1. California Electricity
Deregulation 2.0
Why This Time?...Why Now?
April 2010

2. Today’s Conversation Topics
Agenda Item Theme
Electricity Deregulation 2.0— • Discuss how Senate Bill 695 mitigates the structural
Why Should We Believe You This and regulatory failings of the previous attempt at
Time? deregulation of the electricity market in California
• Review PG&E rate setting process and legacy contracts
• Review current market price for wholesale energy vs.
Value Proposition to Property
utility tariff rate
Owner—Why Does Leaving
PG&E Save Me Money? • Highlight savings opportunity for a commercial
property owner to enter Direct Access market and
choose an ESP
• Review the size of the CAP and how it is determined
for the 4 year phase in of the DA load
Limited Widow of Opportunity—
• Review process for switching from PG&E to an ESP
Why Now?
(NOI and DASR)
• Discuss wait list procedures
• Review the advantages of partnering with Glacial
Why Glacial Energy?
Energy for less costly electricity.
Questions and Answers • Interactive Discussion
This information is commercially confidential 2

3. California Deregulation
Key Milestones in the California Direct Access Market
The
Aftermath 2009
1980’s 1998 2001
• CPUC allows • Based on success • Combination of • IOUs experienced • On October 11,
unbundled service of Natural Gas high demand, low complete financial 2009, Governor
for commercial deregulation hydro, band melt-down Schwarzenegger
and industrial Investor Owned weather, and the signed Senate Bill
customers utilities • State entered into (SB) 695 into law.
failure of a poorly long-term
implemented constructed short
• Customers can contracts to • SB 695 opens the
restructuring of term market
buy their own purchase power Direct Access
Electricity market resulted in a
natural gas on behalf of IOU market to all
• Deregulation complete collapse that will not expire Commercial
• “Deregulation” of forced divestiture of the electricity until 2015 Customers of the
the Natural Gas of Utility power system IOUs in California
market in generating assets • Direct Access subject to DA
California has • ESPs failed in customers must
droves and market cap to be
worked well for • No incentives for pay for fare share phased in over
nearly three new generating returned of stranded costs
customers to the four years.
decades capacity to be and non by-
built Utilities passable costs
• Complex market • On September 20,
balancing and 2001, CPUC
trading rules for suspended Direct
Energy Service Access except to
Providers customers who
had valid
contracts prior to
this date.
This information is commercially confidential 3

4. Current PG&E Rates (3/1/2010)
Time-of- Time-of- "Average"
Customer Demand Charge Total Energy Charge
Rate Schedule Season Use Use Total Rate 1/
Charge (per kW) (per kWh)
Period Period (per kWh)
Single Phase Service
A-1 Basic general service rate. Generally
per meter/day Summer $0.20495
optimal rate for customers w ith low electric use $0.18603
=$0.29569 Polyphase
and low load factors, w ith most usage during
Service per meter/day Winter $0.14867
PG&E's peak and partial peak TOU periods.
=$0.44353
Single phase service
A-6 Rates vary according to the time of day
per meter/day
On peak $0.46177
electricity is used. Typically, the A-6 rate benefits
=$0.29569; Polyphase Summer Part Peak $0.20618
customers w ho use a significant percentage of
service per meter/day
their electricity during the off peak period.
=$0.44353. Plus Meter Off Peak $0.12152 $0.17945
charge =$0.20107per
day for A6 or A6X; Part Peak $0.17091
=$0.05914 per day for Winter
A6W3/ Off Peak $0.12555
Secondary Primary Transmission Secondary Primary Transmission
A-10 Customers w ith high electric use and
Summer $11.32 $10.67 $8.21 $0.14340 $0.13646 $0.11963
medium to high load factors generally benefit under $3.94251 per
Schedule A-10. Part of a customer's bill varies 0.16508
meter per day
according to the customer's maximum monthly Winter $6.91 $6.38 $4.46 $0.10969 $0.10437 $0.09295
electric demand.
Secondary
A-10 TOU Customers w ith high electric Peak $0.16628 $0.15712 $0.13936
$0.16515
use and medium to high load factors generally
benefit under Schedule A-10 TOU. Part of a Summer $11.32 $10.67 $8.21 Part-Peak $0.14370 $0.13701 $0.11995
customer's bill varies according to the customer's $3.94251 per Prim ary
Off-Peak $0.13026 $0.12454 $0.10838
maximum monthly electric demand. meter per day $0.15374
Part-Peak $0.11512 $0.10868 $0.09702
Winter $6.91 $6.38 $4.46
Transm ission
Off-Peak $0.10433 $0.10021 $0.08903
$0.12743
Meter charge: Secondary
E-19 Offers demand-metered time-of-use
=$4.11992/day for Max. Peak $13.17 $11.89 $9.16 Peak $0.15568 $0.15520 $0.11577 $0.14380
(TOU) service. Customers likely to benefit have
E19 V or X;
high electric use and high load factors and are able Summer Part Peak $3.02 $2.72 $2.07 Part Peak $0.10813 $0.10603 $0.09372
=$3.97799/day for
to use significant percentages of their electricity
E19W2/;
during the off-peak period. There are optional Prim ary
=$13.55236/day for Maximum $9.02 $7.88 $5.80 Off Peak $0.08871 $0.08482 $0.08054 $0.13709
(E19V, E19 X and E19W) versions below 500 kW
E19S mandatory;
as w ell as E19 m andatory w hich applies to
=$19.71253/day for Part Peak $1.15 $0.87 $0.00 Part Peak $0.09682 $0.09180 $0.08572
accounts w ith demands betw een 500 and 1,000
E19P mandatory; Winter
kW. See tariff for rate limiter, pow er factor, Transm ission
=$39.42505/day for
nonfirm. Maximum $9.02 $7.88 $5.80 Off Peak $0.08585 $0.08101 $0.07662 $0.12223
E19T mandatory
This information is commercially confidential 4

5. 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
This information is commercially confidential 5

6. Imbedded Utility Costs Create Market Opportunity for Index Price
This information is commercially confidential 6

7. Understanding kWh Price Elements
2009 Annual Average kWh Price Comparison
Incremental Costs of kWh
Embedded in Glacial Index
$0.10
• Energy Losses and Unaccounted for Energy $0.0917
(UFE)
$0.09 • ISO charges and Other Ancillary Fees
• Zonal Congestion
$0.08 • Capacity & Related Fees
• Market Settlement Charges $0.0744
• Glacial Margin
$0.07
$0.06
Wholesale Cost
of kWh at
$0.05 CAISO
$0.0393
$0.04
$0.03
$0.02
$0.01
$0.00
CAISO (NP15) GLACIAL ENERGY PG&E E-19 TARIFF
INDEX RATE
Source: FERC, Glacial Energy
This information is commercially confidential 7

8. Direct Access Capacity CAP—Limited Market Opportunity
DIRECT ACCESS CAPACITY AS
DIRECT ACCESS CAPACITY
A PERCENTAGE OF TOTAL
CAP PHASE-IN BY EACH YEAR
CAP Expressed Across All Three Utilities UTILITY LOAD
CAP Expressed Across All Three Utilities
200,000,000,000
180,000,000,000
160,000,000,000
140,000,000,000
Direct Access
120,000,000,000 Market Load will
be Over 14% of
100,000,000,000 Total UDC Load
by 2013
80,000,000,000
60,000,000,000
40,000,000,000
20,000,000,000
0
Existing New UDC Load
DA Load DA Load
(Left Over (Post 2013)
from 2001)
This information is commercially confidential 8

9. Time Line For Selecting Direct Access
April 16th, 2010
20 Days
March After NOI 60 Days
to April Submitted After NOI
is Affirmed
July 2010
• Review benefits of • Submit Notice of • After receiving • Customer • Final meter
entering direct Intent (NOI) to the the NOI from a must enter read by Utility
access their Utility customer, the into a contract is completed
Utility will with an Energy and the ESP
• Identify potential • Indicates to utility confirm or deny
Service becomes the
Energy Service that customer the customers Provider provider of
Providers desires to enter reservation in record
Direct Access the Direct
• Determine pros • Energy Service
and cons of Access market Provider must
entering Direct submit a DASR
Access market on behalf of
the customer
requesting
that service be
switched from
the Utility to
the ESP
This information is commercially confidential 9