Transcript CMTA Summer Energy Conference – July, 2004

CMTA Summer Energy Conference
July, 2004
Industrial Rates in a Reformed
Electricity Market: Is Relief In
Sight?
William H. Booth, Counsel to CLECA
1
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?
2
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.
3
CA Industrial Rates Greatly Exceed
Those In Other States
Ave rage Indus trial Rate s by State 2002
State
Average Industrial
Rate (Cents/kWh)
Arizona
California
Idaho
Illinois
Massachusetts
Michigan
New York
Oregon
Nevada
5.2
10.09
4.34
4.75
8.58
4.97
4.63
4.72
7.25
50 s tate s
4.74
Source: EIA Feb. 2002 Report
Includes publicly- and privately-owned utilities
4
Current Industrial Rates Greatly Exceed
Historical Rates
Edison Class Average Rates: June 1996 vs. July 2004
Cents/kWh
Jun-96 Jul-04
Increase --
% Increase
Residential
12.7
12.6
-0.1
-1%
Commercial
10.6
13.8
3.2
30%
7
10.2
3.2
46%
TOU-8-Sub
4.5
7.6
3.1
69%
System
10.1
12.3
2.2
22%
TOU-8
5
The Same Is True For PG&E Customers
PG&E Class Average Rates: June 1996 vs. July 2004
Cents/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%
4.7
8.83
4.13
88%
E-20-T
6
System
9.4
12.8
3.4
36%
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

7
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 Shift
Millions*
Residential
11.87
126%
12.55
98%
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%
Comm (A-10)
$
(1,040)
*The reduction of the current Residential class average rate from 126% to just 98% of
8
the current system average rate, saves residential customers $1.040 billion/year.
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 Shift
Millions*
Residential
12.7
126%
12.6
102%
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%
$
(725)
*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.
9
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.

10
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
11
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
12
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
13
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.
14
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

15
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
16
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
17
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%.
18
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

19
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)
20
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?
21
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
22
business electric customers?