1. 1 CMTA Summer Energy Conference July, 2004 Industrial Rates in a Reformed Electricity Market: Is Relief In Sight? William H. Booth, Counsel to CLECA

2. 2 Industrial Rates in a Reformed Electric Market Are industrial rates too high presently? Too high in relation to what? If they are too high, what can be done about it? What are the causes? Do decisions regarding market structure affect the outcome for industrial rates? What can be achieved politically, and over what time frame?

3. 3 Are California Industrial Electric Rates Too High? YES, By Several Measures. Ask the purchasing manager. Look at electric costs as a percentage of production costs. Compare CA rates to those in other states. Compare current industrial electric rates to those in effect before the energy crisis. Compare class average rates to utility system average rates over time. Compare class average rates to cost of service.

4. 4 CA Industrial Rates Greatly Exceed Those In Other States

5. 5 Current Industrial Rates Greatly Exceed Historical Rates

6. 6 The Same Is True For PG&E Customers

7. 7 The CPUC Set 1996 Rates Based on Then Current Cost of Service In todays decision, we reaffirm our commitment to the policy of marginal cost-based ratemaking. The decrease in Edisons revenue requirements affords us an opportunity to align rates closer to costs while keeping bill impacts at a reasonable level. CPUC Decision 96-04-050 Marginal costs should be the starting point and the central focus of revenue allocation and rate design for setting Edisons rates. D.96-04-0540

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10. 10 Direct Access Rates Are Also High, and Can Exceed Bundled Rates Energy Cost – Spot/2 yr block3.5-5.5 ISO Costs0.5 Utility T&D (Trans. Customer)1.0 Capped CRS2.7 Total7.7-9.7 –Note that Edisons bundled rate for transmission customers is currently 7.6 cents and PG&Es is 8.8 cents.

11. 11 Return to Bundled Service Is Not A Great Option For DA Customers 6 mos. notice with market pricing in the interim, plus 2.7 cent CRS 3-yr commitment to bundled service Full CRS undercollection repayment begins in a few years ($460 MM for SCE, $250 MM for PG&E through 12/31/03) Bundled rates plus repayment of CRS undercollection at up to 2.7 cents/kWh

12. 12 Industrial Rates Are Clearly Too High, But What Can Be Done About It? As a result of the energy crisis, CA has added billions to utility revenue requirement –DWR undercollections of $8 billion in 2001 –DWR contract portfolio is at least $15 billion over market levels through 2011 –Utilities granted recovery of billions of procurement undercollections and get well costs Edisons system average rate is up 22% and PG&Es is up 36% from pre-crisis levels

13. 13 Much of the Higher Revenue Requirement is Locked in, at Least Through 2012 DWR undercollection is bonded through 2022 at 5 mills/kWh DWR contract portfolio runs through 2012 at a current average cost of 9 cents/kWh PG&Es $2 billion regulatory asset is set for 9 years at roughly 6 mills/kWh Edison QF contract portfolio has an average cost of 7.9 cents

14. 14 Are There Real Opportunities to Reduce Utility Rev Req? Will natural gas prices fall? Refinancing PG&Es Reg Asset with a DRC will reduce its cost to 4.5 mills/kWh Many QF contracts terminate over the next several years Further restructuring of DWR contracts? Possible supplier refunds? –Recall how CA handled the $1 billion DWR bond refund in October 2003.

15. 15 What About Cost Allocation Changes/Reform? Both Edison and PG&E have pending allocation proceedings before CPUC –Decisions are due in early and mid 2005 Returning PG&Es E-20 class average rate to its historic relationship to SAR would drop it from 10.6 cents to 8.8 cents PG&Es E-20T rate would drop from 8.8 cents to 6.4 cents

16. 16 PG&E and Edison Propose Just Slight Reductions for Large Industrial Rates PG&Es E-20 rate would fall from 10.6 to 9.7 cents (E-20T from 8.8 to 8.6 cents) Edisons TOU-8 rate would drop from 10.3 to 9.95 cents But, Edisons TOU-8-Sub rate would actually increase from 7.6 to 8.0 cents –A return to the 1996 relationship would drop this rate from 7.6 to 5.5 cents

17. 17 What Constrains Further Reductions In Industrial Rates? Perceived need to reduce commercial rates –SCE proposes 0.9 cent reduction for GS-2 –PG&E proposes 1.9 cent reduction for A-10 Perceived need to limit residential rate increases –SCE proposes 14.6% residential class increase –PG&E proposes a 12.2% residential increase

18. 18 Will the CPUC Permit Even These Modest Residential Increases? AB 1X exempted all residential usage below 130% of baseline from any rate increase for duration of DWR contracts. –65% of resid. load and 25% of utility bundled load. –Exemption worth roughly $600 million for each of the SCE and PG&E resid. groups in June 2001 increase. –Approval of SCEs proposed 15% resid. increase requires a 45% increase for the top 35% of resid. usage. Residential and Agricultural customers will demand caps on class increases, say 5%.

19. 19 Other Constraints On Rate Reductions Through Cost Allocation ? The nature of the underlying cost increases –DWR commodity energy purchases –Bond charges spread uniformly per kWh –Higher natural gas costs –Increased PPP and CARE costs spread uniform cents Unbundling of rate elements changes the CPUCs traditional cost allocation technique from Equal Percentage of Marginal Cost (EPMC) to functional marginal cost allocation Industrial customer load factors decline when large customers leave for DA service

20. 20 Does the Structure of the Electric Market Affect Industrial Rates? Current hybrid market means some industrials are bundled and some DA DA customers pay exit fees to make bundled customers indifferent –The Indifference calculation is complex and sensitive –DA customers pay for DWR power they dont receive –Capped CRS is financed by bundled commercial - industrial customers at a cost of 4 mills/kWh CPUC rules permit coming and going subject to limitations (6 mos notice and 3 year term)

21. 21 Would Core/Non-Core Help? Opening DA to new load could mean higher CRS –DA is not economic at todays CRS levels –Movement of load to DA can increase Indifference fee Core/Non-Core could mean stricter rules re: movement between bundled and DA –5 year term or one-time election Uncertainty re Core/Non-Core complicates utility procurement and potentially adds costs –How much load are utilities to purchase for? –Who is the provider of last resort?

22. 22 In The End, These Are Political Questions Policymakers are more concerned about electric reliability than about cost of service. Are these goals best served by: –Moving to a Core/Non-Core Structure? –Adding energy efficiency, renewables and demand side management? Is electricity unique, such that market solutions do not apply? How does California value its business climate? Should California favor residential (voters) over business electric customers?