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Review of Bulk Energy Storage in
SEM
Gaelectric Energy Storage
T&SC Modification Working Group
6th September 2012
Energy, from Utility to User
Working Group TOR
•
Define “Technical characteristics & capabilities of a CAES unit, and of other units having
similar characteristics ”
•
Proposer: “impacts of registering in the SEM and the Market Rules as currently drafted”
– Whether one or more existing registration options could be amended to allow
registration of a CAES unit (perhaps by changing definitions in the TSC).
•
Examine the current Special Unit clauses to see if they can accommodate such units
•
Identify potential changes to the TSC
•
What are the likely high level impacts (time, cost and resources to implement option)?
•
How the identified option(s) further(s) the objective of the Demand Side Vision and
other SEM
•
Deliver a recommendation to SEM Committee with a drafted modification
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Evaluation Criteria Impacts (TOR)
•
Assess the options in terms of the following questions:
–
The Working Group should consider how the following items, and others that may be
discussed, can be addressed with respect to the option by which registration of CAES Units and
other energy Storage Units in the TSC will occur.
•
–
Offering & Scheduling
–
Commercial Offer data
–
Technical Offer Data
–
Other data provision & sharing
•
Energy Settlement
•
Calculation of Eligible Availability
•
Calculation of Capacity Payments
–
When in generation mode
–
When in pumping mode
•
Calculation of Constraint Payments and Charges
•
Calculation of Uninstructed Imbalance Payments and Charges
•
Credit & Settlement
•
Inclusion in the MSP software and uplift
•
Treatment of Energy Storage Units when under test
Committee policy objectives?
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Policy Objectives
• We also need to agree as a group what a unit registration
in SEM should facilitate for that unit
• While each proposal must understand how it impacts the
list of the TOR evaluation criteria, e.g. Energy Settlement,
these more flow from wider SEM policy
• The policy must be the first high-level port of call when
evaluating options, not the detail
– Although the detail is important and ultimately required
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Our Objectives for this Meeting
• Long-term: a method for registering storage technologies
in the SEM that allows them to recover their short-run
costs and compete equitably within the market schedule
• Today:
– A restatement of SEM Policy, becoming the first set of agreed
evaluation criteria for our discussions
– Evaluation of existing SEM options against those criteria
– Agreement that existing options are not sufficient
– Listing/workshop alternative structures, agreeing next steps
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CAES Overview
Compression
Train
Generation
Train
81MW load
~53 MW minimum
134MW generation
27MW minimum
Well Head
Depth
pmax
pmin
Δp
Storage
Cavern
At stated figures:
• 8 hours running
• 10 hours to fill
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CAES and Other Storage
• CAES running costs comprise:
–
–
–
–
The electrical energy consumed to compress air
Avoidable import UoS when consuming power *
The gas consumed in the running of the generator *
Avoidable O&M *
• We believe what is missing from the T&SC is the ability to
ensure those costs marked * are recoverable
• We believe recovery of such short run energy costs is important
for all storage technologies
• A project needs to evaluate these SEM revenues alongside other DS3
revenues
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SEM Policy Evaluation Criteria
• Apart from the market structures allowing the recovery of
appropriate costs, insofar as possible we should have…
– Market schedule should reflect generator characteristics to lower
constraint costs for consumers
– System operator should have correct data to minimise cost of
production in SO dispatch
– Commercial offer structures should allow transparent compliance
demonstrable to RAs under BCOP
– Market revenues earned by generators are independent of SO
dispatch, based on the context of the COD and TOD
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Insofar as possible…
• Market does not always succeed in getting COD and TOD to
match generator capabilities
– Increasing price quantity pairs for CCGT
– Generator mode and fuel switching
• These are limitations caused by the technical / time feasibility
of solving the MSP software, and therefore not “unduly
discriminatory”
• This does not mean, however, that a “principle of acceptance”
has been established that generators should be OK with
managing unreflective cost structures
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Existing Options and Underlying
Assumptions
• Option 1: “The Split Unit”
– Demand Side Unit plus Energy Limited Generator Unit
– Potentially “negative generator” instead of DSU
• Option 2: Pumped Storage
– With adjusted efficiency to capture running costs
• Our Assumptions
– Generators, “negative generators” and pumped storage demand
subject to full central dispatch
– Demand Side Units subject to demand reduction dispatch from a
nominated schedule
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Option 1: The Split Unit
Demand Side Unit
Energy Limited Generator Unit
Submits Running
Schedule to Market,
COD, TOD
Submits COD and
TOD to Market
Dispatched down by
System Operator
Dispatched by
System Operator
Actual Availability,
Dispatch, Metered
Generation Ex Post
MSQ Calculated,
Constraint Payments
Energy
Limit
Actual Availability,
Dispatch, Metered
Generation Ex Post
MSQ Calculated,
Constraint Payments
Dispatch of the demand side impacts the energy limit of the Generator Unit
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Option 1: The Split Unit Challenges
• Commercial Offer Data
– Both generation and demand have to forecast SMP in making their offer
– DSU must forecast a) low demand price and b) when it occurs in nomination
– Generation offer made up of cost of demand and overall running costs
– Storage has to forecast market prices making BCOP difficult to comply with
• Energy Limit
– Energy limited plant is required to correct energy limits in TOD to minimise cost
of constraints
– Storage is reliant on SO DSU dispatch to determine stored energy
– Generator MSQ revenues are dependent on stored energy
– Revenues are not independent of SO dispatch
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Option 1: The Split Unit Challenges
• Restrictive offering of service
– Unit owner submitting demand profiles
– Demand dispatch down only…
– Offer structure limits capability of machine to reduce cost of
production
A Demand Side Unit service is an overly restrictive
operation of a storage device, and is not supported by
Gaelectric.
(This also includes making the demand not centrally dispatchable via retail
registration in a standard Supplier Unit)
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Option 1: Further Commentary on DSU /
Standard Supplier Unit
• Power purchased like any other demand customer
• This assumes that storage would have the right to
manage its own demand schedule
• When storing, demand has direct impact on generator
availability – implication is generator would be selfdecommitting
• Alternatively, demand is fully dispatchable and outside
of market
• Penal relative to existing precedent of pumped storage
rules; charged demand price
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Option 1: Split Unit with
Negative Generator…
• Will improve offered flexibility to system operator
– But may need to have some form of maximum stored energy
limit to prevent non-technical air compression…
• Issues with BCOP compliance remain
– Any structure that relies on storage submitting a definite price
will not be transparent
• Dependence of revenue on SO dispatch likely to become
more difficult
– SOs may determine based on COD not to store any energy…
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Option 2: Pumped Storage
• Standard pumped storage unit with efficiency increased to
capture running costs
• What does this mean? See some example on next slide…
• Note that efficiency increase needs to assume a relationship
between forecast SMP and the running costs
– Again, this may pose issues with BCOP
– But let’s continue to examine this option to see how it evaluates
against the other criteria
•
•
•
•
Constraint costs
Cost of production
Revenue dispatch independent
Generator recovering revenues
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Option 2: Standard Efficiency (Standard Storage
Technology)
Efficiency = 0.7MWh. 1MWh storage. Running costs to be recovered = €30
SMP = €20/MWh
SMP = €60/MWh
MSQ
Gen
0.7
MWh
Time
1MWh
(one Trading
Day)
Pump
Revenue = -€20 + €42 = €22; Have not recovered the running costs
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Option 2: Adjusted Efficiency (Standard Storage
Technology)
Efficiency at 1.2. We assume that plant due to energy limit is not impacting prices
SMP = €20/MWh
SMP = €60/MWh
MSQ
Gen
1.2
MWh
Time
1MWh
(one Trading
Day)
Pump
Revenue = -€20 + €72 = €52; (IR in previous example plus running costs)
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Option 2: Standard Efficiency (CAES)
Efficiency = 1.3MWh (burning gas for CAES adds to energy release beyond that stored).
1MWh storage. Running costs to be recovered = €30. Lower high price for demonstration.
SMP = €30/MWh
SMP = €40/MWh
MSQ
Gen
1.3
MWh
Time
1MWh
(one Trading
Day)
Pump
Revenue = -€30 + €52 = €22; Have not recovered the running costs with “IR”
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Option 2: Adjusted Efficiency (CAES)
Efficiency at 1.8. We assume that plant due to energy limit is not impacting prices
SMP = €20/MWh
SMP = €40/MWh
MSQ
Gen
1.8
MWh
Time
1MWh
(one Trading
Day)
Pump
Revenue = -€20 + €72 = €52; (IR in previous example plus running costs)
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Option 2: Adjusted Efficiency (CAES)
Flat SEM Price Example…
SMP = €20/MWh
SMP = €20/MWh
MSQ
Gen
1.8
MWh
Time
1MWh
(one Trading
Day)
Pump
Revenue = -€20 + €36 = €16; Market will schedule plant with flat SMP
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Option 2: Pumped Storage Review
• Constraint costs: We are deliberately enshrining technical
inaccuracies into MSQ to manage commercial cost recovery
– MSQ becomes deliberately infeasible to follow in physical dispatch – we
enshrine increased constraint costs to the consumer into the code
– And unfair MSQ pressure on other generators!
• Cost of production: System operators are provided with inaccurate
data to dispatch the system;
– SO requirement to minimise production costs undermined
• SMP revenue is dispatch independent: good!
– But see constraint revenues below…
• Constraint payments: They are not paid to generator
– The lack of constraint payments to pumped storage means that generator is
not guaranteed to recover costs
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Review of Existing Options
• Split Unit:
– Struggles with BCOP compliance
– Revenue not dispatch independent
– Generator not guaranteed to recover its costs (worse with negative
generator)
– Restrictive offer reduces value in reduction of production costs (for DSU)
• Pumped Storage
– BCOP compliance again difficult
– Market revenue dispatch independent: good
– Generator not guaranteed to recover its costs under constraint scenarios
– Enshrining increased constraint costs on consumers
– Makes minimisation of cost of production difficult with non-technically
accurate offers
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Gaelectric Conclusions
• No existing structure is fit for purpose
• Gaelectric believes that potential viable options are:
– “Interconnector Unit” style unit, with
• similar flexibility to manage COD as IU, e.g. participant is allowed
to manage offer to procure “storage”
• similar to IU procuring BETTA energy
– Pumped Storage Unit, with
• explicit commercial costs considered in MSQ schedule
• Constraint payments
• Seek agreement on first statement, and commitment to
work towards development of listed and further
potential options…
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