environmental energy technologies division energy analysis department the costs and benefits of...

Environmental Energy Technologies Division • Energy Analysis Department

The Costs and Benefits of State RPS Policies: Cost-Impact Studies, Actual

Costs, and Cost Containment

Ryan H. Wiser

Lawrence Berkeley National [email protected] (510.486.5474)

Oregon Renewable Energy Working Group May 31, 2006

Environmental Energy Technologies Division • Energy Analysis Department2

Presentation Overview

1. Review of State/Utility RPS Cost-Impact StudiesA. Project Motivation and Scope

B. Projected Renewable Resource and Direct Cost Results

C. Projected Benefits

D. Cost Study Methodologies and Assumptions

E. Conclusions and Areas for Improvement

2. Actual Costs of State RPS Policies to Date

3. Approaches to Limit RPS Costs

4. Impact of RPS Design on Expected Cost


RPS Cost-Impact Projections: Project Overview

• Project scope– Survey of 26 RPS cost impact projections conducted since 1998– Sample includes state or utility-level analyses in the U.S.

• Comparison of key results– Direct or inferred retail rate impacts– Renewable deployment by technology– Scenario analysis; secondary cost impacts; and benefits– All results presented are taken from the first year that each RPS hits its

ultimate target level (e.g. 2013 for New York, 2010 for California)

• Comparison of study methodologies– General modeling approaches; cost characterizations; and key assumptions

Objective: State RPS policies have become a major driver of renewable energy, but the adoption of new RPS policies hinges on expected costs and benefits. We review previous RPS cost studies to compare projected impacts and provide methodological guidance for future RPS cost analysis.


RPS Cost-Impact Study Sample: Who, When, and Where?

Synapse 2003

Synapse 2003

Rutgers 2004

Tellus 2002

SEA 2002

GDS 2001

EC 2004 (LADWP)

Lazarus 2003 Tellus 2004

PPC 2004

UCS 2004

PEG 1998

AZ PIRG 2005

UCS 2005

UCS 2003

WUC 2000

WUC 2001

B&V 2004 UCS 2001 UCS

2001

CCAP/ ICF 2003 ICF 2003 DPS 2004 Potomac 2005

Tellus 2004

Tellus 2004

CRS 2005

CEC 2006


Author and Funding Entity Type

Consultant(14)

Academic(1)

State agency(1)

Non-governmental organization

(10)State

commission/ agency (7)

Trade organization

(1)

Utility group(1)

National agency/department (2)

ISO(1)

Foundation/NGO (14)

Author Type Funding Entity Type


-

10,000

20,000

30,000

40,000V

T (

Syn

apse

)

RI

(Tel

lus)

MA

(S

EA

)

NY

(C

CA

P)

NY

(D

PS

)

PA

(B

&V

)

VA

(C

EC

)

NE

(U

CS

)

IA (

WU

C)

MN

(W

UC

)

WI

(UC

S)

TX

(U

CS

)

HI

(GD

S)

AZ

(P

EG

)

CO

(U

CS

)

CO

(P

PC

)

OR

(T

ellu

s)

WA

(T

ellu

s)

WA

(La

zaru

s)

AZ

(P

IRG

)

CA

(T

ellu

s)

CA

(U

CS

)

CA

(C

RS

)

Gen

erat

ion

in 1

st P

eak

Tar

get Y

r. (

GW

h) OtherGeothermalSolarHydroLandfill GasBiomass Co-FireBiomassWind

MidwestEast West

Wind Expected to Fare Well, but Not to Dominate in All Regions

Wind represents 61% of incremental generation: - 90% in Midwest - 62% in East - 51% in West


20 of 28* Analyses Predict Rate Increases of Less Than or Equal to 1%

* Number of analyses is more than 26 because results for each state in CA/OR/WA (Tellus) are shown separately

-6%

-3%

0%

3%

6%

9%

12%

TX

(U

CS

) -

3%

CA

(T

ellu

s) -

11%

HI (

GD

S)

- 4%

CA

(U

CS

) -

13%

OR

(T

ellu

s) -

11%

PA

(B

&V

) -

7%

CO

(P

PC

) -

9%

CA

(C

RS

) -

17%

WA

(La

zaru

s) -

15%

NY

(D

PS

) -

8%

CO

(U

CS

) -

6%

NE

(U

CS

) -

10%

IA (

WU

C)

- 9%

WI (

UC

S)

- 9%

NY

(P

otom

ac)

- 7%

MD

(S

ynap

se)

- 8%

VT

(S

ynap

se)

- 10

%

VA

(C

EC

) -

17%

AZ

(P

EG

) -

1%

MN

(W

UC

) -

9%

CA

(LA

DW

P)

- 20

%

MA

(S

EA

) -

7%

WA

(T

ellu

s) -

17%

NY

(C

CA

P)

- 5%

NJ

(Rut

gers

) -

14%

RI (

Tel

lus)

- 1

8%

AZ

(P

IRG

) -

20%

NY

(IC

F)

- 8%

Study - Incremental RPS Target %

-0.50

-0.25

0.00

0.25

0.50

0.75

1.00

Average retail (% - left axis)

Average retail (¢/kWh - right axis)

Median retail rate increase = +0.7%Median change in retail rates = +0.04¢5 analyses predict rate savings

Cha

nge

in

Rat

es in

1st

Pea

k T

arge

t Y

r.

Cha

nge

in R

ates

in 1

st P

eak

Tar

get

Yr.

(20

03 ¢

/kW

h)


0 2 4 6 8 10 12 14 16

<-1%

-1%-0

0-1%

1%-2%

2%-3%

3%-4%

4%-5%

>5%

Ch

an

ge

in R

ate

s in

1st

Pe

ak

Ta

rge

t Y

r.

Number of Studies

The Estimated Cost of RPS Policies is Typically Modest, But Varies Considerably by Study

* Number of analyses is more than 26 because results for each state in CA/OR/WA (Tellus) are shown separately


Scenario Analysis Is Often Used to Bound the Possible Impacts

1

1

1

2

2

4

5

5

5

7

8

9

9

0 1 2 3 4 5 6 7 8 9 10

Exposure to Price Risk

Carbon Credit Value

Expected Load Growth

Maximun Compliance Penalty Cost

Demand for RE from Other Sources

Renewable Resource Eligibility

Financing/Contract Assumptions

Wholesale Market Price Uncertainty

Availability of Renewable Imports

Alternate RPS Target Levels

Renewable Technology Cost

Production Tax Credit Availability

Fossil Fuel Price Uncertainty

Number of Studies Considering Each Scenario


Projected Residential Electricity Bill Impacts are Lowest in Midwest and West

$(5.0)

$(2.5)

$-

$2.5

$5.0

$7.5

$10.0P

A (

B&

V)

- 7

%

NY

(D

PS

) -

8%

NY

(P

oto

ma

c) -

7%

VT

(S

yna

pse

) -

10

%

VA

(C

EC

) -

17

%

MD

(S

yna

pse

) -

8%

MA

(S

EA

) -

7%

NY

(C

CA

P)

- 5

%

RI (

Te

llus)

- 1

8%

NJ

(Ru

tge

rs)

- 1

4%

NY

(IC

F)

- 8

%

TX

(U

CS

) -

3%

NE

(U

CS

) -

10

%

WI (

UC

S)

- 9

%

IA (

WU

C)

- 9

%

MN

(W

UC

) -

9%

HI (

GD

S)

- 4

%

CA

(T

ellu

s) -

11

%

CA

(U

CS

) -

13

%

OR

(T

ellu

s) -

11

%

CO

(P

PC

) -

9%

CA

(C

RS

) -

17

%

CO

(U

CS

) -

6%

WA

(L

aza

rus)

- 1

5%

CA

(L

AD

WP

) -

20

%

AZ

(P

EG

) -

1%

WA

(T

ellu

s) -

17

%

AZ

(P

IRG

) -

20

%

Study - Incremental RPS Target %

Avg

. Bill

Impa

ct in

1st

Pea

k T

arge

t Yr.

(2

003$

/mo)

$16.8

East WestMidwest

Base caseAlternate scenarios


Many Studies Evaluate Potential Public Benefits

2

7

14

5

7

6

6

7

0 2 4 6 8 10 12 14 16

Water Use Reduction

Criteria Pollutant Emissions Reduction

CO2 Emissions Reduction

Natural Gas Price Reduction

Wholesale Electric Price Reduction

Income

Gross State Product

Employment

En

viro

nm

en

tal

Ris

k M

itig

atio

nM

acr

oe

con

om

ic

Number of Studies Considering Each Scenario


Studies Predict Varying Levels of Net Employment Gains

0

30

60

90

120

AZ (PIRG) PA (B&V) NE (UCS) CO (UCS) NJ (Rutgers) TX (UCS) AZ (PEG)

Net

Job

s C

reat

ed P

er In

crem

enta

l MW

hO

of R

enew

able

Gen

.

0

4,000

8,000

12,000

16,000

Net

Job

s C

reat

ed O

ver

Ana

lysi

s T

imef

ram

eO

Net Jobs Created Per Renewable MWh - left axis

Cumulative Net Jobs Created - right axis


RPS May Put Downward Pressure on Market Prices, But Impacts Are Not Well Understood

Note: CO (UCS), RI (Tellus), and TX (UCS) also model wholesale price reductions but do not provide detailed data

$(0.42)

$(1.59)

$(0.60)

$(0.95)

$0.24

$1.40

$0.02

$(0.18) $(0.19)

$(0.58)

$(1.06)

$(0.11)

$(2.00)

$(1.00)

$-

$1.00

$2.00

NY (CCAP) NY (Potomac) NY (DPS) NY (ICF)

Ch

an

ge

in 1

st P

ea

k T

arg

et

Yr.

(2

00

3$

/MW

h)

Energy

Capacity

Firm power


RPS May Put Downward Pressure on Natural Gas Prices

Note: NY (CCAP) and NY (ICF) also model NG price reductions but do not provide detailed data

$(0.06)

$(0.05)

$(0.04)

$(0.03)

$(0.02)

$(0.01)

$-

RI (Tellus) TX (UCS) CO (UCS)

Ave

rag

e S

avi

ng

s R

ela

tive

to R

efe

ren

ce C

ase

(2

00

3$

/MM

Btu

)


Renewable Energy As a Hedge Against Natural Gas Price Risk: Sensitivity Analysis Results

($1.50)

($1.00)

($0.50)

$0.00

$0.50

$1.00

($2.00) ($1.00) $0.00 $1.00 $2.00 $3.00

Change in Natural Gas Price in 1st Yr. of Peak RPS Target (2003$/MMBtu)

Change in

Resid

entia

l Bill

Im

pact in

1st Y

r. o

f P

eak

RP

S T

arg

et (2

003$/m

o.)

As natural gas price expectations rise, the predicted cost (benefit) of the RPS declines (increases)


RPS Policies Are Estimated to Displace CO2 Emissions Primarily from Natural Gas Plants

0.00

0.25

0.50

0.75

1.00

WA (T

ellus

)

NY (DPS)

NY (CCAP)

CO (P

PC)

TX (UCS)

NY (ICF)

AZ (PIR

G)

RI (Tell

us)

OR (Tellu

s)

MA (S

EA)

VA (CEC)

CA (UCS)

CA (Tell

us)

CO (U

CS)

WI (

UCS)

Dis

plac

ed E

mis

sion

s R

ate

in 1

st P

eak

Tar

get

Yr.

(M

TC

O2/

MW

h)

0

5

10

15

20

25

30

CO

2 R

educ

tions

in 1

st P

eak

Tar

get Y

r.

(Mill

ion

met

ric to

ns)

Displaced Emissions RateCO2 Reductions

Conventional Coal Plant Emissions Rate

NGCC Plant Emissions Rate

US Electric Sector Average Emissions Rate


Implied CO2 Abatement Costs Vary Widely

($50)

($25)

$0

$25

$50

$75

$100

TX (UCS)

CO (U

CS)

CA (Tell

us)

CO (P

PC)

CA (UCS)

OR (Tellu

s)

VA (CEC)

WI (

UCS)

NY (DPS)

WA (T

ellus

)

MA (S

EA)

RI (Tell

us)

AZ (PIR

G)

NY (CCAP)

NY (ICF)

CO

2 R

educ

tion

Cos

t in

1st P

eak

Tar

get Y

r.

(200

3$/M

TC

O2)

$295

$(426)

Median Abatement Cost = $5/MTCO2 Standard Deviation = $143/MTCO2

60% of these studies imply abatement costs of less than $10/metric ton


Category A(17 studies) Category D

(6 studies)

AZ (PIRG), AZ (PEG), CA (CRS), CA (UCS),

CA LADWP, CO (PPC), HI (GDS), IA (WUC), MD (Synapse), MN

(WUC), NE (UCS), PA (B&V), VA (CEC), VT

(Synapse), WA (Lazarus), WI (UCS)

CA/OR/WA, CO (UCS), NY

(CCAP), NY (ICF), RI (Tellus),

TX (UCS)

Category C (2 studies)

Category B(2 studies)

MA (SEA), NJ (Rutgers)

NY (DPS), NY (Potomac)

Four General Modeling Approaches Have Been Used

Four broad categories: Category A: Linear spreadsheet

model of both RE + avoided utility cost

Category B: Linear spreadsheet model of RE + generation dispatch model of avoided utility cost with base-case resource mix

Category C: Linear spreadsheet model of RE + generation dispatch model of avoided utility cost with implied RPS mix

Category D: Integrated energy model


Assumptions Matter More than the Selection of the Model

UNDER-ESTIMATION OF COSTS

– Wind capital cost assumptions appear low in many cases

– Transmission/integration costs not always considered fully

– Lack of consideration of RE demand from other sources

– Increased likelihood that RE displaces coal, not gas, not considered fully

– Expectations in some cases of long-term PTC availability

OVER-ESTIMATION OF COSTS

– Reliance on natural gas price forecasts that appear too low

– Secondary electric and gas price impacts ignored in many cases

– Potential for future carbon regulations not considered

– Expectations in many cases that PTC will be extended for a very limited period, or not at all


Wind Capital Cost Assumptions Range from $750/kW to $3,000/kW in 2010-2015

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

2003 2005 2007 2009 2011 2013 2015 2017 2019

Cap

ital C

ost (

$200

3/kW

)

CA (CRS)

CA/OR/WA

CA LADWP

IA (WUC)

MD (Synapse)

MN (WUC)

NE (UCS)

NY (Potomac)

NY (DPS)

NY (ICF)

PA (B&V)

RI (Tellus)

VT (Synapse)

WA (Lazarus)

WI (UCS)

US EIA

$3,115

Current costsrange from

$1300-$1800/kW


Most Studies’ Natural Gas Price Projections are Probably Too Low

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

Del

iver

ed N

atu

ral G

as

Pric

es fo

r E

lect

ric

Gen

erat

ors

($2

003/

MM

Btu

)

AZ (PIRG) CA (CRS) CA (UCS) CA/OR/WA CA (LADWP)CO (PPC) CO (UCS) IA (WUC) MD (Synapse) MN (WUC)

NE (UCS) NY (DPS) PA (B&V) RI (Tellus) TX (UCS)

VT (Synapse) WA (Lazarus) WI (UCS) US EIA VA (CEC)

NYMEX Futures as of 4/16/06


Inconsistent PTC Assumptions Reflect Substantial Political Uncertainty

2010

20062006200620062006200620062006

20052005

2003

2009

2003 2006 2009 2012

IA (WUC)NY (CCAP)

NY (Potomac)NY (DPS)NY (ICF)

MD (Synapse)MN (WUC)PA (B&V)WI (UCS)

WA (Tellus)VT (Synapse)

NE (UCS)MA (SEA)CO (PPC)CA (UCS)

NJ (Rutgers)TX (UCS)CO (UCS)

CA/OR/WA (Tellus)

Final year of PTC extension (Base-Case Analysis)*

* These Studies Assume No PTC Availability: AZ (PEG), AZ (PIRG), CA (LADWP), CA (CRS), HI (GDS), RI (Tellus), VA


Many Studies Appropriately Consider the Secondary Costs of Renewable Generation

Cost VariableNumber

of studiesStudies

Capacity value 18AZ (PEG), CA (CRS), CA/OR/WA (Tellus), CO (PPC), CO (UCS), IA (WUC), MD (Synapse), MA (SEA), MN (WUC), NE (UCS), NY (CCAP), NY (DPS), NY (ICF), NY (Potomac), PA (B&V), RI (Tellus), TX (UCS), WI (UCS)

Transmission cost 13CA (CRS), CA (UCS), CA/OR/WA (Tellus), CA LADWP, CO (PPC), CO (UCS), IA (WUC), MA (SEA), MN (WUC), NE (UCS), TX (UCS), VT (Synapse), WI (UCS)

Integration cost 10CA (CRS), CA/OR/WA (Tellus), CO (PPC), CO (UCS), IA (WUC), MN (WUC), NJ (Rutgers), TX (UCS), WA (Lazarus), WI (UCS)

Admin. & transaction cost 4 CA (UCS), MA (SEA), WA (Lazarus), WI (UCS)

But as renewable penetrations reach higher levels, some of these costs need to be more carefully considered


Conclusions from the Cost Studies

• Projecting RPS costs is inherently uncertain, but… despite uncertainties, majority of studies project modest cost impacts

• Recent trend toward studies that forecast not just direct costs and environmental benefits, but also macroeconomic and hedge benefits

• Studies use variety of methods/data sources to calculate costs and benefits: a standard study “template” has not yet emerged

• Assumptions for primary and secondary costs and benefits likely to be more important than what model is used

• Sophistication of models used, and range of secondary impacts and public benefits considered, affect the cost of undertaking a study: $100k will buy a very thorough study


Some Possible Areas of Improvement…

• Improved Treatment of Transmission/Integration Costs: need better estimates of these costs w/high RE penetrations

• Competing RPS Requirements: consider how potential RPS policies in nearby states would affect RE resource supply and cost

• Natural Gas Price Forecasts: benchmark to NYMEX in early years

• Coal as the Marginal Price Setter: at high natural gas prices, need to consider possibility that RE will increasingly offset coal

• Greater Use of Scenario/Risk Analysis: natural gas and wholesale price uncertainty, PTC availability, wind capital costs

• Consideration of Future Carbon Regulation: consider impacts in the event that future carbon regulations are established

• More Robust Treatment of Public benefits: greater efforts to quantify the magnitude of hedge and macroeconomic benefits


Actual Costs of RPS Policies

RECs Markets: In markets where RECs or surcharge sets above-market cost, 2006 rate impacts estimated to be at most: ME (0.1%), MD (0.1%), NY (0.1%), CA (0.3%), CT (0.2%), AZ (0.4%), NJ (0.1%), MA (1.1%)

Contract Markets: In many markets where bundled contracts predominate, RPS may provide savings or at worst modest rate increases: TX, CA, NM, MN, CO, MT (unclear in WI, NV)

Actual costs and benefits not widely collected and reported, because: (1) policies have been operating for a short duration; (2) lack of publicly available data on

long-term contract prices; (3) challenges in estimating secondary costs/benefits

Compliance REC Prices

0

10

20

30

40

50

60

$/M

Wh

MA New

CT Class I

Texas

NJ Class IMD Class I


RPS Cost Cap Mechanisms in Use in Other RPS States (1)

• Retail Rate/Revenue Cost Cap– Colorado (1% of total annual electric bills, by customer class)– New Mexico (1% in 2006, increasing 0.2%/yr, until 2% in 2011)– Washington (proposed; 4% of retail revenue on incremental cost)

• Bundled Contract Price Caps– New Mexico ($49/MWh wind and hydro; $62.54/MWh biomass and

geothermal; $150/MWh for solar <10 kW, $100/MWh >10 kW)– Hawaii (avoided cost)– Montana (115% of avoided cost for non-restructured suppliers;

100% for restructured suppliers)

• Alternative Compliance Payments (freely available)– Massachusetts ($55.13/MWh, adjusted for inflation)– New Jersey ($50/MWh for Tier 1 and Tier 2; $300/MWh for solar)– Rhode Island ($50/MWh, adjusted for inflation)



• Alternative Compliance Payments (available/recoverable in rates if least cost measure and/or insufficient available RE)– Delaware ($25/MWh; subsequent payments increase by $10/MWh

to a maximum of $50/MWh)

– District of Columbia ($25/MWh Tier 1; $10/MWh for Tier 2; $300/MWh for solar)

– Maryland ($20/MWh for Tier 1; $15/MWh for Tier 2; $8/MWh for Tier 1 industrial process load customers, steadily dropping to $2/MWh by 2017 and thereafter, $0/MWh for Tier 2)

• Financial Penalty (for competitive suppliers, will act as cost cap; not so for regulated utilities because RE contract costs are recoverable, regardless of the cost level)– Connecticut ($55/MWh)

– Texas ($50/MWh or 200% of average REC price)

– Pennsylvania ($45/MWh; 200% of average REC price for solar)



• Customer Class Bill Impact– New Mexico ($49,000 for large customers with consumption

over 10,000 MWh, rising $10,000/year to $99,000 in 2011– Maryland, Delaware, Maine exempt certain customer loads

altogether

• Renewable Energy Fund Limitation– Arizona– California– New York

• Force Majeure– Pennsylvania, Minnesota, Nevada, Maine, many others


Maximum Cost Impacts, Based on Cost Caps

Notes: Actual costs likely to be significantly below maximum costs, in many cases. Assumes that RPS costs will be capped at ACP (or penalty amount in restructured markets). Only includes SBC limits in a some states (e.g., CA), not separately adding any additional incremental transmission or integration costs that might exist.

0%

2%

4%

6%

8%

10%

12%

Hawaii

Mon

tana

Califo

rnia

New Y

ork

Colora

do

Mar

yland

Arizon

a (p

ropo

sal)

New M

exico

Mas

sach

uset

ts

Texas

Was

hingt

on, D

.C.

Penns

ylvan

ia

Delawar

e

Conne

cticu

t

Rhode

Islan

d

New Je

rsey

Iowa

Main

e

Minn

esot

a

Nevad

a

Wisc

onsin

Ma

x. %

Inc

rea

se

in A

vg

. Re

tail

Ra

tes

No Explicit Caps


Cost Cap Options: Lessons Learned

• General: Cost cap/penalty should exceed expected cost of compliance

• Retail Rate Cap: Possible in still-regulated markets; will inevitably impose calculation difficulties and debates

• Contract Price Caps: Used infrequently, and calculation difficulties may exist depending on application; reasonableness of RE costs depend on cost of alternatives, making the cap a moving target

• Alternative Compliance Payments: Useful and common in restructured markets because avoids contested regulatory proceedings; can be useful in regulated markets, but may need to ensure that ACP payments are least-cost compliance option, which imposes some regulatory complexity

• Non-Recoverable Penalty: Not a cost cap for still-regulated providers

• RE Fund Limitation: Creates undue complexity; not recommended

• Customer-Class Based Cap: Recommend considering exemptions, not cost caps, if such treatment is necessary

• Force Majeure: Can create considerable uncertainty in application; use with care, define with precision, and limit application


Use of Collected Funds from Penalty/ Alternative Compliance Payments

• Funds can be used to serve multiple purposes…

– support renewable energy– support the general fund

• Most – but not all – programs recycle any collected funds to support renewable energy

– typically by depositing funds into existing or new state renewable energy fund


Cost Recovery for Regulated Utilities

• Prudently incurred costs should be recovered, and this should be made clear in RPS legislation

– Not all compliance costs should necessarily be deemed prudent (e.g., purchasing high-priced RECs on the short-term market, when low cost renewables are available under long-term contracts; or using the ACP when less expensive compliance options exist)

• Contract pre-approval is often an element of state RPS policies in still-regulated markets, as are various planning and competitive solicitations requirements

• Some states provide a specific cost recovery mechanism beyond regular rate recovery, e.g.

– pre-authorized pass-through of certain costs

– system-benefits charge

• Some states are additionally investigating the development of a utility profit incentive for purchasing RE (e.g., Colorado, Hawaii)


Design Elements that Will Affect Compliance Costs

• Percentage targets and timeframes

• Resource eligibility

• Geographic eligibility and delivery requirements

• Set-asides for solar or other resource types

• Flexible compliance mechanisms (RECs, banking, borrowing, settlement periods)

• Encouragement for long-term contracting


Conclusions

• Expected cost of other state RPS policies is modest; benefits are not insignificant

• Oregon could do its own cost study

• Actual RPS costs in other states have, in general, been relatively low

• Cost caps and RPS design can be tailored to avoid adverse cost impacts

• But… it is true that an RPS may increase retail electricity rates

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