electricity market

8/9/2019 electricity market

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PJM Organization and Markets

Saudi DelegationColumbus Ohio

May 22, 2012


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Agenda

www.pjm.com

Introduction & GovernanceEnergy Markets

LMP

FTRs/ARRs

Two Settlement

Virtual Bids

Ancillary

Capacity - Reliability Pricing Model


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www.pjm.com

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What is an RTO?

www.pjm.com

A Regional Transmission Organization (RTO) is:

– Independent from all market participants

– Responsible for grid operations and reliability – Responsible for transmission service within region


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PJM Demographics

Complexity

1365 Generation Resources with Diverse FuelOver 56,250 Miles of Transmission LinesOver 60 Million People Served

UniquenessSingle Control Area in NERC Region Area Served: 13 States + DC

Members/CustomersMember Companies ~ 760 +Transmission Svc. Customers ~ 100 +158,450 MW Peak Load (July 21, 2011)

www.pjm.com



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PJM Service Territory

PJM©2010 6 5/30/2012


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Transmission Owner Zones

www.pjm.com


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Nine Major North American RTOs / ISOs

PJM©2010 8 5/30/2012


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PJM Functions

3 – Plan for transmissionexpansion on a regional basis

Grid Operat ions

- 24/7 Monitor in g ofTransmiss ion Lines

- 24/7 Generation &Load B alance

Market Operation

- Energy-Capaci ty

- An ci l lary Services

RegionalP lanning

15 Year look- ahead toensure transmission

capability

1a & 1 b

2

3

1a – Monitor the high-voltagetransmission grid for reliability

1b – Balance generation and load onan instantaneous basis

2 – Operatecompetitive,

non-discriminatory

markets


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Function 1a - Monitoring the Bulk Power System for Reliability


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Operations Goal – Keeping the RTO in Balance at All Timeswhile Respecting Transmission LimitationsFunction 1b


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Electricity Markets - Match Buyers and Sellers

Sellers - Supply ResourcesFossil, Hydro, Nuclear, RenewableFERC Approved Power Marketers

B uyers - Wholesales EntitiesLoad Serving Entities

FERC Approved Power Marketers

Function 2


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Planning an Adequate and Reliable Transmission System

The Regional Transmission Expansion Planning Processidentifies upgrades to meet customers’ requirements:

• operational

• economic

• reliability requirements

Merchant Generation Base Line Upgrades

Function 3


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How is PJM different from the local utility?

PJM does:• Direct operation of the transmission system• Remain profit neutral

• Maintain independence from PJM members• Coordinate maintenance of grid facilities

www.pjm.com


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How is PJM different from the local utility?

PJM does not:• Own any transmission or generation assets.• Function as a publicly traded company.

• Take ownership of the energy on the system.• Perform the actual maintenance on generators or

transmission systems.• Serve, directly, any end use (retail) customers.

www.pjm.com



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www.pjm.com


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Governance

www.pjm.com


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Two Tier Governance Structure

www.pjm.com

Independent Board (10)

Members Committee (Sectors)

GenerationOwners Transmission

Owners

OtherSuppliers

ElectricDistributors

End-UseCustomers



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Members Committee Voting Protocol

www.pjm.com

Transmission Owners

Generation Owners

Other Supplier

End Use Customers

Electric Distributors

5/7 0.71

2/8 0.25

21/23 0.91

5/5 1.00

Required to pass = 0.667Number of Sectors = 5

Required Affirmative = 5 x 0.667 = 3.335

3.47

3/5 0.60



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PJM Committee Structure

www.pjm.com


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www.pjm.com


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Dispatch Function

www.pjm.com


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5/30/2012

Valley Forge Control Room


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5/30/2012

Milford Control Room


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Dispatch Functions

• Ensure sufficient generation is available orrunning to satisfy the demand at any hour ofthe day including maintaining adequatereserves. This is called Generation Control .

• Monitor, operate and control the high voltagetransmission system in a reliable manner.This is called Transmission Control .

www.pjm.com


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Load Curve – Summer Profile

26 5/30/2012

RTO Load (MW)

70000

80000

90000

100000

110000

120000

130000

140000

150000

T i m e

( E P T )

0 : 3

9

1 : 1

9

1 : 5

9

2 : 3

9

3 : 1

9

3 : 5

9

4 : 3

9

5 : 1

9

5 : 5

9

6 : 3

9

7 : 1

9

7 : 5

9

8 : 3

9

9 : 1

9

9 : 5

9

1 0 : 3

9

1 1 : 1

9

1 1 : 5

9

1 2 : 3

9

1 3 : 1

9

1 3 : 5

9

1 4 : 3

9

1 5 : 1

9

1 5 : 5

9

1 6 : 3

9

1 7 : 1

9

1 7 : 5

9

1 8 : 3

9

1 9 : 1

9

1 9 : 5

9

2 0 : 3

9

2 1 : 1

9

2 1 : 5

9

2 2 : 3

9

2 3 : 1

9

Long, gradual rise

Significantpersistence

2+ hour drop offAt 9,000 MW/Hr


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Load Curve – Winter Profile

27

RTO Load (MW)

70000

75000

80000

85000

90000

95000

100000

T i m e

( E P T )

0 : 3

9

1 : 1

9

1 : 5

9

2 : 3

9

3 : 1

9

3 : 5

9

4 : 3

9

5 : 1

9

5 : 5

9

6 : 3

9

7 : 1

9

7 : 5

9

8 : 3

9

9 : 1

9

9 : 5

9

1 0 : 3

9

1 1 : 1

9

1 1 : 5

9

1 2 : 3

9

1 3 : 1

9

1 3 : 5

9

1 4 : 3

9

1 5 : 1

9

1 5 : 5

9

1 6 : 3

9

1 7 : 1

9

1 7 : 5

9

1 8 : 3

9

1 9 : 1

9

1 9 : 5

9

2 0 : 3

9

2 1 : 1

9

2 1 : 5

9

2 2 : 3

9

2 3 : 1

9

4-hour pickupAt 4,000 MW/Hr

3-hour eveningpeak period

4-hour drop offAt 4,500 MW/Hr

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www.pjm.com


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Locational Marginal Price

www.pjm.com


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What is Locational Marginal Price?

www.pjm.com

Pricing method PJM uses to:price energy purchases and sales inPJM Marketprice transmission congestion costs to

move energy within PJM RTOprice losses on the bulk power system

Physical, flow-based pricing system:how energy actually flows, NOTcontract paths


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How does PJM Use LMP?

www.pjm.com

Generators get paid at generation bus LMPLoads or Customer Demand pay at load bus LMPBilateral Transactions pay differential in source andsink LMPPJM LMPs are the result of the physical flow ofenergy, not a contract path


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Locational Marginal Price

www.pjm.com

SystemEnergy

Price

TransmissionCongestion

Cost

Cost ofMarginal

Losses

LMP is made up of 3 independent components


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LMP Components - System Energy Price

PJM©2009 33

SystemEnergy

Price


Cost

Cost ofMarginal

Losses

System Energy PriceRepresents optimal dispatch ignoring congestion andlosses

Same price for every bus in PJM

Calculated both in day ahead and real time

Intersection of the Supply and Demand Curve


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LMP Components - Congestion

PJM©2009 35

SystemEnergy

Price


Cost

Cost ofMarginal

Losses

Congestion PriceRepresents price of congestion for binding constraints

Calculated using cost of marginal units controlling constraints andsensitivity factors on each bus

Will be zero if no constraintsWill vary by location if system is constrained

Calculated both in day ahead and real time


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LMP Components - Congestion

www.pjm.com

Limit = 1000 MW

Load = 1500MW$20 Power

$50 PowerSystem Energy Price = $20Congestion = $ 0

Losses =LMP = $20

System Energy Price = $20Congestion = $30Losses =LMP= $50

Dispatch 1000 MWFlow = 1000 MW

Dispatch 500 MW


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LMP Components – Marginal Losses

PJM©2009 37

SystemEnergy

Price


Cost

Cost ofMarginal

Losses

Loss PriceRepresents price of marginal losses

Calculated using penalty factorsWill vary by location

Calculated both in day-ahead and real-time


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Transmission Losses

Real Power (MW) LossesPower flow converted to heat in transmission equipmentHeat produced by current (I) flowing through resistance (R)

Losses equal to I2R

Heat loss sets the “thermal rating” of equipment

Losses increase with:Lower voltageLonger linesHigher current

www.pjm.com


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LMP Components Marginal Losses

www.pjm.com

Limit = 1000 MW

Load = 1500MW$20 Power

$50 PowerSystem Energy Price = $20Congestion = $ 0

Losses = ($ 1)LMP = $19

System Energy Price = $20Congestion = $30Losses = $ 2LMP= $52

Dispatch 1000 MWFlow = 1000 MW

Dispatch 500 MW


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www.pjm.com


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What are FTRs?

Financial Transmission Rights are …

www.pjm.com

financial instruments awardedto bidders in the FTR

Auctions that entitle the

holder to a stream ofrevenues (or charges) basedon the hourly Day Aheadcongestion price differences

across the path+

LMP =SystemEnergyPrice

CongestionPrice

MarginalLossPrice

+


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Why do we need FTRs?

Challenge:Protect Load Servers from price uncertainty for congestionchargesRedistribute excess congestion charges

Solution:FTR credits equal congestion charges on same path

FTRs provide hedging mechanism that can be tradedseparately from transmission service

www.pjm.com


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• Economic value based on Day AheadCongestion Component of LMP

• Defined from source to sink• Financial entitlement, not physical right• Independent of energy delivery

Characteristics of FTRs


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Energy Delivery Consistent with FTR

www.pjm.com

Source(Sending End)

Thermal Limit

FTR = 100 MW

Congestion Charge = 100 MW * ($30-$15) = $1500

Congestion= $30Congestion = $15

Sink(Receiving End)

Bus BBus A Energy Delivery = 100 MWh

FTR Credit = 100 MW * ($30-$15) = $1500


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PJM©2009 46

100 MW FTR

SourceLMP =$18

System Energy = $20Congestion = ($3)Marginal Loss = $1

SinkLMP =$29System Energy = $20Congestion = $7Marginal Loss = $2

FTR Value = 100 MW * (7 - (-3)) = $1,000 Credit

“Prevailing Flow” FTRs point in the same direction as the congestion”

FTRs as a Benefit

b l


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PJM©2009 47

100 MW FTR

SinkLMP =$18

System Energy = $20Congestion = ($3)Marginal Loss = $1

SourceLMP =$29

System Energy = $20Congestion = $7Marginal Loss = $2

FTR Value = 100 MW * ((-3) - 7) = $1,000 Liability

“Counterflow ” FTRs point in the opposite direction of the congestion”

FTRs as a Liability

Ob i i


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Obtaining FTRs

Annual AuctionMulti-roundMulti-periodMulti-productEntire System Capability

Secondary market -- bilateral tradingFTRs that exist are bought or sold

Monthly & Balance of Planning Period FTR Auction --centralized market

purchase “left over” capability

www.pjm.com

Wh FTR W h?


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What are FTRs Worth?

Economic value determined by

Day ahead hourly LMPs

Benefit (Credit)Prevailing Flow

Liability (Charge)Counterflow

FTR Options availableNever negatively valued

www.pjm.com

Wh ARR ?


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What are ARRs?

Auction Revenue Rights …

www.pjm.com

are entitlements allocated

annually to Firm TransmissionService Customers that entitle theholder to receive an allocation of

the revenues from the AnnualFTR Auction


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Wh t th h ld d ith th FTR?


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What can the holder do with the FTR?

“Self -Scheduling” FTR into Annual Auction on exactsame path as ARRReconfigure ARR by bidding into Annual Auction to

acquire FTR on alternative path or for alternativeproductMay retain allocated ARR and receive associatedallocation of revenues from the auction

www.pjm.com


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Two Settlement

www.pjm.com

Wh t i T –S ttl t?


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What is Two –Settlement?

It provides PJM Market Participants with theoption to participate in a forward market forelectric energy in PJM

Consists of two marketsSeparate settlements performed for each market

www.pjm.com

Two Settlement Markets


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Two-Settlement Markets

• Day-ahead Market

– Financial market using Bid-In Load – Prices calculated hourly / Hourly settlements – Includes virtual bids and price sensitive demand

• Real-time Market – Physical Market based on actual system conditions – Prices calculated every 5 minutes – Hourly Settlements based on deviations from Day-Ahead position

www.pjm.com


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Day Ahead Market Timeline


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Day-Ahead Market Timeline

www.pjm.com

6:00 pm

12:00 noon

12:00 - 4:00 pmDay-ahead market isclosed for evaluation

by PJM

4:00 - 6:00 pm

Re-bidding period

Throughout Operating DayPJM continually re-evaluates and sends

out individual generation schedule

updates, as required

Up to 12:00 noon PJM receives bids andoffers for energy next

Operating Day

midnight

4:00 pm

4:00 pm

PJM posts day-aheadLMPs & hourlyschedules

Day Ahead vs Real Time LMP 2009


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Day-Ahead vs. Real-Time LMP - 2009

www.pjm.com


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www.pjm.com


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Virtual Bids

www.pjm.com


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INCS vs DECS


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INCS vs. DECS

• Look like a generator(injects MW)

• Specifies a price andquantity

• Turns on when the pricegets high enough

64

INCS DECS

• Look like a load(withdrawals MW)

• Specifies a price andquantity

• Turns on when the pricegets low enough

How do virtual bids make money?


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How do virtual bids make money?

• Sells MW into Day AheadMarket at High Price

• Buys replacement MW

from Real-Time Market atLower Price• Hopes that Day-Ahead

Prices are Higher thanReal-Time Prices

PJM©2009 65

INCs DECs

• Buys MW from DayAhead Market at LowPrice

• Sells those MW in Real-Time Market at HigherPrice

• Hopes that Day-AheadPrices are Lower thanReal-Time Prices


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www.pjm.com


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Ancillary Services


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Ancillary Services

• Regulation Market• Synchronized Reserve Market• Black Start Service• Reactive Services• Scheduling, System Control & Dispatch

www.pjm.com

Regulation Market


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Regulation Market

Purpose: To provide for the continuous balancing of generation

and load

www.pjm.com

• Generation and Demand Response resources

• Transmission customer must provide or purchase• RMCP = Regulation Market Clearing Price• Regulation Price = Higher of RMCP or offer price plus

opportunity cost

Synchronized Reserves Market


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• LSE’s have obligation to purchase based on Load Ratio

Share – Bilateral – Scheduling owned resources – Purchase from Synchronized Reserve Market

• Co-optimized with Regulation Market• Allows for participation by Demand Side Response

resources

www.pjm.com

Purpose: To bring generation and load back in balance after the

loss of generation

Synchronized Reserves Market

Blackstart Service


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www.pjm.com

• Transmission Owners, with PJM identify critical

Blackstart units• Generator annual revenue requirements - Cost-

based service• Charges go to Transmission Customers

• Annual Blackstart testing requirements

Purpose: To provide for the continuous balancing of generation

and load

Blackstart Service


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Scheduling, System Control & Dispatch


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Scheduling, System Control & Dispatch

www.pjm.com

• Schedule 9 of PJM Tariff

- Control Area Administrative Service- FTR Administrative Service- Market Support Service- Regulation Administrative Service

- Capacity Resource and Obligation Service

Purpose: To provide transmission service and operate the energy

market.


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Capacity vs. Energy


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p y gy

Capacity

• A commitment of a resourceto provide energy duringPJM emergency under thecapped energy price.

• Capacity revenues paid tocommitted resourcewhether or not energy isproduced by resource.

• Daily product

Energy

• Generation of electricalpower over a period of time

• Energy revenues paid toresource based on

participation in PJM’s Day -Ahead & Real-Time EnergyMarkets

• Hourly product

Capacity, energy & ancillary services revenues are expected, in the long term, to meet thefixed and variable costs of generation resources to ensure that adequate generation is

maintained for reliability of the electric grid.

Objectives of RPM


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j

• Resource commitments to meet system peakloads three years in the future

• Three year forward pricing which is aligned with

reliability requirements and which adequatelyvalues all capacity resources

• Provide transparent information to all

participants far enough in advance for actionableresponse

Purpose of RPM is to enable PJM to obtain sufficient resources to reliably meet the needsof electric consumers within PJM.

Resource Adequacy Requirement


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q y q

• Determines the amount of capacity resourcesrequired to serve the forecast peak load andsatisfy the reliability criterion.

• The reliability criterion is based on Loss of LoadExpectation (LOLE) not exceeding one event inten years.

An Installed Reserve Margin (IRM) = 15.3% satisfies the reliability criterion for the2013/14 Delivery Year.

Resource Adequacy ICAP Requirement = Forecast Peak Load * (1+ IRM)


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Locational Deliverability Areas


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y

• Regions – Western PJM (ComEd, AEP, Dayton, APS, Duquesne, ATSI, Duke) – Mid-Atlantic Area Council (MAAC) Region – Eastern MAAC (PSE&G, JCP&L, PECO, AE, DPL & RECO) – Southwestern MAAC (PEPCO & BG&E) – Western MAAC (Penelec, MetEd, PPL)

• Zones – AE, AEP, APS, ATSI, BGE, Comed, Dayton, DUQ, Dominion, DPL, Duke,

JCPL, MetEd, PECO, Penelec, PEPCO, PPL, PSEG

• Sub-Zones – PSEG Northern Region (north of Linden substation) – DPL Southern Region (south of Chesapeake and Delaware Channel)

* Includes ATSI effective with 13/14 DY and Duke effective with 14/15 DY.

PJM required to make a filing with FERC before adding a new LDA.

RTEPP has currently identified 25* sub-regions as Locational Deliverability Areas (LDAs) for evaluatingthe locational constraints.

RPM Structure3 Years


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Base ResidualAuction

DeliveryYear

SecondIncrementalAuction

ThirdIncrementalAuction

June May

3 months

10 months

FirstIncrementalAuction

20 months

EFORdFixed

Ongoing Bilateral Market

InterruptibleLoad forReliability (ILR)(Only effectiveprior to 12/13DY)

May

Feb.

July

Sept

ConditionalIncremental

Auction Effective12/13 DY)

May bescheduledat any timeprior to DY

Mar

RPM Auctions (Starting with 12/13 DY)


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( g )

Activity Purpose Cost of Procurement

Base Residual Auction Procurement of RTO Obligation less anamount reserved for short lead timeresources, less FRR Obligation

Allocated to LSEs through LocationalReliability Charge

1st Incremental Auction Allows for:(1) replacement resource procurement(2) increases and decreases in resource

commitments due to reliability

requirement adjustments; and(3) deferred short-term resource

procurement

Allocated to resource providers thatpurchased replacement resourcesand LSEs through LocationalReliability Charge2nd Incremental

Auction

3rd Incremental Auction

Conditional IncrementalAuction

Procurement of additional capacity in aLDA to address reliability problem that iscaused by a significant transmission linedelay

Allocated to LSEs through LocationalReliability Charge

Interruptible Load forReliability (ILR)

ILR Option eliminated starting with 12/13 DY

What is the VRR?


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• The price is higher when the resources are less thanthe reliability requirement and lower when theresources are in excess.

• VRR Curves are defined for the PJM RTO and for

each constrained Locational Deliverability Area(LDA) within the PJM region.

The Variable Resource Requirement (VRR) Curve is a downward slopingdemand curve that relates the maximum price for a given level ofcapacity resource commitment relative to reliability requirements.


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www.pjm.com

Source: PJM 2014/15 Base Residual Auction Report

Clearing 2012/2013 Base Residual Auction


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Clearing determined by the intersection of the supply and the demand curves.


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