First Hydro Analysts Conference
July 2005
Introduction
Paul Jenkinson
First Hydro Company
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Key locations:
~ Commercial Office - Bala House
~ Dinorwig pumped storage power station
~ Ffestiniog pumped storage power station
~ Visitor centre
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The only Pumped Storage Power Stations in England and Wales
(representing 75% of Great Britain Pump Storage capacity)
•
Station built initially to support the management of the System
~ now well placed to participate in the competitive market place
•
Full time employees 188
~ reorganisation programme completed - 20% staff reduction delivered
•
Experienced management and operational teams
~ integrated teams across all locations
~ incentives aligned to financial performance
Asset overview
Mike Maudsley
Mike Hickey
Director Production
Director Asset Management
The pumped storage principle
Dinorwig
Dinorwig
The largest pumped storage plant in Western Europe
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Commissioned in 1983
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Total plant capacity 1,728 MW
•
6 reversible pump/turbines:
~ each generating up to 288 MW and pumping at 275 MW
~ capable of achieving full load from stand still in < 2 minutes
~ capable of achieving full load from Spinning in < 20 seconds
•
Cycle Efficiency 74-75%
•
Total water storage capacity ~9 GWh
•
Connection to the National Grid via six 18/400kV 340 MVA transformers
•
Two 3.3kV 2 MW diesel generators provide ‘black start’ capability
Dinorwig
Plant design profile
Dinorwig – inside the mountain
Dinorwig
Shaft base and High Pressure water tunnel
Dinorwig
Water manifold
Dinorwig
Section of plant
Dinorwig
Generator/motor
Dinorwig
Pump/turbine
Ffestiniog
Ffestiniog
First major pumped storage station in the UK
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•
•
•
•
•
•
Commissioned in 1963
Total plant capacity 360 MW
4 units (with separate pump and turbines on the same shaft):
~ each generating up to 90 MW and pumping at 75 MW
~ capable of achieving full load from stand still in < 5 minutes
~ capable of achieving full load from Spinning in < 60 seconds
Cycle efficiency 72-73%
Remotely operated from Dinorwig
Total water storage capacity ~1.4 GWh
Connection to the National Grid via two 16/275kV 190 MVA
transformers
Ffestiniog
Plant design profile
Ffestiniog
Section of plant
Ffestiniog
Stwlan Dam
Plant performance
Dinorwig mode times change (seconds)
Pump
Generate
360 s
90 s
12 s
Spin
Generate
Shutdown
All times are typical
30 s
Spin
Pump
Competitive advantage
Typical start up times (minutes)
90
Typical loading rates (MW/minute)
3000
60
1.5
2.5
Dinorwig Ffestiniog
300
CCGT
(hot)
Coal
(hot)
Dinorwig Ffestiniog
10
10
CCGT
(hot)
Coal
(hot)
First Hydro Company
Reliability and availability
•
Mode changes per annum c.35,000
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Overall mode changes reliability c.99%
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Overall technical availability c. 95%
Plant focus
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Safety first (no compromise)
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Operate and maintain plant to achieve competitive flexibility and
reliability
~ working expertise in Electrical, C&I, Mechanical, Civil and IT
~ experienced, broad based and flexible teams
~ balance of quality in-house maintenance and specialist contract
work
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Close working relationship between Plant and Commercial Teams
~ Shift Trading and plant control room
~ daily and weekly operational strategy
~ long term operational and maintenance programme
Commercial overview
David Alcock, Trading
Kevin Dibble, Marketing
Commercial efficiency
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Buy electricity overnight - pump water to top reservoir
Release water to generate at times of peak price
Marchlyn
Pumping
Import 1 MWh
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•
Generation
Peris
Export ~.75 MWh
Overall cycle efficiency approximately 75%
Additional costs include transmission losses and Balancing System charges
Markets
•
First Hydro operates in three markets
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Has competitive advantage
•
Proportion of revenues from each market changes year on year
Market
Competitive Advantage
Ancillary Services
Frequency response and
fast reserve capabilities
Balancing MechanismPremium dynamics
Trading
Ability to deliver almost any
contract shape and despatch
plant right up to gate closure
Plant Reliability
Maximising asset value
People
• Solid understanding of physical market drivers (real-time and long
term)
• Strong commercial and plant integration
Systems
• Robust trading and despatch systems
• Customised real time information and decision support systems
Processes
• Strong focus on understanding and managing business
opportunities
• Traders discretion on price/product
~ strict risk management limits
~ daily (half-hourly) benchmarking of trading performance
Capacity allocation
•
Capacity/energy
allocated
according to value
2,088 MW
10.5 GWh/day
Ancillary
Services
Balancing
Mechanism
Trading
Ancillary services overview
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Physical services to facilitate system security and power quality
~ wholesale markets operate on half-hourly basis
~ ancillary services enable system balancing on a second-bysecond basis
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Procured by National Grid Company (NGC)
~ GB System Operator
~ NGC obliged to operate the system in an ‘efficient, economic
and co-ordinated’ manner
~ costs managed via a regulated annual incentive scheme
Key ancillary services
Reserve
Forward procurement options
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Standing Reserve (20 mins. notice)
~ annual or seasonal tender
~ hydro, OCGT, demand-side
~ approximately 2000 MW procured
annually
•
Fast Reserve (2 mins. notice)
~ monthly tender, few eligible
providers, small volumes
MW
Short term procurement
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Inherent level of reserve delivered by
the market
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Residual reserve purchased by NGC via
the Balancing Mechanism
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Require ~3500 MW of reserve in total
Source: NGC
Key ancillary services
Frequency response
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NGC manage system frequency in line with statutory obligations (within
1% of 50Hz) and operational requirements
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Dynamic Frequency Response
~ units operate at part-load with output varying in response to
frequency deviations - provides “second-by-second energy
balancing”
~ basic level of capability is mandatory for all generators
- utilised as required, mainly from steam plant
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Static Frequency Response
~ automatically triggered by low frequency events
- pumped storage, demand-side providers have capability
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NGC currently forward contracts for enhanced services through
Balancing Mechanism (BM)
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Deals with residual energy
balancing once traded markets
have closed
Example:
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Generators have sold half-hourly
energy, and scheduled plant to
meet contract position
BM offers
required
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System operator matches
generation to actual demand by
adjusting generation (or demand)
via offers or bids in the BM
Scheduled
energy
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All parties required to bid into the
BM, but due to flexible nature of
assets, FHC is well-placed
Required
Demand
Fast-acting plant in the BM
Morning run-up
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Gas/coal unit synchronisation risk
High rate of change of demand =
greater risk
Plant trip
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Unpredictable events that require
fast-acting plant held in reserve
Evening TV pickups
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Domestic load swings driven by
TV events
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Largely predictable
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NGC able to plan using
combination of fast and slow plant
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System Demand and Fast Response BOAs
(25 May 2005)
Demand
Fast Response BOAs
45 GW
800 MW
700 MW
40 GW
600 MW
500 MW
35 GW
400 MW
300 MW
30 GW
200 MW
100 MW
25 GW
0 MW
20 GW
-100 MW
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Half-hourly Settlement Period
BOAs = Bid-Offer Acceptances
Demand pick-ups
Champions League Final
Source: NGC
BM activity
Champions League Final
2000 MW
1500 MW
Fast
1000 MW
Offers
500 MW
0 MW
-500 MW
-1000 MW
-1500 MW
-2000 MW
-2500 MW
Gas
Coal
Bids
Wholesale markets (trading)
Trading considerations
• Capacity and energy dedicated to ancillary services
• Margin (net of pumping) available in traded markets
• Probability of being used in balancing mechanism
• Reservoir management
Key advantages
• Asset physical ability to deliver any shape close to real time
• Experienced traders in APX/short term markets
• Proprietary live market information and decision support tools
• Systems facilitate trading up to gate closure
Trading process 1
Week ahead position
MW
600
+ve
Sales 400
200
0
-200
-ve
Purchases -400
-600
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Developed over time
through combination of:
~ structured deals with
counterparties
~ standard products
traded OTC
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Broadly balanced position
Generation
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Pumping
Hour
• Handed to shift trading
Example of energy-balanced book
team Friday morning
4,800 MWh pumping; 3,600 MWh generation
Trading process 2
Typical power exchange price shape - winter
£/MWh
Generate
Marginal Cost
Pump
1
3
5
7
9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Half-hourly Settlement Period
Trading
example
Trading process 3
Generation optimisation
MW
600
300 MWh moved from hour 19-20
Net value-added £15,000
400
Buy @
£30/MWh
Sell @
£80/MWh
200
Generation
0
1
2
3
4
5
-200
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour
Pumping
-400
-600
Trading
example
Trading process 4
Pump/generation optimisation
MW
600
Net value-added £6,000
Buy 450 MWh @ £20/MWh
400
200
Generation
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
-200
Hour
Pumping
-400
-600
Sell 600 MWh
@ £25/MWh
Trading
example
Trading process 5
Evolution of final position
Long term trading
Shift trading
Bilateral
Final position
APX
Summary
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Diversity in revenue streams
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Competitive advantage through assets
~ includes people and proprietary systems
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Niche expertise in short term markets and system
services
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The UK’s most dynamic provider of electricity
UK portfolio overview
Steve Riley
First Hydro
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Key addition
~ excellent fit within portfolio
• Unique
asset with competitive
advantage
~ speed of response and reliability
~ positioned to benefit from tightening
reserve margin
• Energy
trading
~ deep market knowledge - benefits
entire portfolio
UK asset portfolio
Name
Rugeley
Deeside
Derwent
First Hydro
Saltend
Total
Saltend
Deeside
First Hydro
Derwent
Rugeley
Country
England
Wales
England
Wales
England
Gross
Capacity
(MW)
1,050
500
214
2,088
1,200
5,052
IPR
Share
(MW)
1,050
500
50
1,462
840
3,902
Fuel
Type
Coal
Gas
Gas
PS
Gas
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5 assets with gross capacity of just over 5 GW
~ IPR net share = 7th largest portfolio in the UK
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Largely merchant capacity
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Good fuel diversity
~gas, coal and pumped storage
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Robust operational and environmental
UK recovery signals
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Tightening reserve margin
~ 2.4 GW nuclear plant (Magnox)
expected to retire before 2010
~ limited new-build anticipated
before 2010
~ 2.6 GW interconnector links to
Netherlands and Norway unlikely
to proceed before 2010
~ renewable growth largely from
intermittent wind power requirement for firm power during
peaks
~ environmental legislation will
restrict 10-12 GW non-FGD
output
Increasing development and
England & Wales Reserve Margin
above Peak Demand (2004-10)
25%
Notional Target Reserve
20%
Forecast
Reserve Margin
15%
Notional New-Entrant Point
10%
5%
2004
2005
2006
2007
2008
2009
2010
Source – National Grid January 2005 Update.
Forecast includes all generation projects under construction and
all planned closures of generation.
Spreads - recent history
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Over the past 12 months, gas prices
have increased on the back of rising oil
price
~ current oil prices remain close to
all time high
20
Coal prices (delivered ARA) have
declined since Jan 05 from ~$80/t to
~$65/t
10
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EU ETS commenced January 05
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CO2 credit prices have increased since
Jan 05
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Baseload power prices increased end
04/early 05 driven by rising gas price
UK Historic Baseload
Gas & Coal Spreads
£/MWh
Coal Spread pre CO2
15
Gas Spread
pre-CO2
5
0
M
J
J
A
2004
S
O
N
D
J
F
M
2005
A
M
UK market - forward view
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Forward spreads indicate recovery
~ gas prices are expected to
decline
~ coal prices expected to remain
steady
As environmental constraints tighten
Rugeley will shift to a more peaking
role
From Jan 2005, cost of emitting CO2
has been treated as an additional
marginal cost:
~ will be offset by NAP allocation
~ market liquidity increasing
~ early clarity on Phase 2
Forward Baseload Gas Spreads,
£/MWh
14
12
Gas Spreads post-CO2, no allocation
Gas Spreads pre-CO2
10
8
6
4
2
0
2005
2006
2007
2008
Forward prices sourced from
Argus
Environment - implications for IPR
Legislation
IPR strategy
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EU Emissions Trading Scheme
commenced Jan 05
~ CO2 credits trading at €20-€23/t
in June 05 for Phase 1
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Large Combustion Plant Directive
(2008)
~ reduces emissions of SOx, NOx
and dust from coal/oil plant
Actively trade emissions to support plant
operations and maximise asset value
~ May 05 allocations imply load factors
of 44% for Rugeley, 55% for
Deeside, 64% for Saltend
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Rugeley
~ final decision, likely December 2005
~ focus on low sulphur coals to
maximise value under LCPD
constraints
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Renewables
~ biomass co-firing at Rugeley
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Targets for renewable generation
~ EU policy to reduce long term
dependence on fossil fuels
~ current HMG target of 10%
generation by 2010 under
pressure
Summary
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Well balanced asset portfolio
~ positioned to benefit from recovering spreads
~ portfolio enhanced with acquisition of Saltend
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First Hydro - key asset
~ excellent fit in UK portfolio
~ particularly in a tightening reserve margin
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Focus on maximising financial returns