RTO 101: What RTOs Do and Why
Session 1 - System Operations
Session 2 - RTO Spot Markets
Prepared by John D. Chandley
for
PJM and Midwest ISO States
May 2008
Topics for This Meeting
Session 1: Understanding System Operations
•
•
•
•
System operations, dispatch and reliability
Many control areas but one grid
How RTO dispatch replaces local dispatches to improve reliability
How the RTO dispatch automatically creates a spot market
Session 2: Advanced RTO Spot Markets
• Inter-RTO coordination and Joint/Common Markets
• Day-ahead and real-time markets – two-settlement systems
• How RTOs support DR, contracting, renewables, climate issues
• EXTRA: How RTOs meet FERC’s open access requirements
2
Topics for This Meeting (cont.)
Session 3: Locational Marginal Pricing
• Why LMP and not something else?
• LMP example and observations
Session 4: Financial Transmission Rights
• How FTRs work
• How FTRs are allocated
• Are there enough FTRs?
Session 5: Resource Adequacy in an RTO Framework
•
•
•
•
•
The “missing money” problem
Path B: Capacity payment approaches to the problem
Issues with earlier capacity approaches
Reform approaches in NY, NE, and PJM’s RPM
Path A: Can MISO avoid a capacity market? Convergence?
3
Understanding System Operations
4
A Utility Is Commonly Thought of as Having
Three Major Operational Functions:
Generation . . .
Transmission . . .
Distribution . . .
But there is another function – SYSTEM OPERATIONS
5
ISOs and Most Utilities Have a Control
Room for System Operations
(This is MISO’s; PJM & large utilities have them)
6
System Operators Work in Local Dispatch
Centers That Manage “Control Areas”
A control area may cover one utility grid/service area, or two or
more interconnected grids. An RTO may cover a broad region.
• There are over 140 control areas in the United States alone.
• Each control area manages only a piece of an interconnection.
In fact, there are only three very large “interconnections.”
• Dozens of separately owned grids/control areas are interconnected.
• And energy flows travel throughout each interconnection along all
possible paths – the laws of physics dictate this.
• Each interconnection functions like one huge electrical machine.
7
8
Essential Reliability Functions Center Around
Each System Operator’s Dispatch
Maintain Voltage
and Frequency
TLR
Coordinate
Inter-utility
Flows w/Others
Grid Operating
Instructions
Monitor Flows, Limits
& Contingencies
SecurityConstrained
Economic
Dispatch
& Regulation
Real-Time
Balancing
Congestion
Redispatch
(internal only?)
Manage Operating
Reserves
Keep Flows
Within Limits
9
A System Operator’s Dispatch Matches
Supply and Demand Every Second
• Dispatchers instruct generators how much to
generate at each location in each dispatch
interval (usually every 5 minutes).
•There’s virtually no “storage” in electricity, so
=
electricity must be generated as it is consumed.
•Automated “regulation” fine tunes output in
seconds to balance supply/demand at all times.
•Energy dispatch keeps frequency at 60Hz
+
Losses
•Reactive power dispatch keeps voltage stable
•These and other actions keep the lights on
Demand
Total MW
=
Supply
Total MW
10
The System Operator’s Dispatch Also Tries
to Meet Demand At Lowest Cost
$/MWh
• Operators try to dispatch economically.
$50
UNCONSTRAINED MERIT ORDER DISPATCH
80
System
Load
$40
60
East
Gas
40
$35
Must
run?
20
West
Nuke
East
Coal
South
Gen
West
Gas
$30
0
0
100
200
300
400
500
$20
Capacity (MW)
11
Security-Constrained Economic Dispatch:
Congestion Requires Operators to Dispatch Out of Merit Order
to Avoid Overloading Transmission.
$60
“Redispatch” is Needed, but It Raises Costs
Demand
$50
Constrained-On Unit
Unconstrained
Merit Order
Marginal Cost
Or
Clearing Price
$40
Least cost
Redispatch
$30
Q
O
Constrained-Off
Unit
$20
M
K
I
J
H
$10
E
A
$0
L
N
P
Units H & N
are the most
cost-effective
to constrain
off and on to
relieve the
constraint
B
C
F
G
D
12
RTOs Are Regional Open Power Pools
Power pools solve important reliability and network coordination
problems that cannot be ignored. Pools were inevitable.
 PJM, ISO-New England and NY ISO started as power pools
 California ISO is a power pool for the three large private utilities
 ERCOT is a power pool for most of Texas’ utilities
 MISO is a new power pool for many utilities in the Midwest.
 Large non-RTO utilities created closed pools (Southern, Entergy)
How these pools operate explains the basic structure of wholesale
electricity markets.
13
An RTO Uses a Regional Dispatch To
Replace Local Control Area Dispatches
RTO
Functions
TLR
Original Control
Area A
Coordinate
Flows
Control Grid
Operations
Monitor
Grid
TLR
Original Control
Area D
Maintain Voltage
and Frequency
Regional
SecurityConstrained
Economic
Dispatch
Manage
Reserves
Original Control
Area B
Coordinate
with other
RTOs
Real-Time
Balancing
Manage
Congestion
Keep Flows
W/in Limits
Original Control
Area C
14
RTO Open Power Pools Create Spot Markets
Once you create a dispatch power pool, and open it to everyone, it
automatically creates a spot market.
 Quantity/price offers/bids determine who gets dispatched.
 ISO-Pool has to pay generators/sellers for the energy they inject.
 ISO-Pool has to charge loads/buyers for energy they withdraw.
 ISO-pool has to charge/pay everyone for their imbalances.
 ISO must charge/pay for redispatch to relieve congestion.
A spot market and spot prices flow directly from the dispatch.
15
RTOs with Standard Core Features
Enhance Grid Reliability – And Create Spot Markets
Market Inputs
RTO
Functions
Market Support
Ensure Reliability
Generator Offers
$/MWh at A
Reserves
Cover
Imbalances
Co-Optimized
Load Bids
$/MWh at B
Bilateral
Schedules
e.g., A to B
Self Schedules
In at A, out at B,
C to D, etc
$$$
Regional
SecurityConstrained
Economic
Dispatch
Calculate
Dispatch
Prices
(LMP)
Use LMPs for
Settlements
Reliably Serve
All Loads
Real-Time
Balancing
Congestion
Redispatch
(In lieu of TLR)
Allocate Firm
TX Rights
Buy and Sell
Spot Energy
Transmission
Usage Charge
Pay (LMPB - LMPA)
Financially
Firm Rights
Receive (LMPB - LMPA)
$$$
16
Reliability and Spot Markets Are Linked
An open spot market arises naturally from . . .
 The reliability necessity of a security-constrained dispatch
 The desirability of having an economic (“least-cost”) dispatch
 The commercial necessity of paying/charging all parties that use the
dispatch at market prices
Reliability is supported by spot market prices linked to dispatch.
 Prices consistent with the dispatch and offers/bids encourage parties to
follow dispatch instructions and use the grid efficiently.
 If prices are inconsistent with dispatch, reliability can suffer.
• (e.g., early PJM, California, etc)
17
The Energy Spot Markets Are “Voluntary”
No one is forced to buy energy from the RTO spot
markets or sell energy into the spot market
• Any LSE/utility can self-schedule its own generation to its own
loads – load is served at the LSE/utility’s generation costs
• Any entity can arrange pt-to-pt contracts to serve its loads –
load is served at the price of the bilateral contract
But parties that use the dispatch/spot market must
accept its settlements
• Parties that have imbalances/deviations settle at spot prices
• Parties that buy/sell “extra” energy through the dispatch also
settle at spot prices.
18
Session 2. Common Features of
RTO Spot Markets
• Day-ahead and real-time markets
•Inter-RTO Coordination and Joint Market
•How RTOs support policy options
19
RTO May Operate Multiple Spot Markets
There is always a “real-time” spot (balancing) market
• The Real-time market flows from the real-time dispatch
But US RTOs use the same approach to create a dayahead spot market
• Day ahead, the RTO accepts schedules, offers and bids. It
arranges a day-ahead security-constrained economic dispatch
• The RTO then prices the dispatch to define day-ahead LMP
prices for spot energy and day-ahead usage charges
20
Day-Ahead Market for Day-Ahead Trades
Sets Up Real-time Reliability and Dispatch
DA Inputs
RTO DA
Functions
Generator Offers
Commitment
DA Outcomes
Enough Capacity
Committed to
Meet RT Loads
Co-Optimized
Load Bids and
Forecasts
Self Schedules
(and virtuals)
Imports and
Exports
Reserves
Co-Optimized
DA Regional
SecurityConstrained
Economic
Dispatch
Day-Ahead
Schedules
Calculate
DA
LMPs
MW * (LMPB - LMPA)
(Later)
Bilateral data
(Financial)
Cash Out
FTRs
$$$
1st Settlement at
DA LMP Prices
Pay Usage for
DA Schedules
MW * (LMPB - LMPA)
Buy and Sell
Energy DA
(at DA LMPs)
21
PJM/MISO Use A “2-Settlement” System
A party that schedules (or buys/sells) in the Day-ahead (DA) market
is in the 1st settlement:
• Energy spot sales and purchases at DA spot prices = LMPDA
• Pays for spot transmission at DA transmission usage prices
– Usage charge = MW times (LMPsink – LMPsource)
– FTR Credit = MWFTRs times (LMPFTR Sink – LMPFTR Source)
– So . . . If FTRs match the actual schedule, the FTR credits
effectively “hedge” (offset) the transmission usage charge.
A party that deviates from its day-ahead schedules in real time is in
the 2nd Settlement:
• Settles the deviations at the real-time spot prices = LMPRT
22
Real-Time Market = Real-Time Dispatch
Deviations From DA Settled at Real Time Prices
Inputs
RTO RT
Functions
Outcomes
Reserves
Reliably Serve
All Loads
Generator Offers
Co-Optimized
Load Bids
Self Schedules
RT Regional
SecurityConstrained
Economic
Dispatch
Hour-ahead
Import/Export
2nd
Bilateral data
(Financial)
Settle DA v RT
Deviations
Calculate
RT
LMPs
Day-Ahead
Schedules
(Later)
Real-time
Schedules
Settlement at
RT LMP Prices
(at RT LMPs)
$$$
$
Uplift
Pay Usage for
RT Schedules
MW * (LMPB - LMPA)
Buy and Sell
Energy RT
(at RT LMPs)
23
Interim Coordination Between RTOs Can
Partly Reconfigure RTO Boundaries
MISO
PJM
(1) MISO/PJM coordinate flows between them
(2) PJM responsible for redispatch for some MISO transmission
limits affected more by PJM generation and flows
(3) MISO responsible for redispatch for some PJM Tx limits . . .
(4) Substitutes more efficient inter-regional redispatch for TLRs
24
Future Coordination Between RTO Markets
Can Create Joint/Common Market
MISO
PJM
(1) MISO & PJM exchange data on constraints, bids, LMP prices
(2) MISO & PJM readjust their respective dispatches
(3) MISO & PJM exchange data again, etc.
(4) Iterations lead to optimized inter-regional dispatch and prices
(5) Forms basis for joint/common market = one unified dispatch
25
How RTOs Accommodate
• Traditional Utility Service
• Merchant Generation
• Wind/Renewables
•Demand Response
• Retail Choice
•Carbon Reduction Policies
26
RTOs with These Core Features Support
Reliability, Renewables, DR and Contracts
Market Inputs
RTO
Functions
Market Support
Ensure Reliability
Generator Offers
Reserves
Cover
Imbalances
Co-Optimized
Load Bids
Bilateral
Schedules
Self Schedules
$$$
Regional
SecurityConstrained
Economic
Dispatch
Calculate
Dispatch
Prices
(LMP)
Settlements at
Spot Prices
Reliably Serve
All Loads
Real-Time
Balancing
Congestion
Redispatch
(In lieu of TLR)
Allocate &
Auction FTRs
$$$
Buy and Sell
Spot Energy
Transmission
Usage Charge
(LMPB - LMPA)
Financially
Firm Tx
(LMPB - LMPA)
Efficient
Price signals
27
The RTO Structure Readily Accommodates
Many Public Policy Options - Ownership
Traditional utility-owned generation
• Any State with traditional cost-of-service regulation can continue
within the RTO’s regional dispatch.
• Regulated utility can self-schedule it’s own plants to meet its own
loads. If they have outages, they use spot purchases as backup.
• Utilities free to purchase extra power if needed from spot market, or
to sell surplus power to spot market (same as “economy sales”).
• Retail rates remain under state regulation = cost of service.
Independent power generation
• Merchant plants can contract with utilities and schedule with the ISO.
• Or they can offer power to the ISO dispatch and sell at spot price.
• Generators can cover their imbalances by buying from or selling to
spot market.
• Doesn’t change state jurisdiction over retail rates.
28
The RTO Accommodates . . . Wind
Intermittent and Distributed Generation
Intermittent power, e.g., wind
• Wind generators don’t have to “schedule” an unpredictable output.
• When it generates, the wind generator is contributing to the dispatch,
so it receives the spot price (LMP) at its location.
• Generators with contracts and scheduled deliveries can cover their
imbalances from the ISO spot market.
• RTO accepts delivery at the generator’s location; transmission owner
provides the interconnection (costs allocated per FERC rules)
Distributed generation
• Can be treated same as wind. When it generates, it receives the
spot price (LMP) at its location for the MWh it produces.
• It can use net metering settlement feature to account for on-site load
• Interconnection at the distribution level defined by local utility, and
state regulation, just as today.
29
The RTO Accommodates . . .
Demand-side Response/Real-time Pricing
Customer demand-side response and real-time pricing
• RTO spot markets are wholesale; demand side response is either
wholesale (by the utility or DR provider) or retail (end-use customers)
• Utility/DR provider faces the ISO spot prices as incentives.
• End-use customers face retail rates as incentives, but . . .
• With real-time pricing, customers can face spot prices as incentives.
• Customer sells back its bought energy, at the LMP spot price.
Efficient demand side response reacts to the marginal cost of
generation in real time. That’s what the RTO spot price is.
30
The RTO Accommodates . . .
Retail Choice with Default Supply
ISO spot market supports efficient retail choice and default supply
options.
• All competitive suppliers and LSEs have open access to grid and the
ISO spot market to support their supply contracts.
• Competitive suppliers use the spot market to cover their imbalances.
• Retailers pay their share of redispatch costs, so allowing retail choice
does not shift power or delivery costs from those who shop
(commercial/industrial) to those who don’t (residential).
No matter what policy applies, the RTO handles grid reliability and
wholesale spot market, leaving states free to regulate retail rates
and service. Retail choice is a state option, not a federal mandate.
The RTO/ISO is neutral on these policy choices.
31
State Default Supply Auctions
(Some Retail Choice States Only)
Auction Bidders
Genco
Marketer
Auction Winners Sign
Contracts with Utility
Declining Clock Auction
Picks
Lowest Cost Suppliers
S
p1
p2
2-yr Contract
For small C&I
P
Marketer
D
Auction monitors:
Retailer
1-yr Contract
For med C&I
3-yr Contract
For Residential
-- Independent
auctioneer
-- State PUC
32
To Reduce Carbon Emissions, We Have to Displace the
Coal Plants. It Won’t Be Easy.
$/MWh
These plants not
likely to be coal
PShortage
Shortage hours
PPeak
Demand
PShoulder
Peak hours
Supply
offers
POff-peak
Off-peak hours
Shoulder hours
The Coal plants are typically baseload, near the bottom of the
dispatch merit order. Without a mandate to retire, you need
enough alternatives to push coal plants to the margin.
33
How RTOs
Provide Open Access
To All Parties
Without Discrimination
34
RTOs with These Core Features Provide Open Access
Without Discrimination
Market Inputs
RTO
Functions
Market Support
Ensure Reliability
Generator Offers
Reserves
Cover
Imbalances
Co-Optimized
Load Bids
Bilateral
Schedules
Self Schedules
$$$
Regional
SecurityConstrained
Economic
Dispatch
Calculate
Dispatch
Prices
(LMP)
Settlements at
Spot Prices
Reliably Serve
All Loads
Real-Time
Balancing
Congestion
Redispatch
(In lieu of TLR)
Allocate &
Auction FTRs
$$$
Buy and Sell
Spot Energy
Transmission
Usage Charge
(LMPB - LMPA)
Financially
Firm Tx
(LMPB - LMPA)
Efficient
Price signals
35
What Does “Open Access” Mean?
Since 1992, the Federal Power Act requires the FERC to:
 Prohibit “undue discrimination” in the way jurisdictional transmission
owners make their transmission systems available for use by others.
 Promote competition by allowing competing generators to have fair
access to the grid.
In Orders 888/889 (1996) FERC translated this statutory mandate
into an “Open Access” requirement:
 Transmission owners must provide open access to their systems by
others in ways that do not unduly discriminate against those users.
• Original FERC authority extends only to privately-owned utilities
• 2005 Energy Policy Act extends FERC authority to public-owned
36
The Golden Rule of “Comparable Access”
Grid owners must “Do unto others as . . .”
Under Order 888’s “golden rule” . . .
A transmission owner is required to provide
transmission service on its grid to other parties on
essentially the same (or “comparable”) basis as the
transmission owner provides to itself.
But Order 888 doesn’t really apply this principle . . .
And the Order misunderstood the key features of how
the system actually operated, especially the meaning of
“available transmission capacity” (ATC).
37
Two Basic Problems with FERC’s Approach
1. It ignores the dispatch: Access to transmission
and ATC both depend on how the system operators
dispatch the system. Changing dispatch changes ATC.
2. It ignores the physics: Scheduling along “contract
paths” misses how electricity actually flows and causes
congestion. Actual flows don’t follow contract paths.
 Comments from NERC and utilities on the open access rules
pointed out this serious flaw, but FERC ignored the comments in
final rules.
 To understand these flaws, and correct the problem, FERC
needs to acknowledge how the system actually operates.
38
888: Contract Path Scheduling and TLRs
Under Order 888 parties reserve transmission from the grid owner
by reserving and paying for a “contract path” with sufficient ATC.
 The contract path concept bears little relationship to physical flows.
 The contract path is only one of many paths along which electricity
actually flows from “source” to “sink” for any given schedule.
Although a contract path may be able to accommodate the
flows...other possible paths on which the flows actually travel may
not be able to accommodate those flows without overloading.
 When this happens, control areas must either “redispatch” or
“unschedule” the overloaded lines to keep flows within security limits.
 System Operators and Reliability Coordinators use “TLRs” -Transmission Line Loading Relief = curtailment rules set by NERC.
39
Contract Path Scheduling Is Flawed
Because It Ignores the Actual Flows/Physics
Schedule with flows
along the contract path . . .
Control Area A
Control Area B
(not congested)
Loop flows can cause
congestion (flows above
line limits) anywhere along
any path
. . . causes flows
on all other paths
Control Area C
Contract path scheduling needs curtailments (TLRs) to
“unschedule” the grid to get flows within security limits
40
Why Didn’t FERC Require Redispatch?
FERC did not understand transmission service fundamentals:
 Dispatch/redispatch is the essential service that provides open access to
transmission.
 LMP identifies the marginal cost of redispatch. If you can price
redispatch service, you can sell it to those who wish to avoid curtailment.
Without this understanding, FERC’s Order 888 said that utilities do
not have to offer redispatch to 3rd parties. Instead, utilities may
curtail the 3rd party transactions that would otherwise require
redispatch.
Of course, without redispatch, operators must use TLR to curtail 3rd
party schedules to relieve congestion.
41
Can We Still Rely On TLRs For Reliability?
There may have been a time when primary reliance of TLRs was
sufficient to ensure reliable inter-control area grid coordination.
With hundreds of TLR curtailments being called, that time is past.
TLRs are inadequate because . . .
• TLRs can take too long – couldn’t have avoided 2003 blackouts.
• TLRs often curtail too many schedules, which leaves the grid underutilized => creates artificial need for more grid investments
• TLR rules don’t cover all flows, so they discriminate
• TLRs curtailments ignore economics => higher costs
42
An RTO Uses a Regional Dispatch To
Replace TLR within its Boundaries
RTO
Functions
TLR
Original Control
Area A
Coordinate
Flows
Control Grid
Operations
Monitor
Grid
TLR
Original Control
Area D
Maintain Voltage
and Frequency
Regional
SecurityConstrained
Economic
Dispatch
Manage
Reserves
Original Control
Area B
Coordinate
with other
RTOs
Real-Time
Balancing
Manage
Congestion
Keep Flows
W/in Limits
Original Control
Area C
43
FERC Has Approved Inconsistent Access Rules.
Only One Meets the Test of Non-Discrimination
A non-RTO utility -- does not have to offer redispatch service and
need not even make its dispatch open to 3rd parties for balancing
on the same basis as its own usage.
 A utility will always redispatch generation and provide balancing to
accommodate its own schedules to serve its own loads. No TLRs.
 But it will not redispatch generation to accommodate 3rd party
schedules. It uses ATC limits without redispatch to limit access to the
grid. It imposes TLRs and charges arbitrary prices for balancing.
 This is inherently discriminatory and leads to higher cost (re)dispatch.
An RTO -- offers redispatch service to every user willing to pay the
marginal cost of redispatch; it also offers balancing to all at LMP.




It finds the lowest cost redispatch to solve congestion across the region.
It uses LMP to price this redispatch and LMP to price imbalances.
Redispatch marginal costs = the difference in LMP at A and LMP at B.
Every user willing to pay this cost receives redispatch service. No TLR.
44
All Previous FERC Orders Fell Short
Order 888/889 – decreed “open access,” but conceptually flawed
•
•
•
•
Based on contract path scheduling, inconsistent with physics
Ignored access to dispatch, restricted access to balancing
Without LMP, pricing for imbalances was discriminatory
Allowed those with 888-compliant OATTs to continue discrimination
Order 2000 – saw the need for a balancing market, but didn’t
clearly connect this to the ISO’s real-time dispatch. The two are
the same.
•
•
•
•
Led to confusion about who/how to provide balancing market
Slowed efforts to create regional dispatch and spot markets
FERC liked LMP at PJM/NY, but didn’t require it in new ISOs
Left confusion over ISO vs Transco, different RTO functions, etc.
– “Alliance RTO” was a two-year waste of time, money
FERC’s current Open Access Order 890 is a retreat to the flawed
Order 888 model. It will sanction undue discrimination again.
45
The RTO Model Works. What Else Works?
RTO Model is based on open access to a regional dispatch and
associated spot market, using LMP.
That model provides:







Regional power pool to lower costs, improve reliability
Open access to transmission without discrimination
Reliability supported by the right incentives
Support for markets and traditional cost-of-service regulation
Support for demand response and renewables (wind)
Compatible with physics and how the system actually works . . .
Preserves state jurisdiction at utility/retail level
So far, no one has developed an alternative to this model that
meets all of these criteria.
46
Extra Slides
47
RTO Reliability Functions and Benefits
An RTO that offers a bid-based security-constrained economic
dispatch and related monitoring tools across its region can . . .
• Internalize regional loop flows and congestion in a large region
• Solve congestion region-wide every 5 minutes, before it happens,
and solve much of it day ahead with bid-based day-ahead markets
• Replace reliance on TLRs within its regional dispatch area
• Monitor and react quickly to grid problems on a regional basis
• Vastly simplify the coordination needed to ensure regional reliability
• Facilitate reserve sharing and reduce operating reserve requirements
(diversity is more reliable and saves money)
48
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
49
Before RTOs, Many Small Control Areas
Made Reliability Harder and More Costly
• Actions here affect flows there – it’s one interconnected grid
• Coordination is challenging, unforgiving – every operator must do
his/her job and let neighbors know quickly about problems.
• A single control area’s problems can black out a huge area -- the
August 14, 2003 blackout began in Ohio, but quickly spread to NE.
• Economic dispatch is balkanized – each local dispatch is less
efficient than it could be: we pay more in each area.
• Market power is easier to exercise -- the entity that controls the
dispatch controls grid access, imbalance pricing, curtailments, etc.
50
State Auctions Don’t Decide ISO Dispatch
State Auction Winners . . .
 Receive contracts with the utility to serve a slice of the utility’s demand.
 Can meet their contract obligations via self-generation, contract
purchases or purchases from ISO spot markets.
 These financial arrangements don’t dictate physical dispatch.
All generators are eligible for ISO Dispatch
 Every generator is free to offer it’s power to ISO for real-time dispatch
• ISO will select the lowest-cost offers that can meet demand and
satisfy reliability requirements.
• Whether a generator has a default supply contract is irrelevant.
 And any generator can sell power in ISO’s day-ahead market.
51
With Many Local Dispatches, the Weak Link in Reliability
Is the Time It Takes to Readjust Inter-CA Flows.
Control Area A
TLR
Coordinate
Inter-utility
Flows w/Others
Grid Operating
Instructions
(to Tx owners)
Monitor Flows, Limits
& Contingencies
(with state estimator)
Real-Time
Balancing
SecuritySecurityConstrained
Constrained
Economic
Economic
Dispatch
Dispatch
&&Regulation
Regulation
Congestion
Redispatch
(internal only?)
Manage Operating
Reserves
Keep Flows
Within Limits
(with contingency analysis)
Control Area B
TLR
“Interchange” is
Preset and Fixed
Every 30-60 Min
Coordinate
Inter-utility
Flows w/Others
Grid Operating
Instructions
(to Tx owners)
Monitor Flows, Limits
& Contingencies
(with state estimator)
SecuritySecurityConstrained
Constrained
Economic
Economic
Dispatch
Dispatch
&&Regulation
Regulation
Manage Operating
Reserves
(with contingency analysis)
Real-Time
Balancing
Congestion
Redispatch
(internal only?)
Keep Flows
Within Limits
Control Area C
TLR
Coordinate
Inter-utility
Flows w/Others
Grid Operating
Instructions
(to Tx owners)
Monitor Flows, Limits
& Contingencies
(with state estimator)
Security
-Security
Constrained
Constrained
Economic
Economic
Dispatch
Dispatch
&&Regulation
Regulation
Manage Operating
Reserves
(with contingency analysis)
Real-Time
Balancing
Timing:
Congestion
Redispatch
(internal only?)
Keep Flows
Within Limits
Flows = near light speed
AGC – regulation = seconds
Internal/local dispatch = 5 min
Adjust Inter-CA schedules = 3060 min
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