREDIT SALES METHOD Test Year 1. Total Sales a/ $129,050, Lag Days Service to Billing b/ 20 days 3. Total Dollar Days of Unbilled Sales - 2,581,000 Thousand Dollar-Days (Lines 1 x 2) 4. Summation for 365 Days of Accounts 2,710,050 Thousand Dollar-Days Receivable - Billed Customers 5. Deduct Advance Billing & Payments c/ - for 365 Days 6. Net Accounts Receivable - Billed Customers 2,710,050 Thousand Dollar-Days (Lines 4-5) 7. Total Dollar-Days (Lines 3 + 6) 5,291,050 Thousand Dollar-Days 8. Average Number Revenue Lag Days a/ 41.0 Days (Lines 7/1) AVERAGE AMOUNT OF CASH AVAILABLE AS RESULT OF COLLECTING REVENUES IN ADVANCE OF PAYING EXPENSES AND TAXES AND ACCRUING DEPRECIATION 1. Average Lag in Payment of Expenses and Taxes and Accruing Depreciation a/ 16.0 Days** 2. Average Lag in Collection of Revenues a/ 41.0 Days 3. Excess of Payment Lag Over Collection Lag (25.0) Days 1-24

269 Total of Expenses, Taxes and Depreciation $95,892,000** 5. Average Amount of Working Cash Capital Available as a Result of Collecting Revenues in Advance of Paying Expenses, Taxes and Depreciation (25.0) x $95,892,000 $ (6,567,643) 365 (Red Figure) USE (6,568,000) ** See Sheet 2 of 5 for development of these amounts. a/ Based upon an assumed 7.0% rate of return for the Electric department operation. b/ Assumes for the purpose of this example that the unbilled lag is the same for all classes of customers. c/ Applicable to flat rate water service and telephone exchange service which are normally billed in advance and are included in accounts receivable. 1-25

270 269 TABLE 3-A Sheet 4 of 5 Detailed Basis California Light, Power, Gas & Water, Inc. Electric Department DEVELOPMENT OF AVERAGE LAG IN COLLECTION OF REVENUES RATIO OF ACCOUNTS RECEIVABLE (INCLUDING UNBILLED SALES) TO CREDIT SALES METHOD Test Year 1. Total Sales a/ $129,050, Summation for 365 Days of Accounts 5,291,050 Thousand Dollar-Days Receivable - Customers 3. Deduct Advance Billing & Payments b/ - for 365 Days 4. Net Accounts Receivable - Customers 5,291,050 Thousand Dollar-Days (Lines 2-3) 5. Average Number Revenue Lag Days a/ 41.0 days (Lines 4/1) a/ Based upon an assumed 7.0% rate of return for the Electric Department operations. b/ Applicable to flat rate water service and telephone exchange service which are normally billed in advance and are included in accounts receivable. 1-26

271 270 TABLE 3-A Sheet 5 of 5 Detailed Basis California Light, Power, Gas & Water, Inc. Electric Department DEVELOPMENT OF AVERAGE LAG IN COLLECTION OF REVENUES STATISTICAL SAMPLING METHOD Test Year Avg. No. Thousands Annual a/ of of Dollar- Class of Service Revenues Days Lag Days Lag (1) (2) (3) = (1) x (2) 1 Domestic $48,100, $2,020,200 2 Agricultural 9,400, ,000 3 Commercial 27,200, ,033,600 4 Industrial 32,000, ,216,000 5 Public Authorities 8,300, ,900 6 Railways 1,100, ,600 7 Resale 2,250, ,000 8 Miscellaneous 700, ,500 Totals 129,050,000 5,310,800 Average Lag = 5,310,800 = 41.0 Days 129,050 a/ Based upon an assumed 7.0% rate of return for the Electric Department operations. 1-27

272 271 TABLE 3-B EFFECT OF CHANGES IN WORKING CASH ITEMS ON WORKING CASH ALLOWANCE Changes in Working Cash Items Effect on Working Cash Allowance 1 An increase in Balance Sheet Current Assets Increase A decrease in Balance Sheet Current Liabilities Decrease 2 If payment lag days of an expense item are lead days, zero or less than the composite average expense lag days An increase in dollar amounts of an expense item A decrease in dollar amounts of an expense item Increases Decreases 3 If payment lag days of an expense item are greater than the composite average expense lag days An increase in dollar amounts of an expense item A decrease in dollar amounts of an expense item Decreases Increases 4 If collection lag days of a particular revenue class are greater than the composite average revenue lag days An increase in dollar amounts of a revenue class A decrease in dollar amounts of a revenue class Increases Decreases 5 If collection lag days of a particular revenue class are less than the composite average revenue lag days An increase in dollar amounts of a revenue class A decrease in dollar amounts of a revenue class Decreases Increases 6 If composite average expense lag days Increases Decreases 1-28 Decreases Increases

273 272 7 If composite average revenue lag days Increases Decreases Increases Decreases 1-29

274 273 Chapter 4 PREPARATION OF STAFF REPORT 1. The working cash allowance is included in the table in which the rate base is developed in a results of operation report. An explanation of the basis used to develop the allowance should be included in the text of the rate base chapter. 2. The following paragraph on working cash is suggested for inclusion in the staff report where the determination of the allowance has been made on the simplified basis: An allowance for working cash is included in order that the investors may be compensated for moneys which they have supplied for the operations of the utility over and above the investment in tangible and intangible property. The working cash allowance is a judgment amount which gives effect to a certain number of months' average operating expenses, based upon the manner in which the utility's expenses and revenues are billed 1 and to the offsetting effect of average accruals available because of lag in the payment of taxes. 3. Where the determination of the allowance has been made using the detailed basis, it is suggested that the following paragraph be included in the staff report: An allowance for working cash is included in order that investors may be compensated for monies which they have supplied, over and above investment in utility property, and for funds provided by them which are committed to the business for the following purposes: 1. Payment of operating expenses in advance of receipt of revenues from its customers. 2. Maintaining working funds and minimum bank balances. 3. The incurrence of certain deferred debits and credits not included in the income statement. 1 For utilities operating as individuals or partnerships, the paragraph will end here. 4-1

275 The engineer in explaining the basis of developing the working cash allowance should include references to Commission decisions which set the precedent for the basis in developing the working cash allowance. Chapters 2 and 3 of this Standard Practice cite some of the more important decisions which would be useful as references. 4-2

276 275 APPENDIX I (Referred to in Table 2-C) Derivation of Basis for Calculating Federal Income Tax Applicable To Increase in Net Revenue for Incorporated Companies (insert graph here) (insert abbreviations here) i

277 276 TESTIMONY OF TURN WITNESS WILLIAM MARCUS ON CUSTOMER DEPOSITS, SCE 2003 TEST YEAR GENERAL RATE CASE

278 277 Report on Various Results of Operations Issues in Southern California Edison s 2003 Test Year General Rate Case Prepared testimony of William B. Marcus JBS Energy, Inc. 311 D Street West Sacramento California, USA on behalf of The Utility Reform Network California Public Utilities Commission Application December 6, 2002

279 278 Instead, we adopt TURN s recommendation not to be contributed [sic] these dollars to the trusts until they are tax-deductible. Any money which is collected but not yet contributed then becomes a rate base offset, which is reduced by deferred taxes associated with the asset for the taxes due when the money is collected. This approach will address necessary tax requirements, but avoids imposing an additional cost on the ratepayers. This is an example of an approach which aligns both shareholders and ratepayers interests. (D , slip op. at 152) By not contributing this accelerated contribution to the PBOPs trust fund, PBOPs expense in the current year is higher than it would otherwise be (because the investment on which a return would be earned is less). 17 Ratepayers must be compensated for this cost. TURN therefore recommends that $20,684, be treated as a rate base offset consistent with the ratemaking adopted in D Edison should be allowed to request that the rate base offset be discontinued on a going-forward basis after 2003 (in conjunction with any annual rate adjustment) upon a showing that the accelerated funds were in fact contributed to the fund. D. Customer Deposits Should Be an Offset to Rate Base The utilities require that an applicant for new service be required to establish credit with the utility under Rule 6 Establishment and Reestablishment of Credit. If the customer has not qualified for the establishment of credit with the utility, then they are required to submit a deposit to the utility under Rule 7. This policy pertains to both the utility s residential and nonresidential customers. As outlined in Rule 7 (p. 2), the utility must return deposits to the customer (provided the customer s service is not temporarily, or permanently 17 See response to TURN DR 10-15, which states that contributions actually made from accelerated CTC contributions reduce ratemaking expenses. This means that contributions from accelerated CTC that were never made increase ratemaking expenses. 18 $34,908,000 not contributed to the trust net of $14,224,000 of deferred taxes at full statutory state and federal rates. Testimony of W. B. Marcus for TURN Page 38 CPUC App (Edison 2003 TY GRC)

280 279 discontinued due to nonpayment of bills) with interest. According to this rule, the interest rate applicable is the interest rate on commercial paper (prime, 3 months) as reported by the Federal Reserve Statistical Release. Customer deposits represent a source of working capital to utilities that is not provided by investors. The only difference from other sources of permanent capital not supplied by investors (accrued vacation, user taxes, etc.) is that the utility must pay its ratepayers interest at the Commercial Paper rate. The amount of customer deposits is substantial, as shown in Figure 3, taken from Edison s response to TURN DR (Attachment 17) As of October 2002, Edison holds over $142 million of its customers money as deposits, for which it pays an interest rate based on commercial paper (today less than 2%). With the exception of the end of the year 2000, Edison has held over $80 million in customer deposits at the end of each year from 1996 to date. Moreover, Edison appears to have made a policy change to increase either the number of deposits or the amount of deposits per customer or both in Deposits increased over $30 million in a single month (from February to March, 2002) and have increased by $15 million more since then. (Figure 3) Testimony of W. B. Marcus for TURN Page 39 CPUC App (Edison 2003 TY GRC)

281 280 Figure 3: Edison s Customer Deposits Edison's Customer Deposits, $ millions Jan-98 Apr-98 Jul-98 Oct-98 Jan-99 Apr-99 Jul-99 Oct-99 Jan-00 Apr-00 Jul-00 Oct-00 Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Testimony of W. B. Marcus for TURN Page 40 CPUC App (Edison 2003 TY GRC)

282 281 Many states reflect customer deposits as a source of capital for ratemaking purposes. Each of the other states in which I have worked most recently reflect customer deposits either as a reduction to rate base (working capital not provided by investors) with interest added back to operating expenses (Arizona, Oklahoma, Maryland) or as an element of the capital structure itself (Arkansas, Nevada). The Alberta Energy and Utilities Board also included customer deposits in the capital structure of the Alberta utilities (over utility objections) in 1999/2000 (the last case before the province went to 100% retail access and the amount of deposits was significantly reduced as a result). This Commission last reviewed the issue in the 1996 cost of capital case, when the issue was referred to a workshop. No action was ever taken by the Commission. TURN understands that the 1969 Standard Practice U-16 provides that interestbearing items are not included in working capital. Nevertheless, this policy requires review for the specific case of customer deposits, given the information provided above and the passage of 33 years since its adoption, 19 and in light of the contrary practice of a number of other jurisdictions. Customer deposits represent a source of capital that the utility has on a permanent basis, unlike short-term debt borrowed to fund balancing account undercollections or as a bridge before permanent long-term debt or equity financing is obtained. In the case of deposits, as funds are repaid to some customers, other customers pay deposits. Over time, the utility continually holds a significant block of funds To give some perspective, in 1969, Ronald Reagan was Governor of California, and the witness sponsoring this testimony, who is nearly 50 years old, had not yet graduated from high school. 20 This is analogous to the treatment of employee vacation as a permanent source of capital not provided by investors, even though the individual transaction may be on the books for a relatively short period of time between the time when the employee accrues the vacation and uses it. Nevertheless, it is treated as permanent working capital not supplied by investors. The only difference between accrued vacation and customer deposits is the pittance of interest paid on the deposits. Testimony of W. B. Marcus for TURN Page 41 CPUC App (Edison 2003 TY GRC)

283 282 It pays less than 2% interest on them at present. At the same time, Edison s rate of return on rate base (including working capital supplied by investors) is in excess of 13% including income taxes on the equity return. TURN recommends that the Commission reduce Edison s rate base by $ million, based on the most recent 13-month average of customer deposits (October 2001 to October 2002). This calculation is conservative in light of the large increase in deposits between March and June of 2002 and the most recent recorded figure of $142 million. If the Commission treats deposits as a rate base offset, it should also increase Edison s operating expenses by $3.343 million to reflect interest on deposits at a projected 2% interest rate. X. The Commission Should Abolish the Service Establishment Charge, Not Increase It. Prior to 1996, Edison had a service establishment charge of $5 for next-day service and $10 for same-day service. In Decision , Edison was granted a service establishment charge of $10 for next-day service and $17.50 for sameday service. Edison is now proposing to increase the charges to $17 and $27 respectively based on its new estimates of cost. Edison s estimate of revenue from the service establishment charge at current levels is $ million; with its proposed increase, it forecasts revenue of $ million. TURN believes that a utility service establishment charge is simply a bad public policy. 21 It is aimed at recovering the cost of establishing service from customers who move. As a result, it has highly disproportionate impacts on renters and 21 We did not propose a rollback in 1996, because we did not expect to be heard sympathetically on the topic (particularly after SoCal Gas received an increase in 1994). However we did oppose Edison s proposed increases to the charge and it was not increased as much as Edison proposed. Testimony of W. B. Marcus for TURN Page 42 CPUC App (Edison 2003 TY GRC)

284 283 TESTIMONY OF TURN WITNESS WILLIAM MARCUS ON CUSTOMER DEPOSITS, 1995 GENERIC COST OF CAPITAL PROCEEDING

285 284

286 285

287 286

288 287

289 288 EXCERPT FROM A , EXHIBIT SCE-11B

290 289 Application No.: Exhibit No.: SCE-11, Vol. 2 Witnesses: S. Abbott R. Boada G. Bridges T. Felix R. Fisher D. Klun R. Pierce O. Thomsen (U 338-E) 2009 General Rate Case Results of Operations (R/O) Volume 2 Plant, Taxes, Depreciation Expense And Reserve, And Rate Base Before the Public Utilities Commission of the State of California Rosemead, California November 2007

291 C. Permanent Working Capital Adjustments: Customer Deposits And Nuclear Fuel Inventory 1. Introduction And Summary Of SCE s Proposal This section discusses two working capital items: customer deposits and nuclear fuel inventory. Some intervenors in previous proceedings 106 have argued that customer deposits -- funds held by the utility to secure bill payment -- represent a source of funds available to finance rate base. Although customers earn a short-term interest rate while these funds are held as bill payment security, 107 these intervenors have pressed for a reduction in rate base to account for the perceived ongoing availability of these funds. As discussed in the Section 2 below, the Commission has yet to set forth a consistent policy regarding customer deposits. In a similar sense, nuclear fuel inventories offer some parallels to customer deposits as working capital-sources and uses. Because ongoing inventory balances must be maintained for plant operation, these inventories are permanent assets which require financing. In effect, nuclear fuel inventory represents a mirror image of customer deposits, due to its permanence qualities. However, in prior proceedings the Commission has established a policy of financing fuel inventories with short-term debt. SCE s proposal in this proceeding attempts to reconcile the customer deposit issue within established Commission precedents while recognizing its financial impacts and permanent aspects. SCE recommends that the Commission deem customer deposit balances a source of financing for nuclear fuel inventories. As discussed in more detail below, this proposal has the following benefits: It is consistent with the Commission s Standard Practice U-16 and other precedents, which treat customer deposits as short-term debt. It will maintain the existing Commission policy of financing fuel inventories with short-term debt. 106 See for example, TURN, William B. Marcus, Exhibit 231, SCE 2003 General Rate Case A , December 6, 2002, and TURN, Marcus, Exhibit TURN-01, PG&E 2007 General Rate Case, A , June 20, Interest is suspended if a customer s bill is past due. 92

292 It recognizes the permanent nature of fuel inventories as well as the permanent aspects of customer deposits. It will establish and maintain a fair balance between investor risks and customer costs. As shown in the sections that follow, SCE s projected nuclear fuel financing requirements are expected to exceed the funds available from customer deposits between 2009 and As a result, SCE will need to access the capital markets for the additional funds required to fully finance these inventories. Below, Section 2 briefly reviews recent regulatory history on customer deposits and fuel inventories. Sections 3 and 4 describe nuclear fuel inventories and customer deposits and their permanent characteristics. In Sections 5 and 6, the testimony discusses the negative financial impacts of the current Commission policies on nuclear fuel inventories and customer deposits. Sections 7 and 8 explain how SCE s proposal complies with current Commission policies and balances shareholder and customer interests. 2. Regulatory History Of Customer Deposits And Fuel Inventories a) Customer Deposits Prior to SCE s 2003 GRC, the Commission followed the ratemaking approach outlined in Standard Practice U-16 for customer deposits. SP U-16 states that interest-bearing customer deposits are to be excluded from working cash adjustment calculations. 108 The interest rate on customer deposits was set at the utility s short-term borrowing rate in a 1980 Commission decision that also governs the interest rate calculated on balancing account over- and under-collections. However, in response to TURN s recommendation in SCE s 2003 GRC, 109 the Commission decided that a portion of SCE s customer deposit balances should be deemed a source of permanent working capital and included 108 California Public Utilities Commission Utilities Division, Determination of Working Cash Allowance, Standard Practice U-16, September 13, 1968, pp See TURN, William B. Marcus, Exhibit 231, SCE 2003 General Rate Case A , December 6,

293 as an offset to rate base. 110 Although SCE did not agree with this finding, the Company implemented it accordingly. In its 2006 GRC, SCE followed the Commission s 2003 GRC Decision and deducted customer deposits from rate base. However, in the March 2007 decision in PG&E s most recent GRC the Commission rejected a rate base adjustment for customer deposits. Although this decision adopts a settlement and therefore cannot be deemed precedential, the text of the decision suggests questions remain regarding the proper policy. The decision states: The largest issue regarding working cash is whether to adopt Aglet s and TURN s proposal to treat customer deposits as a reduction to working cash. We decline to adopt their proposal. The record shows that PG&E and the Settlement Agreement calculated working cash in accordance with SP U-16, which has been in effect since As such, we view the Settlement outcome on working cash as presumptively reasonable. Aglet and TURN raise several arguments for why it is appropriate to depart from a key element of SP U-16. Perhaps their best argument is that the Commission s decisions in the two most recent GRCs for SCE departed from SP U-16 and deducted customer deposits from working cash. They assert that the Commission should treat PG&E the same as SCE. We disagree. Our review of Commission precedent reveals that SCE is somewhat of an aberration in this regard. In the last two years alone there have been numerous Commission decisions that relied on SP U-16 to determine working cash. See for example, D and D b) Nuclear Fuel Inventories Although it is not SCE s intent to argue for rate base treatment of fuel inventories in this proceeding, a brief review of the regulatory history associated with this asset provides some useful background. Prior to the institution of separate Energy Cost Adjustment Clause (ECAC) proceedings to address fuel costs, SCE's fuel inventories were treated exactly like other inventories. Fuel inventory levels were set in GRC proceedings and variations in costs from the levels set were the responsibility of shareholders. Fuel inventories still receive this ratemaking treatment in resale jurisdictions regulated by the Federal Energy Regulatory Commission (FERC) D (mimeo), pp D (mimeo), p See 10 FERC Paragraph 61,238, at pp. 61, (1980). 94

294 When separate proceedings were instituted for fuel costs in California, fuel inventories were split from other capital assets and considered along with other fuel costs. The Commission reassessed its treatment of fuel inventories in SCE's 1985 ECAC proceeding, and in D authorized SCE rate recovery of short-term interest costs on its investment in fuel oil inventory. 113 Because fuel oil inventory cost recovery was accorded balancing account treatment, the Commission determined that the investment risks for this asset did not warrant recovery at the weighted average cost of capital rate. In subsequent decisions, the Commission applied similar principles to nuclear fuel, gas, and coal inventories. 114 Due to changes in the composition of SCE s generating fleet related to industry restructuring and other regulatory requirements, nuclear fuel is now the only remaining fuel with sizeable inventories. In response to the Commission s 2003 policy change for SCE s customer deposits, SCE s 2006 GRC application pointed out the similarities between customer deposits and nuclear fuel inventories and requested parallel treatment of the two. SCE stated that if customer deposits constituted permanent funds and were thus deducted from rate base, nuclear fuel inventory, a permanent asset, should be included once again in rate base. 115 SCE s proposal for 2009 retains financing for nuclear fuel inventory at the short-term debt rate, and thus differs substantially from its 2006 request. In the next two sections this testimony points out the features of fuel inventories and customer deposits salient to their disposition in working capital. 3. Nuclear Fuel Inventories Are Long-Term Permanent Assets Nuclear fuel does not meet the strict definition of an inventory because, unlike other inventories that are set aside for future use, nuclear fuel is either being processed or being utilized while in the core of a nuclear unit. Nonetheless, it is an asset with inventory-like characteristics. As discussed 113 D (mimeo), p D (mimeo), p A , Exhibit SCE-8, Volume 2. 95

295 below in the testimony of Owen Thomsen, 116 SCE s nuclear fuel inventory is divided into two components, pre-core and in-core fuel. Although these two components receive different ratemaking treatment, both components are assets currently financed with short-term debt. During the processing period for pre-core fuel, the raw material and processing costs are financed with short-term debt. No fuel costs are recovered in rates during this time. As a result, the ratemaking for pre-core nuclear fuel is analogous to AFUDC, in which all costs, including financing costs, are incorporated in the asset s value. Once the fuel is placed into the reactor and nuclear power generation has begun, it becomes in-core fuel, which is then utilized in energy production for a period of years before it is replaced. The value of in-core fuel is amortized over the fuel s life and recovered through the ERRA proceeding. The unamortized portion of in-core fuel is financed with short-term debt. Nuclear fuel inventory is an integral part of plant operations for the life of a nuclear power plant. As a result, it must be considered a permanent asset like other inventories. A basic financial principle is that assets should be financed with instruments with similar lives. By financing a long-term asset for the length of its life, a company is following a prudent financial policy of asset and liability matching. 117 Because permanently maintained nuclear fuel inventories function like long-lived assets, they should be financed with similarly long-lived instruments. Commission treatment of other inventories is consistent with this financial principle. Inventories of materials and supplies are set in GRC proceedings every three years and receive financing cost recovery based on the weighted average cost of capital. As discussed in Mr. Thomsen s testimony, the value of SCE s nuclear fuel inventory at any point in time is substantial. Table IV-28 shows the projected combined average balance of SCE s out-of core and in-core nuclear fuel for SCE s nuclear fuel balance is projected to average $260 million over this time period. 116 Mr. Thomsen s testimony is found in Chapter IV, Section C.10, below. 117 As discussed in Section 5 below, a basic tenet of corporate finance is that assets and liabilities should have similar economic lives in order to properly match duration risks. 96

296 295 Table IV-28 Projected Nuclear Fuel Financing Requirements, (Nominal $millions) Average Pre-Core Fuel Balance Average In-Core Fuel Balance Combined Nuclear Fuel Balances Customer Deposits Are Short-Term Debts With Some Permanent Characteristics In response to the Commission s 2003 GRC decision on this issue, SCE implemented the Commission s ruling that funds provided by customer deposits have permanent characteristics. 118 However, Commission policies on customer deposits should recognize that the ongoing existence of deposit balances does not change the fact that each deposit is a short-term obligation owed to an individual customer. In general, customer deposits are returned as soon as a customer makes on-time payments for 12 months or when an account closes. 119 Customers receive interest based on SCE s short-term borrowing rate, which varies with the prevailing market rate. As a result, from a financial perspective, each customer deposit is a short-term debt. Because these deposits are short term in nature and the principal is repaid in full, it is appropriate to provide customers a relatively low interest rate on the balance. Customer deposits do not bear the same risks as funds from common shareholders or holders of long-term bonds, whose principal may be substantially at risk from either internal company circumstances or external market forces. In the capital markets, equity investors and long-term bond holders are compensated for this additional risk with higher rates of return compared to short-term lenders. Use of the utility s short-term borrowing rate to compensate customers for their deposits is fully in keeping with the policy of fairness stated in the concurring decision of Commissioner Simon 118 As discussed in Section 2 above, the Commission subsequently characterized its ruling as an aberration. 119 Customer deposits are usually applied to a customer s energy bill at the end of the 12 months. Alternatively, customers may request a refund check. 97

297 in PG&E s 2007 GRC: To the extent that customers are making a capital contribution through this deposit process, they should be treated on par with other sources of capital including, but not limited to, the investment banking and commercial banking community. 120 By using the interest rate the utility pays to other short-term lenders, customers are compensated on par with other investors taking the same risk. This policy also parallels long-standing regulatory principles outlined by the U. S. Supreme Court that investors should be provided rates of return commensurate with the returns on investments of similar risk Financial Impact Of Current Commission Ratemaking For Fuel Inventories And Customer Deposits a) Consistent Regulation Is Key To Financial Flexibility While recognizing that the Commission s decisions are based on a variety of factors, the importance of the opinions of the financial community about the effect regulatory decisions may have on the financial strength of a regulated company cannot be emphasized too strongly. Investors will react with demands for higher returns on all borrowed or invested monies if regulatory decisions result in a diminution of cash flow available to pay all business and financial obligations. 122 In the case of regulated utilities, cash flow is primarily affected by the returns allowed, and the amount of equity and the size of the rate base on which they are allowed to earn those returns. Cash flow also stems from the return of invested capital through the recovery of depreciation expense in rates. Rating agencies and institutional investors carefully examine the ability of companies they rate and invest in to 120 D Bluefield Waterworks & Improvement Co. v. Public Service Commission of West Virginia et al. ( Bluefield, 262 U.S. 679, 43 S.Ct. 675 (1923)), and Federal Power Commission et al. v. Hope Natural Gas Co. ( Hope, 320 U.S. 591, 64 S.Ct. 281 (1944)). 122 Cash flow is a key element in investors assessments of a firm s ability to withstand financial stress. If fixed costs such as interest expense absorb a major proportion of cash flow, a company will be less able to avoid default in the face of a sudden drop in revenues or unforeseen increase in costs. 98

298 generate cash flow to ensure that the reward associated with such an investment is commensurate with the risks being taken. 123 The most important issue in the assessment of a regulated utility is the quality of regulation. Rating agencies evaluate the regulatory environment to assure themselves that it is consistent, fair and balanced. Standard & Poor s (S&P) emphasizes that their analysts look at the ability of the commission to render a fair and balanced decision that appropriately considers the interest of all the participants in the process. 124 An inconsistent or unbalanced regulatory environment puts pressure on a company s financial flexibility, and therefore its ratings. Lower ratings increase the cost of capital and decrease market access. These additional costs eventually find their way into the rates the company charges its customers. Therefore, maintaining a high level of financial flexibility, and therefore rating level, will accrue to the benefit of the customer. A consistent and logical treatment of rate base and expenses is essential for rating agencies to form a good opinion of the regulatory environment in which a company operates. The Commission s current regulatory treatment of the two items under discussion, customer deposits and fixed fuel inventories, (1) affect cash flow, and (2) demonstrate a lack of consistency in regulatory treatment. The Commission has treated customer deposits as permanent short-term debt, taking it out of the rate base, but allowing the expense of the interest paid customers on their deposits to be included as a financial expense. This issue is a subtle detail in the arena of credit analysis, but if coupled with other potential cash flow sapping rulings, could seriously affect the financial flexibility of the company. Rating agencies will assign risk to (1) the never-ending need to repay the deposits on a regular basis, converting customer deposits into a debt-like instrument like they do purchased power, and (2) the interest rates assigned to the deposits since they are based on short-term rates, which are quite volatile. 123 Because rating agencies act as proxies for institutional investors, only rating agencies will be directly referred to in this testimony. 124 Utility Regulation Determines its Ratings, Standard & Poor s, Online Exclusive, February 3,

299 In addition, and compounding the pressure on the company s cash flow generation capability, is the Commission stance on nuclear fuel inventories. Where short-term customer deposits are being treated as a source of long-term financing, nuclear fuel inventory, a long-lived asset, is being treated as a short-term item that is fully covered by the fuel adjustment mechanism. Nuclear fuel inventories are, as discussed in Section 3, long-term permanent assets and should be supported by long-term financing like other rate-based long-lived assets. However, the Commission treats fuel inventories as short-term assets to be supported by short-term debt. b) Corporate Finance Practices It is one of the most basic tenets of good corporate finance practices that long-term assets be financed with long-term sources of capital, and short-term assets with short term capital. In the Foundations of Financial Management on-line course from Texas Christian and DePaul Universities, Professors Block and Hirt write short-term sources of financing should be used to finance all current assets and long-term sources of financing should be used to finance all assets with maturities of more than one year. 125 Rating agencies routinely analyze an enterprise s use of debt to finance assets, fully expecting that in most cases, asset life and financial support will match in tenor. When short-term debt is used to finance long-term assets, rating agencies become discomforted with the increase in risk associated with the need to refinance a fixed asset frequently. The nature or earning power of the fixed or long-term asset does not change, but financing a long-term asset with short-term debt introduces uncertainty as to cost and availability of funds as the debt needs to be continuously rolled over. Regardless of how interest rates behave at any given moment, the uncertainty associated with potential movement in rates is anathema to investors. In addition, financial markets can become difficult to access in times of turmoil, even when that turmoil has nothing to do with the borrower in question. Therefore, rating agencies are much more comfortable when asset lives and debt maturities reflect one 125 E-Learning Session, Working Capital and the Financing Decision, 100

300 another rather than a company being exposed to the risks associated with a short term maturity schedule for assets with long lives. Because uncertainty is created by short-term borrowing, and a mismatch between asset life and financial support can bring a firm s financial management into question, investors will require a greater financial cushion in order to continue to lend at comparable rates to a firm with such a mismatch. Conversely, the firm with a mismatch between asset life and financial support will be required to pay more in the marketplace for both borrowed and invested money. As a result, that firm s financial flexibility will be reduced, and the credit capacity necessary to cover other aspects of operations, such as collateral requirements or balancing account under-collections, will be diminished. Over all, the cascading effect of a mismatch between asset life and financing can multiply the damage that might be recognized at first glance. In any complex firm, financial management policies must consider the totality of assets to be financed rather than try to match each asset with discrete financing. Rating agencies are more concerned with the resulting cash generating capability a firm achieves rather than specific details on how it was achieved. Given the mischaracterization of customer deposits as permanent financing, and fixed nuclear fuel inventories as short-term assets, an appropriate counterbalancing of these two issues would inure to the benefit of both shareholders and customers and satisfy the rating agencies needs for consistency and balance. c) Liquidity And Risk Management Issues While the most visible and well understood rating agency guidelines concern financial metrics such as Funds Flow from Operations (FFO) as percent of Outstanding Debt, FFO/interest, and capitalization ratios like Debt as percent of Total Capitalization, the rating agencies examine and measure many other metrics to determine ratings. Moody s in particular has separated many of the elements in the rating process into their component parts. Two of the issues they examine quite closely are liquidity and risk management. Moody s calls liquidity analysis a core element of 101

301 fundamental credit analysis. 126 Good risk management incorporates an analysis of risk from all sources 127 that could have a deleterious effect on the financial condition of a company. One of the major issues for an assessment of liquidity is a company s internal cash resources. While rating committees at Moody s disaggregate liquidity into four components (internal sources, external sources of committed financing, covenants and alternative liquidity) Moody s clearly states that internal cash sources are the most significant driver of liquidity ratings. 128 Internal cash is generated from the returns earned on equity and rate base, as mentioned above. To exclude fixed assets like permanent fuel inventory from rate base diminishes internally generated cash flow, and therefore liquidity, which is necessary for a healthy financial condition and maintenance of an investment grade rating. Likewise, prudent risk management requires that managements guard against events that reduce core earnings capacity, or increase the volatility of earnings. Excluding the fixed portion of the fuel inventory from rate base would have the effect of reducing core earnings capacity at the least. If fixed fuel inventory were allowed to be financed with customer deposits, the deleterious effect of removing both customer deposits and fixed fuel inventory from the rate base would be somewhat abated. The Commission granting such treatment would also be looked on as the proper and prudent thing to do by the financial community. d) Balancing Customer And Investor Interests As mentioned at the beginning of this section, rating agencies are especially sensitive to balance in regulatory decision-making. While recognizing that regulators stand proxy for the marketplace by assuring utilities provide reliable service at a reasonable price, including a fair return, rating agencies react negatively when they believe decisions are made to favor the customer at the expense of the investors in the company. 126 Moody s Observations on Speculative-Grade Liquidity Ratings, Special Comment, Moody s Investors Service, November Risk Management Assessments, Research Methodology, Moody s Investors Service, July Id. 102

302 Eliminating customer deposits from rate base has reduced rate base by the amount deemed permanent short-term funding by the Commission. Using customer deposits as a means to finance fixed nuclear fuel inventories would allow SCE to minimize the cost of funding for the fuel, which benefits customers. At the same time, the rate base shareholders depend on for their return will not be jeopardized by the volatility of customer deposits. This proposal is a fair tradeoff, and would be viewed neutrally by the rating agencies. Doing anything less would erode the financial stability of the company and raise concerns at the rating agencies and in the financial community at large. 6. Rate Base Adjustments For Customer Deposits Increase Shareholder Risk As discussed in Section 5 above, the Commission s current customer deposit policies for SCE have negative impacts on SCE s financial condition. Using these funds to finance permanent assets exposes the Company to additional cash flow volatility not seen with other long-term financing due to both volume and price exposures. First, SCE is exposed to the volatility of customer deposit balances themselves. To the extent balances are below predicted, SCE must borrow more capital and shareholders must absorb the cost of these funds. Second, SCE s operating costs are credited with an amount to cover the short-term interest rate owed to customers on their deposits. Because short-term rates are highly volatile, shareholders are placed at risk for variations in these rates as well. For example, in SCE s last GRC, the Company forecast that its short-term rate would equal 3.59 percent for Instead, SCE s short-term borrowing costs were substantially higher, averaging approximately 5 percent in SCE is not exposed to such volatility on its long-term debt portfolio, where the vast majority of its debt rates are fixed and predictable. This volatility disadvantages customers as well as shareholders. To the extent greater volatility increases bondholder and shareholder return requirements, the utility s cost of capital will increase, raising electricity rates. In addition, because interest rates are unpredictable, forecasting error cannot be avoided and over time will work to the detriment of customers as well as to their benefit. As discussed in Section 8, SCE s proposal will address both volatility and risk imbalances by eliminating 129 A , Exhibit SCE-8, Volume 2, p

303 the need to forecast both the amount of customer deposits and the credit in the GRC for the interest owed to customers. 7. SCE s Proposal Is Consistent With Prior Commission Policies The Commission s Standard Practic U-16 has governed working cash calculations for nearly 40 years. U-16 simply says that only non-interest bearing deposits should be considered in working cash calculations. 130 This practice recognizes that if a utility is already paying interest on the funds, an additional deduction to account for their value is not appropriate. However, U-16 does not specify the rate to be paid on the funds, nor does it attempt to identify the potential uses of the funds. The application of the utility s short-term debt rate to customer deposits stems from D.91269, which has governed the use of short-term borrowing rates for more than 25 years. This decision chose to use the utility commercial paper rate for balancing account over- and under-collections in order to reasonably reflect the cost of short-term borrowing available to the utilities. The Commission also concluded that the same considerations supporting the decision on balancing account borrowing costs applied to other interest bearing deposits as well, and adopted the same interest calculations for customer deposits. 131 Neither SP U-16 nor D recognize how customer deposits may be used by the utility, and it is this policy gap that remains to be fully resolved. The Commission s ruling in SCE s 2003 GRC deems that customer deposits are available to meet the utility s financing needs and treats these deposits as perfect substitutes for the other two principal sources of long-term financing, shareholder equity and long-term debt. As discussed in Sections 5 and 6, customer deposits provide no support for the utility s credit quality, and in fact, increase earnings volatility. As a result, customer deposits are not equivalent to long-term debt and equity, nor should they be treated as an exact replacement for them. By adopting SCE s proposal to apply customer deposits toward financing nuclear fuel inventories, the Commission can match this source of funds to a parallel asset. This policy recognizes 130 SP U-16, p D.91269, OII No. 56 (January 29, 1980,) Decisions of the Public Utilities Commission of the State of California, Volume 3, CPUC 2d, pp

304 the validity of SP U-16, compensates customers at the risk-appropriate interest rate determined in D.91269, and acknowledges the permanent aspects of both fuel inventories and customer deposits. 8. SCE s Proposal Simplifies Current Ratemaking Procedures Table IV-30 shows that SCE s customer deposit balances are projected to average $249 million for 2009 to SCE s nuclear fuel financing requirements are projected to exceed these balances over the same time frame, averaging $260 million. SCE will access the capital markets for the additional short-term debt needed to support nuclear fuel financing in excess of the amount available from customer deposits. Because SCE has proposed that nuclear fuel will continue to be financed with short-term debt, there will be little change to the ERRA cost recovery mechanism for nuclear fuel. Pre-core fuel will continue to accrue financing costs at SCE s short-term borrowing rate, and the financing costs associated with in-core fuel balances will be incurred at the same rate. Interest on deposits earned by customers will be paid at the short-term borrowing rate as well. SCE will recover in ERRA the short-term interest on the outstanding nuclear fuel inventory value, and these funds will be used to compensate customers for interest owed on their deposits. Amounts remaining after customers are compensated will pay for interest on the external short-term borrowing covering the shortfall between the funds from customer deposits and the value of the fuel inventories. 132 This approach will simplify current ratemaking by removing the rate base deduction for customer deposits and eliminating the additional GRC expense currently recovered to compensate the utility for interest paid on customer deposits. 9. SCE s Proposal Sets A Fair Balance Between Customer Costs And Investor Risks Finally, this proposal will maintain a fair balance between investor risks and customer costs. Nuclear fuel inventories will continue to be financed with funds bearing interest at the utility s short-term borrowing rate. Investors will not bear inappropriate risks from the use of customer deposits 132 Therefore, the only change required in the ERRA proceeding will be revisions to fuel inventory interest reporting and forecasting to account for the use of customer deposits as a financing source. In accordance with current ERRA balancing account policies, only actual interest costs will be recovered. 105

305 to finance rate base assets. Not only does this represent good regulatory policy, but as discussed in Section 5 such policies are instrumental in supporting utility credit quality. Thus, this policy will continue to maintain the utility s financial integrity and limit the long-term cost of capital rates paid by customers. 10. Nuclear Inventory Nuclear fuel inventory is carried as either pre-core (fuel in process prior to installation in the core during refueling) or in-core (unamortized fuel in the core of a nuclear unit following refueling). Pre-core nuclear fuel value includes all batch component purchases incurred prior to installation of the new fuel batch in the reactor core during refueling. Batch components include uranium, conversion, enrichment, fabrication, vendor engineering and carrying costs. Purchasing of batch components begins a minimum of eight months prior to installation in the core during refueling. Upon installation in the reactor core, pre-core costs are transferred to the in-core unamortized nuclear fuel balance. Once the fuel is placed in the core, it is then maintained there for a period of years before it is replaced. Only a portion of the in-core fuel in each nuclear unit is removed during any refueling and a portion always remains in the core. Furthermore, some amount of pre-core fuel is always being processed in preparation for the next refueling. As pre-core fuel is processed for a refueling, the pre-core balance tends to rise as the associated in-core balance declines. As a result, the amount of nuclear fuel in place at any time is substantial. With respect to the Palo Verde Nuclear Generating Station (PVNGS) which is operated by Arizona Public Service (APS) and which SCE has an ownership interest in, APS has elected to procure additional nuclear fuel as a strategic inventory to provide a hedge against potential nuclear fuel supply interruptions. The strategic inventory is included within the pre-core inventory balance. Table IV-29 shows that SCE will maintain an annual average value of pre-core and unamortized in-core nuclear fuel of $233.3 million in As the table shows, total nuclear fuel inventories are expected to increase over the next five years, averaging $332.8 million by

306 305 Table IV-29 Nuclear Fuel Inventory Average Balances (SCE Share, Nominal, $Millions) Year Pre-Core In-Core Total 2008 $76.7 $147.9 $ $89.7 $143.6 $ $90.3 $161.0 $ $114.6 $182.0 $ $107.5 $225.3 $ Customer Deposits For 2006, SCE s average customer deposits held totaled approximately $190.0 million. Deposits held are expected to continue to increase through the 2009 Test Year, when we estimate we will have approximately $ million of customer deposits on hand. The 2009 Test Year estimate is based on the average growth rate of deposits held in 2004 and This two year average growth rate of 7.2 percent 133 was applied to the average of customer deposits held in 2006, and compounded for five years to Table IV-30 summarizes the total average customer deposits on-hand and their annual growth rate for each year from 2002 through This table also includes our forecast for deposits through See Table IV-2, 7.2 percent equals (7.6 percent plus 6.7 percent) /

307 306 Line No. Table IV-30 Average Customer Deposits Held 2002 through 2011 $000 (nominal) Description 1. Recorded Deposits $129,758 $148,325 $159,649 $177,102 $188, Growth Rate 14.3% 7.6% 10.9% * 6.7% 5. Forecast Deposits $202,527 $217,049 $232,611 $249,290 $267, Growth Rate 7.2% 7.2% 7.2% 7.2% 7.2% *Note: The 2005 recorded growth rate reflects the one time effect of policy changes affecting the number of deposits requested and the number of waivers allowed. SCE s Rule 7 establishes when a deposit is required, the amount of the deposit and when such deposits shall be refunded. In accordance with Rule 7, deposits are only collected from customers who have not established credit with SCE. The amount of individual deposits collected from residential customers establishing new service is based on twice their average monthly bill. For non-residential new service and for all customers paying a deposit after disconnection for non-payment, the deposits are based on twice the maximum monthly bill. Deposits are held on average for 12 to 24 months, depending on the customer s payment record. Thus, the deposits on hand at any given time are based on customer bills from a previous 12 to 24 months. a) Historic Review of Customer Deposits The amount of customer deposits held is a direct function of revenue. Because deposits are held for a minimum of 12 months, there is a one to two-year lag from any revenue increase until the time the level of deposits held is affected. 108

308 Beginning in 2003, our policy on collecting and holding deposits has become more strictly enforced by applying more rigorous risk assessment processes to evaluate customers applying for credit 134 and by reducing the number and amount of deposit waivers. These new processes have contributed to an increase in the amount of deposits held. Initially the new policies reduced both the amount of deposits requested and the amount of deposit waivers, these changes had only a moderate effect on the growth rate for deposits in 2003 and By 2005, the amount of total deposits requested leveled out while the amount of deposit waivers continued to decrease, causing the annual growth rate of deposits to increase from 7.6 percent in 2004 to 10.9 percent in The effect of the reduction in deposit waivers on deposits held has now stabilized and is having less effect on deposit growth rates. b) Estimating Methodology In past GRC s we have used an average of the historic ratio of deposits to revenues for purposes of forecasting deposits. However, given the extraordinarily high revenues recorded in 2006, the current ratio of recorded deposits to revenue would not provide a reasonable estimate of 2009 test-year deposits. Another method of estimating future deposits is to use an average of the historic growth rate for deposits over recent years, coinciding with when we began to more strictly apply our policy on waivers. Since the impact of this reduction in deposit waivers has stabilized and is now having less effect on deposit growth rates, we believe the recorded deposit growth rate of 10.9 percent for 2005 is inordinately high. For this reason, we have chosen not to use 2005 recorded deposits for forecasting purposes. Given these circumstances, we believe the 2004 and 2006 recorded growth rates are the most reasonable indicators of what we expect in the future. Thus, we chose to use the average of the 2004 and 2006 growth rates to forecast the level of deposits expected to be held in 2009 through This resulted in an adjusted average growth rate of 7.2 percent, which was then applied to each of the forecast years 2007 through See SCE-4, Volume 2, Ch. III.D for a description of the SCE s risk assessment processes. 109

309 308 EXCERPT FROM A , EXHIBIT SCE-10, VOLUME 2

310 309