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Wind Power and Electricity Markets
A living summary of markets and market rules for wind energy and capacity in North America
Information compiled through August 2009
Compiled by
Sari Fink, Exeter Associates, Inc.
Jennifer Rogers, Exeter Associates, Inc.
Kevin Porter, Exeter Associates, Inc.
and incorporating review comments from
Ken Schuyler, PJM Interconnection
John Buechler, New York ISO
Michael Falvo and Martin Hastings, Independent Electric System Operator of Ontario
Paul Gribik, Midwest ISO
Warren Lasher and David Maggio, ERCOT
Dave Hawkins and Jim Blatchford, California ISO
John Kehler, Alberta Electric System Operator
Jay Caspary, Southwest Power Pool
Jonathan Lowell, ISO New England
UWIG plans to update this information as regional electricity markets evolve
Wind Power and Electricity Markets
The following table addresses market rules for wind power purchase in key regions of North America. Table entries are
responses to the following questions:
•
Scheduling in Energy Markets: How is wind energy scheduled and procured?
•
Imbalance Settlement: How are wind energy imbalances settled – either through a balancing market or another
settlement procedure?
•
Ancillary Services: How are wind plants’ ancillary service needs and costs recognized?
•
Wind Forecasting: What role does wind forecasting play?
•
Capacity Calculation: How is capacity value or capacity credit for wind plants calculated? Is there a distinction
between capacity values for planning reserves (months and years time frame) and operating reserves (same-day
to next-day)? If so, what is it?
•
Capacity Recognition: How is capacity value recognized in capacity obligations and capacity markets?
•
Wind Power Management: Are various restrictions imposed on wind power under certain circumstances, such as
ramping limits or curtailment?
Wind Power and RTO/ISO Market Rules
PJM NYISO ISO‐NE Midwest ISO SPP Energy Market Structure Real‐Time and Day‐Ahead LMP‐based energy markets Real‐Time and Day‐Ahead LMP‐based energy markets Real‐Time and Day‐
Ahead LMP‐based energy markets Scheduling in Energy Markets If a capacity resource, wind must offer in the day‐ahead market. Negative price bids allowed. Wind resources that are not capacity resources are permitted, but not required, to offer into the day‐ahead market. A wind resource participating only in the real‐
time market receives real‐time LMP for energy provided. Wind bids a price curve that can include negative prices. Required for real‐time and optional for day‐ahead. Scheduled with other generation. The price‐
quantity offers submitted by each wind plant will determine the basepoint economic dispatch for each wind plant. Can submit bid curve or self‐schedule into day‐
ahead market, but not required to do so. Resources with a Capacity Supply Obligation must offer or self‐schedule into real‐
time market. Bilateral market for day‐
ahead, LMP‐based energy imbalance (real‐time) market. No centralized energy If an intermittent market; transactions done resource is designated as a “capacity resource,” on bilateral basis. SPP then it must offer in the implemented a central energy imbalance market day‐ahead market and on February 1, 2007. the reliability assessment commitment (RAC) process. Otherwise, the wind resource can – but has no obligation to – offer into the day‐ahead market. 5 min. 5 min. 5 min. 5 min. For wind resources that are self‐scheduled, operating reserve deviation charges apply on differential between day‐ahead and real‐time levels exceeding a dead band; differentials less than 5% or 5 MW incur no deviation charges. Wind resources that are not self‐scheduled are assessed deviation charges based on how closely they follow PJM dispatch signals. If scheduling day‐ahead, buy out shortfalls at real‐time LMPs. Up to 3,300 MW exempt from under‐generation penalties when output differs from real‐time schedule during unconstrained operations. Energy deviations between real‐time and day‐ahead markets are settled at real‐time LMP. Wind resources are not assessed a share of certain uplift costs that are allocated based on deviations. Settled at real‐time price Real‐time balancing with no deviation market launched in penalties. February 2007. The real‐
time balancing market is an offer‐based market, and locational prices will be based on the resource offers submitted to SPP. Wind is not subject to uninstructed deviation charges. Dispatch Frequency Imbalance Settlement Real‐Time and Day‐
Ahead LMP‐based energy markets. 5 min. PJM NYISO ISO‐NE Midwest ISO SPP Ancillary Services Market Structure Day‐Ahead and Real‐Time markets for regulation, synchronized, and supplemental reserves. Ancillary service costs borne by loads. Day‐Ahead and Real‐Time markets for regulation, synchronized, 10‐minute non‐synchronous, and supplemental reserves. Ancillary service costs borne by loads. Day‐Ahead and Real‐
Time markets for regulation, synchronized, 10‐minute non‐synchronous, and supplemental reserves. Ancillary service costs borne by loads. Includes Day‐Ahead and Real‐Time markets for regulation, spinning reserves, and supplemental reserves. Ancillary service costs borne by load. SPP does not offer ancillary services directly, since SPP is not a control area operator. SPP can act as the transmission customer’s agent to procure ancillary services. Ancillary Services Market and Wind Wind is not precluded from participating in ancillary service markets if they can meet the requirements. No impact yet on the level of ancillary service requirements. Wind is not precluded from applying but must meet the eligibility requirements for each category to participate in the ancillary services market for that category. No impact yet on the level of ancillary service requirements. Wind not able to participate in ancillary services markets. No impact yet on level of ancillary services required, but ISO‐NE is considering how increased wind penetration may alter requirements for some ancillary services. Wind is not eligible as regulation qualified resources, spin qualified resources, or supplemental qualified resources in either the Day‐Ahead or Real‐Time markets. Wind may provide ancillary services if their ability to provide them is not inhibited by their ability to maintain their schedules or follow dispatch instructions. Wind Forecasting Centralized wind forecasting system in place. Wind plants must meet technical requirements and provide meteorological data. Centralized wind forecasting No role so far. Likely to system in place. Wind plants change with higher must meet technical penetrations. requirements and provide meteorological data. Started centralized wind No centralized wind forecasting in June 2008. forecasting in place. Wind forecasting is the responsibility of balancing authorities and wind generators. Wind Forecasting Utilization Used for day‐ahead transmission security and reserve adequacy assessments. Not currently using wind forecasting as input into day‐ahead markets. Used in determining if enough generation is committed day‐ahead to serve forecasted load. Real‐
time wind forecast integrated into real‐time commitment and dispatch. MISO uses the wind forecast in their reliability unit commitment, for transmission outage coordination, transmission security and peak load analysis and potential impact of wind ramps on flowgates. No centralized wind forecasting. No centralized wind forecasting in place. Wind forecasting is the responsibility of balancing authorities and wind generators. PJM NYISO Capacity Market Structure Three‐year forward market for capacity through the Reliability Pricing Model (RPM); with supplemental annual auctions as needed. LSEs can also self‐
supply or procure capacity through bi‐lateral contracts. LSEs may self supply, purchase bilaterally, or purchase capacity in monthly auctions or biennial six‐month capacity auctions. Capacity Calculation 3‐yr rolling average, capacity factors for hours ending 2‐to‐6 pm, 6/1 through 8/31. Default value: 13% of net plant rating until operating data becomes available. Wind capacity resources must bid into day‐
ahead energy market to receive capacity market revenues. Wind generator’s capacity factor between 2 pm and 6 pm from June through August and 4 pm through 8 pm from December through February. Intermittent resources not required to participate in day‐ahead market to receive capacity revenues. Capacity Recognition Wind can bid into RPM auctions. Wind can participate as a capacity resource. ISO‐NE Midwest ISO SPP Three‐year Forward No capacity market. Capacity Market (FCM). LSEs can also self‐supply or procure capacity through bilateral contracts. Three FCM Auctions have taken place for delivery periods 2010/11, 2011/12, and 2012/13. Wind assigned at a 15% New FCM rules take capacity credit. effect 6/1/2010, and specify wind resource capacity value is based on median historical output during Summer/Winter Intermittent Reliability Hours – 1‐6 pm summer weekdays, 5‐7 pm winter weekdays, plus shortage events. No capacity market. Can participate as a capacity resource in FCM. First FCM delivery period starts 6/1/2010. Wind resources are not penalized for lack of availability, including during shortage Events. SPP does not operate a capacity market. Capacity demonstration is the responsibility of the entity owning, operating, and/or contracted for wind farm capacity. Payments received in bilateral market for capacity if designated as a Network Resource in MISO. As a designated Network Resource, must offer capacity into the Day‐Ahead Market. Output level that wind plant equals or exceeds during 85% of period defined by top 10% of load hours. PJM Wind Power Wind plants must be able to Management accept electronic basepoint signals. During constrained operations, PJM will redispatch all resources on a cost‐
effective basis according to each resource’s bid curve. PJM will send wind plants a desired MW basepoint and any curtailments should be achieved within 15 minutes or PJM needs to be notified if that is not achievable. NYISO Wind plants must be able to accept electronic basepoint signals. During constrained operations, wind plants must follow the re‐dispatch signal and meet the basepoint output limit within 5 minutes. Penalties for non‐compliance equal to MW above basepoint multiplied by the regulation clearing price. A 3% error is allowed. ISO‐NE None so far. Midwest ISO None so far. SPP None so far. Energy Market Structure ERCOT CAISO Alberta ESO Ontario IESO Real‐Time market based on a Province‐wide clearing price for energy. Energy suppliers can commit resources in day‐ahead commitment process; market clearing prices and dispatch still set in real‐time market. Scheduling in Bilateral market. Like other Wind generators can sell into the Wind generators do not submit Generators required to submit Energy real‐time market if willing to accept offers into the energy market and energy forecasts. Energy from resources, wind scheduled as Markets the real‐time market price. The part of a Qualified Scheduling are price takers. The AESO is variable renewable energy proposing that wind generators Entity’s (QSE) portfolio. ERCOT energy will still be scheduled hour generation accepted as ahead (defined as 75 minutes ahead) participate in a centralized wind requires the low sustainable generated—wind resources are forecast service to the AESO and treated as price‐takers. but it will be a price taker. limit for wind generators to be continue to not offer into the set at most to 10% of the energy markets. resource’s registered nameplate capacity. Wind generators in service before 2003 are exempt. Dispatch 15 min. 5 min. Wind units are not dispatched As required. No minimum or 5 min. Wind is classified as an Frequency in PIRP. maximum time. intermittent resource, and does not receive normal dispatch signals. Imbalance Any imbalances are settled at No penalties. No penalties for settlement If participating in wind forecasting, Settlement zonal Market Clearing Price of imbalances but penalties can be then hourly deviations are settled at Energy (MCPE). No take back of a monthly weighted market‐clearing assessed for not meeting wind price and accumulated for monthly payment for over generation if forecasting obligations. average of energy imbalances. If not within ±50% of scheduled participating in wind forecasting, capacity. then subject to 10‐minute imbalance energy charges. Wind‐only QSEs are exempt from charges due to deviation from submitted energy schedules. Bilateral market for day‐ahead, zonal energy imbalance (real‐
time) market. Transitioning to a Day‐Ahead and Real‐Time LMP‐based energy market in late 2010. Recently began Real‐Time and Day‐
Ahead LMP‐based energy markets. Real‐Time market based on a Province‐wide clearing price for energy. ERCOT CAISO Alberta ESO Ontario IESO Real‐Time markets for regulation, synchronized (spinning) reserve available within 10 minutes, non‐
synchronized reserve available within 10‐minutes, and 30‐
minute reserve (synchronized and non‐synchronized) available within 30 minutes, and supplemental reserves. Additional ancillary services for regulation, reactive, and reliability‐must‐run are procured via contract. Ancillary service costs are borne by loads. Wind cannot offer into ancillary service markets. Ancillary Services Market Structure Market for regulation, spinning, and supplemental reserve. All ancillary service costs are borne by loads. The day‐ahead market accepts bids for ancillary services. The services procured include: regulation reserve, spinning reserve, and non‐
spinning reserve. Day‐Ahead market for regulation, spinning, and supplemental reserves. Ancillary Services Market and Wind Wind does not participate in the Participation in the Participating ancillary services market. Intermittent Resources Program (PIRP) specifically excludes the wind generator from taking part in the ancillary services market. Wind Forecasting Started centralized wind forecasting in 2008. The AESO has proposed that additional regulating reserves or equivalent type service be procured to ensure sufficient ramping capability for forecasted wind power ramps. The costs of these additional ancillary services will be paid for by load. AESO completed a wind forecasting pilot and plans to implement a centralized wind forecasting system in 2010. Once in place, wind generators will be required to comply with the requirements. Centralized wind forecasting since 2004 (PIRP). PIRP wind generators pay small fee. Exports out of CAISO subject to export fee. Wind generators must provide meteorological data. Issued wind forecasting RFP earlier in 2009; evaluating bids currently. Wind operators provide forecasts. Forecasts must be provided by 11 a.m., covering every hour of the remainder of that day and the next day. Wind operators must provide updates if actual output is reasonably expected to differ from the forecast by 2% or 10 MW, whichever is greater. Will adopt centralized forecasting in 2010. Wind Forecasting Utilization Capacity Market Structure Capacity Calculation ERCOT 80% exceedance wind forecast is used for Day‐Ahead planning for sufficient commitment. Amount of installed wind capacity considered for acquiring regulation reserves. Wind and load forecast error considered for procuring non‐
spinning reserves. No capacity market. Wind generation is included in capacity reserve margin calculations at 8.7% of nameplate capacity, based on stochastic analysis of effective load‐carrying capability. CAISO Alberta ESO The wind generation forecast is used as the energy schedule for real‐time operations. Day‐ahead forecasts advisory. Once wind forecasting system is in place, AESO will integrate wind forecast into expected need for next day operating reserves and procurement, as well as real‐time operation for energy market dispatch, short term adequacy and Available Transfer Capability (ATC). No capacity market. Real‐time scheduling uses persistence wind forecasts. Plan to adopt central wind forecasting in 2010. The capacity value for wind power has been given a 20% value until further studies determine a better value or method. For the next 30 day period, wind capacity will be forecast on a seasonal basis (Winter, Summer and Shoulder periods) using the minimum capacity from each season’s daily production profile. The daily production profile is based on the median hourly production for that season. For 18‐month (mid‐term) forecast timeframe, seasonal capacity values for wind are calculated by taking the median wind capacity factor from historical wind output at selected seasonal peak hours. Both modeled (10 years of history, 1997‐2006) and actual (3 years of history, 2006‐
present) wind data history is used. The lower of the two (modeled or actual) capacity values for each season is applied. In collaboration with the CAISO, the California PUC annually sets capacity requirements for 10 areas within California, plus a planning reserve margin (now 15%). For three years, plant output that equals or exceeds 70% of period between 4:00 and 9:00 p.m. for Jan‐
March, and Nov. and Dec.; and between 1:00 and 6:00 p.m. from April through October. Wind projects assigned to one of six wind areas (Tehachapi, San Gorgonio, Altamont, Solano, Pacheco Pass, San Diego). Diversity benefit adder if wind area capacity credit higher than individual wind project. Various adjustments if wind project operating less than three years. Ontario IESO No capacity market. ERCOT CAISO There are no payments received by any generation for capacity in ERCOT. No payments received for capacity—
just credit toward overall system reliability through reserve margins. No capacity market. No capacity market. Wind Power Wind generators must limit Management ramp rates to 10% per minute when responding to or releasing from an ERCOT deployment, except during Force Majeure events, or if there is a demonstrated decrease in available wind resources, or if a wind generator operating under a Special Protection Scheme (SPS) is decreasing output to avoid SPS activation. ERCOT can also request wind generators to ignore the ramping limit requirement if necessary to maintain system reliability. The CAISO does not currently require intermittent resources to respond to real‐time curtailment requests except for transmission overload issues. However, there are plans to implement such tariff provisions in the near future to deal with over‐generation problems. In the process of implementing wind power management. Plan is to calculate a real‐time System Wind Power limit every 20 minutes and assign pro‐rata generation limits to wind plants as needed. Wind plants will need to accept wind power limits for their facilities and respond within 10 minutes. IESO operator must have contact with wind plant operator at all times. Wind plant operator must follow requests within 5 minutes of notification Must keep production schedules as up to date as possible. Capacity Recognition Alberta ESO Ontario IESO