Robert J. KingGoodCompany AssociatesJanuary 30

Slide 1: Robert J. King GoodCompany Associates January 30, 2007

Exploring Aggregated Demand Response Solutions In ERCOT Markets

Slide 2:ERCOT AUGUST 17 PEAK DAYOPERATIONS DATA

57,376 MW 63,259 MW 64,731 MW

Slide 3:ERCOT AUGUST 17 PEAK DAYOperations and Planning AnalysisFrom Ken Donoho, 9/17/06

Slide 4:Clarifying Definitions

Electric Load (kW) Electric Load (kW) Time of Day Electric Load (kW) ENERGY EFFICIENCY Reduce total kWh of loadshape with permanent efficient technologies. E.g.: CFLs, PE Motors, T8�s, etc.. DEMAND RESPONSE Temporary reduction of peak energy usage for a defined duration. Curtailment �events� triggered by either reliability or high prices. E.g.: Load-control switch, Thermostats LOAD SHIFTING �Flattening� the loadshape by using off-peak power in place of on-peak power. Often permanent shift driven by combining appropriate technology and rates (TOU). E.g: Thermal Energy Storage

Slide 5:Actual Residential Test

Average Daily Load Profiles for all Homes in Program (July � September)

Slide 6:Commercial Example

Managing Retail HVAC/Lighting Loads

Slide 8:Characteristics Of Demand Response

Load Granularity: Large industrial loads may only be available in MW chunks while small loads can be aggregated and finely tuned. Response Time: The time between sending the signal and actually curtailing the load can vary from sub-seconds to day-ahead. Control Symmetry: The ability to control loads both "up" and "down". Some industrial loads can be shed in a few minutes, but take hours to return to the grid. Other DR technologies can respond in seconds. Monitoring: Load changes must be measured and verified, and feedback may be required for the load provider to ensure performance. Settlements can be based on measured or stipulated performance. Duration and Frequency: How often can the load be curtailed? For how long? How much warning is required? DR �types� can vary according to many factors, technology, monitoring method, end-use customers, costs and benefits. The key differences include the following operational qualities:

Slide 9:Conceptual Map of DR Types

Basic Components Grid Components (Meters, RTUs, SCADA, LCD, Xfrms, etc�) Advanced Components Basic Network Advanced Network Communication Network Near-real-time 2-way data Detailed Control DR Infrastructure can overlap with AMI Infrastructure LaaRs Tiered Frequency Response Direct Cut-off DR Intelligent DR Load Co-op TOU Load Control Relays Thermostat Setback w/ metering Thermostat Setback

Slide 10:In Home Display ($180 plus $100 installation) Basic Load Control Switch, Single Load ($75 + $100 for installation) 1 way communication with no verification Can control various loads (pool pumps, water heater, A/C, etc�) Enhanced Load Control Switch ($250 plus $100 installation) 2 way communication, allows verification Load shed determined by historical use Allows emergency low frequency event participation Remote Controlled Thermostat ($200 plus $100 installation) 1 way communication, no verification Web/internet programmable, variable load shed Controlled equipment: A/C Home Automation/Energy Management System (>$2500) 2 way communication available, allows verification Variable load shed Controlled equipment: A/C, pool pumps, water heater, appliances, lights

Sample DR Technologies (Residential)

Slide 11:Sample DR Technologies (C&I)

Basic Load Control Switch, Single Load ($75 + $100 install) Remote Controlled Thermostat ($200 plus $100 installation) Energy Management System Interface ($100 + $100-500 install) 1 way communication with no verification Must enable a pre-programmed demand response mode Dimmable Lighting Ballasts ($15-$40/ballast) Lights can dim 40% over 15 minutes without complaints Addressable by circuit or ballast Great application for combining EE and DR Energy Management Systems ($500-$20,000 + >$1000 install) 2 way communication with verification EMS must be able programmed to operate in �load shed� mode Specialty Control Device Products (costs vary) Industrial Gas OEM�s can fill tanks on flexible notice Various products for remote dispatch of DG assets

Slide 13:Providers of DR Technologies

These firms offer a wide range of DR technology & services Ice Energy Infotility Invensys Johnson Controls muNet.com PowerGrid Communications Powerweb Technologies RETX Siemens Building Technologies Silver Spring Networks Site-Controls SmartSynch � TAC/Tour Andover Controls Trilliant Networks Automated Energy, Inc. Automated Power Exchange Cannon Technologies Comverge Technologies Connected Energy Corp. ConsumerPower Line Corporate Systems Current Technologies Energy Controls & Concepts EnerNOC Enerwise Engage Networks, Inc. GoodCents Sollutions Honeywell Utility Services Hunt Power/Apogee Interactive Note: We have had discussions with the 22 firms in bold and meetings with the 6 firms followed by (*). MOVE CANNONMOVE CANNON

Slide 14:Who�s Doing DR Today? (1 of 3)

Demand Response is used as an important tool of most ISOs

Slide 15:Who�s Doing DR Today? (2 of 3)

Demand Response is used as an important tool of most ISOs

Slide 16:Who�s Doing DR Today? (3 of 3)

Demand Response is also used as an important tool by many IOUs

Slide 17:FERC Demand Response Survey

Data from comprehensive report released to Congress in August 2006 Customers Enrolled in Direct Load Control (DLC) Programs Number of Entities Offering Capacity, Demand Bidding, and Emergency Programs Although the Technology exists, ERCOT exhibits limited participation in DR programs compared with other NARC Regions��

Slide 18:Conclusions from Existing Research

Studies find substantial system value for Demand Response. Benefits are difficult to capture, quantify, and monetize. Lack of standard definitions of benefits and �DR Types�. Large uncertainties in quantifying benefits. Reliability is complex to model, VOLL, option value, risk and efficient frontier analysis Arbitrage value exists at low-frequency extremes (e.g. most expensive 20-200 hours, which vary by year) Many non-quantifiable benefits (e.g. operational flexibility, customer choice, anti-collusion, etc�)� �Value� depends on perspective and most analysis looks at �system benefits� or net social benefits.

Slide 19:ERCOT: Identifying / Quantifying Value

Regulatory and Social Benefits Increased Reliability Enhanced Customer Choices More Efficient Use of Resources Developing Demand Response Capacity in Texas delivers value to different parties. Benefits fall into one of three categories. Benefits Realized Internally by TDUs Benefits Realized by Other Market Participants Operational Efficiencies Deferred Capital Costs of T&D Regulatory Goodwill REPs �Commodity value, lower LMPs, facilitates expanded service and rate offerings. QSE � reduction of imbalance events ERCOT � additional sources of reserves and ancillary services Customers � premium services

Slide 20:Quantifying Value in ERCOT

EE Program Incentives Total Avoided Costs � Add range of potential increases from other slide (ISSER)Total Avoided Costs � Add range of potential increases from other slide (ISSER)

Slide 21:EE Benefits Alone do not Cover Costs

Load Mgmt. General (25% AC) Load Mgmt. (C&I) (35% AC) Load Mgmt. (Residential) (55% AC) Load Mgmt. (HTR) (100% AC) �Avoided Cost� (AC) defined as $78.50/kW/year In Congested Areas Technology Costs Range $60-$110 /kW/year Technology Costs Technologies are mature and proven. Costs vary widely and are very site-specific. EE Budget (�25.181) will cover full DR costs in only a few rare situations. Must identify additional sources of value to fill this gap�

Slide 22:TDU Benefits

Operational Efficiencies Reduction in local outages Increased operational flexibility More options in system planning Deferred Capital Costs of T&D Transmission capital deferral limited to TDU share of postage stamp rates Distribution capital cost deferral value accrues to TDU directly Realizing this value depends on rate structure, regulatory lag Potential revenue loss from reducing peak demand by large customers on rates that have large demand component Regulatory Goodwill

Slide 23:Quantifying Values: Previous Studies

Pacific Northwest National Lab (June 2006) GridWise demonstration combining DR and DG System Benefit Analysis of capital deferral Gen: $15 � 36 LMP: $10 � 15 Dist: $13 � 90 Trans: $8 � 40 TOTAL: $46 � 181 /kW/yr MADRI States DR Benefits (November 2005) System wide study for state PUCs for incenting distributed resources System Benefit Analysis of capital deferral Capacity benefit: $40 LMP: $34 Dist: $35 Other (Emis, Reliabil.): $100 TOTAL $209 /kW/yr DRR Valuation and Market Analysis, IEA (2006). Monte Carlo Simulations of Strategist asset-based system model Defined 3 �types� of demand response: Interruptible CPP Callable w/ RTP Total System Cost Savings from each type was $48, $574, $1,984 million (20-year NPV)

Slide 24:Quantifying Benefits to T&D Utilitites

Transmission and Distribution benefits vary widely over a TDU�s territory (we calculate $490/KW NPV from CNP Rate Case) Marginal Costs are much higher than average costs, so higher in utilities with growth Additional Studies by CEC and EPRI regarding energy storage attempt to quantify avoided T&D Costs for demand reduction Range for costs avoided ranges from $35/kW to over $1900 Distribution upgrades suggest an internal value for capital deferrals. Other studies found 10% of the substation upgrade capital to be >$1000/kW. RANGE: $35 - $1900 $/kW/yr Conservative Value: $40 $/kW/yr Benefits Realized Internally by TDU

Slide 25:Benefits realized by others

REPS, DR Aggregator - Ancillary Services Revenues Must meet conditions for eligibility for each market. Currently, DR only receives revenue as LaaRs. QSE would have to bid DR. REPs � Arbitrage Value REPs have little interest in DR for arbitrage under current market. Difficult for DR to qualify and sell into the Balancing Energy Market. AMI, change in settlement from profile could make DR a valuable option. Will DR receive LMP? REPs � lower LMPs Requires large amounts of DR to lower market price, socialized benefit. DR can reduce local congestion, but REPs will be charged zonal price.� QSE � could benefit from reduction of imbalance events. ERCOT �source of reserves and ancillary services; avoids ICAP costs.

Slide 27:Commodity Value in ERCOT

Slide 28:Quantifying Value

($19-$78) ($20 - $120) ($4 - $20) ($35-$185) Value Stack for Demand Response NOTE: This does not include costs for marketing or profit sharing among parties. Costs and Value of DR ($/kW/year) TYPE A Social Benefits TYPE B Internal TDU Benefits TYPE C External Benefits Total Gross Benefits Current Technology Costs $40 ($19-$78) $40 ($20 - $1900) $10.00 $60.00 $90 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 EE Program Incentives T&D Avoided Cost (BES Market) TOTAL GROSS BENEFITS Average Technology Costs ($4 - $20)

Slide 29:Quantifying Value

($19-$78) ($20 - $120) ($4 - $20) ($35-$185) Value Stack for Demand Response NOTE: This does not include costs for marketing or profit sharing among parties. Costs and Value of DR ($/kW/year) TYPE A Social Benefits TYPE B Internal TDU Benefits TYPE C External Benefits Total Gross Benefits Current Technology Costs $40 ($19-$78) $40 ($20 - $1900) $10.00 $60.00 $90 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 EE Program Incentives T&D Avoided Cost (BES Market) TOTAL GROSS BENEFITS Average Technology Costs ($4 - $20) Total Avoided Generation Cost Additional T&D Avoided Cost Market Potential (LaaRs=$40 to $69/kW)

Slide 30:Conceptual ERCOT Market Structure

Texas Legislature Texas PUC Bid Dispatch Rate Total Payment (G, T, D, + A) T&D Proposals Metering Services Committed Load Payment for Committed Load ($) Load Forecast Metering Services Physical Delivery Physical Delivery ERCOT Settlement (RPRS +BES) GenCo (or Power Marketer) REP End-User ERCOT TDSP Payment Metering Svcs QSE QSE T&D Co ERCOT Settlement (BES)

Slide 31:ERCOT Regulatory Environment

Advanced Meter Rules are currently under consideration. TDU cannot provide Competitive Services�can�t reach behind the meter. Limits on energy-efficiency incentive payments (~$20-40/kW/year) established by rule. Existing LaaRs Market limited to very large customers (2005:� 1,803 MW eligible, $71.1M payments or $39.40/eligible kW/year). REP/QSE only access point into ERCOT energy market settlement process. Fixed settlement profiles are a barrier to realizing DR value to REP and Customer.

Slide 32:REP Interviews � Highlights

REPs today sell largely on cost (3). REPs expect to sell more on service (8). AMI more important influence than PTB. REPs don�t understand the EE Programs (although affiliated C&I ESCOs do). Reducing acquisition costs all important. Selling equipment to customers complicates sales process. Most potential value perceived in mass market. Want to be �in the loop� for demand response. BOB KINGBOB KING

Slide 33:Business Model 1

TDU REP End-Users Contractual Payment Marketing Installation EE Program ($) Avoided T&D ($) Dispatch 3rd Party EE Program ($)

Slide 34:Business Model 2

TDU REP (multiple) End-Users Contractual Payment Marketing Installation EE Program ($) (Avoided T&D ($)) 3rd Party Joint Marketing Joint Dispatch (Z times per year) Performance Guarantee Commodity Value ($) EE Program ($) Joint Dispatch (Y times per year) Performance Guarantee

Slide 35:Section 39.905 (a) (3) Goal for Energy Efficiency

Envisioned a larger role for REPs �each electric utility will provide, through market-based standard offer programs or limited, targeted, market-transformation programs, incentives sufficient for retail electric providers and competitive energy service providers to acquire additional cost-effective energy efficiency equivalent to at least 10 percent of the electric utility's annual growth in demand� The PUCT has opened the Energy Efficiency Rule for reconsideration. Additional Funding is required if we are truly hoping to have the REPs participate, and take efficiency to a new level. If the avoided cost calculation can be modified to include the real avoided cost of T&D in addition to Generation, even with the current caps (35% for C&I, 50% for Res, 100% for HTR), Demand Response will likely flourish in the ERCOT Market

Slide 36:Quantifying Value

($19-$78) ($20 - $120) ($4 - $20) ($35-$185) Value Stack for Demand Response NOTE: This does not include costs for marketing or profit sharing among parties. Costs and Value of DR ($/kW/year) TYPE A Social Benefits TYPE B Internal TDU Benefits TYPE C External Benefits Total Gross Benefits Current Technology Costs $40 ($19-$78) $40 ($20 - $1900) $10.00 $60.00 $90 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 EE Program Avoided Gen. Cost T&D Avoided Cost (BES Market) TOTAL GROSS BENEFITS Average Technology Costs ($4 - $20) +

Slide 37:Quantifying Value

($19-$78) ($20 - $120) ($4 - $20) ($35-$185) Value Stack for Demand Response NOTE: This does not include costs for marketing or profit sharing among parties. Costs and Value of DR ($/kW/year) TYPE A Social Benefits TYPE B Internal TDU Benefits TYPE C External Benefits Total Gross Benefits Current Technology Costs $40 ($19-$78) $40 ($20 - $1900) $10.00 $60.00 $90 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 EE Program Incentives (BES Market) TOTAL GROSS BENEFITS Average Technology Costs ($4 - $20)

Slide 38:Business Model 3

TDU REP (multiple) End-Users Marketing Installation EE Program ($) 3rd Party Settlement Payment Joint Dispatch (Z times per year) Performance Guarantee Contractual Payment Performance Guarantee EE Program ($) ERCOT Supply Bids Dispatch Order