Utility Regulation

March 10, 2011

Raj AddepalliDeputy Director, Electric, Office of Electric,Gas and Water

New York State Department of Public Servicerpa@dps.state.ny.us

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Utility Regulation Table of Contents

1. Key NY Industry Statistics

2. NYISO Market Products

Section I

New York: Key Electric Industry Statistics

Fuel Mix of Generation Capacity Basis

1997 Capacity (MW) Fuel Mix in New York

Gas & Oil35%

Coal12%Hydro

15%

Nuclear14%

Other1%

Gas10%

Oil13%

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Gas & Oil36%

Coal7%Hydro

15%

Nuclear14%

Other1%

Gas18%

Oil9%

2010 Capacity (MW) Fuel Mix in New York

Fuel Mix of Generation Energy Basis

1997 Energy (GWH) Fuel Mix in New York

Gas & Oil39%

Coal17%

Hydro21%

Nuclear21%

Other2%

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Gas & Oil35%

Coal9%Hydro

20%

Nuclear32%

Other4%

2009 Energy (GWH) Fuel Mix in New York

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Wholesale Energy Prices

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010$0

$20

$40

$60

$80

$100

$120

NY WEST

NY CAPITL

NY HUD VL NYC

NY LONGIL

PJM West

NE West

Annual Day-Ahead Electric Energy Prices

NY WEST NY CAPITL NY HUD VL NYC NY LONGIL PJM WestNew England West

$/M

WH

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2006 2007 2008 2009 2010$0

$500,000,000

$1,000,000,000

$1,500,000,000

$2,000,000,000

$2,500,000,000

$618,394,525$760,420,429

$641,356,077 $663,689,741

$436,645,075

$1,025,652,110

$1,045,590,440

$542,602,443 $575,911,234 $987,378,236

$454,939,318

$380,046,784

$185,905,413 $156,316,949

$107,906,247

NYCA Capacity Costs 2006-2010

LI

NYC

ROS

Year

Cos

t ($)

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NYCA Load Duration Curve

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Average Load, 18,665 MW

Peak Load, 33,452 MW

Minimum Load, 11,859 MW

2010 New York State Hourly Integrated Real-Time Load Dura-tion Curve

Percent of Time

Lo

ad (M

W)

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NYCA Price Duration Curve

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

Average Price, $50/MWh

Maximum Price, $181/MWh

Minimum Price, $17/MWh

2010 New York State Load-Weighted Day-Ahead Market Price Duration Curve

Percent of Time

Pri

ce (

$/M

Wh

)

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Resource Additions• Generation: Over 8,000 MW added since NYISO inception,

some “merchant” and some supported by regulated entities and public authorities

Period Addition (MW)

1985-1990 2,004

1991-1995 4,794

1996-2000 303

2000-2010 8,890*

• Transmission: Over 1,300 MW added

• Demand Response: Over 2,000 MW of DSR participating in NYISO SCR program; about 260 MW in EDRP program

* Includes approximately 1,300 MW of wind generation

Section II NYISO Market Products

NYISO Wholesale Market Products

• Energy – Day-Ahead, Real Time• Installed Capacity• Ancillary Services

– Operating Reserves– Regulation– Blackstart – Voltage Support

• Transmission Congestion Contracts and Virtuals

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Competitive and Cost Based Products

• Competitive markets set prices for energy, capacity and some of the ancillary services (operating reserves and regulation)

• Day-Ahead Energy Market has about 95% of the transactions; the remainder is in Real-Time markets

• Over half the volume settled in the DAM is scheduled through the bilateral market

• Cost of Service pricing for Voltage Support and Blackstart services

• Market Power mitigation measures in place where there is potential for manipulation 15

Energy Markets

• NYISO markets use a uniform clearing price auction approach to set competitive energy prices

• The Day-Ahead Market is a forward market in which hourly LMPs (Locational Marginal Pricing) are calculated for the next operating day based on generation offers, demand bids and scheduled bilateral transactions.

• The Real-Time Market is a spot market in which current LMPs are calculated at five-minute intervals based on actual grid operating conditions.

• Uniform Clearing Price auction creates an incentive for producers to lower their costs and bid competitively. They also provide transparency to the marketplace, as all participants are aware of the value of energy

• The auction is conducted using sophisticated software that simultaneously determines how to serve the load utilizing generators with the combined lowest total production cost 16

Installed Capacity Market

• The NYISO must ensure that sufficient resources are available to meet projected load on a long-term basis. In order to facilitate this, the NYISO administers a capacity market. This market matches buyers and sellers of capacity using the clearing price methodology

• There are monthly auctions as well as six-month strip auctions

• Given the constrained nature of the transmission system, the capacity market has locational features, which reflect system reliability requirements that mandate loads in New York City and Long Island to buy a certain percentage of their capacity from suppliers in those areas 17

Ancillary Services

• The two competitively procured services are reserves and regulation

• Reserves include spinning and non-spinning; 10 minute and 30 minute reserves

• NYISO selects generating units with the lowest total production cost to provide energy, reserves, and regulation in order to minimize the cost of serving load

• Reserves and regulation are typically provided by generators; however the NYISO has opened these markets to include loads (demand-side providers)

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Transmission Congestion Contracts and Virtuals

• The owner of a TCC is entitled to receive (or obligated to pay) the difference in the LBMP congestion component between the source and sink of the contract

• TCCs are auctioned competitively and allow purchasers to lock-in a congestion cost payment

• Virtuals: Participants effectively buy (or sell) power at the day-ahead price and then sell (or buy) it back at the real-time price without having to actually produce or take delivery of the power

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Installed Capacity Market

• Installed Capacity (ICAP) market construct has been in place since the inception of NYISO

• Effectively, three markets - - New York City, Long Island, Statewide

• NYC and LI more constrained with higher HHIs• Voluntary forward auction frequencies: summer and

winter six-month strips, monthly auctions; mandatory spot auction for the next month; spot prices are determined by the use of demand curve construct

• Loads have to satisfy their ICAP obligations

Installed Capacity Market

• Developed to ensure that sufficient resources are available to meet projected load on a long-term basis

• LSE’s are required to purchase an amount of capacity based on their forecasted contribution to it’s transmission district peak load + an additional amount to cover IRM (installed reserve margin)

• System reliability requirements mandate loads in NYC and Long Island buy a certain percentage of their capacity from suppliers in their own area

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Use of Demand Curve in ICAP

• Introduced in 2003• Primary goals:

– Reduce volatility in ICAP prices and thus provide more certainty in revenue stream to sellers and help attract new entry

– Reduce potential for market power of both buyers and sellers

– Help keep economic units from retiring prematurely

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Demand Curve (contd)

• Three year cycle for updates of the key parameters • First cycle: June 2003- April 2005; 2nd cycle: May 2005-

April 2008; 3rd cycle: May 2008- April 2011; currently working on 4th cycle: May 2011-April 2014

• Cost of new entry, energy and ancillary service offsets, slope of the curve key variables of debate

• NYISO Market Monitor to file periodic compliance reports to FERC on how DC is working

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Market Power

• Given the slope of the Demand Curve, there could an incentive for some of the generators to withhold some capacity and still be better off financially with the resulting higher market price although they sell less quantity

• This results in an outcome that is not as competitive as it could be

• FERC imposed market power mitigation rules on all sellers to address this issue; at the same time, FERC imposed buyer market power rules as well

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Other Current ICAP Issues

• Buyer-Side market power• Role of Forward Capacity Markets for

Resource Adequacy purpose• Additional Locational ICAP Requirements