HomeMy WebLinkAbout09/15/1998, 5 - ELECTRIC DEREGULATION STRATEGYCouncil Agenda Report — Electric Deregulation Strategy
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would provide the flexibility needed to secure a contract in a timely manner to take advantage of
the changing environment in electric deregulation.
Advantages: Able to negotiate directly with electric service providers for electric rate and added
services; probability for entering into a short term agreement; could provide greater cost savings
than other alternatives; able to take advantage of offers made by an ESP in a timely manner and
respond to the new market conditions.
Disadvantages: Requires more staff involvement and time than alternative 2 and 3 for
monitoring the utility bills and the Direct Access contract; potential higher risk than Alternative
1; requires ongoing monitoring.
Alternative 1. Direct Access for City Facilities Only, "RFP".
This alternative would provide potential cost savings through the competitive proposal process.
If this option is chosen, staff would prepare and issue an agency specific Request for Proposal.
Advantages: Able to negotiate directly with electric service providers for electric rate and added
services; probability for entering into a short tern agreement; could provide greater cost savings
than Alternatives 2 and 3.
Disadvantages: Requires considerable staff involvement and time; higher risk than Alternative
2; complicated in teras of evaluation process of ESP contracts; requires ongoing monitoring;
because of the time required for the RFP process, may not provide the flexibility and
responsiveness required by today's electric market.
Alternative 2: Direct Access "Selective Aggregation".
With this alternative the City would aggregate with a larger program such as the State of
Califomia, Department of General Service's Electric Power Services (DGS) or ABAG.
Advanta es: Less administrative time involved since the aggregating organization (DGS,
ABAG, etc.) will provide the staff to oversee and manage contracts with the electric service
providers (ESPs); lower risk to the city than other alternatives.
Disadvantages: Obligated to the terms and conditions offered by the aggregating organization
for the duration of the contract; may be difficult to enter into a short term agreement; depending
on aggregator to secure best pricing; must pay an administrative fee to the aggregating
organization.
Alternative 3. Bundled Utility Service.
This alternative would guarantee the Power Exchange (PX) pricing during the transition period
by remaining with the City's current service provider (PG&E).
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Advantages: Simple in terms of implementation; low risk; reliable source of electricity; short
term in length of commitment; no service provider costs.
Disadvantages: No cost savings from PX price.
Long Term Plan
It is recommended that, during the transition period of electric deregulation, a long term plan be
developed taking into account the latest information, the goals and program evaluation criteria.
This will allow staff to monitor and evaluate adjustments that occur in the deregulated market
during the transition period and for further research and understanding of the impacts of those
changes.
In addition to the evaluation criteria previously discussed, the suggested goals to be used as
guidelines in the planning and evaluation process for the long term plan are as follows.
The plan should:
• Provide a reasonable monetary savings compared to cost to secure an electric services
contract;
• Provide public information, assistance and guidance to our citizens; and
• Establish an energy demand management (energy conservation) and monitoring program for
all City facilities.
The long term fiscal impacts of the plan will be identified upon completion of the evaluation
process.
CONCURRENCES
The Finance Department and the City's electric deregulation committee concur with the
recommendation made in this report.
FISCAL IMPACT
Assuming a suitable agreement can be reached with an ESP, the City should anticipate a savings
of $20,000 to $30,000 per year. Some minor costs may be incurred with the transition from
PG&E to another ESP. These costs will be included in the evaluation process and should not
exceed the first year's savings.
ATTACHMENTS
Attachment l- Regional Electric Deregulation Strategy
Attachment 1
Electric Deregulation:
A Regional Strategy
INTRODUCTION
On September 23, 1996, Governor Pete Wilson signed into law Assembly Bill 1890
which dramatically changed the market system that has been in place for more than
eighty years for serving the electricity needs of California's homes, businesses, industry
and farms. The legislation:
• Recognizes that new technology and new federal laws allow us to change today's
highly regulated market structure to one that relies on competition to set the price of
the generation component of electricity bills.
• Creates two new market entities, one to oversee the high voltage transmission system,
and one to create an auction market for buying and selling of electricity.
• Authorizes retail competition, which allows customers to choose their electricity
supplier, beginning with some users March 31, 1998, and encompassing all customers
no later than 2002.
• Permits new business opportunities to develop in buying, selling or brokering
electricity for individual customers or customer group.
• Permits utilities to recover their transition costs from ratepayers.
• Mandates a 10 percent rate reduction for small residential and commercial customers
by January 1, 1998, with a goal of an additional 10 percent by 2002.
• Provides funds for continuation of utility energy conservation; research, development
and demonstration; public assistance; and renewable energy -based electricity
generation activities.
• Allows customers to continue to rely on service from local utility companies as they
have in the past, if they choose not to participate in the competitive market.
Consumers of electricity, including public facilities, institutions and residential
customers, are facing a bewildering array of new services and service providers. The new
electricity market promises to provide savings to electricity consumers who can manage
their demand, understand the intricacies of the electric power markets and make the
purchasing decisions. The purpose of the following information is to outline a strategy to
research, develop and implement a plan for both the short and long term in regards to
how the governmental agencies in the San Luis Obispo County region should proceed in
the new electricity purchasing market. The following components have been identified as
elements of the plan:
1. Formulation of the goals and policies relating to electric deregulation;
2. Legal/legislative evaluation and review of aggregation agreements, power purchase
agreements, franchise and utility user fees, city and county ordinances and billing;
3. Technical evaluation of the energy profile, rate schedules, power purchase
alternatives, demand management options and extended services (e.g. undergrounding
of utilities, clean power generation, etc.) for each jurisdiction; and
4. Public information and education regarding AB 1890 and energy conservation.
1. Goals and Policies
The primary decision to be made in regards to electric deregulation is how each
jurisdiction will proceed in the new electric market in terms of the various options for
aggregation or in acting alone in finding its own service provider. There appears to be a
significant amount of uncertainty in regards to the future of electric deregulation and the
actual cost savings available to customers. Because of this, it is recommended that a
short and long tens planning approach be implemented to define the strategy needed to
ensure that each participating jurisdiction will be able to accomplish the established
goals. The "Recommendation' section of this report discusses the short and long term
strategies in more detail.
When analyzing the components of the plan, the following program goals have been
identified as guidelines in the planning and evaluation process. The plan will:
Provide real cost savings to the participating jurisdictions
Provide public information, assistance and guidance to our citizens
Establish an energy demand management (energy conservation) and monitoring
program within each participating jurisdiction
Additionally, the evaluation criteria and overall strategy should be:
• Simple in approach;
• Provide for a reliable source of electricity;
• Be flexible in terms of the length of commitment; and
• Be low risk to each jurisdiction.
2. LegaULegislative Component
It is important that each jurisdiction evaluate current franchise and utility user fees and
monitor legislative actions that would affect these revenue sources. Additionally, it may
be necessary to introduce new or change existing ordinances that may be affected by
changes in State law. The following are areas which require review by each jurisdiction.
• Franchise fees
• Utility User fees
• Ordinances
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Additionally, a review process should be established to analyze potential aggregation and
power purchase agreements. Once an agreement is entered into, monitoring procedures
will need to be established to ensure that the contract provisions are being adhered to.
Because of the complicated nature of these agreements, the initial staff time required for
monitoring could be significant.
3. Technical Evaluation
An energy profile, also known as a load profile, is the amount of electricity being used at
any given time during a 24 hour period. The cost of electricity, measured as a certain rate
per kilowatt hour, varies depending on the amount used and the time of day the use
occurs. Using the City of San Luis Obispo's energy profile as an example, the following
is a breakdown of the City's electric use by type of account and rate schedule.
City of San Luis Obispo's Rate Schedules & Energy Profile
• A-1 The A-1 rate is used for residential and small general service commercial
customers. Actual electrical rates per kilowatt hour of use vary from summer
($0.14870) to winter ($0.10193). This is the basic electric rate that most customers
are familiar with. The City of San Luis Obispo has 79 A-1 rate accounts comprising
approximately 6% of the City's overall electrical use.
• A-6 The A-6 rate has the same general description and customer base as the A-1 rate
with the added component of peaking charges in the summer months. This account is
used to reduce energy costs on accounts where the electrical use can be shifted off
peak, or on continuously operating pumps or similar equipment. The City of San Luis
Obispo has 21 A-6 rate accounts again comprising approximately 6% of the City's
overall electrical use. A-6 rates vary in the following manner;
Summer Winter
On Peak Rate $0.23258 none
Partial Peak Rate $0.10288 $0.11562
Off Peak Rate $0.05618 $0.07169
• A-10 For accounts with demands larger than 20 kilowatts, the A-10 rate comes in to
effect. A-10 rates are metered in two different ways by recording electrical meters.
The basic rate is similar to the A -I rate with the inclusion of demand charges. While
the above rates have metered -only electrical use, A-10 adds electrical demand charges
to the bill. Demand charges are calculated for the large inrush currents typically
required by large motors. The electrical provider must design the electrical
transmission system to provide these inrush currents when necessary, while
maintaining regular service to the other customers in the transmission grid. This
causes the utility to oversize the system for the larger demands. The City has four A-
10 accounts comprising approximately 5.8% of the overall electrical use. The A-10
rates are as follows;
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Summer Winter
Energy Rate $0.08915 $0.07279
Demand Rate $4.75 $1.20
(per kw of demand)
• E-19 For accounts with demands larger than 500 kilowatts, the E-19 rate comes in to
effect. E-19 rates are metered similarly to the A-10 rates with recording electrical
meters, however E-19 adds time of use to the total bill including demand charges.
This is the rate structure that many large business and municipal accounts use. The
rates encourage use of electrical power off peak by escalating charges dramatically
during the on peak period. The City has 13 accounts in this category consuming
approximately 77% of the overall electrical use. The E-19 rates are as follows;
Summer Winter
Energy Use
On Peak Rate $0.08773 none
Partial Peak Rate 0.05810 $0.06392
Off Peak Rate $0.05059 $0.05038
Demand Charges
On Peak Rate $13.35 none
• Partial Peak Rate $3.70 $3.65
• Off Peak Rate $2.55 $2.55
• Miscellaneous accounts include traffic signals, un -metered accounts, and others. The
City has 59 accounts in this category comprising approximately 5% of our overall
electrical use. The rates vary by account, but are generally similar to the A -I rate.
Notes:
Reference to time of use metering ie. Winter vs. Summer means;
Summer = May 1 to October 31
on peak = noon to 6 pm Monday through Friday
part peak = 8:30 am to noon and 6 pm to 9:30 pm Monday through Friday
off peak = 9:30 pm to 8:30 am Monday through Friday, all day Saturday, Sunday,
and holidays
Winter = November 1 to April 30
on peak = none
part peak = 8:30 am to 9:30 pm Monday through Friday
off peak = 9:30 pm to 8:30 am Monday through Friday, all day Saturday, Sunday,
and holidays
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2. These areeg_neral descriptions of the rates currently in use by the City. For actual
account reference, use the P.G. and E. tariff descriptions available from the utility.
Many other factors influence the actual billing received by the City.
Power Purchase Alternatives
There are five alternatives which a jurisdiction can consider for purchasing electricity.
The following is a brief description of each option:
1. Bundled Utility Service- under this option, an agency would remain with the current
electric provider until a future date when the deregulation impacts are fully
understood.
2. Direct Access "Individual Agency Facilities Only"- the focus of this option would
be to determine if selected accounts or all metered service under an agency's control
would provide cost savings. The probable course of action would be the issuance of a
Request for Proposal to energy service providers for cost saving and service
information. This could be either a short term contract such as a one year or year to
year agreement, or a longer term contract in the range of two to four years.
3. Direct Access "Selective Aggregation"- under this option, an agency would partner
with selected businesses, aggregation groups such as ABAG or other governmental
agencies in an attempt to secure the best electric rate. Again, this could be a short or
longer term contract.
4. Direct Access "Community Aggregation"- this option would include an entire
community and would require separate contracts with each participant in the
aggregated group.
5. Municipalization- Under this option, cities would condemn the existing electric
infrastructure and assume the role as the full service electric utility.
In developing the overall strategy it is important to understand the significant milestones
established by AB 1890. The first and probably the most significant is the recovery by
investor owned utilities of stranded costs in the form of a Competition Transition Charge
(CTC). Stranded costs are investments made by investor owned utilities in power plants
and power contracts to ensure an adequate supply of electricity to meet customer
demands but are now considered "uneconomic". The recovery of these costs are to end
no later than March 31, 2002. Until this date, there is limited cost savings to be realized
in the transition period to a true electric market competition. The second milestone is the
repayment of bonds issued by the investor owned utilities under the authorization of AB
1890 to offset the revenues the utilities lose as a result of the mandatory 10% rate
reduction. The payments known as Trust Transfer Amount or TTA, will extend beyond
the end of the CTC recovery and the 10% rate reduction, and will decrease each year. It
is anticipated that these bonds will be paid off over a 10 year period beginning in
December 1997.
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4. Public Information and Education RegardingAB1890 and Energy
Conservation
Electric deregulation offers the opportunity to furnish our communities with general
information regarding AB 1890 and energy conservation. It is proposed that the
information regarding AB 1890 be provided by the participating jurisdictions using
information published by the State and California Public Utilities Commission as a guide.
The energy conservation information can be provided by existing sources such as PG&E.
It is recommended that a regional committee be formed to review the available
information and make recommendations on what and how to distribute it to the various
communities. A funding source would have to be identified to purchase and/or produce
and print the information to be distributed.
RECOMMENDATION
Based on the timeline for repayment and cost recovery of these components of AB 1890,
it is recommended that a two phased approach be considered. Phase. one would be the
short term plan to be implemented during the transition period which would be to the year
2002. This would allow for the development of phase two during this period. Phase two
would look at the changing deregulation arena and recommend a long term plan for the
region.
Short Term Plan
It is recommended that the short term plan will be for the transition period, to the year
2002. After analyzing the five options for purchasing power, it has been determined that
Direct Access "Selective Aggregation, Bundled Service and Direct Access "Individual
Agency Facilities Only" should be considered as alternatives for the transition period.
Each jurisdiction will need to determine which alternative best suites the needs of their
community and the agencies comfort level and staff resources available to manage and
monitor the power purchase contract process.
The following section summarizes the alternatives and discusses the advantages and
disadvantages of each.
Alternative 1: Direct Access "Selective Aggregation".
With this alternative each jurisdiction would individually aggregate with a larger program
such as the State of California, Department of General Service's Electric Power Services
(DGS) or ABAG. At this stage of electric deregulation, it appears this would be the least
risk option while providing some saving on overall electric costs. It is not recommended
that local businesses or governmental organizations aggregate at this time. At this point,
it appears that aggregating with other local entities would be more complicated and costly
(in terms of staff time) for little or no benefit. This will be discussed in more detail in the
following sections.
If this alternative is selected, the participating jurisdictions could research as a group the
aggregation opportunities available and provide an analysis of the various for a service
providers.
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Advantages: Less administrative time involved since the aggregating organization (DGS,
ABAG, etc.) will provide the staff to oversee and manage contracts with the electric
service providers (ESPs); potential increased savings by being part of a larger group of
energy users; lower risk to the cities than other alternatives.
Disadvantages: Obligated to the terms and conditions offered by the aggregating
organization for the duration of the contract; may be difficult to enter into a short term
agreement; depending on aggregator to secure best pricing.
Alternative 2. Direct Access for "Jurisdiction Facilities Only".
This alternative would provide potential cost savings through the competitive proposal
process. If this option is chosen, jurisdiction staff would prepare and issue an agency
specific Request for Proposal.
Advantages: Jurisdiction able to negotiate directly with electric service providers electric
rate and added services; higher probability entering into a short term agreement; could
provide greater cost savings than Alternative 1.
Disadvantages: Requires more staff involvement and time; higher risk than Alternative
1; complicated in terms of evaluation process of ESP contracts; requires ongoing
momtonng.
Alternative 3. Bundled Utility Service.
This alternative would guarantee the Power Exchange (PX) pricing during the transition
period by remaining with the jurisdiction's current service provider.
Advantages: Simple in terms of implementation; low risk; reliable source of electricity;
short term in length of commitment.
Disadvantages: No cost savings from PX price.
Not Recommended: Community Aggregation and Municipalization
Community Aggregation and Municipalization were not chosen as alternatives for the
short term plan because of the staff time and subsequent cost, higher risk exposure and
other direct costs versus the potential cost savings to develop and implement those
programs.
Long Term Plan
It is recommended that, during the transition period of electric deregulation, a long term
plan be developed taking into account the latest information, the goals and program
evaluation criteria. This will allow for adjustments that occur in the deregulated market
during the transition period and for further research and understanding of the impacts of
those changes.
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In conjunction with the evaluation and development of the long term strategy, each
participating jurisdiction will need to perform internal evaluations listed in Attachment 1
of this report. In order to ensure the timely preparation of the long term plan, the
following suggested timeline has been established:
• Formation of Regional Electric July 1998
Deregulation Work Group
• Development of Public Information Program September 1998
• Evaluation of Utility User Fees, January 1999
Franchise Fees, Ordinances
• Evaluation of Regional Energy Profile June 1999
• Monitoring of PX Pricing ongoing
• Review of existing Proposals and ongoing
Contracts from ESP's
• Determine Regional Aggregation Feasibility January 2000
• Formalize Regional Aggregation Organizational June 200
Structure (if considered feasible)
• Determine Regional Aggregation Options and January 200
Select Preferred Plan
• Implement Long Term Plan January 200
The timeline will be adjusted as needed to accommodate changes in the electric
deregulation arena. Dedicated staffing and time allocation to the planning process will
need to be determined to support the proposed timeline.
Estimated Potential Savings
Again using the City of San Luis Obispo as an example, staff has estimated the potential
cost savings on an annual basis during the transition period using Alternative 1: Direct
Access "Selective Aggregation". This alternative was chosen for the analysis because of
the amount information available at the time this report was prepared.
The following is the breakdown of the estimated savings based on information provided
by PG&E and the State of California, General Services Department. As indicated in the
energy use analysis, the estimated savings is derived from using Enron as the energy
service provider through aggregation with DGS.
Regional Electric Deregulation Strategy
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c1IUUARV nF ACCOUNTS CITY OF SAN LUIS OBISPO with 10% MANDATED RATE REDUCTION
RATE
SCHEDULE
NUMBER OF
ACCOUNTS
TOTAL KWH
TOTAL ENERGY
COST
PERCENT OF
TOTAL USAGE
COST/KWH
ESTIMATED 10%
RATE
REDUCTION
Al
79
643,796
$87,907
5.97
$0.1365
$8,791
A6
21
649,242
$64,288
6.02
$0.0990
$5,429
A10
4
625,440
$64,178
5.80
$0.1026
Value
E1913
5.25%
55629,514
8,320,5
$
77.18
$0.0757
MISC.
59
542,040
$61,583
5.03
$0.1136
1
TOTAL
176
10,781,075
$907,470
100
$0.0842
$15,220
ENRON RATES AVAILABLE THROUGH STATE GENERAL SERVICES
DEPARTMENT 3/31/9
Rate
Contract
Contract
Reduction
Duration
Duration
off 1996
PG&E
4 year
5 year
Tariff
General
Accounts
2%
3%
Base
Contract
Value
3.75%
5.25%
Added
Contract
Contract
Contract
Street
Duration
Duration
Lighting
Accounts
4 year
5 year
Base
0.50%
1.25%
Contract
Value
2%
2.25%
Added
Contract
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Race 4 -Year Enron Contract
RATE
SCHEDULE
NUMBER OF
ACCOUNTS
TOTAL KWH
TOTAL ENERGY
COST
PERCENT OF
TOTAL USAGE
COSTIKWH
ESTIMATED 2%
RATE
REDUCTION
Al
79
643,796
$87,907
5.97
$0.1338
$1,758
A6
21
649,242
$64,288
6.02
$0.0970
$1,286
A10
4
625,440
$64,178
5.80
$0.1006
$1,284
E19
13
8,320,555
$629,514
77.18
$0.0741
$12,590
MISC.
59
542,040
$61,583
5.03
$0.1113
$1,232
TOTAL
176
10,781,073
$907,470
100
$0.0825
$18,149
Base 5 -Year Enron Contract
RATE
SCHEDULE
NUMBER OF
ACCOUNTS
TOTAL KWH
TOTAL ENERGY
COST
PERCENT OF
TOTAL USAGE
COSTIKWH
ESTIMATED 3°h
RATE
REDUCTION
Al
79
643,796
$87,907
5.97
$0.1324
$2,637
A6
21
649,242
$64,288
6.02
$0.0960
$1,929
A10
4
625,440
$64,178
5.80
$0.0995
$1,925
E19
13
8,320,555
$629,514
77.18
$0.0734
$18,885
MISC.
i59
542,040
$61,583
5.03
$0.1102
$1,847
TOTAL
176
10,781,073
$907,470
100
$0.0816
$27,224
Value Added 4 -Year Enron Contract
RATE
SCHEDULE
NUMBER OF
ACCOUNTS
TOTAL KWH
TOTAL ENERGY
COST
PERCENT OF
TOTAL USAGE
COSTIKWH
ESTIMATED
3.75% RATE
REDUCTION
Al
79
643,796
$87,907
5.97
$0.1314
$3,297
A6
21
649,242
$64,288
6.02
$0.0953
$2,411
A10
4
625,440
$64,178
5.80
$0.0988
$2,407
E19
13
8,320,555
$629,514
77.18
$0.0728
$23,607
MISC.
59
542,040
$61,583
5.03
$0.1094
$2,309
TOTAL
178
10,781,073100
i$9-60,4-'730
100
$0.0810
$34,030
Value Added 5 -Year Enron Contract
RATE
SCHEDULE
NUMBER OF
ACCOUNTS
TOTAL KWH
TOTAL ENERGY
COST
PERCENT OF
TOTAL USAGE
COSTIKWH
ESTIMATED
5.25% RATE
REDUCTION
Al
79
643,796
$87,907
5.97
$0.1294
$4,615
A6
21
649,242
$64,288
6.02
$0.0938
$3,375
A10
4
625,440
$64,178
5.80
$0.0972
$3,369
E19
13
8,320,555
$629,514
77.18
$0.0717
$33,049
MISC.
59
542,040
$61,583
5.03
$0.1076
$3,233
TOTAL
176
10,781,073
$907,470
100
$0.0798
$47,642
Regional Electric Deregulation Strategy
Page 11
note:
1. Estimates do not include 10% mandated reduction from PGE on A-1
and A-6 accounts.
2. 10% PGE reduction will be adjusted (reduced) for power generation
amount if provided by others.
3. Value Added contracts require participation in energy efficient upgrades to
facilities as determined by Enron.
"Value Added" programs proposed by Enron and other service providers generally
require the contracting agency to agree to certain energy savings or demand management
capital improvements or operating program changes. For example, as a capital
improvement an agency may replace all non energy efficient motors at their water
treatment plant, with energy efficient motors; as an operating program change, an agency
may operate their water treatment plant only during off-peak hours. The "Value Added"
program being offered is for the service provider to assist the agency in identifying
opportunities with reasonable pay back periods, the agency would then agree to complete
the necessary changes and the share a portion of the savings with the energy service
provider.
As an option to "Value Added" contracting, staff would recommend for the short term
plan, that a regional technical group be formed and research, share and assist in the
development of demand management programs for the participating agencies. This
option should allow most agencies access to the various demand opportunities that are
available, with the greatest flexibility in determining which opportunities will be pursued.
Energy Profile Evaluation Summary
To summarize, the total potential combined savings (Enron plus P.G. and E.) from the
various contracts above would be as follows;
Contract Type
4 -year "Base"
• 5 -year "Base"
• 4 -year "Value Added"
• 5 -year "Value Added"
Estimated Savings
$18,149*
$27,224*
$34,030*
$47,642*
Percent Savings
2%
3%
3.75%
5.25%
* does not include the 10% mandated rate reduction for the transmission and distribution
portion of the rate.
Regional Electric Deregulation Strategy
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SUMMARY
Since there appears to be a significant amount of uncertainty in regards to the future of
electric deregulation, the recommended short and long term planning strategy will allow
agencies the opportunity to evaluate future options as more information becomes
available. Until the CTC costs are paid, there is limited cost savings to be realized in the
transition period. Because there are not substantial saving at this point in time, agencies
should evaluate the low risk options while exploring regional aggregation alternatives.
Additionally, there is the opportunity to form a regional technical group to research, share
and assist in the development of demand management programs for the participating
agencies. Public education and information is vital component of any plan in order to
assist our citizens in understanding this complex subject. By following the
recommendations and timeline presented in this report, agencies will be able to make
informed decisions when evaluating the future of electric deregulation.
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