naruc committee on electricity: capacity markets

NARUC COMMITTEE ON NARUC COMMITTEE ON ELECTRICITY:ELECTRICITY:

CAPACITY CAPACITY MARKETSMARKETS


CAPACITY MARKETSCAPACITY MARKETS

Julie SimonJulie Simon

Capacity MarketsCapacity Marketsand Other Means of and Other Means of

AssuringAssuringAdequate Generating Adequate Generating

Capacity:Capacity:How do alternative proposals for How do alternative proposals for

ensuring adequate generation supply ensuring adequate generation supply stack up? stack up?

NARUC Winter Committee MeetingsNARUC Winter Committee MeetingsWashington, D.C.Washington, D.C.February 14, 2006February 14, 2006

Overview: Constellation EnergyOverview: Constellation Energy

FORTUNE 200 competitive energy company FORTUNE 200 competitive energy company headquartered in Baltimoreheadquartered in Baltimore

North America’s No. 1 supplier of energy to North America’s No. 1 supplier of energy to wholesale and to retail commercial and wholesale and to retail commercial and industrial customers in competitive marketsindustrial customers in competitive markets

A major generator of electricity with a A major generator of electricity with a diversified fleet of power plants located diversified fleet of power plants located throughout the U.S.throughout the U.S.

A regulated distributor of electricity and A regulated distributor of electricity and natural gas in Central Marylandnatural gas in Central MarylandVision: To be the first-choice provider for customers seeking energy solutions in the complex and changing marketplace

We Know EnergyWe Know Energy

We serve customers across the energy value chain

Benefits of CompetitionBenefits of Competition

GED/EPSA study: customers saw GED/EPSA study: customers saw $15.1 billion$15.1 billion in in value from wholesale electric competition in Eastern value from wholesale electric competition in Eastern Interconnection (1999-2003)Interconnection (1999-2003)CERA study: US residential customers paid CERA study: US residential customers paid $34 $34 billionbillion less for electricity over the last seven years less for electricity over the last seven years than they would have under a traditional regulatory than they would have under a traditional regulatory modelmodelISO/RTO Council: ISOs/RTOs improve grid reliability, ISO/RTO Council: ISOs/RTOs improve grid reliability, improve operating efficiencies, promote regional improve operating efficiencies, promote regional planning, and lower consumer energy costs by planning, and lower consumer energy costs by providing transparency, liquidity, facilitating risk providing transparency, liquidity, facilitating risk management and providing market monitoring management and providing market monitoring Competition better allocates risks, disciplines prices, Competition better allocates risks, disciplines prices, and enhances efficienciesand enhances efficiencies

““A nickel ain’t worth a dime A nickel ain’t worth a dime anymore.”anymore.”

Need to assure adequate generation, without Need to assure adequate generation, without creating stranded costscreating stranded costsNeed to value capacityNeed to value capacity

Forwardcontracts

Newinvestment

Pricesignals

““It is very difficult to make predictions, It is very difficult to make predictions, especially about the future.”especially about the future.”

Most regions of the country have adequate generation Most regions of the country have adequate generation for the near termfor the near term

2006 Forecasted Reserve Margins*2006 Forecasted Reserve Margins*WECCWECC 32 percent32 percentSPPSPP 31 percent31 percentMAINMAIN 28 percent28 percentNew EnglandNew England 28 percent28 percentECARECAR 27 percent 27 percent SERCSERC 27 percent27 percentNew YorkNew York 25 percent25 percentMROMRO 22 percent22 percentMAACMAAC 20 percent20 percent

* CERA North American Electric Power Watch, Winter 2005/06* CERA North American Electric Power Watch, Winter 2005/06

““Baseball is 90% mental. The other half is Baseball is 90% mental. The other half is physical.”physical.”

Well-designed competitive markets:Well-designed competitive markets:

Value reliabilityValue reliability– Capacity is part of the “energy commodity”Capacity is part of the “energy commodity”– Markets make the dollar value more transparentMarkets make the dollar value more transparent

Send accurate price signalsSend accurate price signals– Forward price signals incent forward contractingForward price signals incent forward contracting

Differentiate scarcity pricing from market powerDifferentiate scarcity pricing from market power

Impose mitigation narrowly to address market Impose mitigation narrowly to address market powerpower– Mitigation creates a “free” regulatory hedgeMitigation creates a “free” regulatory hedge

Have clear and consistent rulesHave clear and consistent rules

““When you come to a fork in the road, When you come to a fork in the road, take it.”take it.”

Energy-only is an end-state visionEnergy-only is an end-state vision

If we are serious about providing better If we are serious about providing better price signals, capacity market constructs price signals, capacity market constructs should continually transition to energy-onlyshould continually transition to energy-only– Modifying mitigation measures to better reflect Modifying mitigation measures to better reflect

scarcity pricing and incent demand responsescarcity pricing and incent demand response– Reduce capacity payment over time as Reduce capacity payment over time as

mitigation is modified and energy prices provide mitigation is modified and energy prices provide an adequate revenue stream for investmentan adequate revenue stream for investment

““You don’t want to make the wrong You don’t want to make the wrong mistake…”mistake…”

Price signals are interrupted by excess mitigationPrice signals are interrupted by excess mitigation– $1000 bid cap$1000 bid cap– Must run contractsMust run contracts– Conduct and impact testConduct and impact test– Local market power mitigationLocal market power mitigation– Imports and reserves that do not set priceImports and reserves that do not set price

Mitigated energy market price signals are Mitigated energy market price signals are insufficient to incent: insufficient to incent: – Development of new generation when and where neededDevelopment of new generation when and where needed– Economically efficient retirement decisionsEconomically efficient retirement decisions– Forward contracting by load and generationForward contracting by load and generation– Demand responseDemand response– Transmission expansionTransmission expansion

““In theory, there is no difference between In theory, there is no difference between theory and practice. In practice, there is.”theory and practice. In practice, there is.”

Well-designed capacity markets:Well-designed capacity markets:Replace the “missing money” caused by mitigationReplace the “missing money” caused by mitigationEncourage load and generators to sign forward contractsEncourage load and generators to sign forward contractsValue locationValue location– Adequate generation in the market-wide footprint does not Adequate generation in the market-wide footprint does not

necessarily mean adequate capacity in specific locationsnecessarily mean adequate capacity in specific locations

Balance transmission, generation and demand responseBalance transmission, generation and demand responseValue desired planning reserve levels (Demand Curve)Value desired planning reserve levels (Demand Curve)– Cannot require a 15% reserve margin and not pay for itCannot require a 15% reserve margin and not pay for it– Smooth boom and bust cycleSmooth boom and bust cycle

Include an adequate planning horizonInclude an adequate planning horizon– It takes years to build a power plantIt takes years to build a power plant– Timing drives fuel sourceTiming drives fuel source

““You can observe a lot just by You can observe a lot just by watching.”watching.”

All markets have demand curves:All markets have demand curves:– If the demand curve is sloped, not vertical:If the demand curve is sloped, not vertical:

Value reliability beyond the required reserve marginValue reliability beyond the required reserve margin

Help manage boom and bust cycleHelp manage boom and bust cycle

Accurate price signals are the best Accurate price signals are the best “guarantee” of needed investment“guarantee” of needed investment

Questions?Questions?

Julie SimonJulie SimonManaging DirectorManaging Director

National Energy Policy & Regulatory AffairsNational Energy Policy & Regulatory Affairs

Constellation EnergyConstellation Energy

750 E. Pratt Street, 14750 E. Pratt Street, 14thth Floor Floor

Baltimore, MD 21202Baltimore, MD 21202

410-783-5214410-783-5214

[email protected]@constellation.com



Hoff StaufferHoff Stauffer

Market Stability and The Cost of Capital

NARUC Winter MeetingsCommittee on Electricity

Presented by

Hoff StaufferFebruary 14, 2006Washington, DC

An Important Concept Has Apparently Been Missing

• This is the clear link between market stability (meaning low capacity price volatility) and the cost of capital.

• Market stability is clearly good for consumers because it reduces the cost of capital and the capacity price.

• Proper design of the capacity markets can achieve market stability.

Conceptual Framework

1. The structure of the markets determines cash flow volatility.

2. Cash flow volatility determines the financial structure used to finance capacity additions.

3. The financial structure determines the cost of capital.

4. The cost of capital determines capacity prices.

5. Capacity prices determine customer costs.

Structure of Markets Drive Cash Flow Volatility

Project Cashflows

$0$25$50$75

$100

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Years

$/kw-

year

Stable

Unstable

In-between

Cash Flow Volatility Drives Financing Structure

Debt Permitted by Coverage Ratios

$0$200$400$600$800

$1,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Years

Debt

($/kw

)

Stable

Unstable

In-between

Financing Structure Determines Cost of Capital

(illustrative example)

Stable UnstableCapital Structure

Debt 87% 18%Equity 13% 82%

Cost Debt 7.5% 7.5%

Equity 15.0% 20.0%Tax rate 40% 40%

WACC 5.9% 17.2%

WACC = % Debt * Cost of Debt * (1 – tax rate) + % Equity * Cost of Equity

Capacity Prices Are Lower in a More Stable Market

Market StructureStable Unstable

WACC 5.9% 17.2%Real Capital Charge Rate 6.1% 20.1%

Initial Capital Costs ($/kw) $400 $400Annual Capital Charges ($/kw-year) $24 $80FOM $10 $10Energy Margin ($2) ($2)Capacity Price ($/kw-year) $32 $88

Capacity Prices Determine Consumer Costs

CONSUMER COSTS$/kwh

Market StructureStable

UnstableEnergy Costs $45 $45Other Costs $15 $15Capacity Price* $ 9 $25Total Costs $69 $85

* at 40% load factor

Market Stability Favors More Efficient Generation Capacity

Stable UnstableCapital Structure CT Coal CT Coal

Debt 87% 88% 18% 55%Equity 13% 12% 82% 45%

CostsDebt 7.5% 7.5% 7.5% 7.5%

Equity 15.0% 15.0% 20.0% 20.0%Tax Rate 40.0% 40.0% 40.0% 40.0%

WACC 5.9% 5.8% 17.2% 11.5%

Real Capital Charge Rate 6.1% 6.0% 20.1% 12.2%Capital Costs ($/kw) $400 $1,500 $400 $1,500Annual Capital Charges $24 $90 $80 $183FOM $10 $30 $10 $30Energy Margin (2) (90) (2) (90)

Capacity Price ($/kw-year) $32 $30 $88 $123

Effect of Contract Term on Capital Charge Rate

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

120.0%

140.0%

0 5 10 15 20 25 30

CCR

Contract Term in years

Design Options for Market Stability

• Extend effective date of auction far enough in the future to permit new entry

• Extend the term of the contract (the longer the better)

• Give RTO authority to “manage” new capacity

• Demand curves (but hard to get right)

Contact Information

Hoff StaufferManaging Director

Wingaersheek Research Group

9 Dune Lane

Gloucester, MA 01930

Office 978-281-1674

Cell 617-407-2632

Email [email protected]

mailto:[email protected]



Ronald McNamaraRonald McNamara

30

Capacity “markets” - substitutes for a good price?

NARUC

February 14, 2006

Ron McNamara

31

Study of Prices in Constrained Areas Two markets were studied

• PJM

• ISO-NE

Prices from both Day-Ahead and Real-Time Markets were analyzed for both peak and off-peak hours of the day.

Prices were analyzed three different ways:

• Nominal

• Real Term

• Fuel Adjusted

32

PJM Market

Delmarva Peninsula is an area in PJM that often suffers import limits

• Delmarva Power (DPL) was used as a surrogate for analyzing the Delmarva Peninsula constrained market.

Prices in Delmarva were compared with PJM system wide prices.• In addition Delmarva prices were compared to

prices at the Western Hub.

• Western Hub was used since much of the transmission congestion that affect DPL prices would not affect Western Hub prices.

33

PJM Market In nominal terms, DPL prices are somewhat higher

than the PJM system or Western Hub of PJM prices given the congestion into DPL.

• The relative price analysis shows the same effects.

• Both the Day-Ahead and Real-Time market display the same price dispersion between the constrained and unconstrained regions of PJM for most of the hours of the day.

While the DPL prices spike higher than PJM and Western Hub prices, the average effect of these spikes may not be large enough to drive needed investment in Delmarva infrastructure.

34

Nominal PricePJM Monthly Averaged RealTime LMP for Peak Period

(from Jan 1999 - Dec 2005)

0

20

40

60

80

100

120

140

160

Time

$

PJMRT WESTERNRT DPLRT

35

Nominal PricePJM Monthly Averaged RealTime LMP for OffPeak Period

(from Jan 1999 - Dec 2005)

0

10

20

30

40

50

60

70

80

Time

$

PJMRT WESTERNRT DPLRT

36

Nominal PricePJM Monthly Averaged DayAhead LMP for Peak Period

(from June 2000 - Dec 2005)

0

20

40

60

80

100

120

140

Time

$

PJMDA WESTERNDA DPLDA

37

Nominal PricePJM Monthly Averaged DayAhead LMP for OffPeak Period


0

10

20

30

40

50

60

70

80

Time

$

PJMDA WESTERNDA DPLDA

38

Nominal PriceRatio (DPL - WESTERN)/WESTERN of RealTime Monthly Averaged LMP for Peak Period

(from Jan 1999 - Dec 2005)

-0.2

0

0.2

0.4

0.6

0.8

1

Time

$

39

Nominal PriceRatio (DPL - WESTERN)/WESTERN of RealTime Monthly Averaged LMP for OffPeak Period

(from Jan 1999 - Dec 2005)

-0.1

0

0.1

0.2

0.3

0.4

0.5

Time

$

40

Nominal PriceRatio (DPL - WESTERN)/WESTERN of DayAhead Monthly Averaged LMP for Peak Period


-0.2

0

0.2

0.4

0.6

0.8

1

Time

$

41

Nominal PriceRatio (DPL - WESTERN)/WESTERN of DayAhead Monthly Averaged LMP for OffPeak Period


-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

Time

$

42

Nominal PriceRatio (DPL - PJM)/PJM of RealTime Monthly Averaged LMP for Peak Period

(from Jan 1999 - Dec 2005)

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Time

$

43

Nominal PriceRatio (DPL - PJM)/PJM of RealTime Monthly Averaged LMP for OffPeak Period

(from Jan 1999 - Dec 2005)

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

Time

$

44

Nominal PriceRatio (DPL - PJM)/PJM of DayAhead Monthly Averaged LMP for Peak Period


-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Time

$

45

Nominal PriceRatio (DPL - PJM)/PJM of DayAhead Monthly Averaged LMP for OffPeak Period


-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

Time

$

46

Real Price(PPI Base = 2000)

DPL Western Hub and PJM System wide prices were adjusted for inflation (PPI).

In real terms, the price spread between the constrained market price of DPL and PJM price is very narrow at best.

Western Hub real price series is the lowest since 1999, except around July 2005 when it started to rise above PJM price.

Price divergence between constrained and unconstrained markets is not clearly discernable most of the period.

47

Real PricePPI Adjusted PJM Monthly Averaged RealTime LMP for Peak Period

(from Jan 1999 - Dec 2005)

0

20

40

60

80

100

120

140

160

TimeNote that PPI Index for 2000 = 100

$

PJM WESTERN HUB DPL

48

Real PricePPI Adjusted PJM Monthly Averaged RealTime LMP for OffPeak Period

(from Jan 1999 - Dec 2005)

0

10

20

30

40

50

60


$

PJM WESTERN HUB DPL

49

Real PricePPI Adjusted PJM Monthly Averaged DayAhead LMP for Peak Period


0

10

20

30

40

50

60

70

80

90

100


$

PJM WESTERN HUB DPL

50

Real PricePPI Adjusted PJM Monthly Averaged DayAhead LMP for OffPeak Period


0

10

20

30

40

50

60

70


$

PJM WESTERN HUB DPL

51

Fuel AdjustedPrice Natural Gas price was used for the fuel adjustment.

Fuel Adjusted Price of DPL is marginally higher than Western Hub and PJM system wide average price for most hours of the day.

Fuel adjusted prices display similar characteristics as real time price movements in both constrained and unconstrained markets.

The price spread between DPL and Western Hub and PJM are very narrow most of the period studied, with a few exceptions when price spikes were noticeable.

52

Fuel AdjustedFuel Adjusted PJM Monthly Averaged RealTime LMP for Peak Period

(from April 2001 - Dec 2005)

0

5

10

15

20

25

30

35

40


$

PJM WESTERN HUB DPL

53

Fuel AdjustedFuel Adjusted PJM Monthly Averaged RealTime LMP for OffPeak Period


0

5

10

15

20

25


$

PJM WESTERN HUB DPL

54

Fuel AdjustedFuel Adjusted PJM Monthly Averaged DayAhead LMP for Peak Period


0

5

10

15

20

25

30

35

40


$

PJM WESTERN HUB DPL

55

Fuel AdjustedFuel Adjusted PJM Monthly Averaged DayAhead LMP for OffPeak Period


0

5

10

15

20

25


$

PJM WESTERN HUB DPL

56

ISO-NE

Prices from three ISO-NE regions were analyzed.

• Boston and Connecticut were selected as regions where transmission into the regions would be often congested.

• Maine was chosen as a region whose prices are most likely to be unaffected by constraints affecting Connecticut and Boston.

• ISO-NE is a system wide average price.

57

Nominal Price In nominal terms, prices in Boston and CT are tend

to be the highest.

• In the Real-Time market, the price trends for the peak and off-peak periods of ISO-NE and CT and Boston prices are very close to one another.

• The prices in Maine produce the lowest price series.

• The CT prices in the Day-Ahead market are slightly higher than both the ISO-NE system average and Maine prices.

• Until June 2005, the peak prices of the constrained Boston and CT areas were virtually converged with ISO-NE average price. CT Real-Time peak prices started to diverge slightly from the ISO-NE averages following June 2005.

58

Nominal PriceISONE Monthly Averaged RealTime LMP for Peak Period

(from March 2003 - Dec 2005)

0

20

40

60

80

100

120

140

160

Time

$

ISO-NE ME CT BOSTON

59

Nominal PriceISONE Monthly Averaged RealTime LMP for OffPeak Period


0

10

20

30

40

50

60

70

80

90

100

Time

$

ISO-NE ME CT BOSTON

60

Nominal PriceISONE Monthly Averaged DayAhead LMP for Peak Period


0

20

40

60

80

100

120

140

Time

$

ISO-NE ME CT BOSTON

61

Nominal PriceISONE Monthly Averaged DayAhead LMP for OffPeak Period


0

10

20

30

40

50

60

70

80

90

100

110

Time

$

ISO-NE ME CT BOSTON

62

Real Prices In real terms, the Boston and CT tend to be

the highest.• There is very little divergence of prices among

the CT and Boston areas and ISO-NE system average.

• This characteristic is more clearly depicted both in the RT and DA off-peak markets.

• The prices in Maine produce the lowest price series.

• In November 2005, the constrained real price in Boston area is virtually on top of ISO-NE average real price.

63

Real PricePPI Adjusted ISONE Monthly Averaged RealTime LMP for Peak Period


0

20

40

60

80

100

120

140

160


$

ISO-NE ME CT BOSTON

64

Real PricePPI Adjusted ISONE Monthly Averaged RealTime LMP for OffPeak Period


0

10

20

30

40

50

60

70

80

90


$

ISO-NE ME CT BOSTON

65

Real PricePPI Adjusted ISONE Monthly Averaged DayAhead LMP for Peak Period


0

20

40

60

80

100

120


$

ISO-NE ME CT BOSTON

66

Real PricePPI Adjusted ISONE Monthly Averaged DayAhead LMP for OffPeak Period


0

10

20

30

40

50

60

70

80

90


$

ISO-NE ME CT BOSTON

67

Fuel Adjusted Price For most of the period since April 2003, the fuel adjusted price

trend analysis, in both the constrained and unconstrained regions for the ISO-NE real-time off peak market indicates that Boston and CT and ISO-NE average are very close whereas Maine is always lower than the other three prices studied.

In most of the period, fuel adjusted prices were virtually on top of one another, except Maine, which is always lower. Price spreads among constrained and unconstrained markets were marginally measurable at best.

In early 2005, CT Day-Ahead constrained market prices started to marginally deviate from the ISO-NE average price, whereas Boston was very close to the ISO-NE average price.

68

Fuel Adjusted PriceFuel Adjusted ISONE Monthly Averaged RealTime LMP for Peak Period


0

5

10

15

20

25

30

35

40

45


$

ISO-NE ME CT BOSTON

69

Fuel Adjusted PriceFuel Adjusted ISONE Monthly Averaged RealTime LMP for OffPeak Period


0

5

10

15

20

25

30

35


$

ISO-NE ME CT BOSTON

70

Fuel Adjusted PriceFuel Adjusted ISONE Monthly Averaged DayAhead LMP for Peak Period


0

5

10

15

20

25

30

35

40

45


$

ISO-NE ME CT BOSTON

71

Fuel Adjusted PriceFuel Adjusted ISONE Monthly Averaged DayAhead LMP for OffPeak Period


0

5

10

15

20

25

30

35


$

ISO-NE ME CT BOSTON

72

Questions?

email: [email protected]: (317) 249 5774



Hon. Kurt AdamsHon. Kurt Adams

Kurt AdamsKurt Adams

ChairmanChairman

Maine PUCMaine PUC

Selecting the marginal unit – Selecting the marginal unit – the bid stackthe bid stack

Bid Stack

0%

20%

40%

60%

80%

100%

120%

1

Generation Type Bid

Per

cen

t L

oad

Cle

ared

Natural gas

Oil

Oil/gas

Wood/refuse

Coal

Coal/oil

Hydro

Nuclear

Natural gas is volatile – and it Natural gas is volatile – and it directly impacts electricity directly impacts electricity pricesprices

Electricity Forwards, Natural Gas Futures Electricity - On peak @ MA HubNatural Gas - NYMEX Henry Hub

60.00

70.00

80.00

90.00

100.00

110.00

120.00

130.00

140.00

Late J

an

Mar

18

M

ar 28

A

pr 4

A

pr 11

A

pr 18

A

pr 25

May

2

M

ay 9

M

ay 16

M

ay 23

M

ay 31

J

un 7

J

un 14

J

un 21

J

ul 5

J

ul 12

J

ul 19

A

ug 2

A

ug 9

A

ug 16

Aug 2

3

S

ept 1

S

ept 9

S

ept 16

Sep

t 23

S

ept 30

Oct

7

O

ct 14

O

ct 21

O

ct 28

N

ov 4

$ p

er

MW

h,

pe

r M

MB

TU

x 1

0

Electricity - next 12 mnths

Natural Gas - next 12 mnths

Electricity - Sep-Feb 05

4 Heretical Questions4 Heretical Questions

If we redesign the capacity markets, If we redesign the capacity markets, do we need to rethink the UCP?do we need to rethink the UCP?

In multi-state pools, do we have the governmental In multi-state pools, do we have the governmental infrastructure to deploy EE/DR effectively – if not infrastructure to deploy EE/DR effectively – if not states, who?states, who?

Will ISOs establish resource Will ISOs establish resource adequacy?adequacy? Have we replaced state regulators with Have we replaced state regulators with federal regulators – is this deregulation?federal regulators – is this deregulation?



Tom WelchTom Welch

©2005 PJMwww.pjm.com 79

Increased Efficiency

• Lower energy prices across the expanded PJM region– ESAI’s technical study: region-wide energy price without integration

would be $0.78/MWh higher in 2005 than with integration.

– Spreading these savings over the total PJM RTO’s energy demand of 700 terawatt-hours (TWh) per year yields aggregate savings of over $500 million per year.

Pre-Integration Price Pattern Post-integration Energy Price Pattern

PJM ©2005

• Heat rates decline– Provides fuel adjusted measure of efficiency– Equivalent heat rate at Western Hub reduced

from 11 MMBTU/ MWh in 1999 to 7.3 MMBTU/MWh in 2004

Increased Efficiency

Heat Rates - Major Pricing Hubs

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

Jan

-99

Ju

l-99

Jan

-00

Ju

l-00

Jan

-01

Ju

l-01

Jan

-02

Ju

l-02

Jan

-03

Ju

l-03

Jan

-04

Ju

l-04

Jan

-05

Ju

l-05

MM

Btu

/MW

h

AEP CINERGYONTARIO PJMTVA ZONEAVACAR Comed/NI


Increased Opportunities for Demand Response

Revenue Opportunity

Central Station Generation (PJM)

PJM (January 2005)

PJM (as of December 31, 2005)

PJM with approval of RPM

PJM with addition of Forward Energy

Real-Time/ Spot Energy Sales

→

Day-Ahead Energy Sales

Demand Side

ResponseForward Energy Sales

No No No Forward Energy Reserve

Forward Capacity Sales

RPM will enhance

→ Limited Limited RPM auction RPM auction

Energy & Capacity payment for emergencies

→ Not in all cases

Ancillary Services

Spin, regulation, etc…

→ No


Future Reliability Violations

Additional studies are being completed to resolve Eastern MAAC and

Southwestern MAAC import requirements beyond 2009


Proposed Timing of RPM Auctions

Base Residual Auction

Planning Year

4 Years

Incremental Auction

Incremental Auction

June May

4 months

13 months

Incremental Auction

23 months

EFORd Fixed

Self- Supply & Bilateral Designation

Ongoing Bilateral Market – (shorter-term reconfiguration)

ILR


May 2007 – June 2008 May 2008 – June 2009

May 2009 – June 2010

$0 - $33 =

$34 - $68 =

$69 - $102 =

$103 - $136 =

$137 - $170 =

$171 - $204 =

Value of Capacity ($/MW-day)

RPM Simulation results


Scarcity Prices: PJM Recommended Demand Curvevs. Vertical Demand Curve at Target Reserve

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29

Year

Sc

arc

ity

Re

ve

nu

e (

$/M

W-Y

R)

Vertical Demand Curve PJM Recommended Demand Curve


Capacity Prices: PJM Recommended Demand Curve vs. Vertical Demand Curve at Target Reserve

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29

Year

Ca

pa

cit

y P

ric

e (

$/M

W-Y

R)

Vertical Demand Curve PJM Recommended Demand Curve


CAPACITY CAPACITY MARKETSMARKETS

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