RTO 101: Session 5 How RTOs Use Markets to Achieve Short-run Reliability and

RTO 101: Session 5
How RTOs Use Markets to Achieve
Short-run Reliability
and
Long-run Resource Adequacy
Prepared by John Chandley
for
PJM and Midwest ISO States
May 2008
Part I
How Much Capacity Do We Need?
Setting the Target and
It’s Impact on Retail Rates
Who Decides the Res. Adequacy Target?
Setting the RA Target drives fixed/capital costs and has
a large impact on rates, as well as affecting quality of
service. These issues are normally thought of as state
responsibilities. However . . .
Under the Energy Policy Act of 2005, Electric Reliability
Organizations, like Reliability First Corporation (RFC)
and Midwest Reliability Organization (MRO), are also
authorized to set the RA target.
EROs thus affect a significant part of the level of retail
rates and indirectly, the reliability of service.
3
Let the Engineers Decide
Traditional “reliability standards” are not economically
based. They are strictly engineering standards based
on historic practices. No one claims they are cost
justified.
A traditional engineering standard for “adequacy” is to
carry enough capacity so that on average, the system
does not run short of capacity – loss of load expectation
-- more than once in 10 years:
 1-day in 10-yr LOLE = reserve margins of about 15%-18%.
4
Let the Economics Decide
An alternative is to allow economics to define the RA
Target.
 The principle is to allow the reliability or reserve target to be
based on what consumers (or states speaking for them) would
be willing to pay for reliability – i.e, to avoid being short of
capacity.
 We’d need a way to figure out what consumers want.
 This could lead to reserve margins more, but probably less than
15%. (that is, consumers might not be willing to pay for 1 day in
10 year LOLE)
5
RA Target Defines the Revenue Requirement
Suppose PJM/MISO accept 1-day in 10-year LOLE . . . e.g., a 15%
- 18% reserve margin (RM) requirement.
Then every state must set retail rates to recover the full revenue
requirements for that level of capacity. Once the RM is set, rates
have to recover about the same total revenues whether we have
markets or regulation (assuming both structures are efficient).
 In regulated states, retail rates must recover the utilities’ full revenue
requirements for building/operating that much capacity to cover their
loads plus the RA target reserve margin. If not, utilities won’t build.
 For market-based investments, wholesale market prices must also
recover full revenue requirements, and retail rates must recover these
same wholesale costs. Otherwise, the investments won’t occur.
6
Part II
The “Missing Money” Problem:
Alternative Ways to Solve It and
Why the Choices Matter
Generators Depend on the Highest-Price Hours
To Recover Most of Their Fixed Costs
$/MWh
Contributions to
Fixed Costs
PShortage
Shortage hours
PPeak
Demand
Supply
offers
Peak hours
PShoulder
POff-peak
Off-peak hours
Shoulder hours
Low-price hours barely cover operating costs
8
A “Missing Money Problem” Arises If the RTO
Does Not Use Shortage-cost Pricing
$/MWh
Lost Contributions
to Fixed Costs
PShortage
PCap
Shortage hours
PPeak
Demand
Supply
offers
Peak hours
PShoulder
POff-peak
Off-peak hours
Shoulder hours
Implicit “caps” on energy prices prevent generators from
receiving a significant contribution to their fixed/capital costs
9
A “Missing Money” Problem Arises In
Shortages If There Is No Shortage Pricing
DPeak
Clearing
Price
“Capped”
Price
The “missing money” = lost
contributions to fixed costs
for every plant
Price set
by
demand
PATH A
Price set
by supply
offer caps
PATH B
Peaker
Intermediate
Base-load
Quantity
The “missing money” problem undermines both long-run
investment and short-run reliable dispatch
10
Path A or Path B?
A key design choice depends on how energy and
operating reserve prices are set. What happens when
the ISO dispatch runs short of plants to supply the total
demand for energy plus operating reserves?
 Path A: Allow scarcity prices to clear the markets for energy and
operating reserves based on demand.
 Path B: Cap the energy prices, but recover the “missing
revenues” from capacity payments and other mechanisms.
PJM, NY, NE chose Path B. MISO is trying Path A.
11
Original ISOs Evolved Into Path B
In the Eastern ISOs, the original “power pools” had an
installed capacity (ICAP) requirement.
 PJM, NYPP, and NEPOOL were shared reserve pools.
The “pool” imposed an ICAP requirement on each
utility-member to cover its own loads + reserve margin
 It supported reserve sharing between the pool members
 It prevented free-riding, which could otherwise occur because
regional dispatch allows “leaning” on others’ resources in real
time. That is, the pool dispatch meets everyone’s load, and
draws from whatever plants are available for dispatch.
12
Features of First Generation ICAP Markets
ISO (or Reliability Authority) sets the required level of capacity.
 Pool region must maintain (e.g.) a 15 % reserve margin
ISO allocates to each LSE its share of capacity requirement.
 Based on LSE’s share at peak, adjusted for retail switching.
ISO conducts an auction market for LSEs/Generators.
 Typically a monthly auction, but could be daily, seasonal, etc.
 Used to buy/sell capacity and set price for “overs” and “unders.”
ISO penalizes LSEs/Generators who fail to meet the rules.
 “Short” LSE must pay deficiency charge each MW it is short.
 Generators that fail to be available pay high penalty.
13
All the First ICAP Markets Failed! Why?
They ignored the underlying incentive problems . . .
 Capped energy prices plus ICAP payments => . . .
• Poor incentives to gencos to be available when needed in RT.
• Poor incentives to provide the right operational features.
• Poor incentives for demand-side response.
Uniform ICAP payments ignored locational differences
 So all ICAP mechanisms are moving to multi-zonal “LICAP.”
And fixed ICAP demand created other problems . . .
 Volatility -- inevitable with fixed capacity requirements.
 Market power -- it’s easy to exercise in earlier capacity markets.
14
ICAP Investment Needed At Right Locations
If there are transmission constraints on delivering power to load
pockets, non-locational ICAP payments cannot allocate the missing
money to the right locations. Instead, uniform ICAP prices result in:
 Not enough investment at the right locations (Boston, SWConn, New
Jersey, Wisconsin, etc.)
 Too much investment at the wrong locations (Maine, Western NY/PA)
The resulting generation cannot sustain reliable operations
because its power can’t all be delivered to loads.
Lesson: If we use ICAP to restore missing money, ICAP payments
need to be locationally different (LICAP) to reflect transmission
limits.
15
Every ICAP Reform Added LICAP Zones
New York ISO: Created three zones with different prices
in each zone.
 New York City, Long Island and “Rest of New York”
New England ISO – earlier LICAP proposal proposed
five fixed LICAP zones.
 In 2006 settlement, ISO will define zones before each auction.
PJM RPM Settlement – starts with 4 LICAP zones and
expands number in 3 years up to 23 zones.
 Eastern MACC, SW MACC, AP & MACC, Rest of PJM
16
RPM May Have Multiple Deliverability Areas
MAAC
Western MAAC
PJM West
Eastern
MAAC
Southwestern
MAAC
AP
PJM South
Initial Proposal
Transition
ComEd
PSEG North
RE
JCPL
PPL
PENELEC
PSEG
DQE
PECO
Dayton
ME
AE
BGE
AP
DPL
Dominion
AEP
DPL South
17
Can LICAP Designs Improve Efficiency?
Locational ICAP (LICAP) can lessen the problems with
non-locational ICAP, but there is a tradeoff.
With many interconnected zones, it is not obvious how
one allocates deliverability rights to constrained
transmission. Transfer capacity is not a fixed number.
PJM’s RPM with many LICAP zones may confront this
problem, and there may not be an efficient solution.
Any large RTO may need many LICAP zones if it
follows Path B.
18
Price Volatility in Earlier ICAP Markets
Original ICAP markets could skip between very low
(near zero) prices and very high prices at deficiency.




ICAP Price
When there is a surplus, the
capacity price tends to be
very low, or near zero.
PCap
When there is a slight
shortage of capacity, the
price rises to the deficiency
charge (Pcap) – a price cap.
The more vertical the supply/
demand curves, the more
price volatility occurs.
P
Investment risks are high.
S
D
Quantity
19
Market Power Incentives in ICAP Markets
The combination of a vertical demand curve and a near-vertical
supply curve presents strong incentives to exercise market power.
Price

Any withheld supply shifts the
Supply curve to the left.
S
Pcap

A slight shift of the supply curve
to the left causes a large
increase in price.

This can easily offset the
revenues foregone as a result of P
withholding.
D
Quantity
20
Two Approaches To Lessen Market Power
Use a downward-sloping curve for ICAP demand.
 A sloping demand curve reduces the incentives for market power.
 Recognizes that capacity beyond the “target” has value.
 Recognizes that capacity is more valuable when short.
Use a forward auction (extend the supply curve).
 Define “product” to be delivered 3-4 years from now.
 New entrants can compete with existing resources.
 May facilitate competition with transmission?
21
NY ISO ICAP Demand Curve
ICAP Price
Price
Ceiling
Net Cost of
Entry
Minimum
ZeroNYCA
Crossing
Requirement Point
ICAP Quantity
22
Proposed ISO-NE Demand Curve
(Not included in Settlement)
23
PJM Initial Demand Curve for
Variable Resource Requirement
Note: The settlement did not adopt this curve.
24
PJM Final Demand Curve for
Variable Resource Requirement
Final Shape
(not to scale)
25
Why the Demand Curves Matter
Changing the demand curve changes investment and
risks.
No matter what, the implicit or explicit demand curve for
energy and reserves (or capacity) will drive the level of
investment.
 Moving the curve down and/or left => less investment
 Moving the curve up and/or right => more investment
If the demand curves don’t reflect the investment
requirements, they can’t achieve the RA goal.
26
Market Power Solution II: Change the
Supply Curve
A joint PJM-NY-NE study developed the concept of
holding the ICAP auctions 3-4 years in advance.
 If the ICAP “product” does not have to be delivered for 3-4 years,
then new entrants could compete against existing plants.
New entry/competition would limit the ability of existing
plants to exercise market power, such as by withholding
capacity from monthly auctions.
PJM’s RPM and ISO-NE’s Settlement use this forward
auction approach.
27
Proposed Timing of RPM Auctions
3 Years
23 months
13 months
4 months
June
Self- Supply
& Bilateral
Designation
EFORd
Fixed
Planning
Year
ILR
Base
Residual
Auction
Incremental
Auction
Incremental
Auction
Incremental
Auction
Ongoing Bilateral Market – (shorter-term reconfiguration)
Source: PJM
28
Recent Results in PJM Capacity Auctions
PJM first held auctions for the 2007-08, 2008-09, and
2009-10 years.
PJM is still in “surplus” for most regions, which means
the clearing prices are often below the “break-even”
points to support new investments.
 Since little new capacity can be offered from this year to next, the
surplus will diminish, and prices gradually rise above the breakeven point where new investments would make sense.
 And PJM recently filed to raise the Net CONE – higher prices
A downward sloping curve yields higher LICAP prices
than would have occurred with a vertical curve when
there is a surplus . . .but about the same prices on
average over time.
29
Availability Incentives: How Should We
Measure and Reward Availability?
In the past, ICAP availability has been measured by EFORd
 What was your unit’s average availability during the last 12 months,
given its various outages as measured by EFORd?
In the LICAP case, ISO-NE proposed to use availability during
operating reserve “shortage hours” to replace EFORd
 Was your unit available during an hour in which the operating reserves
fell below the normal requirement for OR?
 “Available” means producing energy or providing operating reserves.
 If you weren’t running or available for reserves during the shortage hour,
you won’t be paid for that hour. (But the non-payment “penalty” may be
spread out over time by reducing future monthly payments.)
30
Issues with UCAP and EFORd Adjustments
There are concerns about continued use of EFORd as
an effective measure of availability.
EFORd is based on self reporting – can we trust this?
 The capacity that a supplier can sell is defined by UCAP.
 UCAP is ICAP adjusted by EFORd -- by outage hours. Do
Sellers have an incentive to under-report outage hours?
EFORd is an average measure.
 It ignores the fact that the value of availability is higher at some
times than at others. Is a 10% outage rate good or bad?
• Outages during non-peak periods mean little
• Outages during peak demand hours mean a lot
31
Using “Shortage-Hours” to Replace EFORd
Is Defining “Capacity” To Be Like “Energy”
To be “available” during a “shortage hour,” a unit must:
 Be operating – producing energy in real time, or
 Be scheduled or eligible to provide operating reserve
•
Capacity that is capable of starting within 30 minutes could be eligible,
because it could be used as 30 minute reserves.
This metric encourages plants to be available when most needed,
and to be the kinds of plants that are quick-start and flexible.
 If you’re not “available” you don’t get paid
 An energy+OR+scarcity pricing market would work the same way
The “capacity” payment becomes a payment for “energy or
operating reserves,” paid for the hours in which the energy or
reserves are most valuable but prices would likely be capped.
 Pays the revenues missing in shortage hours because of price/bid caps
 Provides the availability incentives missing during those same hours
32
Part III
Solving the Missing Money Problem
With
Shortage-cost Pricing
(So-called “Energy-only” Market
But it’s really energy plus operating reserves)
Revisit the Strategic Decision:
Avoid Missing Money With Shortage Pricing
DPeak
Uncapped
Clearing
Price
Path A
The “missing money” = lost
contributions to fixed costs
Price Cap
Path B
plus
ICAP
Base-load plants
Quantity
Path A = Energy and Op. Reserve Market with Shortage Prices
Path B = Capped Energy Market with (L)ICAP, curves, RPM.34
What the Midwest ISO Is Proposing
Regionalize procurement of operating reserves (OR)
Create bid-based markets to procure OR
Co-optimize procurement of OR and energy  pick the least cost mix
Apply shortage-cost pricing to energy and OR (PATH A).
 When supplies are short, prices can be set by demand – the willingness
of consumers to pay -- not merely by the offers/bids of generators.
 And energy prices are affected by the level of operating reserves. If the
ISO falls short of operating reserves, jeopardizing reliable dispatch,
energy prices would rise to reflect that shortage.
35
Shortage Cost Pricing Approach
(Illustrative)
Shortage Cost
in $/MWh
Demand Curve for
Operating Reserves
VOLL
$1000
$500
$0
Rotating
blackout
warning
Available Supply in MW
Note: Actual ISO methods may use
separate curves for each type of reserves,
and simple steps for the “curve”
Reserve
shortage
warning
0-1% 3% 5%
X% Target
% of Operating Reserves
Above Demand
36
Reminders: Limited Spot Price Exposure
Retail customers have little or no exposure to volatile spot prices.
Only those who choose to rely on spot prices are exposed.
In regulated states (no retail choice) . . .
 If a utility covers full load requirement, retail customers are not exposed.
 If utility purchases any energy from ISO spot market, it pays spot prices
only for that amount; but retail customers are hedged by fixed rates.
In states with retail choice . . .
 Largest customers might face hourly spot prices, but they can be
hedged through contracts, own generation (self supply), demand
response, to the degree they choose. Several states already doing this.
 For smaller customers: Regulators would ensure utility or competitive
LSEs hedge default customers with longer-term contracts. (e.g., New
Jersey/Illinois default supply model)
37
Market Power Mitigation Still Applies
In an energy plus operating reserve market with scarcity
pricing, market power mitigation would still apply.
 Offer caps would still apply to prevent price gouging bids, just as
they do today.
• Unit-specific conduct and impact tests still apply
• $1000/MWh overall cap still applies.
 Must offer rules would prevent physical withholding, just as they
do today.
Shortage cost pricing does NOT mean removal of
market power mitigation. It’s all still used.
38
How the PJM and MISO
Models Could Merge
39
Market Revenues for Generators
Come From Four ISO sources
Energy market
 Primary source of revenues for most generators
 But price caps limit revenues from this source
Operating reserve markets
 Supplemental source of revenues
 Extent depends on scarcity pricing
Capacity market
 Needed if energy and OR markets not enough to support RA target (the
“missing money” problem)
Local reliability-must-run (RMR) contracts in load pockets
 Needed to cover local/other costs not covered by Energy, OR and (if
any) Capacity markets.
 These RMR contracts tend to be based on cost-of-service principles.
40
Different Models Determine
Where Generators Get Their $$$ . . . But
Total Revenue Requirements Are The Same
“RMR”
Operating
Reserve
Energy
MISO
Proposed
Cost of Service
Monthly
payments unless
tied to shortages
Payments
depend on
availability for
real-time
dispatch
RMR
LICAP
RMR
LICAP
helps
lower
local
RMR
ICAP
Operating
Reserve
Operating
Reserve
Energy
Energy
LICAP
PJM/NE/NY
ICAP
Earlier ISOs
41
Difference Between
ICAP and LICAP Approaches
Compare the ICAP and LICAP columns in that slide.
 A locational ICAP approach tends to reallocate the source of
revenues from non-market payments (RMR-type, cost-of-service
contracts) to “market” payments for capacity.
• Mostly, this is money paid to generators in transmission-constrained
load pockets. That’s where most RMR units are.
• Higher locational ICAP (LICAP) payments in load pockets help
substitute for RMR contracts in those load pockets.
 The total revenue requirement for all generators combined stays
about the same for the same level of capacity.
42
Different Models Cost About the Same
First, the total revenue requirements are about the
same for all three approaches, for a given RA target.
 It means aggregate retail rates should be about the same.
Conversely, for the same level of revenues, all three
approaches achieve about the same level of RA.
 That’s because, if total revenues are about the same, the total
dollars available for investment is also about the same.
 (The mix of investments may be a little different, because
investment incentives depend partly on where the revenues
come from – i.e., what are we rewarding? Reliable energy
producers? Or just countable capacity?)
Bottom line: different models change the source of
where generators get their revenues, but not the total.
43
Should We Care About Revenue Source?
Better short run price signals improve reliability.
 If generators get most of their revenues from providing energy
and operating reserves in real time, they have strong incentives
to make their plants available for real-time dispatch and OR.
They’ll make investment in features that improve availability.
 If generators get a large portion of their revenues from monthly
capacity payments, whether or not they show up in RT, they have
weaker incentives to make their plants available when and where
most needed. They’ll invest less in reliable operations.
 Recent capacity market rules try to solve this problem by making
capacity payments conditional on plants being bid in the DAM
and being available for energy/OR during OR shortages.
44
Reserve Margin Target Is Set by ERO
It Determines Total $$$ We Pay
15-17% Reserves
12-14% Reserves
RMR
RMR
Operating
Reserve
LICAP
Energy
About
the
Same
total
costs
Operating
Reserve
Energy
MISO
LICAP
RMR
A 3 Percent
Difference
costs about
$1+ billions
for a
100,000 MW
system
Same load =
Almost same
Operating
cost
LICAP
Operating
Reserve
Energy
LICAP 45
Factors Leading To Common Approach
Regional reliability organizations covering PJM and
MISO support a common RA criterion:
• 1-day in 10 year LOLE => 15-18 % Reserve Margin
It may not be practical for MISO to reach 15-18 % RM
using only energy and OR markets with scarcity pricing.
 To get the extra few %, MISO may need to make capacity
payments to cover the revenue requirements of the extra MW.
Meanwhile, PJM is improving its OR markets and
believes in shortage-cost pricing.
 If it implements better OR and shortage-cost pricing, more
revenues will come from energy and OR markets, and less from
capacity payments.
Because any approach must solve the same problems,
there is a likely convergence (next slide).
46
If All ISOs Must Meet Higher Reserves
Then MISO and PJM May Converge
15-18% RM Mandated by ERO
12-14% RM
RMR
Operating
Reserve
RMR
LICAP
MISO can
add
LICAP to
pay for
higher RM
RMR
Operating
Reserve
PJM
LICAP $$
get
smaller
as . . .
LICAP
Operating
Reserve
Energy
MISO
Improved
energy
and OR
pricing
supports
dispatch
Energy
Convergence?
. . . PJM
improves
energy
and OR
shortage
pricing
Energy
47
PJM w/LICAP
Path C: “Belts and Suspenders” Model
Combine both scarcity pricing (Path A) and some ICAP approach
(Path B), at least for a transition period:
 Get the spot market prices right – solves most of the problem.
• Apply shortage-cost pricing in the real-time and DA markets.
• Co-optimze energy and operating reserve markets.
• Energy prices rise when ISO is short of operating reserves.
• Use regulatory means to ensure default loads are hedged.
 Use ICAP model to reach any non-economic reserve target.
• Spot price supports “economic” but not “engineering” RA.
• Use either short-run (NY) or forward (PJM) ICAP markets.
• Sloped Demand curves are okay. (NY and PJM)
• Contract hedges/options are fine. (NE)
• ICAP payments are net of energy/OR profits. (All ISOs)
48
Extra Slides
49
Why Explicit Demand Curves Are Needed
If spot prices during shortages can be set by the
demand curves, then the ISO must have an
explicit demand curve for setting prices.
But consumers cannot yet define these demand
curves. The ISO must define the curves.
 Some customers can tell us their preferences.
 But most (non-responsive) demand can’t.
50
Energy Demand Curve Components
Price responsive
demand
Average VOLL
Non-responsive
demand
Price-responsive demand
includes:
Price responsive
demand
(dispatchable)
• Dispatchable loads
• Loads with interruptible rates
• Utility sponsored DSM
• LSE-based demand-response
Demand curve with no
responsive demand
• Customers responding
(where they face spot prices)
Quantity
Price responsive loads (or their states, utilities,
LSEs) decide what price they are willing to pay.
51
Some Portion of Demand Cannot Easily
Respond to Price
Price responsive
demand
Average VOLL
Non-responsive
demand
Non-responsive demand
cannot respond to prices
because:
Price responsive
demand
(dispatchable)
• No interval metering
• Don’t face spot prices
• Bundled rates
Someone must speak for
them
Quantity
Some entity (states? ISO?) can estimate what price
these customers would be willing to pay
52
Meaning of Average VOLL
(Value of Lost Load)
Price responsive
demand
Average VOLL
Non-responsive
demand
Price responsive
demand
(dispatchable)
Average VOLL =
The average price for energy at
which non-responsive loads
would be indifferent to being
served or curtailed, if they had
the means to express their
wishes.
Quantity
VOLL applies only when ISO can’t meet minimum
operating reserve without rotating blackouts.
53
The ISO Must Specify a Demand Curve for
Operating Reserves
Operating reserve requirements are essentially
engineering standards – not economic demands.
 We need enough to cover loss of largest contingency.
 We need X MW of 10-minute reserves and 30-minute reserves.
 A percent must be “spinning” (synchonized to grid).
To implement shortage-cost pricing, ISO must translate
these engineering standards into a set of demand
curves for operating reserves that relates quantity to
price.
54
Composite Demand Curve for OR
Min OR
Curve’s
slope
reflects
value of
reserve
shortages
Average VOLL
Min OR = the lowest
level of operating
reserves the ISO will
tolerate before starting
rotating outages to
prevent uncontrolled
blackouts
Target level of
operating reserves
Quantity
Every ISO/SO has a curve. It’s not explicit or transparent.
Proposal: make it transparent and allow it to affect prices.
55
Pricing of Energy and Operating Reserves in
a Market With Shortage-cost Pricing
In a market that recognizes shortage costs, energy
prices are set by supply and demand for both energy
and operating reserves.
If we have enough supply to meet all energy and
operating reserve requirements, the prices remain
moderate.
If we start to run short of operating reserves, energy
(and reserve) prices start to move up.
*Note: the following slides are overly simplified, to
illustrate the concept that operating reserve shortages
can affect energy spot prices.
56
Prices With Ample Supplies
These Apply Most of the Time
Minimum OR
Average VOLL
Clearing Price
Supply offers
Quantity
There is ample supply to meet demand for energy and
operating reserves at low prices.
57
Prices With Tighter Supplies
These Apply On Rare Occasions
Minimum OR
Average VOLL
Clearing Price
Supply offers
Quantity
With ISO unable to meet OR target at lower prices, prices
rise. Some price-responsive load may reduce demand.
58
Prices During Severe Shortages With Some
Curtailments – Extremely Rare
Curtailment needed to
maintain Minimum OR
Clearing price
equals
Average VOLL
Supply offers
Quantity
Unable to maintain minimum operating reserve without
curtailment, ISO curtails enough non-responsive demand
to maintain min. OR. Price rises to average VOLL.
59
Do Energy+OR Designs Help Efficiency?
An energy-plus-OR market design with scarcity pricing
could improve both operational and investment
efficiency. We can get better reliability at lower costs.
Operational efficiency: The real-time prices
provide strong incentives for generators and demandside responses to be available when most needed.
Investment efficiency: The energy and operating
reserve prices are much more precise with respect to:
 Where to build (without the LICAP deliverability problems)
 What types of plants to build (flexible operational features)
60
What Does Adjusting VOLL Do for RA?
The price used for average VOLL will allow a level of
market revenues that corresponds to an “economic”
level of investment. Adjusting VOLL affects investment
and resulting reserve levels.
If the level of average VOLL is set lower, the level of
investment will be lower.
 It will support lower planning reserve margins.
If the level of average VOLL is set higher, the level of
investment will be higher.
 It will support higher planning reserve margins.
61
Adjusting VOLL to Achieve Adequacy
Admin-set
Average VOLL
Price responsive
demand
Non-responsive
demand
Average VOLL
Price responsive
demand
(dispatchable)
The ISO could raise the
“average VOLL” in order to
support investments in higher
reserve margins.
With this higher demand curve,
spot prices would be higher
during reserve shortages.
Quantity
The level of planning reserves supported by prices
is affected by how high/low ISO sets average VOLL
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Adjusting Average VOLL
Adjusting average VOLL is analogous to adjusting the demand
curve for capacity, as in NYISO, NE LICAP and PJM RPM
proposals. But there’s an important difference:
 Adjusting average VOLL affects energy and operating reserve
prices, and the prices directly support reliable dispatch. But they
also affect investment. So pricing for short-run reliability and
long-run resource adequacy are consistent and mutually
supportive.
 Adjusting a demand curve for capacity affects capacity
payments, and these have little/no effect on reliable dispatch.
Additional rules/incentives/penalties must be added to ensure:
• Capacity available when needed (e.g., during shortages).
• Capacity available where needed (reflect transmission limits).
• Capacity available is the right type (load following, quick start,
ramping). These problems are the hardest aspect of ICAP.
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More Market Power Mitigation: NE
Proposed to Set Prices by Demand
Curve and Counting All Supply
P
Total ICAP
This proposal was left out of Settlement
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Why Setting RA Target Is Important
If we adopt a “1-day in 10-year LOLE” reliability
standard . . . that sets the resource adequacy target. It
tells us how much capacity we have to build and pay
for.
There are dozens of issues in designing markets for
resource adequacy. However . . .
No other decision about RA approaches, such as
whether to have an RPM, LICAP, monthly or forward
auctions, shape of demand curves, etc., will have as
large an impact on the level of retail rates.
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RA Target Has Major Impact on Rates
In both cost-of-service and market regimes . . .
The fixed/capital cost of generation is driven largely by
the resource adequacy target. For a system with
100,000 MW peak demand . . .
 A 12% reserve margin requires 112,000 MW of capacity.
 A 15% reserve margin requires 115,000 MW of capacity.
 The 3,000 MW difference may cost an additional $ billion or so.
 Note that in both cases, the operating costs are about the same,
because the demand for energy/dispatch is about the same.
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