Ca dereg 2 0 why now glacial call to action


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Ca dereg 2 0 why now glacial call to action

  1. 1. California Electricity Deregulation 2.0 Why This Time?...Why Now? April 2010
  2. 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. 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. 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. 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. 6. Imbedded Utility Costs Create Market Opportunity for Index Price This information is commercially confidential 6
  7. 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. 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. 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