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A TOU Rate Primer

Art & Science of TOU Rate Design

Robert Levin rl4@cpuc.ca.govRetail Rate Design Section July 30, 2014 Energy Division

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Guiding Principles*Especially Relevant to Developing TOU Rates

2. Rates should be based on marginal cost;

3. Rates should be based on cost-causation principles;

5. Rates should encourage reduction of both coincident

and non-coincident peak demand;

9. Rates should encourage economically efficient decision

making;

*From Assigned Commissioner’s Ruling issued November 26, 2012 in R.12-06-013

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Why Does the CPUC Base Rates on MC?

Quote from a 1981 CPUC decision adopting MC-based rates:

 • We have chosen marginal costs as our foundation for [electric

cost] allocation and rate design.  We have used marginal costs to promote economic efficiency and to provide the greatest good for the greatest number.  (D.93887 (1981), emphasis added.)

 • TOU rates reflect this idea, with the further refinement  that

marginal costs vary predictably by time of day, weekday/weekend, and season.

 

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Marginal Cost Review

What is a Marginal Cost?: Marginal costs may be defined as the change in total cost which results from a change in output. The result of using marginal cost in rate setting is that the rate equals the cost of producing one more unit, or the savings from producing one less unit. (D. 92749, p. 62)

• Ideally, MC-based rates:

– reflect cost causation (Guiding principle #3)

– result in socially optimal levels of consumption (assuming “externalities” are priced in)

– encourage economically efficient decision making (Guiding principle #9).

• The “flip side” of cost causation is cost avoidance– Thus, marginal costs and avoided costs are closely related

Time-of-Use (TOU) Rates

TOU rates attempt to capture the predictable time-variations in marginal cost with a minimum of complexity.

Marginal generation costs vary by

season,

day type (weekend/holiday versus weekday),

time of day.

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Like Hours are Grouped TogetherMost summer hours are off-peak

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Sun

Mon

Tue

Wed

Thu

Fri

Sat

Summer Peak

Summer Off-Peak

Part-peak

Current TOU Period Definitions

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TOU Period Definitions Are Likely to Changex

Summer Peak

Summer Off-Peak

Part-peak

Current TOU Period Definitions

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Sun

Mon

Tue

Wed

Thu

Fri

Sat

Future??? Summer TOU Period Definitions

Decomposition of Rates

D.13-10-019 (pp.7-8) discusses decomposition of rates into the following 3 components:

1. Marginal costs of providing service– Energy– Generation Capacity– Distribution Capacity

2. Nonbypassable charges (“NBCs”)

3. Headroom

This decomposition of costs is useful for constructing TOU rates

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Step 1: Start with Marginal Energy Costs8,760 hourly marginal energy costs are grouped into 5 TOU periods

Peak Shoulder Off Peak Shoulder Off Peak0

1

2

3

4

5

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Marginal Energy Costs by TOU Period

Costs by TOU Period

Summer Winter

Cents per kWh

Summer peak/off-peak ratio is typically about 1.5 to 1

Building a TOU Rate

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Step 2: Add Marginal Generation Capacity Costs

Building a TOU Rate

Most Generation Capacity Cost is Assigned to the Summer Peak Period

Peak Shoulder Off Peak Shoulder Off Peak0

2

4

6

8

10

12

14

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Marginal Generation Costs by TOU Period

Marginal Energy Costs Marginal Capacity Costs

Summer Winter

Cents per kWh

With capacity costs, summer peak/off-peak Gen. MC ratio is typically about 3 to 1 or greater

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Building a TOU Rate

Step 3: Add Marginal Distribution Capacity Costs

Peak Shoulder Off Peak Shoulder Off Peak0

2

4

6

8

10

12

14

16

18

20Marginal Cost by TOU Period

Marginal Energy Costs Marginal Capacity Costs Marginal Distribution Costs

Summer Winter

Cents per kWh

PG&E often Time-differentiates its Distribution MC; SCE and SDG&E typically do not.

Distribution MC is not time-differentiated in this illustration.

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Building a TOU Rate

Step 4: Add Nonbypassable Costs

Peak Shoulder Off Peak Shoulder Off Peak0

5

10

15

20

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Step 4: Add Nonbypassable Costs

Marginal Energy Costs Marginal Capacity Costs Distribution Nonbypassable Costs

Summer Winter

Cents per kWh

NBCs cannot be discounted and must be allocated uniformly to all time periods (see, D.07-09-016, COLs 1& 2, p.35).

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Step 5: Add Remaining Nonmarginal Costs

Building a TOU Rate: Final Result

Peak Shoulder Off Peak Shoulder Off Peak0

5

10

15

20

25

30

35

40

45

Step 5: Final TOU Rate

Marginal Energy Costs Marginal Capacity Costs Distribution Nonbypassable Costs Remaining Costs

Summer Winter

Cents per kWhFinal rate summer peak/off-peak ratio is typically about 2 to 1 or greater

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CPP vs. TOU• In a TOU rate, Gen. Capacity Costs are spread over 600-800 hours, typically resulting an a

rate component of about 10-15 cents per kWh.

• In a (pure) CPP rate, those costs are compressed into 60-80 hours, typically resulting in a rate component of about $1.00 to $1.50 per kWh.

• To preserve economic efficiency, revenue should not be shifted between TOU periods.   Therefore any revenue collected by CPP rates during events should logically be offset from peak period TOU rates only.

Peak Shoulder Off Peak Shoulder Off Peak0

2

4

6

8

10

12

14

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Marginal Generation Costs by TOU Period

Marginal Energy Costs Marginal Capacity Costs

Summer Winter

Cents per kWh

Goals of TOU Rate Design (1)

Relevant guidance from ACR:• Rates should be based on marginal cost;

• Rates should be based on cost-causation principles;

• Rates should encourage economically efficient decision making;

• Rates should encourage reduction of both coincident and non-coincident peak demand;

This suggests that headroom costs be allocated in proportion to the marginal costs;

• Rates should be relatively high in peak and semi-peak periods

• Rates should be relatively low in off-peak periods:

How low? Off-peak rates must collect at least (1) off-peak energy costs + (2) off-peak marginal distribution costs + (3) Nonbypassable costs.

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Goals of TOU Rate Design (2)

More Relevant guidance from ACR:• Rates should be affordable (avoid rate shock);

• Rates should be understandable (avoid unneeded complexity);

• Rates should provide customer choice;

• Rates should be accompanied by appropriate customer education and outreach;

This suggests that TOU price differentials be increased gradually (to avoid rate shock), and

TOU rates should have no more than two tiers (or a single tier with a baseline credit) (to avoid unneeded complexity)

Arizona utilities have successfully offered two or more distinct TOU options. This strategy could promote customer choice.

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Concluding Facts

• The CA Energy Action Plan II (EAP II) identifies Demand Response

(DR), along with energy efficiency, as the State’s “preferred means of

meeting growing energy needs”.

• TOU is (Non-Event-Based) DR (according to both the CPUC & CEC)*

• Arizona Public Service has 53% residential enrollment in opt-in TOU

• Salt River Project has 30% enrollment in opt-in TOU

• Both AZ utilities have been actively promoting TOU for 25 years

• The large CA IOUs have less than 5% residential enrollment in any TVR.

*See, 2013 CEC IEPR p.73; D.08-04-050, Attachment A, p.80

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APPENDIX• x

Single-Tier CA Residential TOU Rates (Summer)

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*Proposed in A.13-12-015, with a $16 per month customer charge

**Limited enrollment experimental rate, EV loads only

Utility Rate Applicability Peak Semi-pk Off-peak Price ratio

PG&E EV EV owners 39.6 21.1 9.8 4.0

SCE TOU-EV-1 EV owners 34.2 10.4 3.3

SCE TOU-D (option B)*

EV owners/all

33.9 18.2 10.9 3.1

SDG&E DR-SES NEM only 44.7 21.3 19.1 2.3

SDG&E EV-TOU-2 EV owners 44.1 20.6 16.1 2.7

SDG&E EPEV-X** EV owners 35.3 21.5 17.6 2.0

SDG&E EPEV-Y** EV owners 53.6 33.7 14 3.8

SDG&E EPEV-Z** EV owners 73.7 29.5 12.9 5.7

Single-Tier CA Residential TOU Rates (Winter)

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*Proposed in A.13-12-015, with a $16 per month customer charge

**Limited enrollment experimental rate, EV loads only

Utility Rate Applicability Peak Semi-pk Off-peak Price ratio

PG&E EV EV owners 26.8 16.9 10 2.7

SCE TOU-EV-1 EV owners 23.6 10.7 2.2

SCE TOU-D (option B)*

EV owners/all

21.7 14.9 10.9 2.0

SDG&E DR-SES NEM only 19.9 18.6 1.1

SDG&E EV-TOU-2 EV owners 19.8 19.5 17.2 1.2

SDG&E EPEV-X** EV owners 21.9 21 17.6 1.2

SDG&E EPEV-Y** EV owners 43.7 29.1 14.4 3.0

SDG&E EPEV-Z** EV owners 63.9 25.5 13.2 4.8

Arizona Residential TOU Rates (Summer)

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Utility Rate & applicability

Peak Semi-pk Off-peak Price ratio

Peak Period

SRP EZ-3 (July-Aug.)

35 8.4 4.2 3 hours; (3-6 or 4-7)

SRP EZ-3 (Other mos.)

29.7 8.2 3.6 3 hours; (3-6 or 4-7)

SRP TOU (July-Aug)

21.2 7.2 2.9 7 hours (1-8)

SRP TOU (other mos.)

19.1 7.1 2.7 7 hours (1-8)

APS ET-SP (June-Aug)

46.5 24.5 5.5 8.5 3 hr. super peak (3-6)

APS ET-SP (Other mos.)

24.5 5.5 4.5 7 hours (12-7)

APS ET-2 (all) 24.5 6.1 4.0 7 hours (12-7)

APS ET-EV (EV owners)

24.8 6.5 4.2 5.9 7 hours (12-7)

Residential TOU Program Summary

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TOU Scenario

Summer peak hours

Sum. Peak rate

Off-peak rate Price Ratio % load drop kW per participant % of eligible customers

PG&E E-6 opt-in 1-7 51.8 (tier 4) 32.6 (tier 4) 1.6 20% (a) 0.22 < 2%

SMUD Opt-in no technology 4-7 27 8 3.4 10% (b) 0.17 16-18%

SMUD Opt-in with technology 4-7 27 8 3.4 13% (c ) 0.24 16-18%

SMUD Opt-Out with technology 4-7 27 8 3.4 6% (d) 0.12 > 90%

Salt River Project E-26 (opt-in) 12-7 21.2 7.2 3.0 11% (e) 19%

Salt River Project EZ-3 (opt-in) 3-6 35 8.4 4.2 25%-27% (f) 11%

Arizona Public Service ET-2 (opt-in) 12-7 24.5 6.1 4.0 5% (g) 53.4% (incl. legacy TOU rates)

Arizona Public Service ET-SP (opt-in, experimental)

3-6 46.5 5.5 8.5 16% (h) 0.1%

Average of many pilots; Brattle Arc of price response @ 2.5 price ratio, no technology

2.5 6.1% (i)

Average of many pilots; Brattle Arc of price response @ 2.5 price ratio, with technology

2.5 13.5% (j)

Residential TOU Program Summary-References

a. See the 2013 Load Impact Evaluation of Pacific Gas and Electric Company's Residential Time-based Pricing Programs, Nexant, Inc., April 1, 2014.

b. From a presentation by Dr. Stephen George, National Town Meeting on Demand Response and Smart Grid, Washington, D.C. , May 21, 2014

c. Id.

d. Id.

e. Loren Kirkeide, “Effects of Three-Hour On-Peak Time-of-Use Plan on Residential Demand during Hot Phoenix Summers”, Electricity Journal, May, 2012

f. Id.

g. Information provided by Chuck Miessner, Pricing Manager APS, April 29 & 30, 2014 (emails to Elise Torres & Robert Levin)

h. Id.

i. Faruqui, Ahmad, and Sanem Sergici. “Arcturus: International Evidence on Dynamic Pricing.” Elsevier, Electricity Journal, 26, no. 7 (2013), as updated June 11, 2014 (per e-mail communication from Dr. Faruqui to Robert Levin).

j. Id.

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