financial transmission rights: design options

For discussion purposes only

Financial Transmission Rights: Design options

Presentation to Electricity Commission

2 September 2009

© Transpower 2009

For discussion purposes only slide 2

Background

• Transpower was asked for advice on how to:

– Simplify and make 2002 FTR more appealing to participants

– Deal with Dr Read’s 2002 concerns

– Implement an FTR market

© Transpower 2009


Background

• Transpower’s advice is a suggested starting point for discussion

• Pricing should reflect underlying physics

• FTRs are internally consistent with locational marginal pricing

• Regulatory arrangements are different to 2002

• FTR trading platform can be significantly simplified without affecting dispatch

• Start simple and evolve with users

© Transpower 2009


What is the problem?

• Nodal prices are consistent with physical dispatch (i.e. they obey the laws of physics!)

• Locational price differences are caused by constraints in the transmission system NOT energy availability

• Commercial implications of transmission constraints:

– Bilateral contracts can only hedge energy costs

– Volatile and unpredictable locational price differences must be hedged separately

© Transpower 2009


What is the problem?

• There is little ability to hedge locational price difference

• Incentive is to vertically integrate and regionalise generation and retail

• Consequences:

– At best a partial locational price hedge

– Barrier to retail competition

– Significant cost to consumers

– Inefficient use of transmission assets

© Transpower 2009


What are the possible solutions?

• Remove locational price differences altogether

– Removes demand side response

• Use “rentals” to fund a hedge product

– The net amount that needs to be hedged is EXACTLY the rentals collected

– Preserves demand side “signals”

© Transpower 2009


Report Structure

• Part 1 – what is an FTR? How do they fit into integrated market design?

• Part 2 – design options

• Part 3 – implementation options

© Transpower 2009


Markets with locational marginal pricing

• A system for the efficient trading of electricity using supply and demand to set price

• Separate contestable and monopoly functions

• Characterised by “spot prices” that differ by location

• Wholesale market = competitive trading

• Retail market = customer choice

© Transpower 2009


Integrated market design

Co-ordinated spot market

Bid-based, security-constrained,

economic dispatch with nodal prices

ENERGY PRICINGBilateral contracts at nodal

price differencesT

RA

NS

MIS

SIO

N P

RIC

ING

Non

-dis

tort

iona

ry a

cces

s ch

arge

s

NE

W IN

VE

ST

ME

NT

Market-driven

RISK MANAGEMENTHedge against locational price

differences

NE

W G

EN

ER

AT

ION

Location and timing

NE

W T

RA

NS

MIS

SIO

NLocation and tim

ing

DE

MA

ND

SID

E P

AR

TIC

IPA

TIO

NN

EW

TR

AN

SM

ISS

ION

Cen

tral

ly p

lann

ed,

regu

lato

ry p

roce

ss,

TP

M

TRANSMISSION CONGESTIONFTR, LRA, vertical integration

RISK MANAGEMENTHedge against locational price

differences

© Transpower 2009


Physics – Kirchoff’s law

• This means that . . .– Every injection into and off-take from the grid effects electricity

flows on every circuit– Physical capacity rights cannot be meaningfully defined

• Which leads us to constraints and nodal prices . . .

© Transpower 2009


Commercial risk

• Kirchhoff's law and the occurrence of constraints create commercial risk:– Actions of other parties can impact on nodal price– Constraints impact on nodal prices

• Two primary risk management tools– Bilateral energy contracts referenced against price at a node

(often internalised by vertical integration) – Hedge to manage locational price risk arising from constraints

© Transpower 2009


Energy contract – example 1

GeneratorOffered at $2300 MW dispatched

Load300 MW

200 MW

100 MW

10

0 M

W

At limit

$2

$2

$2

Vertically integrated utility generates at A, commitment of 300 MW at $2 at B

Generation:

Cost to generate at A: -$600

Gets paid at A $600

Retail:

Buys 300MW from A -$600

Gets paid for 300MW at B: $600

© Transpower 2009


Energy contract – example 2

• Third party load increases at BGenerator 1Offered at $2240 MW dispatched

Load 1300 MW

200 MW

160 MW

40

MW

Constrained

Generator 2Offered at $3120 MW dispatched

$2

$4

$3

Load 260 MW

• Line A – B constrained

• Price at B increases to $4

• Retailer can’t meet obligation of 300MW at its generation cost of $2 to load at B ($600)

• To meet obligation of 300MW at B retailer must purchase all 300MW at B for $4 ($1200)

• Additional cost to gentailer is equivalent to the rentals of the system ($600)

© Transpower 2009


From an energy contract perspective

• The transmission price risk between A and B is the price difference B − A– Generation at A cannot offer an

energy contract referenced at B without taking the transmission price risk

– Load at B cannot accept an energy contract referenced at A without taking the transmission price risk


Load 1300 MW

200 MW

160 MW

40

MW

Constrained


$2

$4

$3

Load 260 MW

© Transpower 2009


How can A or B manage the transmission price risk?

• Either A or B needs a financial product that recompenses the value (PriceB - PriceA)/MW.– Generation at A can then offer a fixed energy price at B, or – Load at B can accept a fixed energy price hedge referenced at A

• The only cash stream correlated with nodal price differences is the rentals

• FTRs use this correlation to hedge price differences

© Transpower 2009


Energy price hedge values differ by location and over time

© Transpower 2002

Transmissionprice risk

Time

Price / MW h

$3

$1

$2

$4

$5

A

Nodal price at A

A

Nodal price at B

B

BEnergy price hedge value at A

Energy price hedge value at B

© Transpower 2009


Features of FTRs – trading risk

• Can be matched to an energy contract of a specified capacity and duration between two nodes – near perfect hedge

• Holder receives the rentals between two specified points for an agreed capacity and duration

• Protect the holder against extreme price risks (constraints, scarcity pricing)

• Can be allocated explicitly and/or through an auction• Traded in secondary auctions or markets• Only known product that exploits correlation of rentals with

locational price differences

© Transpower 2009


Features of FTRs – efficient investment

• Grid could operate with more constraints (more efficient)

• Signal the market value of constraints (FTR auction value)

• Provide an important economic signal to assist with the correct location and timing of new transmission investment

© Transpower 2009


Rental flows without FTRs

Electricity market

Rentals allocation

mechanism (TPM)

Rentals

Those who pay for transmission

Allocation minimises impact on nodal prices

– not paid to energy purchasers

© Transpower 2009


FTR market participants

Rentals

Residual revenue

Post allocation

mechanism

Electricity market participants

FTR Auction mechanism

FTR pre-allocation

mechanism (optional)

Auction revenue

Net revenue

Auctioned FTRs

FTR payments

Cas

h flo

ws

with

FT

Rs

FTR rentals + premiumFTR rentals

Rentals + premium

© Transpower 2009


Design emphasis?

• Merchant new investment?– Network investment governed by Part F of EGRs– Merchant investment in connection assets possible (probable?)– Allocation of FTRs to investors not high priority in short term

• Locational hedging– Reduce reliance on physical hedging– Reduce barriers to new retail entry (increased competition)– Provide means to fully hedge against transmission congestion

• High degree of user influence on design• Start simple and build with experience and need• WHAT DOES THIS MEAN FOR DESIGN?

© Transpower 2009


New Investment

• New investment – Merchant investment no longer the primary mechanism for

transmission upgrades– Allocation of FTRs to investors not high priority in short term

Pre-allocation of FTRs Pre-allocation to investors

No pre-allocation

2009 FTR recommendation

2002 FTR design

© Transpower 2009


Coverage

• Node to node, hubs and nodes, hubs only• Market power?• Start simple

FTR coverage

2002 FTR design

High coverage, Complexity

Low coverage, Simplicity


HVDC only 2 hubs

Large hubs

Small hubs Interconnected grid

Whole grid

© Transpower 2009


Constraints only?

• Losses should be reasonably predictable• Constraints are not predictable• FTRs with losses are complicated and confusing

Losses and constraintsLosses and constraints

2002 FTR design

Constraints only


© Transpower 2009


Revenue adequacy

• Dependent on FTR grid design• Incorrect grid outage assumptions, unplanned outages,

emergencies

FTR Revenue Risk

2002 FTR design

To FTR market participants

To FTR market operator/grid

owner


© Transpower 2009


Revenue adequacy

• PJM, CAISO, MISO– FTR Credits are prorated proportionally

• Payments derated when revenue shortfall occurs• Excess rentals and auction revenue occurring over a month

are transferred to a balancing fund• At end of period balancing fund is used to clear unpaid FTRs

(pro rata)– NYISO

• Revenue shortfall is compensated for by imposing an uplift charge on transmission owners

• Attempts to link transmission maintenance standards with revenue adequacy

© Transpower 2009


FTR Duration

• Any duration required• Start low for accelerated learning• Change with market requirement

FTR duration2002 FTR design Long durationShort duration


Hours Weeks Months Years Decades1 Month

© Transpower 2009


Obligations or options?

• Obligation FTRs can become a cost (obligation FTRs are directional)

• Obligation FTRs still hedge price difference even when –ve• Option FTRs always cash positive BUT lower capacity and

computationally different

OptionsObligations or optionsObligations 2002 FTR design


© Transpower 2009


Post allocation of residual revenue

• Any allocation possible• Change results in value transfers• Simplest approach is to initially make no change

Pre-allocation of FTRs Pre-allocation to investors

No pre-allocation


2002 FTR design

© Transpower 2009


Implementation

• Transpower’s system is “up and running”• Can assist establishing an FTR market quickly if required• Transitional arrangements could see separation of systems from

Transpower

financial transmission rights: design options

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