ca dereg 2 0 why now glacial call to action

California Electricity Deregulation 2.0

Why This Time?...Why Now?

April 2010

Today’s Conversation Topics

Agenda Item Theme

Electricity Deregulation 2.0—Why Should We Believe You This Time?

• Discuss how Senate Bill 695 mitigates the structural and regulatory failings of the previous attempt at deregulation of the electricity market in California

Value Proposition to Property Owner—Why Does Leaving PG&E Save Me Money?

• Review PG&E rate setting process and legacy contracts

• Review current market price for wholesale energy vs. utility tariff rate

• Highlight savings opportunity for a commercial property owner to enter Direct Access market and choose an ESP

Limited Widow of Opportunity—Why Now?

• Review the size of the CAP and how it is determined for the 4 year phase in of the DA load

• Review process for switching from PG&E to an ESP (NOI and DASR)

• Discuss wait list procedures

Why Glacial Energy? • Review the advantages of partnering with Glacial Energy for less costly electricity.

Questions and Answers • Interactive Discussion

2This information is commercially confidential

California Deregulation

This information is commercially confidential 3

1998

• Based on success of Natural Gas deregulation Investor Owned utilities implemented restructuring of Electricity market

• Deregulation forced divestiture of Utility generating assets

• No incentives for new generating capacity to be built

• Complex market balancing and trading rules for Energy Service Providers

2001

• Combination of high demand, low hydro, band weather, and the failure of a poorly constructed short term market resulted in a complete collapse of the electricity power system

• ESPs failed in droves and returned customers to the Utilities

• On September 20, 2001, CPUC suspended Direct Access except to customers who had valid contracts prior to this date.

2009

• On October 11, 2009, Governor Schwarzenegger signed Senate Bill (SB) 695 into law.

• SB 695 opens the Direct Access market to all Commercial Customers of the IOUs in California subject to DA market cap to be phased in over four years.

Key Milestones in the California Direct Access Market

1980’s

• CPUC allows unbundled service for commercial and industrial customers

• Customers can buy their own natural gas

• “Deregulation” of the Natural Gas market in California has worked well for nearly three decades

TheAftermath

• IOUs experienced complete financial melt-down

• State entered into long-term contracts to purchase power on behalf of IOU that will not expire until 2015

• Direct Access customers must pay for fare share of stranded costs and non by-passable costs

Current PG&E Rates (3/1/2010)


Rate Schedule Customer Charge Season

Time-of-Use

Period

Time-of-Use

Period

"Average" Total Rate1/

(per kWh)

Summer

Winter

On peak

Part Peak

Off Peak

Part Peak

Off Peak

Secondary Primary Transmission Secondary Primary Transmission

Summer $11.32 $10.67 $8.21 $0.14340 $0.13646 $0.11963

Winter $6.91 $6.38 $4.46 $0.10969 $0.10437 $0.09295

Peak $0.16628 $0.15712 $0.13936 Secondary $0.16515

Part-Peak $0.14370 $0.13701 $0.11995

Off-Peak $0.13026 $0.12454 $0.10838 Primary $0.15374

Part-Peak $0.11512 $0.10868 $0.09702

Off-Peak $0.10433 $0.10021 $0.08903 Transmission $0.12743

Max. Peak $13.17 $11.89 $9.16 Peak $0.15568 $0.15520 $0.11577Secondary

$0.14380

Part Peak $3.02 $2.72 $2.07 Part Peak $0.10813 $0.10603 $0.09372

Maximum $9.02 $7.88 $5.80 Off Peak $0.08871 $0.08482 $0.08054Primary $0.13709

Part Peak $1.15 $0.87 $0.00 Part Peak $0.09682 $0.09180 $0.08572

Maximum $9.02 $7.88 $5.80 Off Peak $0.08585 $0.08101 $0.07662Transmission

$0.12223

Winter$0.17091

$0.12555

A-10 Customers w ith high electric use and medium to high load factors generally benefit under Schedule A-10. Part of a customer's bill varies according to the customer's maximum monthly electric demand.

$3.94251 per meter per day

$3.94251 per meter per day

Total Energy Charge (per kWh)

$0.20495

$0.14867

$0.46177

A-1 Basic general service rate. Generally optimal rate for customers w ith low electric use and low load factors, w ith most usage during PG&E's peak and partial peak TOU periods.

Single Phase Service per meter/day

=$0.29569 Polyphase Service per meter/day

=$0.44353

Summer

$0.12152

A-6 Rates vary according to the time of day electricity is used. Typically, the A-6 rate benefits customers w ho use a signif icant percentage of their electricity during the off peak period.

Single phase service per meter/day

=$0.29569; Polyphase service per meter/day =$0.44353. Plus Meter charge =$0.20107per

day for A6 or A6X; =$0.05914 per day for

A6W3/

$6.91 $6.38 $4.46

$0.18603

$0.17945

$0.20618

0.16508

Demand Charge (per kW)

$11.32 $10.67 $8.21

A-10 TOU Customers w ith high electric use and medium to high load factors generally benefit under Schedule A-10 TOU. Part of a customer's bill varies according to the customer's maximum monthly electric demand.

Summer

Winter

Summer

Winter

Meter charge: =$4.11992/day for

E19 V or X; =$3.97799/day for

E19W2/; =$13.55236/day for

E19S mandatory; =$19.71253/day for

E19P mandatory; =$39.42505/day for

E19T mandatory

E-19 Offers demand-metered time-of-use (TOU) service. Customers likely to benefit have high electric use and high load factors and are able to use signif icant percentages of their electricity during the off-peak period. There are optional (E19V, E19 X and E19W) versions below 500 kW as w ell as E19 mandatory w hich applies to accounts w ith demands betw een 500 and 1,000 kW. See tarif f for rate limiter, pow er factor, nonfirm.

Direct Access Can Lower Customers Charge for Generation


Cost of Electrons Used by Customer. Could Be Provided by an ESP at Lower Rate per kWh

Imbedded Utility Costs Create Market Opportunity for Index Price


Understanding kWh Price Elements


$0.0393

$0.0744

$0.0917

$0.00

$0.01

$0.02

$0.03

$0.04

$0.05

$0.06

$0.07

$0.08

$0.09

$0.10

CAISO (NP15) GLACIAL ENERGYINDEX

PG&E E-19 TARIFF RATE

Wholesale Cost of kWh at

CAISO

• Energy Losses and Unaccounted for Energy (UFE)

• ISO charges and Other Ancillary Fees • Zonal Congestion • Capacity & Related Fees • Market Settlement Charges • Glacial Margin

Incremental Costs of kWh Embedded in Glacial Index

Source: FERC, Glacial Energy

2009 Annual Average kWh Price Comparison

Direct Access Capacity CAP—Limited Market Opportunity


DIRECT ACCESS CAPACITY CAP PHASE-IN BY EACH YEAR CAP Expressed Across All Three Utilities

Direct Access Market Load will be Over 14% of Total UDC Load

by 2013

0

20,000,000,000

40,000,000,000

60,000,000,000

80,000,000,000

100,000,000,000

120,000,000,000

140,000,000,000

160,000,000,000

180,000,000,000

200,000,000,000

Existing DA Load

(Left Over from 2001)

NewDA Load

(Post 2013)

UDC Load

DIRECT ACCESS CAPACITY AS A PERCENTAGE OF TOTAL

UTILITY LOADCAP Expressed Across All Three Utilities

Time Line For Selecting Direct Access


• Review benefits of entering direct access

• Identify potential Energy Service Providers

• Determine pros and cons of entering Direct Access market

• Submit Notice of Intent (NOI) to the their Utility

• Indicates to utility that customer desires to enter Direct Access

• After receiving the NOI from a customer, the Utility will confirm or deny the customers reservation in the Direct Access market

• Customer must enter into a contract with an Energy Service Provider

• Energy Service Provider must submit a DASR on behalf of the customer requesting that service be switched from the Utility to the ESP

• Final meter read by Utility is completed and the ESP becomes the provider of record

Marchto April

April 16th, 2010

20 Days After NOI Submitted

July 2010

60 Days After NOI

is Affirmed

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