Economic Outage Evaluation
Woody Rickerson
ERCOT Outage Coordination Supervisor
5-9-2008
ISO Outage Coordination Workshops
– 10-7-2007 Folsom, CA
– Attended by approximately 50 people from 8 NERC regions
– 1-8-2008 Austin, TX
– Attended by approximately 45 people from 6 NERC regions
– 7-17-2008 Holyoke, MA
New England’s Electric Power Grid
6.5 million customer meters
–
350+ generators
–
8,000+ miles of high voltage transmission lines
–
5 local control centers
–
12 interconnections with approximately 5000 MW
capability to three neighboring systems:
–
New York
–
New Brunswick
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Hydro Quebec
–
32,000 MW of installed generating capacity
–
Peak load:
–
–
Summer: 28,127 MW (8/06)
–
Winter: 22,818 MW (1/04)
ISO and Local Control Centers
–
400 mi.
650 km
Transmission Outage Requests Processed
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2005 – 4800
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2006 – 5000
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2007 - estimated in excess of 5500
320 mi.
520 km
ISO-NE Outage Coordination History
Extensive review of Outage Coordination processes in 2004
– Changes were necessary to respond to the greater demand for
improved coordination
– Nearly doubled staff to facilitate increased studies and coordination
– Near-term Outage Evaluations (<21 days in advance)
– 10 Positions (7x12 shift)
– Long-term Outage Evaluations (>21 days, up to 12 months ahead)
– 5 Positions as 5 x 8 shift
– 6 degreed positions
– Historically received 90% of transmission outages less than 21 days
notice
– Placed emphasis on increasing notice by use of the following:
– Metrics
– Economics
– 60% now received with less than 21 days notice
ISO-NE Outage Coordination Study Tools
–
–
Current
–
–
AREVA EMS Power Flow - Thermal
AREVA Day Ahead Study System – Economic
–
PSS/E - Voltage and Stability
Future (Under Development)
–
Power World – Interface Limit Calculations
–
Additional economic study software – RFP late 2007
ISO-NE Economic Evaluation History
– Move to consider Economics in outage coordination of transmission
outages began 3 years ago
– Market driven
– TSP opposed
– Generation Outages are generally denied based on capacity needs
(compact system with definitive load pockets)
– Typically scheduled 6 to 18 months in advance
– TSPs elected to recover costs associated with economic
coordination through rate annual rate adjustments
– A mechanism was designed for Load servers to share acceleration costs based
on load ratio -- ultimately rejected by TSPs
– Report of Economic Savings issued each year to TSPs (not public)
–
1st quarter 2008 shows $33 million in savings
ISO-NE Economic Overview
– Market Participant group maintains a list of “economically significant
transmission elements”
–
–
–
–
20% of all transmission elements on list
List is dynamic and can be added or subtracted from at any time
Economic Evaluation of outages is not confined to list
List serves as a aid
– NEISO set threshold for economic consideration
–
$200,000 over a 1 week period
– Transmission vs Generation conflicts
–
–
Transmission usually gives way
Trend starting where transmission is scheduling important outages further in advance
– Outages flagged as “Economic” are subject to NEISO repositioning
ISO-NE Economic Evaluation Process
– Historic load (similar day)
– Generator costs (historic bids – subject to outlier cleanup)
– Virtual bids not used
– Outage-in vs Outage-out 1hr comparison of production cost
–
–
–
–
All other approved outages included
False congestion analyzed by experience
1 hour costs extrapolated over outage period
Unit commitment not considered
– Post Analysis Process being developed
ISO-NE Economic Evaluation Problems
– Planned vs. Actual outage times become crucial
– Outage cancellations can invalidate results
– Personnel with experience in analyzing “typical” bids difficult to find
– Resistance to new Metrics
–
–
–
Number of cancellations
Reasons for cancellations
Planned vs Actual outage times
– TSP fear that realized savings could become public and result in pressure
to decrease maintenance
PJM Power Grid
KEY STATISTICS
PJM member companies
500
millions of people served
51
peak load in megawatts
144,644
MWs of generating capacity 164,905
GWh of annual energy
729,000
generation sources
1,271
area served
13 states + DC
Internal/external tie lines
247
PJM Economic Evaluation History
Financial Transmission Rights (FTR) revenue inadequacy
–
–
–
–
Money is collected from loads to pay generators and FTRs.
Congestion on the system may not allow enough money to be collected.
Generators will be paid first, and then FTRs are paid.
If not enough money is collected to pay the FTRs, they are revenue inadequate.
Outage Acceleration Process was developed to identify possible revenue inadequacy
resulting from transmission outages (2007 first year for acceleration)
Year
Congestion
FTR revenue
inadequacy
2005
2,070,038,758
177,842,265
2006
1,624,292,766
52,613,716
2007
(through
10/31)
1,405,308,639
0
New Outage Timelines added this year to enhance economic opportunities
Over last 2 years – 6 outages subject to acceleration (2 paid)
PJM Economic Outage Evaluation Overview
– Tools used
– Energy Management System (EMS)
– eDart (Dispatcher Application And Reporting Tool) – Internet-based outage management
system for generation and transmission
– Timelines
–
–
–
–
9 to 12 months out
6 months out (minimum for economic evaluation)
1 month out
1 to 3 days out
– Criteria for acceleration
– Outage with significant market impacts
– Outage is five days or more
– Estimated congestion revenue inadequacy in excess of $500,000
– Use the Transmission Adequacy and Reliability Assessment (TARA) tool
– PowerGEM software for off line using PSSE Cases
– Off line Application to run the Security Constrained Economic Dispatch to:
– Move minimum amount of generation to solve or
– Solve on a least cost basis
– Solution and cost for each hour of outage
PJM Economic Outage Evaluation Process
–
Create daily PSSE cases up to 365 days in advance
–
–
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Loads incorporated based on forecasts
Outages automatically incorporated
Added functionality to the TARA application to handle the following network topology changing
events:
–
–
–
–
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Split an existing bus
Add a new bus to the case
Add new pieces of equipment such as branches, transformers
Change the rating of an existing piece of equipment
Change the bus to which a branch, transformer, etc. is connected
–
SCED used for two day out – 12 month out analysis
–
Construct and evaluate all necessary snapshots spanning the duration of the
outage (DC single contingency analysis)
–
–
Benefit – Allows for a several outage snapshots – on peak, off peak, daily, weekends.
AC contingency analysis function to allow checking for the following:
–
–
–
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MVA and current line and transformer flow
Voltage deviations and voltage drop (change) violations
Voltage collapse conditions
Perform a combined reliability and financial impact of proposed transmission
outages Security Constrained Economic Dispatch
–
–
–
Run with and without outage
Determine the production cost difference
Determine the FTR revenue inadequacy
PJM Economic Outage Evaluation Acceleration
Process
– “High Cost” Transmission outages posted four weeks prior to the FTR auction.
– Participant makes request to accelerate to PJM.
– If one or more requests to accelerate are received, PJM will request an estimate to
accelerate from the transmission owner (TO).
– PJM provides participants the details of the estimate once it is received from TO.
– Actual costs to accelerate would be divided across the participants.
– PJM acts as the middleman
PJM Economic Outage Evaluation Problems
– TSP acceleration costs unreasonable
– Capturing actual savings difficult
– Requires good metrics to handle “Planned vs Actual” planning
– Participants that benefit from acceleration not required to contribute to
acceleration costs (only takes one willing to pay)
PJM and NEISO Comparison
NEISO
PJM
Breaker model
Line Model
Independent of CRR Market
Used in conjunction with CRR Market
Utilizes same RUC logic used in RT
Utilizes Line Model “Generator Impact” tool
One hour analysis extrapolated over
outage
Multi-hour or All-hour analysis
Acceleration/Repositioning/Cancellation
decision up to NEISO
Acceleration decision up to Market
TSPs made whole through rates
TSPs made whole by direct payments
Threshold $200K production cost increase
over 1 week
5 day or greater outages that result in
$500K of FTR revenue inadequacy
Annual Report of projected savings
Monthly Report does not include dollar
savings
ERCOT Economic Outage Analysis
Three Uses:
1.
Avoiding high cost combinations of outages
2.
Providing a dollars value for outage acceleration or repositioning savings (is
there enough potential savings to warrant looking at acceleration or
repositioning)
3.
Capturing the cost of construction outages for proposed projects so that they
can be included in the Planning Analysis
ERCOT Nodal Systems
ERCOT Nodal Market supported by multiple integrated systems and multiple
vendors
–
Outage Evaluation Tool = reliability based, multi-time, automatic outage assessment tool
– Vendor: AREVA
–
Outage Scheduling – supports interactions with market participants, and a DB of outage
requests’ statuses
– Vendor: ABB
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Model Source NMMS (in CIM). The same time-dependent source DB for all systems.
– Vendor: Siemens
–
Supporting systems: EMS & Market Management System
– Vendor: AREVA (EMS), ABB (MMS)
Nodal Outage Evaluation Process Steps
1)
User
–
–
Selects all dates/hours for the study
Provides any resources that must be committed or scheduled at a particular value
2)
OE pulls all the data corresponding to selected times, and automatically creates a power flow case
for each selected hour (the user can manually edit any data):
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Network models
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Forecasted loads
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Approved outages
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Forecasted temperatures
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Expected resource status (within 7 days)
3)
For each power flow case the OE separately and economically commits resources to match loads
and then schedules the resources taking into account reliability (N-1 security)
–
Not expected to run hourly analysis, e.g. no need to run similar or back-to-back hours, but it can
if desired
4)
OE computes sensitivity of the production costs to requested outages. If it can not find a secure
operating point, it also finds sensitivities of overloads to requested outages. Outcomes:
–
OE finds an N-1 secure operating point to accommodate all requested outages. It gives
incremental cost of all outages, as well as contribution of each individual outage
–
OE can’t find a secure operating point. It then computes contributions to the overload by each
requested outage. No cost data produced in this case.
5)
OE extracts and condenses the results, and presents a list of outages for approval to the user
6)
If the user accepts approved outages list, OE sends the list to OS for status update.
Nodal Outage Evaluation Tools Challenges
– Automatic case setup - a big challenge to setup cases that are
meaningful from the resource distribution standpoint, and also have
adequate reactive resources to result in a solved power flow case
– Our approach: simplified Unit Commitment based on typical price curves. We are also
expecting the need for some Voltage/Var scheduling considerations.
– Many study hours – computational burden to get N-1 (2000
contingencies) secure operating points for all the cases is enormous.
– Our approach: still in the design stage – maximize the use of in-memory information;
design & try
– Sensitivity computations (cost and violations) with respect to
requested outages very computationally intensive.
– Our position: trading the computer time for the analyst’s time. Without this info, the
analyst would spend considerably more time to arrive at the needed conclusions.
Good Utility Practice and Nodal Protocols
3.1.1 Role of ERCOT
(1) ERCOT shall coordinate and use reasonable efforts, consistent with Good Utility Practice, to accept,
approve or reject all Outage schedules for maintenance, repair, and construction of both Transmission
Facilities and Resources within the ERCOT System. ERCOT may reject an Outage schedule under
certain circumstances, as set forth in Section 3.1.5.6, Rejection Notice; Section 3.1.6, Outages of
Resources Other Than Reliability Resources; and Section 3.1.7, Reliability Resource Outages.
3.1.5.6 Rejection Notice
(2) ERCOT may reject a Planned Outage or Maintenance Outage of Transmission Facilities only:
(a) To protect system reliability or security;
(b) Due to insufficient information regarding the Outage; or
(c) Due to failure to comply with submittal process requirements, as specified in these Protocols.
ERCOT Nodal Protocols
Section 2: Definitions and Acronyms
Good Utility Practice
Any of the practices, methods, and acts engaged in, or approved by, a significant portion of the electric utility
industry during the relevant time period, or any of the practices, methods, and acts that, in the exercise of
reasonable judgment in light of the facts known at the time the decision was made, could have been
expected to accomplish the desired result at a reasonable cost consistent with good business practices,
reliability, safety, and expedition. Good Utility Practice is not intended to be limited to the optimum practice,
method, or act, to the exclusion of all others, but rather is intended to include acceptable practices,
methods, and acts generally accepted in the region.
Dwr Translation -- A practice accepted by most ERCOT market participants to achieve a desired result in a timely
manner without incurring exorbitant cost or compromising reliability and safety.
• Discussion