The Regulatory Assistance Project 50 State Street, Suite 3Montpelier, VT 05602

Phone: 802-223-8199www.raponline.org

Smart Rate Designfor a Smart Future

Olympia, Washington

December 11, 2015

Presented by Jim Lazar

Overview

About RAP

Regulatory History

WUTC Decisions in PURPA Era

Residential Rate Design

Distributed Generation and Net Metering

Adapting to Variable Resources

Smart Grid

2

Brief History of Regulation

3

Medieval England Accommodations

• Business “affected with the public interest.”

• Prices regulated due to monopoly stature

4

New Inn, Gloucester, 1454

US Origin: Munn v. Illinois (1877)

• Grain elevators charging monopoly prices to farmers.

• Supreme Court ruled “affected with the public interest” and subject to price regulation.

5

Bluefield Water Works (1935)

• Prudent investment rule.

• Utility entitled to a return comparable to companies with similar risks.

6

Hope Natural Gas (1944)

• “Just and reasonable” standard upheld.

• End result, not the method employed.

• Intervenors have limited rights.

7

The Roaring ’60s and the Scary ’70s

• Load Growth

• + Inflation

8

Result: Big Rate Increases

9

Centralia 1972

Trojan 1975

WPPSS 1979

Colstrip 3&4: 1983/85

Centralia (1972):

$200/kW

Colstrip 1&2

(1975):

$300/kW

Trojan (1975):

$700/kW

Colstrip 3&4

(1983/85)

$1,300/kW

WPPSS #2 (1985)

$3,000/kW

Public Utility Regulatory Policies Act: 1978

• Avoided Cost for Independent Power

• Right of Intervention

• PURPA Ratemaking Standards

10

Rate Design Standards

Cost of ServiceTime of DaySeasonalInterruptibleDeclining BlockLifeline

Utility Service Standards

Master MeteringFuel Adjustment ClausesInformation to ConsumersTermination of ServiceAdvertising

The PURPA Right of Intervention

• Any subject utility: 750 million kWh/year

• Any consumer may intervene

– Right to present evidence

– Right to reasonable rules of discovery

– Right to intervenor compensation if no consumer advocate is funded.

11

12

Overcapacity and Abandoned Plant

• Sharp rate increases led to low growth

• Abandoned projects in the PNW include:

– Nuclear:

• Skagit 1 & 2 (Puget)

• Pebble Springs 1&2 (Portland GE)

• WPPSS 1, 3, 4, 5 (Public Power)

– Coal

• Creston (Avista)

• Pioneer (Idaho Power)

13

Regulatory Treatment of Excess Capacity and Abandoned Plant

• High rates drove down loads

• High rates drove out aluminum industry

• Efficiency further reduced load growth

• Hotly contested in 1985 – 1995

– Abandoned Plant: ~65% recovery

– Excess Capacity: ~90% recovery

14

Integrated Resource Planning: Examples

• 1975: Seattle City Light Energy 1990

• 1977: NRDC Alternative Scenario

• 1980: NW Power Act

• 1981: Initiative 394

• 1982: “Model Plan”

• 1983: First Power Plan

15

Washington Rate Design History

16

Issues Addressed in the PURPA Docketand the Early 1980s

• Embedded vs. marginal cost of service

Baseload generation vs. peaking

Transmission allocation

Distribution cost allocation

• Lifeline rates vs. baseline rates

Cost basis for inclining block rates

17

Embedded vs. Marginal Cost

• Staff position: Marginal cost

California, Oregon, Montana, Pacific Power, Puget

• Avista, industrials: Embedded cost

• Consumer intervenors: Incremental cost (Seattle method)

• Decision: “Forward-looking embedded cost”

18

Embedded Cost of Service

• Functionalization

• Classification

• Allocation

19

Pro Forma Results of Operations by Customer Group

ELECTRIC COST OF SERVICE STUDY FLOWCHART

TransmissionProductionCommon

Energy /

Commodity

Related

Customer

Related

Demand /

Capacity Related

Residential Small General Large General Extra Large

General

Pumping Street & Area

Lights

Allocation

Pro Forma

Results of

Operations

Functionalization

Distribution and

Customer

Relations

Classification

Direct Assignment

Number of Customers

Weighted Number of

Customers

Direct Assignment

Coincident Peak

Non-Coincident Peak

Direct Assignment

Generation Level mWh's

Customer Level mWh's

Different Approaches to Embedded Cost Allocation

• Production

• Transmission

• Distribution

20

Production Cost

• Peak responsibility (industrial customers)

100% of all investment-related costs and maintenance costs classified as demand

Allocated based on 1 to 12 hours of demand.

• Average and excess demand (Avista)

• Peak credit (PSE, Pacific, intervenors, staff)

• Decision: Peak credit

21

Commission Decisions: Production Cost

• Mr. Schoenbeck's [industrial customers] proposed allocation on a fixed/variable approach is rejected because it fails to recognize whether generation is constructed for baseload or peaking.

- Cause U-82-12, Fourth Supp. Order, P. 34 (Pacific)

22

Production Cost: Now

• Baseload Thermal

• Baseload Renewable

• Peaking Thermal

• Variable Renewable

• Demand Response

• Central Batteries

• Distributed Batteries

23

Production Cost: Now

• Hourly energy (Texas)

• Hourly energy with separate short-duration capacity market (New England)

• Base-intermediate-peak methods

• “Capacity” and “demand-related” are obsolete concepts

24

Discussion: Production Cost

25

Transmission Cost

• Demand-related: Industrials

• Baseload vs. network: PSE, Avista

• As production: Staff, intervenors, Pacific

26

Commission Decisionson Transmission

• The Company is ordered in its next rate case to present a cost of service study that complies literally with the Commission's directive related to the allocation of transmission costs. The Commission does not intend that remote transmission costs should be allocated differently than total transmission costs. - Cause U-82-38, Third Supp. Order, P. 31 (Puget)

27

Commission Decision on Transmission

• Commission Staff's position conforms with our continuing belief that "distribution-related" transmission lines are constructed to deliver energy as well as to meet peak demand. Thus, we reaffirm that transmission network costs should be classified as partly driven by demand and partly by energy, using the approved Peak

Credit ratio.

- Docket No. UE-920499, Ninth Supplemental Order on Rate Design, P. 10 (Puget)

28

Transmission Cost: Now

We now know that peaking resources and demand response are built “in the load center” and should probably bear no high-voltage transmission cost at all.

BUT: Wind and central solar may not meet peak demand, but do need transmission.

29

Distribution Cost

• Most contested issue nationally

• “Minimum system” method: ~50% of distribution infrastructure treated as “per-customer” cost

• “Basic customer” method: Only customer-specific costs treated per-customer

• Now some utilities are pursuing the “straight fixed/variable method: 100% of system per-customer

30

Straight Fixed/

Variable:

100% ofDistribution

System Classified as Customer-

Related

31

Minimum System

Method:

~50% ofDistribution

System Classified as Customer-

Related

32

Basic Customer Method:

ONLY Customer-

Specific Facilities

Classified as Customer-

Related

33

Commission Decisions on Distribution Cost

The Commission rejects the company's use of the zero-intercept method. The minimum system method, of which the zero-intercept method is a variant, is also rejected. Both methods are likely to lead to the double allocation of costs to residential customers and over allocation of costs to low use customers.

- Cause U-83-26, Fifth Supp. Order, P. 33 (Avista)

34

Commission Decisions on Distribution Cost

Costs such as meter reading, billing, the cost of meters and service drops, are properly attributable to the marginal cost of serving a single customer. The cost of a minimum sized system is not. The parties should not use the minimum system approach in future studies.

- Cause U-89-2688-T, Third Supp. Order, P. 71 (Puget)

35

Commission Decisions on Distribution Cost

We agree with Commission Staff that proponents of the Minimum System approach have once again failed to answer criticisms that have led us to reject this approach in the past. We direct the parties not to propose the Minimum System approach in the future unless technological changes in the utility industry emerge, justifying revised proposals.

- Docket No. UE-920499, Ninth Supp. Order (Puget)

36

Lifeline/Baseline Rates

• Commission defined “lifeline” rate to be income-driven.

• “Baseline” rate was defined as a lower cost for initial block for all customers to reflect hydro costs.

• Adopted “baseline” rates.

37

Discussion: Distribution Costs

38

Break

39

Residential Rate Design

• Customer charges

• Inclining block rates

• TOU rates

• Seasonal rates

• Demand charges

• Critical peak pricing

• Net metering / PV customers

40

Customer Charges

• Cost allocation

• Minimum system

• Basic customer

• BUT: Cost allocation is not rate design

• “Forward-looking embedded cost”

41

The Line Extension Policy

Part of the tariff – Avista/Idaho:

42

Comparing Methods

43

Cost Category

Straight

Fixed /

Variable

Minimum

System

Method

Basic

Customer

Method

Poles $10 $5 -$

Wires $20 $10 -$

Transformers $14 $7 -$

Services $1 $1 $1

Meters $1 $1 $1

Billing $3 $3 $3

Customer Service $3 $3 $3

Total $52 $30 $8

$/month/customer

Distribution Cost: Today

• Why are distribution systems built?

• Single-family vs. multi-family

• Urban vs. suburban vs. rural

• Overhead vs. underground

• Role of demand response is avoiding distribution capacity upgrades

• Smart grid investments provide upstream benefits

44

“Subsidies”

Utilities argue that net-billing is a “subsidy” or that “large users are subsidizing small users.”

Rate design is full of subsidies:

• Apartments vs. single-family

• Urban vs. rural

• Overhead service vs. underground

45

Single-Family Sprawl Zone:

4 customers per circuit-mile

46

Studio Apartments:

4,000 customers per circuit-mile

Billing and Collection Costs

WUTC rule: “Not less than bimonthly.”

Why do we bill customers monthly?

47

What About Other Industries?

48

We Pay For Other “Grids”In Volumetric Prices

49

The Most Common Residential Rate Design: Inclining Block

• Goals include:

• Allocation of low-cost resources

• Recognition of load

• Encouragement of conservation

• Essential needs at affordable cost

• Low-income benefits

50

Residential Inclining Block Rate

51

City of Palo Alto (California)

Customer Charge None

First 300 kWh $0.096/kWh

Next 300 kWh $0.130/kWh

Over 600 kWh $0.174/kWh

52

How an Inclining Block RateAffects Most Consumption

Usage

Block

% of

Customers

Whose

Usage Ends

In This Block

% of kWh Sales

To Customers

Whose Usage

Ends in This

Block

% of kWh Sales

to Customers

Whose Usage

Exceeds This

Block

0 - 250 29% 8% 92%

251 - 500 33% 23% 69%

501 - 750 17% 20% 51%

751 - 1,000 9% 15% 34%

>1,000 12% 34%

Average Monthly kWh Usage: 526

Seasonal + Inclining Block

53

Arizona Public Service Company (Arizona) Optional TOU Available

Winter Summer

0 – 400 kWh $0.0942 $0.0969

401 – 800 kWh $0.0942 $0.1382

801 – 3,000 kWh $0.0942 $0.1617

Over 3,000 kWh $0.0942 $0.1726

An Inclining Block Rate CAN BE a Seasonal Rate

54

Cost Basis for Inclining Block Rates

• Load factor

• Resource allocation (baseline rates)

• Conservation policy

• Marginal cost

55

Inclining Block Rate Based on Load Factor

• Start with a typical commercial rate:

–$10/kW/month + $.08/kWh

• Determine load factor of each usage Block

• Compute block rates

56

Primary Usage kWh

Load

Factor Demand Energy Total

Lights/Appliances 400 70% 0.020$ 0.08$ 0.100$

Water Heat 401- 800 40% 0.035$ 0.08$ 0.115$

Space Conditioning >800 20% 0.069$ 0.08$ 0.149$

Baseline Block RatesBased on Resource Types

• Start with typical cost of resources;

• Determine how much of each the utility has available for the class;

• Set blocks to recover costs.

57

Block kWh Energy Delivery Total

Hydro 250 0.02$ 0.06$ 0.08$

Coal 251 - 750 0.04$ 0.06$ 0.10$

New Supply >750 0.10$ 0.06$ 0.16$

Residential Demand Charges

• Newest rate due to fixed charge backlash.

• Common in commercial rates.

• Terrible idea.

58

Problems with Demand Charges

1) Normally measure non-coincident peak, which is irrelevant to anything but the final line transformer.

2) Reward customers that contribute to the peak every day, vs. those whose use varies.

3) Lack of customer understanding.

59

Individual Load Shapes Vary

60

0

0.5

1

1.5

2

2.5

3

12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11

Customer 3: 38% Load Factor

Customer 3

All the Utility Sees Is The Combined Loadof Multiple Customers With Different Shapes

61

Lots of Diversity at the Transformer:26-Unit Apartment Complex, L.A. Area

62

0

20

40

60

80

100

120

140

160

1 2 3 4 5 6 7 8 9 10 11 12

Individual Demand Total Grouped Demand Total

Service Size Rate:Burbank

63

Rate Element Amount

Customer Charge $/month $7.11

Service Size Charge $/month

Small Most multifamily $1.40

Medium Most single family $2.80

Large 400 Amp Panel + $8.40

First 300 kWh $/kWh $.1153

Over 300 kWh $/kWh $.1672

Service Size Charge:Électricité de France (EdF) Base Rate

Typical

Dwelling Units

Contract

power-rating

(kVA)

Subscription

Including Tax

$/month

Price per

kWh incl. tax

$/kWh

Incre-

mental

$/kW /

Month

Apartments 3 $ 4.76 $ 0.154

6 $ 7.73 $ 0.154 0.99$

Small SF Home 9 $ 10.24 $ 0.154 0.84$

12 $ 15.75 $ 0.154 1.84$

15 $ 18.07 $ 0.154 0.77$

Large SF Home 18 $ 20.78 $ 0.154 0.90$

24 $ 44.24 $ 0.154 3.91$

30 $ 54.67 $ 0.154 1.74$

36 $ 63.32 $ 0.154 1.44$

64

Time-of-Use (TOU) Rates

• PURPA decision

• History: PSE Pilot, 1999 – 2002

• Recent California decision

65

PSE Pilot

• 300,000 customers

• Default – opt-out available

• Additional cost implemented in 2002

• ~90% of customers losers

• Suddenly terminated

• Evaluation

66

California PUC Decision

• Three-year process

• No customer charge

• Inclining blocks: 2 blocks 25% differential

• 3-period TOU default by ~2019

67

68

Rates That Require AMI

• Peak-Time Rebate (PTR): A customer gets a credit if they reduce their usage during peak events. No penalty if they do not.

• Critical Peak Price (CPP): A high price defined in advance that takes effect on a day-ahead notice basis.

• Variable Peak Price (VPP): A price that is set one day ahead that takes effect when noticed by the utility.

• Real-Time Price (RTP): A price that is set by the market, and may change with one-hour notice.

69

Peak-Time Rebate

• Risk-free: Customer can win, but cannot lose

• Events are noticed, generally day-ahead

• San Diego Gas and Electric “Reduce Your Use” Rate

– A “use less than” amount is set at program signup

– Email or text notification when events occur

– 11 AM to 6 PM time period

– $.75/kWh for manual reduction

– $1.25/kWh for technology-enabled reduction

– No minimum or maximum periods per year

• “Training wheels” for critical peak pricing

70

Critical Peak PricingEskom (South Africa) RuralFlex

• 17 days per year maximum; day-ahead notice

71

Critical Peak Pricing: Électricité de France Tempo

• Tempo unit shows what price in effect

• All days have on-peak and off-peak

• Inclining customer charge tied to kVa

• Maximum 22 “red” days per year

EdF Tempo

Rate

72

Enabling Technology For CPP and RTP

• Installation of energy management devices that automatically adjust energy use when a price signal is received.

– Air conditioning

– Process and water heat

– Cold storage refrigeration

– Eventually, minor loads like refrigerators, freezers, and laundry equipment

73

Enabling Technology Improves Price Response

74

Peak Load ReductionVaries by Pricing Approach

75

Peak Reduction vs.Energy Reduction

• Inclining block rates produce the most overall reduction in energy usage. This occurs because incremental usage is most discretionary.

• Time-varying prices produce peak load reduction, but may or may not reduce total energy use

– Pre-cooling of buildings may increase total kWh usage

– Curtailment of A/C may lead customers to “not be home” at all, reducing other energy usage

• More complex rates work best with technology enablement.

76

Inclining Block Rates Save Energy;Complex Rates Save Peak

USEPA, Customer Incentives for Energy Efficiency Through Electric and Natural Gas Rate Design, September, 2009

Principles for Modern Rate Design

Universal Service: A customer should be able to connect to the grid for no more than the cost of connecting to the grid.

Time-Varying: Customers should pay for grid services and power supply in proportion to how much they use and when they use it.

Fair Compensation: Customers supplying power to the grid should be compensated fairly for the value of the power they supply.

77

Principle #1

A customer should be allowed to connect to the grid for no more than the cost of connecting to the grid.

78

Principle #2

Customers should pay for the grid in proportion to how much they use the grid, and when they use the grid.

79

Principle #2

Customers should pay for the grid in proportion to how much they use the grid, and when they use the grid.

80

Principle #3

Customers delivering power to the grid should receive full and fair value – no more and no less.

81

A Simple Cost-Based Rate Design

82

Transformer: $/kVA/Mo 1.00$

Off-Peak $/kWh 0.08$

Mid-Peak $/kWh 0.12$

On-Peak $/kWh 0.18$

Critical Peak $/kWh 0.75$

Bi-Directional Energy Charges

Customer-Specific Charges

Customer Charge $/Month 3.00$

Bill Simplification

83

Which Pricing Approach Is More Useful to You as a Consumer?

Crude Oil 2.237$

Tanker to Refinery 0.114$

Refinery Capital 0.213$

Refinery Operating 0.235$

Product Pipeline 0.113$

Terminal Rack 0.023$

Truck to MiniMart 0.114$

Mini-Mart Profit 0.217$

State Taxes 0.349$

Federal Taxes 0.184$

So Why Confuse Consumers?

85

Your Usage: 1,266 kWh

Base Rate Rate Usage Amount

First 500 kWh 0.04000$ 500 20.00$

Next 500 kWh 0.06000$ 500 30.00$

Over 1,000 kwh 0.08000$ 266 21.28$

Fuel Adjustment Charge 0.03456$ 1,266 43.75$

Infrastructure Tracker 0.00789$ 1,266 9.99$

Decoupling Adjustment (0.00057)$ 1,266 (0.72)$

Conservation Program Charge 0.00123$ 1,266 1.56$

Nuclear Decommissioning 0.00037$ 1,266 0.47$

Subtotal: 126.33$

State Tax 5% 6.32$

City Tax 6% 7.96$

Total Due 140.60$

When This is What It Really Means

If you want customersto respond to the rate,

simplify the bill

86

EFFECTIVE RATE INCLUDING ALL ADJUSTMENTS

First 500 kWh 0.09291$ 500 46.46$

Next 500 kWh 0.11517$ 500 57.59$

Over 1,000 kwh 0.13743$ 266 36.56$

Total Due: 140.60$

Discussion: Rate Design

87

Break

88

89

Distributed Generation and Net Metering

Two Views of Cost Recovery

Traditional Utility View• DG customer “uses” the grid

and should pay for it

Solar Advocate View• Value of distributed resource is

greater than the retail rate

90

RMI Survey Of Multiple StudiesAverage: $.1672/kWh

91

92

$0.090

$0.138 $0.135

$0.107$0.115

$0.00

$0.04

$0.08

$0.12

$0.16

MaineShort-Run

MaineLong-Run

Minnesota Austin Averageper-kWh

Rate

Value of Solar Studies: Utility Economic Values Only

Comparison of Washington Ratesto California Residential Rates

• CA first block > Washington tail block

• Average rates in Washington < LRIC

93

Monthly Block 1 Block 2 Block 3 Block 4 Average

Puget 7.87$ 0.094$ 0.110$ 0.104$

Pacific 6.00$ 0.059$ 0.094$ 0.079$

Avista 8.00$ 0.071$ 0.083$ 0.097$ 0.086$

PG&E -$ 0.132$ 0.159$ 0.319$ 0.359$ 0.153$

Strategy for Washington

• Focus on increasing tail blocks to reflect full long-run marginal costs of $.13-$.20

• Reduce customer charges and initial block rates to achieve higher tail blocks.

• If and when tail blocks fall below long-run marginal costs, then raise initial blocks, and only then consider distribution fees for DG customers.

• Address short-run revenue issues with decoupling or other revenue stabilization options.

94

95

A Home-Grown Tomato is a “Better” Tomato

96

Lots of People Grow Their Own Tomatoes

97

What If You Don’t Have Enough?

98

What If You Have Too Many?

99

All Tomatoes Are Not Equal

Local Organic

Tomatoes $3.00/lb.

California Tomatoes

$2.00lb.

100

We Buy Local Organic Tomatoes: $2.00lb.

Utility average cost

of service Retail rates

Traditional Ratemaking

101

Lost revenues from

net metering

Short-run fuel and purchased power

costs avoided by net metering

Critical View of Net Metering

102

Solar Advocate View of Net Metering

Lost revenues from net metering

Long-run avoided cost for generation, transmission, distribution+ Reduced emissions+ Avoided fuel cost and supply risks+ Local economic development+ Future carbon costs+ Shading benefits on AC load+ Much, much more

103

Utility average cost of service

Long-run avoided cost for generation, transmission, distribution+ Avoided emission cost+ Avoided RPS Obligation+ Avoided fuel cost risk+ Avoided fuel supply risk

Balanced Net Metering View

104

Discussion: DG and Net Metering

105

Break Before Adapting to Variable Resources

106

The California ISO “Duck Curve”:Increasing solar means steep afternoon ramping

107

Teaching The Duck to FlyTen Strategies To Align Loads to Resources

(and Resources to Loads) 1. Targeted energy

efficiency

2. Orient solar panels

3. Use solar thermal

with storage

4. Manage electric

water heat

5. Require new large

air conditioners to

include storage

6. Retire older inflexible power

plants

7. Concentrate rates into

“ramping” hours

8. Deploy electricity storage in

targeted locations

9. Implement aggressive demand

response programs

10.Use inter-regional exchanges

of power

108

Not every strategy will be applicable to every utility.

Teaching the Duck to Fly

Requesting Permission for Take-Off

Ten Strategies To Align Loads to Resources(and Resources to Loads)

with Illustrative Values for Each1. Targeted energy

efficiency

2. Orient solar panels

3. Use solar thermal

with storage

4. Manage electric

water heat

5. Require new large

air conditioners to

include storage

6. Retire older inflexible power

plants

7. Concentrate rates into

“ramping” hours

8. Deploy electricity storage in

targeted locations

9. Implement aggressive demand

response programs

10.Use inter-regional exchanges

of power

110

Not every strategy will be applicable to every utility.

Water Heat Is a BIG Load for the Electric System

111

Washington Has 1.7 MillionElectric Water Heaters

112

Electric Customers 2,852,760

Gas Customers 1,088,762

Likely Electric

Water Heaters 1,763,998

kWh/Year (average) 4,000

Annual Use MWh 7,055,992

Total State Residential MWh 35,082,958

% Electric Water Heat 20.1%

Strategy 4:Grid-Interactive Water Heating

• GIWH acts as a low-cost “battery”

• Stores a full day’s supply

• Provides ancillary services to the grid

• NOT: Simple on/off control or timers

113

Electric Water Heater Basics• Two 4.4 kW heating

elements

• Water self-stratifies: hot water rises

• Thermostat on each; top has priority

• When top of tank is cold, top element comes on;

• When top is hot, bottom element comes on until full

114

It’s Easy To Spot a Water Heater

115

Water Heat Is a Peak-Oriented Use

116

Source: Steffes Corp.

Add Heat When Power Is Cheap;Draw Hot Water As Needed

117

Grid-Integrated Water Heating:Low-Cost Battery

• Supercharge to 140F – 170F during low-cost hours

• Coast through other hours

118

• 15 – 25 kWh per water heater

Grid-Integrated Water Heating Also Provides Ancillary Services

119

Ancillary Service Value May Exceed Water Heating Energy Cost

120

Break Before Smart Grid

121

Smart Grid

• Benefits of smart grid

• Costs of smart grid

• Allocation of smart grid costs

122

Benefits of Smart Grid

• Ability to measure interval data

• Automated meter reading

• Remote connect/disconnect

• Line loss reduction

• Peak load management

• Capital cost avoidance

• Reliability

123

Burbank: Smartsaver

124

Burbank Smartsaver

125

Glendale:Conservation Voltage Regulation

• Measure voltage in real-time at every customer

• Dial down voltage to meet minimums

• 2-4% energy savings

• 8-year payback for entire AMI system

126

Empowering Smart Technology

New technologies can minimize total system costs and increase system reliability

127

Electric Vehicles

• Source of on-peak power (V2G)

• Market for off-peak power

• Provide multiple ancillary services

128

Path to Smart Electric Future

1. Cost-effective deployment of smart meters/smart grid

2. Development of smart rate designs

3. Adoption of enabling technology to facilitate transition

4. Incorporation of smart design in new construction codes

5. Consumer education

129

Cost Allocation of Smart Grid Costs:Smart Grid Benefits

Reliability improvement: Distribution automation

Peak load reduction through time of use and critical peak pricing

Loss reduction: Voltage control, power factor correction, phase balancing

Remote shut-off and turn-on

Reduced O&M expense for meter reading

130

Cost Allocation of Smart Grid Costs

131

Smart Grid Element

Pre-Smart Grid

Element

"Traditional"

FERC

Account

Traditional

Classification

Smart Grid

Classification

Smart Meters Meters 370 Customer

Demand /

Energy /

Customer

Distribution Control Devices Station Equipment 362 DemandDemand /

Energy

Data Collection System Meter Readers 902 Customer

Demand /

Energy /

Customer

Meter Data Management System General Plant 391 - 397 Subtotal PTDC

Demand /

Energy /

Customer

Smart Grid ManagersCustomer Accounts

Supervision901 Customer

Demand /

Energy

Energy Storage Devices

(Batteries; Ice Bear)

Installations on

Customer Premises 371 Customer

Demand /

Energy

Discussion: Smart Grid

132

Wrap-Up

Other topics?

How can RAP help?

133

134

RAP Publications on Rate Design

• Smart Rate Design for a Smart Future (2015)

• Designing Distributed Generation Tariffs Well (2014)

• Rate Design Where AMI Has Not Been Fully Deployed (2014)

• Time-Varying and Dynamic Rate Design (2013)

• Pricing Do’s and Don’ts (2011)

About RAP

The Regulatory Assistance Project (RAP) is a global, non-profit team of experts that focuses on the long-term economic and environmental sustainability of the power and natural gas sectors. RAP has deep expertise in regulatory and market policies that:

Promote economic efficiency Protect the environment Ensure system reliability Allocate system benefits fairly among all consumers

Learn more about RAP at www.raponline.org

jlazar@raponline.org