For discussion purposes only
Financial Transmission Rights:
Design options
Presentation to Electricity Commission
2 September 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
For discussion purposes only
slide 3
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
For discussion purposes only
slide 4
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
For discussion purposes only
slide 5
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
For discussion purposes only
slide 6
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
For discussion purposes only
slide 7
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
For discussion purposes only
slide 8
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
For discussion purposes only
slide 9
Integrated market design
NEW TRANSMISSION
Centrally planned, regulatory process,
TPM
TRANSMISSION PRICING
Non-distortionary access
charges
TRANSMISSION CONGESTION
FTR, LRA, vertical integration
NEW TRANSMISSION
Location and timing
RISK MANAGEMENT
Hedge against locational price
differences
NEW GENERATION
Location and timing
Bid-based, securityconstrained,
economic dispatch
with nodal prices
NEW INVESTMENT
Market-driven
Co-ordinated spot
market
DEMAND SIDE PARTICIPATION
ENERGY PRICING
Bilateral contracts at nodal
price differences
© Transpower 2009
For discussion purposes only
slide 10
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
For discussion purposes only
slide 11
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
For discussion purposes only
slide 12
Energy contract – example 1
Generator
Offered at $2
300 MW dispatched
Vertically integrated utility generates at
A, commitment of 300 MW at $2 at B
$2
-$600
$600
Retail:
Buys 300MW from A
Gets paid for 300MW at B:
-$600
$600
100 MW
Generation:
Cost to generate at A:
Gets paid at A
Load
300 MW
$2
$2
© Transpower 2009
For discussion purposes only
slide 13
Energy contract – example 2
• Third party load increases at B
Generator 1
Offered at $2
240 MW dispatched
• Line A – B constrained
• Price at B increases to $4
• 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)
$2
Load 1
300 MW
40 MW
• Retailer can’t meet obligation of
300MW at its generation cost of $2 to
load at B ($600)
$4
Load 2
60 MW
$3
Generator 2
Offered at $3
120 MW dispatched
© Transpower 2009
For discussion purposes only
slide 14
From an energy contract perspective
Generator 1
Offered at $2
240 MW dispatched
$2
Load 1
300 MW
40 MW
• 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
$4
Load 2
60 MW
$3
Generator 2
Offered at $3
120 MW dispatched
© Transpower 2009
For discussion purposes only
slide 15
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
For discussion purposes only
slide 16
Energy price hedge values
differ by location and over time
Price / MWh
Nodal price at B
$5
$4
$3
$2
B
Energy price hedge value at B
B
A
Transmission
price risk
A
Energy price hedge value at A
$1
Nodal price at A
Time
© Transpower 2002
© Transpower 2009
For discussion purposes only
slide 17
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
For discussion purposes only
slide 18
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
For discussion purposes only
slide 19
Rental flows without FTRs
Those who pay for
transmission
Rentals
allocation
mechanism
(TPM)
Allocation minimises
impact on nodal prices
– not paid to energy
purchasers
Rentals
Electricity market
© Transpower 2009
For discussion purposes only
slide 20
Cash flows with FTRs
FTR market participants
Auctioned FTRs
Preallocated
FTR Auction
mechanism
FTR payments
FTR preallocation
mechanism
(optional)
Auction
revenue
FTR rentals
+ premium
Post
allocation
mechanism
FTR rentals
Residual
Rentals +revenue
premium
Net revenue
Rentals
Electricity market participants
© Transpower 2009
For discussion purposes only
slide 21
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
For discussion purposes only
slide 22
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
No preallocation
2009 FTR
recommendation
Pre-allocation
to investors
Pre-allocation of FTRs
2002 FTR
design
© Transpower 2009
For discussion purposes only
slide 23
Coverage
• Node to node, hubs and nodes, hubs only
• Market power?
• Start simple
HVDC only
2 hubs
Low coverage,
Simplicity
Large
hubs
Small hubs
Interconnected
grid
Whole grid
High coverage,
Complexity
FTR coverage
2009 FTR
recommendation
2002 FTR
design
© Transpower 2009
For discussion purposes only
slide 24
Constraints only?
• Losses should be reasonably predictable
• Constraints are not predictable
• FTRs with losses are complicated and confusing
Constraints
only
2009 FTR
recommendation
Losses and
constraints
Losses and constraints
2002 FTR
design
© Transpower 2009
For discussion purposes only
slide 25
Revenue adequacy
• Dependent on FTR grid design
• Incorrect grid outage assumptions, unplanned outages,
emergencies
2009 FTR
recommendation
To FTR market
operator/grid
owner
To FTR market
participants
FTR Revenue Risk
2002 FTR
design
© Transpower 2009
For discussion purposes only
slide 26
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
For discussion purposes only
slide 27
Revenue adequacy in PJM
© Transpower 2009
For discussion purposes only
slide 28
FTR Duration
• Any duration required
• Start low for accelerated learning
• Change with market requirement
Hours Weeks
Months
1 Month
Short duration
2002 FTR design
Years
FTR duration
Decades
Long duration
2009 FTR
recommendation
© Transpower 2009
For discussion purposes only
slide 29
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
Obligations
2002 FTR design
Obligations or options
Options
2009 FTR
recommendation
© Transpower 2009
For discussion purposes only
slide 30
Post allocation of residual revenue
• Any allocation possible
• Change results in value transfers
• Simplest approach is to initially make no change
No preallocation
2009 FTR
recommendation
Pre-allocation
to investors
Pre-allocation of FTRs
2002 FTR
design
© Transpower 2009
For discussion purposes only
slide 31
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
© Transpower 2009