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WESEP REU June 3, 2013 Iowa State University

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Electric Power Industry Overview WESEP REU June 3, 2013 Iowa State University James D. McCalley Harpole Professor of Electrical & Computer Engineering – PowerPoint PPT presentation

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Title: WESEP REU June 3, 2013 Iowa State University


1
WESEP REUJune 3, 2013Iowa State University
  • Electric Power Industry Overview

James D. McCalley Harpole Professor of
Electrical Computer Engineering
2
Outline
  1. The electric power industry
  2. Control centers
  3. Electricity markets

2
3
Organizations comprising the Electric Power
Industry
  • Investor-owned utilities 239 (MEC, Alliant,
    Xcel, Exelon, )
  • Federally-owned 10 (TVA, BPA, WAPA, SEPA, APA,
    SWPA)
  • Public-owned 2009 (Ames, Cedar Falls, Muscatine,
    )
  • Consumer-owned 912 (Dairyland, CIPCO, Corn Belt,
    )
  • Non-utility power producers 1934 (Alcoa,
    DuPont,)
  • Power marketers 400 (e.g., Cinergy, Mirant,
    Illinova, Shell Energy, PECO-Power Team, Williams
    Energy,)
  • Coordination organizations 9 (ISO-NE, NYISO,
    PJM, MISO, SPP, ERCOT, CAISO, AESO, NBSO), 7 are
    in the US.
  • Oversight organizations
  • Regulatory 52 state, 1 Fed (FERC)
  • Reliability 1 National (NERC), 8 regional
    entities
  • Environment 52 state (DNR), 1 Fed (EPA)
  • Manufacturers GE, ABB, Toshiba, Schweitzer,
    Westinghouse,
  • Consultants BlackVeatch, BurnsMcDonnell, HD
    Electric,
  • Vendors Siemens, Areva, OSI,
  • Govt agencies DOE, National Labs,
  • Professional organizations IEEE PES
  • Advocacy organizations AEWA, IWEA, Wind on
    Wires
  • Trade Associations EEI, EPSA, NAESCO, NRECA,
    APPA, PMA,
  • Law-making bodies 52 state legislatures, US
    Congress

3
4
Big changes between 1992 and about 2002.
4
5
Independent System Operator
Vertically Integrated Utility
1900-1996/2000
5
6
What are the North American Interconnections?
Synchronized
6
7
What is NERC?
  • NERC The North American Reliability Corporation,
    certified by federal government (FERC) as the
    electric reliability organization for the
    United States.
  • Overriding responsibility is to maintain North
    American bulk transmission/generation
    reliability. Specific functions include
    maintaining standards, monitoring compliance and
    enforcing penalties, performing reliability
    assessments, performing event analysis,
    facilitating real-time situational awareness,
    ensuring infrastructure security,
    trains/certifies system operators.
  • There are eight NERC regional councils (see below
    map) who share NERCs mission for their
    respective geographies within North America
    through formally delegated enforcement authority
  • Western Electricity Coordinating Council (WECC)
  • Midwest Reliability Organization (MRO)
  • Southwest Power Pool (SPP)
  • Texas Reliability Entity (TRE)
  • Reliability First Corporation (RFC)
  • Southeast Electric Reliability Council (SERC)
  • Florida Reliability Coordinating Council (FRCC)
  • Northeast Power Coordinating Council (NPCC)

7
8
What is FERC?
  • An independent agency that regulates the
    interstate transmission of electricity, natural
    gas, and oil. It does the following
  • Regulates transmission wholesale sales of
    electricity in interstate commerce
  • Regulates all wholesale natural gas transmission
  • Reviews mergers/acquisitions /corporate
    transactions by electricity companies
  • Can review some siting applications for electric
    transmission projects
  • Licenses and inspects private, municipal, and
    state hydroelectric projects
  • Protects the reliability of the high voltage
    interstate transmission system through mandatory
    reliability standards
  • Monitors and investigates energy markets
  • Enforces FERC regulatory requirements via civil
    penalties/other means
  • Oversees environmental matters related to natural
    gas/hydroelectric projects
  • Administers accounting/financial reporting
    regsconduct of regulated companies
  • FERC does not
  • Regulate retail electricity and natural gas sales
    to consumers
  • Regulate activities of municipals or federal
    power marketing agencies
  • Regulate nuclear power plants (NRC does this)
  • Address reliability problems related to failures
    of local distribution facilities
  • Consider tree trimmings near local distribution
    power lines in residential neighborhoods

8
9
Regional Transmission Organizations/Independent
System Operators
  • The regional system operator monitors and
    controls grid in real-time
  • The regional market operator monitors and
    controls the electricity markets
  • The regional planner coordinates 5 and 10 year
    planning efforts
  • They own no electric power equipment.
  • None of them existed before 1996.
  • They are central to electricity production and
    transmission today.

9
10
Energy Control Centers
  • Energy Control Center (ECC)
  • SCADA, EMS, operational personnel
  • Heart (eyes hands, brains) of the power
    system
  • Supervisory control data acquisition (SCADA)
  • Supervisory control remote control of field
    devices, including gen
  • Data acquisition monitoring of field conditions
  • SCADA components
  • Master Station System Nerve Center located in
    ECC
  • Remote terminal units Gathers data at
    substations sends to Master Station
  • Communications Links Master Station with Field
    Devices, telemetry is done by either leased wire,
    PLC, microwave, or fiber optics.
  • Energy management system (EMS)
  • Topology processor network configurator
  • State estimator and power flow model development
  • Automatic generation control (AGC), Optimal power
    flow (OPF)
  • Security assessment and alarm processing

10
11
Energy control centers
11
12
ECCs EMS SCADA
Remote terminal unit
Substation
SCADA Master Station
Communication link
Energy control center with EMS
EMS alarm display
EMS 1-line diagram
12
13
ECCs SCADA, Telemetry, EMS, RT, DA Markets
Automatic Generation Control (AGC) is a feedback
control system that regulates the power output of
electric generators to maintain a specified
system frequency and/or scheduled interchange.
13
14
Balancing authorities
Performs AGC within designated area. 105 BAs in
N. Am. 67 in EI, 38 in WI, 1 in Texas. Every ISO
is a BA. Not every BA is an ISO.
14
15
Basic market design used by all ISOs today.
Schedules entire next-day 24hr period.
Schedules interchange for entire next-day 24hr
period, starting at current hour, optimizing one
hour at a time (1 value per hr)
Computes dispatch every 5 minutes.
15
16
Balancing Systems
ENERGY BUY BIDS
DAY-AHEAD MARKET 1 sol/day gives 24 oprting cdtns
ENERGY RESERVE SELL OFFERS
min SS zitCost(GENit)Cost(RSRVit) sbjct to
ntwrkstatus cnstraints
REQUIRED RESERVES
LARGE MIXED INTEGER PROGRAM
BOTH CO-OPTIMIZE energy reserves
ENERGY BUY BIDS
REAL-TIME MARKET 1 sol/5min gives 1 oprtng cdtn
ENERGY RESERVE SELL OFFERS
min SS Cost(GENit)Cost(RSRVit) sbjct to ntwrk
cnstraints
REQUIRED RESERVES
LARGE LINEAR PROGRAM
NETWORK
AUTOMATIC GENERATION CONTROL SYSTEM
FREQUENCY DEVIATION FROM 60 HZ
16
17
Basics of electricity markets
  1. Locational marginal prices (LMPs), /MWhr,
    indicate the energy price at each bus.
  2. Markets compute LMPs via an internet-based double
    auction that maximizes participant benefits. The
    LMPs are computed from SCED every hour in the DAM
    and every 5 minutes in the RTM.
  3. The DAM and the RTM are 2 separate settlement
    processes.

17
18
Internet-based two-sided auction markets
  • Buyers submit bids to buy in terms of
  • Price (/MWhr)
  • Quantity (MWhr)
  • Sellers submit offers to sell in terms of
  • Price (/MWhr)
  • Quantity (MWhr)

Price at which seller is willing to sell
increases with amount (cost of producing 1 more
energy unit increases as a gen is loaded higher)
Price at which buyer is willing to buy decreases
with amount (first unit is used to supply most
critical needs and after those needs are
satisfied, next units of energy are used to
satisfy less critical needs)
Offers to sell 1 MWhr Offers to sell 1 MWhr Bids to buy 1 MWhr Bids to buy 1 MWhr Bids to buy 1 MWhr
S1 S2 B1 B2 B3
10.00 10.00 70.00 70.00 25.00
50.00 50.00 70.00 50.00 0
65.00 70.00 65.00 25.00 0
70.00 70.00 65.00 0 0
8 8 0 0 0
8 8 0 0 0
8 8 0 0 0
This table orders offers and bids for each agent.
18
19
Internet-based two-sided auction markets
Offers to sell 1 MWhr Offers to sell 1 MWhr Bids to buy 1 MWhr Bids to buy 1 MWhr Bids to buy 1 MWhr
S1 S2 B1 B2 B3
10.00 10.00 70.00 70.00 25.00
50.00 50.00 70.00 50.00 0
65.00 70.00 65.00 25.00 0
70.00 70.00 65.00 0 0
8 8 0 0 0
8 8 0 0 0
8 8 0 0 0
This table orders offers and bids for each agent
(same as previous slide)
Offer/bid order Offers to sell 1 MWhr Offers to sell 1 MWhr Bids to buy 1 MWhr Bids to buy 1 MWhr
Offer/bid order Seller Price Buyer Price
1 S1 10.00 B1 70.00
2 S2 10.00 B1 70.00
3 S1 50.00 B2 70.00
4 S2 50.00 B1 65.00
5 S1 65.00 B1 65.00
6 S2 70.00 B2 50.00
7 S1 70.00 B2 25.00
8 S2 70.00 B3 25.00
This table orders offers and bids across all
selling and buying agents, respectively.
19
20
Market clearing price
L. Tesfatsion, Auction Basics for Wholesale
Power Markets Objectives and Pricing Rules,
Proceedings of the 2009 IEEE Power and Energy
Society General Meeting, July, 2009.
Computed as the price where the supply schedule
intersects the demand schedule.
SUPPLY
Price (/MWhr)
DEMAND
Quantity (MWhr)
20
21
Market clearing price
L. Tesfatsion, Auction Basics for Wholesale
Power Markets Objectives and Pricing Rules,
Proceedings of the 2009 IEEE Power and Energy
Society General Meeting, July, 2009.
Computed as the price where the supply schedule
intersects the demand schedule.
SUPPLY
Price (/MWhr)
DEMAND
Quantity (MWhr)
21
22
Security-constrained economic dispatch (SCED)
Subject to
1. SCED obj fnct also includes regulation term,
separating reg-up from reg-down.
2. Value terms in obj fnct can be set by
stepped curves established by ISO.
Max demand S diwiltDMAXi for all i (9)
  • We allow offers and bids to be made on energy and
    reserves.
  • This problem is solved for a single operating
    condition.
  • The operating condition is representative
    for
  • a certain time period (either 1 hour or 5
    minutes).

The above is a simplified version. The MISO
Business Practice Manual BPM-002-r11, Chapter 6,
provides a detailed description of the SCED. See
https//www.midwestiso.org/Library/BusinessPractic
esManuals/Pages/BusinessPracticesManuals.aspx.
23
Security-constrained unit commitment (SCUC)
Subject to
1. SCUC obj fnct also includes regulation term,
separating reg-up from reg-down.
2. Value terms in obj fnct can be set by
stepped curves established by ISO.
Max demand S diwiltDMAXi for all
I,t (13)
  • We allow offers and bids to be made on energy
    reserves. This problem is solved across multiple
    time periods, usually 24 hrs (1 hr at a time) but
    sometimes fewer (e.g, 4 or 6) and sometimes more.

The above is a simplified version. The MISO
Business Practice Manual BPM-002-r11, Chapter 4,
provides a detailed description of the SCUC. See
https//www.midwestiso.org/Library/BusinessPractic
esManuals/Pages/BusinessPracticesManuals.aspx.
24
Two markets - comments
  1. Two markets Energy operating reserve are 2
    different markets, 1 for buying/selling energy, 1
    for buying/selling operating reserve.
  2. Co-optimization The first SC in
    SC-SCED/SC-SCUC stands for simultaneous
    co-optimized referring to the fact that both
    energy operating reserve markets are cleared
    within 1 optimization formulation.
  3. Reserves Regulation reserve supplies
    minute-by-minute variation in net-demand via AGC.
    Spinning/supplemental reserve provide backup for
    contingencies (gen loss). Spinning is
    inter-connected, supplemental need not be both
    must be available within 10 mins of a request.
  4. Use of SC-SCED In DAM, SC-SCUC solves once per
    hour and then for that hour, SC-SCED is also
    solved. RTM uses the RT commitment as input to
    SC-SCED in computing RT dispatch every 5 minutes.
  5. LMPs SC-SCUC gives hourly commitment dispatch,
    but no nodal prices (LMPs). SC-SCED (given a
    commitment) gives dispatch nodal prices.
  6. Contingencies Transmission security constraints
    for SC-SCUC are enforced via a predefined
    constraint list for the SCUC and a simultaneous
    feasibility testing (SFT) function iterating with
    SCED.

25
Electricity two settlement markets
Internet system
Energy reserve offers from gens
Day-Ahead Market (every day)
Which gens get committed, at roughly what levels
for next 24 hours, and settlement
Energy bids from loads
Generates 100 mw paid 100.
Internet system
Energy offers from gens
Generation levels for next 5 minutes and
settlement for deviations from day-ahead market
Real-Time Market (every 5 minutes)
Energy bids from loads
Generates 99 mw pays 1.
25
26
Locational marginal prices
  1. Units are /MWhr
  2. One for each bus in the network.
  3. If the network is lossless, transmission capacity
    is infinite, then all buses have the same LMP, ?.
    In this case, ? is the increase in system cost if
    total load increases by 1 unit (corresponds to
    simple market we will see).
  4. With a lossy and congested network, LMPk is the
    increase in cost of bus k MW load increases by 1
    unit.

26
27
MISO and PJM balancing areas
27
28
RT LMPs in the MISO and PJM balancing areas
720 am (CST) 9/8/2011
Source MISO - PJM Interconnection Joint and
Common Market Web site, previously at
www.miso-pjm.com/ but not maintained.
28
29
RT LMPs in the MISO and PJM balancing areas
740 am (CST) 9/8/2011
Source MISO - PJM Interconnection Joint and
Common Market Web site, previously at
www.miso-pjm.com/ but not maintained.
29
30
Average annual locational marginal prices
30
31
Locational marginal prices effect of
transmission.
31
32
RT LMPs in the MISO and PJM balancing areas -
temporal variation for four different nodes
600 am-noon (CST) 8/28/2012
32
33
RT LMPs in the MISO balancing area
https//www.midwestiso.org/MarketsOperations/RealT
imeMarketData/Pages/RealTimeMarketData.aspx
March 4, 2013, 1020 CST
33
34
Ancillary services in the MISO balancing area
https//www.midwestiso.org/MarketsOperations/RealT
imeMarketData/Pages/RealTimeMarketData.aspx
March 4, 2013, 1020 CST
34
35
Market prices - Energy
Real-Time 825 am (CST) 6/4/2013
35
36
Market prices Ancillary Services
Day-ahead hour ending 9 am (CST) 6/4/2013
Real-Time 825 am (CST) 6/4/2013
36
37
Day-ahead LMPs in ISO-NE balancing areas
For hour ending 1100 am (EST) 9/8/2011
37
New England ISO website, at http//www.iso-ne.com/
portal/jsp/lmpmap/Index.jsp but no longer
available.
38
RT LMPs in the ISO-NE balancing areas
1025 am (EST) 9/8/2011
38
New England ISO website, at http//www.iso-ne.com/
portal/jsp/lmpmap/Index.jsp but no longer
available.
39
RTAncillary service prices in ISO-NE bal areas
TMSR10min spinning rsrv TMNSR10min non-spinning
rsrv TMOR30min operating rsrv
Regulation clearing price is 5.11/MW.
Load Zones Connecticut (CT), Southwest CT
(SWCT), Northeast Massachusetts/Boston (NEMABSTN)
1025 am (EST) 9/8/2011
39
New England ISO website, at http//www.iso-ne.com/
portal/jsp/lmpmap/Index.jsp but no longer
available.
40
Market time line
Ref A. Botterud, J. Wang, C. Monteiro, and V.
Miranda Wind Power Forecasting and Electricity
Market Operations, available at
www.usaee.org/usaee2009/submissions/OnlineProceedi
ngs/Botterud_etal_paper.pdf
41
Base point calculation via real-time market
ADS automatic dispatch system DOT dispatch
operating target
Focus on interval 2, t5, t10. For interval
2, a short-term net load forecast is made 7.5 min
before interval 2 begins, at t-2.5, and
generation set points are computed accordingly
via SCED. At t2.5, which is 2.5 minutes before
interval 2 begins, the units start to move. The
units are ramped at a rate which provides that
they reach the desired base point at t7.5 min,
which is 2.5 min after the interval begins.
Key point The base point is computed from a net
load forecast. There is error in this forecast,
which typically increases as wind penetration
increases. This error contributes to power
imbalance and therefore frequency deviation.
Source Y. Makarov, C. Loutan, J. Ma, and P. de
Mello, Operational impacts of wind generation on
California power systems, IEEE Trans on Power
Systems, Vol. 24, No. 2, May 2009.
41
42
How did wind participate in markets?
  • Old approach
  • Participates in day-ahead energy market
  • Does not participate in day-ahead AS market
  • Does not participate in RTM
  • Wind generates what it can (self-scheduled/price-t
    aker)
  • No deviation penalties
  • Paid based on computed LMP without wind, Point X
    below
  • Marginal unit backed off

Does not affect supply curve!
An excellent summary of wind and markets for all
North American ISOs (as of Oct. 2011) can be
found at http//www.uwig.org/windinmarketstableOct
2011.pdf.
42
43
How does wind participate in markets?
  • New Midwest ISO approach
  • Dispatchable intermittent resource (DIR)
  • Participates in day-ahead energy
  • Makes offer into RT market like any other
    generator. But one unique DIR feature
  • Instead of capacity max offered in by other
    generation resources, the forecasted wind MW is
    used as the operation capacity maximum
  • Units are expected to follow the dispatch signal
  • Units missing schedule band of 8 on either
    side of dispatch instruction for four consecutive
    5-min periods are penalized.
  • What are implications?

43
44
How does wind participate in markets?
  • What are implications?
  • ? Wind is dispatchable! Forecasting is key!
  • DIRs are expected to provide rolling forecast of
    12 five-minute periods for the Forecast Maximum
    Limit.
  • If forecast not submitted in time, MISO forecast
    is used.
  • Each 5 minute dispatch optimization uses Forecast
    Maximum Limit based on the following order
  • 1. Participant submitted Forecast for the
    interval
  • Must be less than or equal to the Feasibility
    Limit
  • Must have been submitted less than 30 minutes ago
  • 2.MISO Forecast
  • Must be less than or equal to the Feasibility
    Limit
  • Must have been created less than 30 minutes ago
  • 3.State Estimator

44
45
How does wind participate in markets?
45
46
Midwest ISOs wind forecasting accuracy?
46
47
Why is DIR beneficial? (from MISO document)
1. The entire market benefits when more resources
are fully integrated into the Energy Market.
Specifically, operational efficiency and market
transparency will be improved, since fewer manual
wind curtailments will be necessary, and LMPs
will reflect each resource that impacts a
constraint(s). For these reasons, registration as
DIR is consistent with Good Utility Practice. 2.
The automated dispatch for DIRs will be more
efficient than the manual curtailment process
currently in place for Intermittent Resources.
This will lead to more optimal economic solutions
that utilize wind more completely than a manual
process. 3. The make -whole provisions of the
tariff apply to DIRs, whereas they do not apply
to Intermittent Resources. If a DIR is
unprofitably dispatched above its Day-Ahead
position, it is eligible for the RT Offer Revenue
Sufficiency Guarantee (RSG) Payment provisions of
the tariff. If a DIR is dispatched below its
Day-Ahead position, and does not maintain its
Day-Ahead margin, it is eligible for the Day
Ahead Margin Assurance Payment provisions of the
Tariff. This provides DIRs with assurance that
dispatches, both upward and downward, will be
economical.
See https//www.midwestiso.org/Library/Repository/
Communication20Material/Strategic20Initiatives/D
IR20FAQ.pdf.
47
48
Why is DIR beneficial?
  • Inclusion of the DIRs in the RT dispatch provides
    that DIR offers are optimized by SCED.
  • This provides more flexibility to manage
    constraints. Therefore, there will be fewer
    manual curtailments, which benefits wind for
    increased MWhrs produced, and benefits others
    because it can be predicted (improves
    transparency).
  • Benefits to system because wind offers low and
    therefore affects all time periods some (has very
    large effect during peak periods) see next
    slide.

Why does wind offer low when its LCOE is high?
Because markets incentivize agents to offer their
marginal cost (cost of producing the next MW) to
be dispatched. This is the value for which they
break-even in the short-term. Since wind requires
no fuel, its marginal costs are mainly
maintenance-related and subsequently low compared
to marginal cost of fuel-based units.
How then, can wind energy be profitable in the
long-term, if it is offering prices that are
lower than its LCOE?.
It is because markets settle at the clearing
price, i.e., (assuming infinite transmission no
losses), everyone gets paid the clearing price,
not their offer price
48
49
Why is DIR beneficial?
Difference in prices with (solid) and without
(dashed) wind. Slanted lines are demand curves
for night, day, and peak. Without wind, prices
are slightly higher at night, significantly
higher during the day, and much higher during the
peak.
Wind energy and Electricity Prices Exploring
the merit order effect, a literature review by
Poyry for the European Wind Energy Association,
April , 2010., available at www.ewea.org/fileadmin
/ewea_documents/documents/publications/reports/Mer
itOrder.pdf.
49
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