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Electric Markets in the United States

Electric Markets in the United States

W. Scott Miller, IIIExecutive Director, Market Applications

PJM Interconnection, L.L.C.

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54,430 MW Peak212 Generating Units

54,430 MW Peak212 Generating Units

60,157 MW Peak555 Generating Units

60,157 MW Peak555 Generating Units

EDF (France)EDF (France) 80,190 MW Peak608 Generating Units

80,190 MW Peak608 Generating Units

PJMPJM 63,726 MW Peak 594 Generating Units

63,726 MW Peak 594 Generating Units

Tokyo ElectricTokyo Electric 64,300 MW Peak147 Generating Units

64,300 MW Peak147 Generating Units

PJM / PJM West ISO Worldwide Comparison

National Grid(England)

ERCOT

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CAISO45,900

ERCOT60,157

PJM 63,726

NYISO30,983

ISONE25,158

IMO25,269

PJM is currently the largest centrally dispatched Control Area in North

America

AESO7,800

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The Law and The Rules in the U.S.

The Law: Title VII of Energy Policy Act of 1992

“to promote greater competition in bulk power markets...”

The Rules: 1996: Order 888

“put in place the foundation necessary for competitive wholesale power markets in this country - open access...”

1999: Order No. 2000 “ensure that customers have the benefit of competitively priced

generation...”

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“…markets don’t always

operate efficiently because

buyers and sellers don’t

always have access

to the information

they need to make

optimal choices.” Akerlof, Spence, & StiglitzNobel prize winners for economics

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PJM eData Services Main Screen

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Creation of Value From Information Technologies

BU

SIN

ESS

IM

PA

CT

Magnitude of Consumer Base ReachedHigh

High

1991 2002

1991 2002

MediaDigitalization

Network Architecture

1991 2002

Bandwidth

Advancing TechnologiesAdvancing Technologies

1991 2002

ACCESSIBILITY

PRESENTATION INFRASTRUCTURE

ENABLERS

WebSmartProducts

Low

1991 2002

Portals1991 2002

HardwareCPU

Speed

1991 20021991 2002 1991 2002

SecurityMultimedia

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Information Exchange

Information Exchange

20,000+ Data Points Every 2-10 Seconds:• Operational

• Generation availability• Transfer capability• Telemetry• Generation control signals• Security recommendations• Pricing

• Planning• Expected load forecasts• Constrained conditions• Congested areas

•

• •

• •

Local Control Centers

Market Participants

Generators

Load Serving Entities

Public

Market Centers

Regulators

Other

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$0 $500 $1,000 $1,500 $2,000 $2,500

Other

Energy

Construction

Transport / Communications

Government

Manufacturing

Wholesale and Retail Trade

Financial Services

Services

Energy Costs in the Gross Domestic Product

Energy Industry = $221 Billion Annually; 2% of Gross Domestic Product

Source: Bureau of Economic Analysis, Dept. of Commerce

2001 Gross Domestic Product by Industry(Dollars in Billions)

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4/97 - Opened bid-based market based on Market Clearing Price

4/98 - Implemented LMP and FTRs (with overlying zones and trading hubs)

10/98 – Implemented capacity markets 1/99 - Implemented full customer choice in PA – Implemented daily capacity market 4/99 - Market-based pricing authority granted 4/99 - PJM FTR Monthly Auction market

PJM Market Evolution

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6/00 - PJM Day-Ahead Market and

Regulation Market 4/02 – PJM West implemented 12/02- PJM Spinning Reserve Market

PJM Market Evolution

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Maturing Energy Market Prices in PJM

$31.97$32.75

$28.46$30.36

$32.38

$28.30

$25

$27

$29

$31

$33

$35

2000 2001 2002

Day-Ahead Real-Time

Average Day-Ahead and Real-Time LMPs

($ per megawatt hour)

Average Day-Ahead and Real-Time LMPs

($ per megawatt hour)

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PJM Capacity Markets

The PJM-East Region's Daily and Monthly Capacity Credit Market Performance 2002

0

25,000

50,000

75,000

100,000

125,000

150,000

Jan-

02

Feb

-02

Mar

-02

Apr

-02

May

-02

Jun-

02

Jul-

02

Aug

-02

Sep

-02

Oct

-02

Nov

-02

Dec

-02

Vol

ume

of C

redi

ts T

rans

acte

d (U

nfor

ced

MW

)

$0

$50

$100

$150

$200

$250

Weig

hte

d-A

vera

ge C

apaci

ty C

lea

ring

Pri

ce (

$/M

W-d

ay)

Daily CCM (MW) Monthly CCM (MW) Wtg Avg Price Monthly ($/MW) Wtd Avg Price Daily ($/MW)

The fundamentals of supply and demand are reflected by the prices in the daily and monthly capacity markets.

The fundamentals of supply and demand are reflected by the prices in the daily and monthly capacity markets.

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PJM Regulation Market

Regulation Costs 1999-2003

$-

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

19993Q

19994Q

20001Q

20002Q

20003Q

20004Q

20011Q

20012Q

20013Q

20014Q

20021Q

20022Q

20023Q

20024Q

20031Q

20032Q

Market ImplementedJune 1, 2000

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Spinning Reserve Market Opened December 1, 2002

Spinning Reserve Costs

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

Jan-02

Feb-02

Mar-02

Apr-02 May-02

Jun-02

Jul-02 Aug-02

Sep-02

Oct-02 Nov-02

Dec-02

Jan-03

Feb-03

Mar-03

SpinningReserveMarketPayments

SynchronousCondenserPayments

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Liquidity at U.S. Hubs

0

5,000

10,000

15,000

20,000

25,000

PJM-W

Hub**

Mid

Colu

mbia

*

Palo V

erde*

Ciner

gy*

COB*

Four Corn

ers*

Mea

d/Mar

ketp

lace

*

GW

H

3Q 2002 4Q 2002 1Q 2003 2Q 2003

* Dow Jones Electricity Index** PJM Settlements Data

July 2003

PJM is the most liquid Trading Hub

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Wholesale Power Purchases

0%

10%

20%

30%

40%

50%

60%

70%

80%

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Vertically Integrated Investor-Owned UtilitiesGeneration and Distribution CooperativesLarge Federal and Municipal Puclic Power Authorities

Source: Platts POWERDAT Database

Wholesale Power Purchases as a Percentage of Purchases and Self-Generation (1989 – 2001)

Wholesale Power Purchases as a Percentage of Purchases and Self-Generation (1989 – 2001)

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PJM Prices are Stable

Wholesale Energy Prices Reduced Wholesale prices dropped to $35.33/MWH in 2002 from

$43.63/MWH in 2001 – 25% hotter in 2002. Nine all-time peaks in summer of 2002 – peak load served

at an average of $150/MWH as compared to $900/MWH on peak days in 2001 (savings of about $10 million to wholesale energy customers).

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Markets Improve Generator Performance

The PJM-East Region's Equivalent Demand Forced Outage Rate (EFORd)

0

2

4

6

8

10

12

1994 1995 1996 1997 1998 1999 2000 2001 2002

Per

cen

t

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Demand Response Growth

Demand Response Empowered PJM’s demand response programs enabling customers to

manage their own electricity costs grew 300 percent in 2002.

The most active 2002 demand side management hour lowered prices by more than 12%.

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Common Market Cost/Benefit Analysis

“Creation of common MISO-PJM-SPP market results in …

Lower energy price for region as a whole – Effects estimated at up to $7 billion over ten years”

“As effective power markets mature, the spread between forward price and the ultimate spot price should diminish.”

Every $1 forward premium reduction from MISO-PJM-SPP common market is ultimate consumer savings of $1.7 billion per year.

ESAI July 11, 2002 Report to Standard Market Design Forum

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0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

In-Service 2003 2004 2005 2006 2007

Queued Capacity by In-Service DateM

egaw

atts

of

Gen

erat

ion

Cap

acit

y

Scheduled In-Service Date

Over 35,000 megawatts scheduled will facilitate robust, competitive markets and may further reduce congestion.

In Service

Scheduled in Service

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Value of Large, Competitive Wholesale Markets

Average PJM Region Aggregate Supply Curve (June - September)

0

100

200

300

400

500

600

700

800

900

1,000

PJM Demand (MW)

PJM

($/

MW

Hr)

2001 Peak

2002 Peak

Avg Jun-Sep 2001

Avg Jun-Sep 2002

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Renewed Futures Market

Futures market necessary for hedging and assist in price discover

Lack of highly liquid futures market in the US Failed COB/Palo Verde contract in Western US

New York Mercantile Exchange (NYMEX) recently launched renewed “PJM West” futures market

Open interest increasing and price dropping

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“The future requires

a higher sophistication

in acknowledging

and dealing with

differences…”Peter F. Drucker

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