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CMTA Summer Energy ConferenceJuly, 2004

Industrial Rates in a Reformed Electricity Market: Is Relief In Sight?

William H. Booth, Counsel to CLECA

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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?

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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.

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CA Industrial Rates Greatly Exceed Those In Other States

Average Industrial Rates by State 2002

Average IndustrialState Rate (Cents/kWh)

Arizona 5.2California 10.09

Idaho 4.34Illinois 4.75

Massachusetts 8.58Michigan 4.97

New York 4.63Oregon 4.72Nevada 7.25

50 states 4.74

Source: EIA Feb. 2002 ReportIncludes publicly- and privately-owned utilities

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Current Industrial Rates Greatly Exceed Historical Rates

Edison Class Average Rates: June 1996 vs. July 2004Cents/kWh

Jun-96 Jul-04 Increase -- % Increase

Residential 12.7 12.6 -0.1 -1%

Commercial 10.6 13.8 3.2 30%

TOU-8 7 10.2 3.2 46%

TOU-8-Sub 4.5 7.6 3.1 69%

System 10.1 12.3 2.2 22%

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The Same Is True For PG&E Customers

PG&E Class Average Rates: June 1996 vs. July 2004Cents/kWh

Jun-96 Jul-04 Increase % Increase

Residential 11.9 12.55 0.65 5%

Comm A-10 9.9 14.14 4.2 42%

E-19 8.72 12.77 4.05 46%

E-20 6.48 10.62 4.14 64%

E-20-T 4.7 8.83 4.13 88%

System 9.4 12.8 3.4 36%

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The CPUC Set 1996 Rates Based on Then Current Cost of Service

“In today’s decision, we reaffirm our commitment to the policy of marginal cost-based ratemaking. The decrease in Edison’s 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 Edison’s rates.” D.96-04-0540

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Compare PG&E Class Average Rates to the System Average Rate: June 1996 vs. July 2004

Cents/kWh

Jun-96 % of SAR Jul-04 % of SAR Dollar ShiftMillions*

Residential 11.87 126% 12.55 98% (1,040)$

Comm (A-10) 9.9 105% 14.14 110%

E-19 8.72 93% 12.77 100%

E-20 6.48 69% 10.62 83%

E-20-T 4.7 50% 8.83 69%

System 9.4 100% 12.8 100%

*The reduction of the current Residential class average rate from 126% to just 98% of the current system average rate, saves residential customers $1.040 billion/year.

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Compare Edison Class Average Rates to the System Average Rate: June 1996 vs. July 2004

Cents/kWh

Jun-96 % of SAR Jul-04 % of SAR Dollar ShiftMillions*

Residential 12.7 126% 12.6 102% (725)$

Comm 10.6 105% 13.8 112%

TOU-8 7 69% 10.2 83%

TOU-8-Sub 4.5 45% 7.6 61%

System 10.1 100% 12.3 100%

*The reduction of the current Residential class average rate from 126% to 102% of the current system average rate, saves residential customers $725 billion/year.

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Direct Access Rates Are Also High, and Can Exceed Bundled Rates Energy Cost – Spot/2 yr block 3.5-5.5 ISO Costs 0.5 Utility T&D (Trans. Customer) 1.0 Capped CRS 2.7 Total 7.7-9.7

– Note that Edison’s bundled rate for transmission customers is currently 7.6 cents and PG&E’s is 8.8 cents.

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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

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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 Edison’s system average rate is up 22% and

PG&E’s is up 36% from pre-crisis levels

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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&E’s $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

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Are There Real Opportunities to Reduce Utility Rev Req?

Will natural gas prices fall? Refinancing PG&E’s 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.

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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&E’s E-20 class average rate to its historic relationship to SAR would drop it from 10.6 cents to 8.8 cents

PG&E’s E-20T rate would drop from 8.8 cents to 6.4 cents

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PG&E and Edison Propose Just Slight Reductions for Large Industrial Rates

PG&E’s E-20 rate would fall from 10.6 to 9.7 cents (E-20T from 8.8 to 8.6 cents)

Edison’s TOU-8 rate would drop from 10.3 to 9.95 cents

But, Edison’s 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

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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

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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 SCE’s 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%.

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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 CPUC’s 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

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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 don’t 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)

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Would Core/Non-Core Help? Opening DA to new load could mean higher CRS

– DA is not economic at today’s 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?

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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?