Wind in Market Stable Oct 2011

PO Box 2787 Reston, VA 20195

Phone: 252-715-0796 Fax: 865-218-8999

E-mail: [email protected] Web: www.UWIG.org

Wind Power and Electricity Markets

A living summary of markets and market rules for wind energy and capacity in North America

Information compiled through October 2011

Compiled by Jennifer Rogers, Exeter Associates, Inc.

Kevin Porter, Exeter Associates, Inc.

and incorporating review comments from Ken Schuyler and Glenn Weiss, PJM Interconnection

David Edelson, New York ISO Joseph Freire, Independent Electric System Operator of Ontario

Dale Osborn, Rao Konidena, Nivad Navid, and Michael McMullen, Midwest ISO David Maggio, Warren Lasher and Claudia D’Annunizo, ERCOT

Jim Blatchford, California ISO Doug Johnson, Bart McManus, Scott Winner and Eric King, Bonneville Power Administration

Jacques Duchesne, Alberta Electric System Operator Jay Caspary and Jason Smith, Southwest Power Pool Jonathan Lowell and Bill Henson, 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:

Energy Market Structure: What type of energy market is in operation?

Scheduling in Energy Markets: How is wind energy scheduled and procured?

Ability of Wind to Bid Day-Ahead and Set Price: Can wind bid into a day-ahead market and set the overall market price?

Allowance of Negative Price Bidding: Are negative prices, and negative price bidding, permitted?

Dispatch Frequency: At what interval is generation dispatched?

Imbalance Settlement: How are wind energy imbalances settled – either through a balancing market or another settlement procedure?

Ancillary Services Market Structure: How and what type of ancillary serves are procured, and at what time frame?

Ancillary Services Market and Wind: Can wind plants provide ancillary services?

Impact of Wind on Ancillary Services Requirements: Has wind prompted the utility or RTO to change the amount, the type and the timing of procuring ancillary services?

Eligibility of Wind to Provide Frequency Response and Inertial Response: Can wind provide frequency response or inertial response?

Type of Wind Forecasting System: Does wind forecasting play a role, and if so, what type of wind forecasting system is in place?

Description of Wind Forecasts: What type of wind forecasts are prepared and at what time frame?

Wind Forecast Tools/Techniques: How are wind forecasts prepared, and what tools and techniques are used?

Availability of Ramp Forecast: Is a separate forecast prepared on the potential for wind ramps?

Wind Forecast Cost Allocation: Who pays for the wind forecasts?

Wind Forecast Utilization: How are the wind forecasts used?

Provision of Capacity Adequacy: How is sufficient capacity for reliability determined and obtained?

Capacity Reserve Margin: What is the reserve margin that is determined to ensure reliability?

Capacity Market Structure: How is capacity procured that is needed to ensure reliability?

Determination of Capacity Value for Wind: 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?

Ability of Wind to Contribute to Capacity Adequacy: Can wind bid into capacity markets or be considered as a capacity resource?

Wind Power Management: Are various restrictions imposed on wind power under certain circumstances, such as ramping limits or curtailment?

Incorporation of Wind into System Dispatch/AGC: Is wind generation incorporated into system dispatch, and if so, under what conditions?

As a baseline for the table, FERC Orders 888’s and 890’s discussion of these questions is summarized here: Scheduling in Energy Markets: No requirement for centralized energy markets.

Imbalance Settlement: Energy imbalance charges may apply if energy deliveries differ by more than +/- 1.5% from advance schedules. Under Order 888, actual penalties or payments for underdeliveries/overdeliveries are left to the discretion of the transmission provider, but they may be substantial. Under Order 890, FERC requires that imbalances of less than or equal to 1.5% of scheduled energy, or up to 2 MW be netted monthly and settled at the transmission provider’s incremental or decremental cost. Imbalances of between 1.5% and 7.5% of scheduled energy, or between 2 and 10 MW (whichever is larger), are settled at 90% of decremental costs and 110% of incremental costs. Imbalances greater than 7.5% (or 10 megawatts, whichever is larger) would be settled at 75 percent of the system decremental cost for overscheduling imbalances or 125 percent of the incremental cost for underscheduling imbalances. Intermittent resources, however, would be settled at 90% of decremental costs and 110% of incremental costs for imbalances greater than 7.5% or 10 megawatts. Ancillary Services: Transmission provider required to offer scheduling and billing services and to act as purchasing agent for transmission customers that need ancillary services. Wind Forecasting, Wind Power Management and Capacity Calculation and Recognition for wind are not discussed in Order 890. In November 2010, FERC released a proposed rule that would require transmission providers to offer intra-hour transmission schedules; require variable energy generators to provide meteorological and operational data to utilities for variable energy forecasting; and add a variable generation regulation and frequency response ancillary service into the Order 890 pro forma transmission tariffs, but only if 15-minute transmission schedules and variable energy forecasting are in place. FERC has not yet issued a final rule.

Wind Power and RTO/ISO Market Rules

PJM NYISO ISO-NE Midwest ISO

Energy Market Structure

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. 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 price bids. Required for real-time and optional for day-ahead. If the wind resource needs to limit its output, the price-quantity offers submitted by each wind plant will determine the reduced base point for each wind plant for economic dispatch.

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.

If an Intermittent Resource is designated as a capacity resource, then it must offer in the day-ahead market. Otherwise, the Intermittent Resource can – but has no obligation to – offer into the day-ahead market. Intermittent Resources and Dispatchable Intermittent Resources (DIRs) can reduce exposure to Revenue Sufficiency Guarantee charges by participating in the day-ahead market.

Ability of Wind to Bid Day-Ahead and Set Price

If a capacity resource, must bid in day-ahead market, and is able to update hourly. A wind generator can set the market price if selected economically in the day-ahead market and is not designated as “must-run.” Otherwise, wind is not required to bid in the Day-Ahead.

Day-ahead market participation is optional for intermittent resources. If participates, is treated as any other resource and can set price if it is the marginal unit – buys shortfall at real-time price.

Day-ahead market participation optional. Settle at real-time nodal price for deviations from day-ahead schedule. Although wind resources are permitted to offer into the market as economically dispatchable resources, and as such would be eligible to set price, current wind resources are offering in as a non-dispatchable resource and are therefore ineligible to set price. ISO-NE software currently not able to automatically incorporate sub-hourly changes in wind production. ISO-NE planning to incorporate 5-minute telemetry of wind plants and short-term wind forecasts that will allow for economic dispatch of wind plants and allow wind plants to set price.

If an Intermittent Resource is designated as a “capacity resource,” then it must offer in the day-ahead market. If a Must Offer unit is the marginal unit, it can set the market price. DIRs required to participate in the real-time market. All wind resources (except for PURPA QF wind projects and wind projects installed before April 2005) to transition to DIR by March 1, 2013. Non-DIR wind resources considered Intermittent Resources. See “Incorporation of Wind Into System Dispatch/AGC.”


Allowance of Negative Price Bidding

Negative pricing allowed. Negative pricing allowed. Negative pricing not allowed. Negative pricing allowed.

Dispatch Frequency

5 min. 5 min. 5 min. 5 min.

Imbalance Settlement

Balancing operating reserve charges are allocated to wind and other resources for deviations in real time from day-ahead schedules. Generators can self schedule at a fixed output or within an operating range and will not be assessed balancing operating reserve charges if follow PJM dispatch directions, and actually will be eligible for operating reserve credits. A generator can decide not to follow PJM dispatch and will not be assessed balancing operating reserve charges if real time output matches day-ahead schedules but will not be eligible for operating reserve credits. Differentials less than 5% or 5 MW incur no deviation charges.

If scheduling day-ahead, buy or sell deviations at real-time LMPs. Up to 3,300 MW of installed wind capacity is exempt from under-generation penalties when output differs from real-time schedule during unconstrained operations. Penalties may be assessed during constrained operations (described below).

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.

Intermittent Resources and DIRs are subject to Revenue Sufficiency Guarantee Charges for positive scheduling deviations for DIRs for day-ahead schedules, and for positive and negative deviations for Intermittent Resources. DIRs (but not Intermittent Resources) can receive real-time make-whole credits. DIRs (but not Intermittent Resources) are assessed an Excessive or Deficient Energy Deployment Change if a 8% tolerance band is exceeded for four or more consecutive 5-minute intervals within an hour. Deviations less than between 6 MWh and 30 MWh are exempt. Generators are also exempt during events beyond their control, such as wind speed cut-out during high wind events.

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.

Forward (seasonal) and Real-Time markets for 10 minute synchronized, 10-minute non-synchronized, and supplemental reserves. Real-time market for regulation. 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.


Ancillary Services Market and Wind

Wind is not precluded from participating in ancillary service markets if they can meet the requirements.

Wind is not precluded from applying but must meet the eligibility requirements for the individual ancillary service.

Wind is not able to participate in ancillary services markets.

Wind cannot supply operating reserves or other ancillary services. The MISO is required to report to FERC by March 2012 whether variable energy resources can provide supplemental, spinning or regulation reserves.

Impact of Wind on Ancillary Services Requirements

No impact yet on the level of ancillary service requirements.

Higher amounts of regulation will be needed in a 2010 integration study of 8 GW of wind. No impact on the amount of operating reserves for contingency events.

2010 integration study found additional need for regulation at higher levels of wind penetration, although sufficient levels of regulation capacity may be in place, assuming no resource attrition. Higher levels of spinning and non-spinning reserves may also be needed. Wind technology can participate in voltage regulation.

MISO is working with stakeholders to develop potential Ramp Capability product(s) that could access and pre-position flexible resources in the real-time markets.

Eligibility of Wind to Provide Frequency Response and Inertial Response

Wind does not provide frequency response or inertial response.

None. Wind does not provide frequency response or inertial response.

None.

Eligibility of Wind to Provide Up or Down Regulation

Wind is not precluded from participating in the regulation market if it can meet the requirements. PJM does not have separate Up and Down regulation markets.

Wind is not precluded from applying but must meet the eligibility requirements for the individual ancillary service.

Not allowed presently. Not allowed presently.

Type of Wind Forecasting System

Centralized wind forecasting since April 2009. Wind plants must meet technical requirements and provide meteorological data.

Centralized wind forecasting system in place since June 2008; used for individual wind plant economic dispatch decisions since May 2009. Wind plants must meet technical requirements and provide meteorological data.

Phase 1 of centralized wind forecasting system is scheduled to be in place Q3 of 2012. Implementation work ongoing.

Centralized wind forecasting since June 2008.


Description of Wind Forecasts

Long Term: Provided hourly, from 48 hours ahead to 168 hours ahead. Medium Term: Updated from 6 hours ahead to 48 hours ahead. Short Term: Updated with frequency of every 10 min, forecast interval of 5 min for next 6 hours. Forecast on the following aggregation levels: wind projects; electrically close wind farms; Transmission Owners; Regional – West, Mid-Atlantic; Council – RFC or SERC (currently none in SERC); PJM RTO

Day-ahead forecasts updated twice daily, covering next two operating days at 4 AM and 4 PM. Real-time forecasts updated every 15 minutes on a 15-minute interval basis, covering an 8 hour time horizon. Real-time forecast is blended with persistence forecast to develop wind plant schedules in real-time commitment (which looks ahead in 15-minute intervals for 2.5 hours) and real-time dispatch, which looks ahead in 5 to 15-minute intervals for 60 minutes. 100% persistence used in very short-term.

No centralized wind forecasting yet. 5 minute granular forecasts for each Commercial Pricing (CP) node (100+), and updates every 5 minutes are provided for the next 6 hours. The MISO also receives hourly updated forecasts from Energy & Meteo for each hour beyond 6 hours for the next 6 ½ days, for the same CP nodes. Energy & Meteo provides forecasts at 4 levels: CP nodes, zones, regions and all of MISO. Three different Numerical Weather Prediction (NWP) models are used for each of these levels. Dispatchable Intermittent Resources also receive a separate 5 minute forecast (See ‘Incorporation of Wind into System Dispatch/AGC’). Integrating the two 5 minute forecasts is under consideration.


Wind Forecast Tools/Techniques

Physical model that uses NWP forecasts as input. Energy & Meteo uses NWP input, a combination of three numerical weather models weighted according to the weather situation and historical performance; site-specific power curves based on historical data, and a shorter-term model (0-10 hours) based on wind power measurements and NWPs.

Uses ensemble forecasts and statistical analysis to prepare wind power forecast. Uses the following inputs: grid point output from regional-scale and global-scale NWP models; measurement data from several meteorological sensors; high-resolution geographical data; and meteorological and generation data from wind projects.

No centralized wind forecasting. Physical model that uses NWP forecasts as input. Energy & Meteo uses NWP input, a combination of three numerical weather models weighted according to the weather situation and historical performance; site-specific power curves based on historical data, and a shorter-term model (0-10 hours) based on wind power measurements and NWP input.

Availability of Ramp Forecast

Updated every 10 minutes at 5-min intervals for next 6 hours. Currently under evaluation for potential use in operations.

No ramp forecast; under consideration.

No centralized wind forecasting. No ramp forecast; under consideration.

Wind Forecast Cost Allocation

PJM pays for the central wind power forecasting service.

Fee assessed to each wind project. Charge includes the sum of a monthly fee of $500 and a separate monthly fee of $7.50 per MW of nameplate capacity. Fees are subject to change as more wind projects are added.

No centralized wind forecasting. MISO pays for the central wind power forecasting service.

Wind Forecast Utilization

Used to determine whether there is sufficient generation scheduled within PJM to meet expected load, transaction schedules, and reserve requirements.

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.

Phase 1 will incorporate wind power forecast into the day-ahead scheduling and commitment process and also the scheduling and commitment update process that occurs periodically within the operating day. Phase 1 will also include displays and alarms to enhance operator situational awareness.

MISO uses the wind forecast to inform their reliability unit commitment, for transmission outage coordination, transmission security and peak load analysis and potential impact of wind ramps on flowgates. Refer to Incorporation of Wind into Dispatch and AGC.


Provision of Capacity Adequacy

3-year Forward Capacity market. Incremental auctions if necessary, as determined by PJM.

Capacity Market. Separate auctions for capability period, monthly and spot market.

3-year Forward Capacity Market. ISO-NE also conducts annual and monthly reconfiguration auctions.

Monthly Voluntary Capacity Auction. In July 2011, MISO filed a proposal with FERC for a one-year Forward Capacity Market for the 2013 planning period. Would be mandatory, with the exception that Load Serving Entities would be allowed to opt-out.

Capacity Reserve Margin

15.6% recommended Installed Reserve Margin (IRM) for the 2012/2013 Delivery Year, and a 15.4% IRM for the 2013/2014, 2014/2015, and 2015/2016 Delivery Years.

15.5% for the 2011 Capability Year is under base case conditions.

~ 14% for the 2014/2015 capacity auction period, including benefits of ties with Hydro Quebec; ~17%. Otherwise, 14.4% for the 2014/15 Capability Year.

2011 Planning Reserve Margin is 17.4%, while 2012 Planning Reserve Margin is 16.7%.

Capacity Market Structure

3-year forward market for capacity through the Reliability Pricing Model (RPM); with up to three supplemental annual auctions as needed. LSEs can also self-supply or procure capacity through bilateral contracts.

LSEs may self supply, purchase bilaterally, or purchase capacity in monthly auctions or biennial six-month capacity auctions.

Three-year Forward Capacity Market (FCM). LSEs can also self-supply or procure capacity through bilateral contracts. Five FCM Auctions have taken place for delivery periods out through 2014/15.

Bilateral contracting, self-supply, and a voluntary centralized monthly capacity auction. In July 2011, MISO filed a proposal with FERC for a one-year Forward Capacity Market for the 2013 planning period (June 2013 - May 2014). Would be mandatory, with the exception that Load Serving Entities would be allowed to opt-out.


Determination of Capacity Value for Wind

3-year rolling average of capacity factor of wind plant between 2 pm and 6 pm (local time), 6/1 through 8/31. Default value: class average of 13% of nameplate capacity until operating data becomes available. Wind capacity resources must bid into day-ahead energy market to participate in the RPM.

Capacity factor of wind plant between 2 pm and 6 pm from June through August and 4 pm through 8 pm from December through February. Default summer capacity value: 10% of nameplate capacity until operating data becomes available for onshore wind; 38% for offshore wind. Default winter capacity value: 30% of nameplate capacity until operating data becomes available for onshore wind; 38% for offshore wind. Intermittent resources not required to participate in day-ahead market to receive capacity revenues.

Summer capacity credit is the 5 year rolling average from 1pm – 6pm from June to September. Winter capacity credit is the 5 year rolling average from 5 pm – 7 pm from October to May. New facilities determine capacity credit based on 1 year of on-site data.

Uses the ELCC method of calculation. Capacity credit currently 12.9% of rated capacity in 2011 and 14.9% in 2012.

Ability of Wind to Contribute to Capacity Adequacy

Wind can bid into RPM auctions.

Wind can participate as a capacity resource.

Can participate as a capacity resource in Forward Capacity Market. Wind resources are not penalized for lack of availability, including during shortage events. If actual performance significantly below obligation, must cover or submit restoration plan.

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. Must be deliverable to qualify.


Wind Power Management

Wind included in procedures for Transmission Constraints and Light Load Events. Wind curtailed along with other generation based on $/MW effect for transmission constraints and economic bids for Light Load Events. Wind would normally have an emergency minimum of zero, but can submit a greater value. Generators must be able to adjust their output level when operating in the range between the economic minimum and Maximum Facility Output (MFO). Resources may not submit an economic minimum in the real-time energy market that exceeds the greater of the resource’s physical minimum operating level or the level of its Capacity Interconnection Rights (CIR). For wind plants the CIRs are typically equal to thirteen percent of the MFO. PJM does not currently impose any limitations on wind ramp rates.

Wind Power Management is handled automatically via economic dispatch. 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.

Under development. Will curtail variable and other generation during Minimum Generation Events after using the emergency range (between energy minimum and energy maximum) of conventional generation. Intermittent Resources are curtailed out of market for transmission congestion and minimum generation events. Order of curtailment based on the impact on the transmission constraint and priority of transmission service. During normal operation, DIRs with lower offer price than market clearing price dispatched to maximum level, and to minimum level if offer price higher than market clearing price. If there is transmission congestion, DIR projects with higher offer price will be curtailed first.


Incorporation of Wind into System Dispatch/AGC

Wind plants must be able to accept dispatch instructions. During constrained operations, PJM will redispatch all resources 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.

Real-time economic dispatch, with centralized forecast used as the upper limit. If dispatched down, over-generation charges may apply. Wind is exempt from under-generation charges.

Proposal to require wind to follow dispatch procedures and to submit bid curves is under consideration.

All wind resources in operation after April 1, 2005, and not totally delivered under network or long-term point to point service must register as a Dispatchable Intermittent Resource (DIR) by March 1, 2013. Wind QFs under PURPA are exempt. In the real-time market, DIRs must submit 5-minute CP node level wind forecast, or accept the MISO’s default wind forecast. The MISO default wind forecast is also used if the DIR’s forecast is over 30 minutes old or exceeds the feasibility limit of the wind plant. DIR forecasts up to 110% of the feasibility limit are accepted. DIRs can update their forecast maximum limit up to 10 minutes before each scheduling interval (i.e., up to 15 minutes ahead). If DIR chooses to use the MISO provided 5-min wind generation forecast values on its CP Node, this forecast value will be used as economical maximum limit for the wind plant in the dispatch function.

SPP ERCOT CAISO Alberta ESO


LMP-based (real-time) market for energy imbalances only. Additional Day-Ahead LMP-based energy markets scheduled to be implemented in March 2014.

Day-Ahead and Real-Time LMP-based energy market.

Day-Ahead and Real-Time LMP-based energy markets.

Real-Time market based on a Province-wide clearing price for energy.


No centralized energy market, except for energy imbalances. Transactions are done on a bilateral basis.

All generation resources, including wind resources, are given individual dispatch instructions by ERCOT, generally at a 5-minute frequency. This dispatch is primarily based on real-time telemetry from the Resources, Resources offers, and current system conditions.

Wind generators can sell into the real-time market if willing to accept the real-time market price. The energy will still be scheduled hour ahead (defined as 75 minutes ahead) but it will be a price taker. Generators in the Participating Intermittent Resources Program (PIRP) are not allowed to submit economic bids.

Wind generators do not submit offers into the energy market and are price takers.


Not applicable. Wind resources are permitted to bid in the Day-Ahead market on a voluntary basis.

Wind is permitted to bid day-ahead, but there is no protection if they do not deliver. No wind generator has bid day-ahead and set the price to date. Proposing to require new variable energy generators to submit economic bids.

Generators submit day-ahead supply curve offers; used to create energy market merit order. Wind generation is a price taker in the market and receives market price for the MW generated/supplied.


Negative pricing allowed. Offer Curve price minimum/floor set at negative $1,000.

Negative pricing allowed. Negative pricing allowed. Proposing to lower the energy bid floor from negative $30/MWh to $150/MWh, then to negative $300/MWh.

Negative pricing not allowed.

Dispatch Frequency

5 min. 5 min. 5 min. As required. No minimum or maximum time.



Has a real-time energy imbalance market, which 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.

All generation resources are settled in real-time based on their Real-Time Settlement Point Price (RTSPP) and their net injection at the generation resource’s settlement point. The settlement intervals are 15 minutes and the RTSPPs are calculated using the Nodal LMPs. Generation resources may be charged a penalty for deviating from their real-time Base Point instructions. For wind resources, penalties are determined by examining periods when they have been given an economic dispatch below their high dispatch limit (or capability). During these periods, if a wind resource is generating more than 10% above its expected base point, it will be charged for the deviation based on real-time prices.

If participating in PIRP, then hourly deviations are settled at a monthly weighted market-clearing price and accumulated for monthly average of energy imbalances. Proposed that monthly imbalance charges from PIRP facilities be allocated to the scheduling coordinators of LSEs buying the energy from PIRP facilities instead of being uplifted across the entire CAISO. If not participating in wind forecasting, then subject to 10-minute imbalance energy charges.

No penalties.


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 some ancillary services.

Market for regulation, spinning and supplemental reserves (a 30-minute Non-spinning Reserve Service and a 10-minute Responsive Reserve Service). All ancillary service costs are borne by loads.

The day-ahead market accepts bids for ancillary services. CAISO currently procures 100% of its ancillary service requirements in the day-ahead market, with incremental ancillary services procures as needed in the real-time market. The services procured include: regulation up, regulation down reserve, spinning reserve, and non-spinning reserve.

Day-ahead market for regulation, spinning, and supplemental reserves.



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 resources do not participate in the ancillary services market.

Participation in PIRP specifically excludes the wind generator from taking part in the ancillary services market.

Wind resources do not participate in the ancillary services market.


According to a SPP wind integration study, published in January 2010, increased wind penetration results in a need for increased regulation capacity, which accelerates as wind penetration increases. Regulation needs are time-dependant. Regulation-up and regulation-down requirements are not symmetric and may differ.

Wind forecasts are taken into account when determining the amount of non-spinning reserve requirements. Regulation requirements consider historical 5-minute variations in wind generation and account for any increases in installed wind capacity.

Are now differentiating regulation purchases by season, and are thus impacted by high wind seasons. Expect to need more regulation and load following in the future.

Level of operating reserves unchanged with present level of wind capacity, but that may change with higher levels of wind capacity. Considering developing a ramping service for wind, load and interties; adding regulation for the long term, and/or allowing wind to provide ramping down service.

Eligibility of Wind to Provide Frequency Response and Inertial Response

No market based mechanism exists for Frequency Response in SPP.

Wind resources with Standard Generation Interconnection Agreements (SGIAs) signed after 1/1/10 are required to provide Primary Frequency Response. Resources are not paid to provide Frequency or Inertial Response in the ERCOT Market.

CAISO does not have an inertial response or frequency response market.

New rule, effective December 1, 2011, requires non-exempt wind projects to comply with frequency response requirements. The AESO does not foresee inertia response problems at current level of wind penetration but will be continuously evaluate if there is a system need for inertia response.


Wind could be eligible to provide Down Regulation based on their ability to follow a dispatch instruction.

Wind resources are not prohibited from providing regulation.

While wind is permitted to provide up and down regulation, a unit must be telemetered and tested for the product in order to provide it. CAISO has had no wind unit test to date.

Wind does not participate in ancillary service markets or provide regulation.



Centralized forecasting since January 2011.

Centralized wind forecasting since July 2008.

Centralized wind forecasting since 2004 (PIRP). All intermittent generator, whether in PIRP or not, pay $0.10/MWh. Exports out of CAISO subject to export fee. Wind generators must provide meteorological data. Solar generators must provide solar insolation date. Variable energy generation from dynamic transfers eligible for PIRP by November 2012.

Centralized wind forecasting since January 2010. Currently rolling out real time (10 minute) site specific data. Wind generators must provide wind speed, wind direction, temperature and pressure every 10 minutes. Power data including turbine availability, net to grid and power limit are also required.


5-minute forecast for two hours ahead, updated every 5 minutes. Hourly forecast for the upcoming 24-hour period, updated hourly. Hourly forecast for each hour beginning 25 hours in the future, updated every 4-6 hours.

Short-Term Wind Power Forecast (STWPF): Hourly 50% probability of exceedance forecast for an upcoming 48-hour period, updated hourly and delivered 15 minutes past the hour. Similarly, an 80% probability of exceedance forecast is also provided.

Next day: production (MW) for each hour of next calendar day, delivered by 5:30 AM. Next hour: production (MW) for each of the next 7 hours, delivered by 15 minutes after each hour and at least 1 hour and 45 minutes before real time. For hour-ahead and day-ahead forecasts, AWS Truepower also applies 80% and 20% MW probability of exceedance values. Expanding forecast for intermittent dynamic transfers for intra-hour instead of hourly. Developing interval forecasting tool for sub-hourly and two hours ahead.

Day-ahead forecast up to 6 days (144 hours), updated every 24 hours. Will begin short-term hourly forecast and ramp forecast in December 2011 and it will be updated every 10 minutes.



Three different NWP models are used, with one that is run every 6 hours, and two that are run every 12 hours. Wind power forecast is generated with individual power curves per generation resource and weather model. Higher level forecasts are optimized to reflect influence between all underlying generation resources. Forecasts are combined using statistical methods to analyze forecast performance and calculate dynamic factors for specific weather regimes for each generation resource as well as for all higher level forecasts in real-time. Very short term forecast (0 - 6 hours) on all levels is performed using a very short term module taking current generation into account.

AWS Truepower uses an integrated forecast system based on physical and statistical models. -Days ahead: Uses an ensemble composite of statistically adjusted Numerical Weather Prediction (NWP) Forecasts. -Hours ahead: Uses time series methods, feature detection algorithms, and a rapid update NWP in addition to the ensemble composite above. Wind plant output models are also used to transform predictions of meteorological variables to power output forecasts.

Uses ensemble forecasts and statistical analysis to prepare wind power forecast. Uses the following inputs: grid point output from regional-scale and global-scale NWP models; measurement data from several meteorological sensors; high-resolution geographical data; and meteorological and generation data from wind projects. Solar insolation data requested from solar projects.

WEPROG uses a short-range ensemble prediction system based on a multi-scheme approach, which is an integrated weather forecasting system that uses 75 individual forecasts to replicate weather uncertainty for the next six days. Each ensemble member is based on a single NWP kernel, where the ensemble members are generated by varying dynamic and physical processes within the NWP model.



Forecast probabilistic ramping events with predefined confidence ranges per site, including event duration and magnitude.

AWS Truepower provides the ERCOT Large Ramp Alert System (ELRAS) which forecasts probabilistic ramping events of predefined magnitude and duration. ELRAS generates 15-minute regional and system-wide forecasts for the upcoming 6 hours, updating every 15 minutes. At the present, the ramp forecasts provided by ELRAS are only used by ERCOT’s System Operators for situational awareness.

Currently investigating a wind ramp tool similar to the ERCOT ELRAS tool, which does forecasting of ramps using a probabilistic algorithm.

Ramp forecast will begin in December 2011.


SPP pays for the central wind power forecasting system.

ERCOT pays for the central wind power forecasting system.

Fee assessed on all eligible intermittent resources of $0.10/MWh, and the CAISO covers about $0.03/MWh from within its operating budget. The CAISO also charges an export fee for energy from PIRP facilities exported outside the CAISO balancing area.

A $/MWh charge to wind generators, and reconciling the differences between wind power forecast costs and revenue from the surcharge annually.



Wind forecast is currently used for reliability capacity and next day planning. With implementation of SPP’s Day-Ahead and Ancillary Services Market in 2014, the wind forecast will be used to determine validity of day-ahead offers and commitment.

Qualified Scheduling Entities (QSE) representing wind resources must use the most recently provided Short-Term Wind Power Forecast (STWPF) in their Current Operating Plans (COP). The COPs are then used in both the Day-Ahead and Hour-Ahead Reliability Unit Commitment Studies which ensure that an adequate amount of capacity is available to reliably operate the system. QSEs shall adjust the provided forecasts for any unreported unavailability. Wind forecasts are also used in determining monthly requirements of non-spinning reserves.

The wind generation forecast is used as the energy schedule for real-time operations. Day-ahead forecasts advisory.

AESO uses wind forecast to project their 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). Expect to incorporate wind forecast into energy management system in near future, perhaps as soon as 2012.


Self-supply and bilateral contracting.


Forward capacity requirement from CPUC, but no centralized capacity market. CAISO bilaterally procures capacity deficiencies.



Target of 12%. (9% if the Load Serving Member’s capacity is comprised of at least 75% hydro based generation)

Target minimum of 13.75%. 15%. Information not provided.


No capacity market. No capacity market. No capacity market. In collaboration with the CAISO, the California PUC annually sets capacity requirements for 10 areas within California, plus a planning reserve margin (now 15%).

No capacity market.



Output level that wind plant equals or exceeds during 85% of period defined by top 10% of load hours.

Wind generation is included in the planning reserve margin calculations at 8.7% of nameplate capacity, based on stochastic analysis of effective load-carrying capability.

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, and 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.

The capacity value for wind power has been given a 20% value until further studies determine a better value or method.


SPP does not operate a capacity market. Capacity demonstration is the responsibility of the entity owning, operating, and/or contracted for wind farm capacity.

ERCOT does not operate a capacity market.

No payments received for capacity—just credit toward overall system reliability through reserve margins.

AESO excludes wind in determining their available reserve margin.



Real-time or forecast system overloads or other reliability issues may require localized curtailment or constraints on output from generation resources, including wind.

Unless exempted, wind resources must limit their ramp rate to 10% per minute when responding to or when being released from an ERCOT deployment, except: - during Force Majeure events, - if there is a demonstrated decrease in available wind resources or, - if a wind resource is operating under a Special Protection Scheme (SPS) and is decreasing its output to avoid an SPS activation. ERCOT can also request wind resources 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. CAISO will rely on economic bids from variable generators, which must follow economic dispatch instructions.

Effective December 1, 2011, AESO will temporarily limit real power production from wind plants when system conditions are such that the total amount of available real wind power cannot be accommodated and all other control methods have been exhausted. AESO has over-frequency control, power limiting, and up-ramp limits. Ramp rate controls must limit up ramps to between 5% and 20% of maximum authorized power. Also, if directed by AESO, wind generators must limit one-minute power output from exceeding 2% of maximum authorized power.


Market System Dispatch is simply an echo of current output. No modifications to wind resource dispatch instructions by AGC/Market System at this time. Directives are issued in the case of real-time reliability issues to limit output to specific levels. Wind not subject to Uninstructed Deviation Charges.

Wind resources are incorporated into the Economic Dispatch like all other generation resources. However, wind resources are only required to respond to electronic signals setting dispatched generation base-points when needed for congestion or when the resource appears not to be economical.

Wind generation is not dispatchable and does not submit offers into the market.

Ontario IESO BPA Xcel Energy (PSCo)


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.

Bilateral market. Vertically integrated utility. At wholesale, bilateral energy market under FERC Order 890.


Market participant wind generators are defined as those wind generators that participate in the IESO market. All grid connected wind generators must be market participants while wind farms embedded within a distribution system can elect to be market participants or stay as embedded facilities within the host local distribution companies. Small facilities within local distribution companies are generally not visible to IESO. Currently, wind generators are required to submit energy forecasts. Energy from variable renewable energy generation is accepted as generated unless it impacts system reliability.

Hourly scheduling but experimenting with several intra-hour scheduling pilots. Running a Committed Intra-Hour Scheduling pilot, in which wind projects commit to submit half-hourly schedules. Half-hourly scheduling is currently voluntary. Wind generators that participate are eligible for a 34% reduction in the wind integration rate. Also running a pilot where BPA can purchase or transmission customers can self-supply non-federal supplemental reserves to limit curtailments. BPA is also expanding an existing intra-hour scheduling pilot from increases in non-firm schedules to intra-hour schedules increases and decreases for firm and non-firm service. BPA also starting a one-year intra-hour scheduling pilot with the California ISO on the California-Oregon Intertie through October 2012. BPA also a participant in the Joint Initiative’s half-hour transmission scheduling initiative and the Intra-Hour Transaction Accelerator platform. BPA also is offering dynamic transfer capacity on some transmission paths and is a participant in the Joint Initiative’s Dynamic Scheduling System.

Follows scheduling protocols under Order 890.



None currently. With the implementation of centralized forecasting, market participant wind generators will be able to offer into day-ahead markets.

Not applicable. Not applicable.


Price can be zero or negative, but not less than the marginal clearing price. Dispatchable resources can submit offers from -$2000 to $2000. Currently, wind generators are typically classified as self-scheduling or intermittent generation and do not submit offers –they are price takers.

Negative pricing not permitted. Not applicable.

Dispatch Frequency

5 minutes for dispatchable facilities. Currently, wind generators are not classified as dispatchable and do not receive regular dispatch instructions. With the implementation of centralized forecasting and changes to dispatch obligations, market participant wind generators will be dispatched on a five-minute economic basis.

Hourly, but experimenting with several intra-hour scheduling pilots.

External—hourly schedules. WECC looking at going to 30-minute schedules with proposed FERC variable generation rule. Internal—real-time with merit order dispatch. Add plants to AGC as needed.



Currently, no penalties for settlement imbalances but penalties can be assessed for not meeting wind forecasting obligations. When central forecasting is implemented, market participant wind generators will be required to operate within a compliance dead-band when ambient conditions offer sufficient wind (to be determined).

For wind and solar projects of 200 kW or more, BPA imposes a Variable Energy Resource Balancing Service charge of $1.23/kW-month on wind generators and $0.21/kW-month on solar generators. Persistent deviation penalties applied for positive and negative schedule deviations that exceed both 15% of schedule and 20 MW in an hour for four consecutive hours. On January 1, 2012, this will be reduced to three consecutive hours. Over-deliveries are not paid, while BPA’s under-deliveries are charged the greater of BPA’s highest incremental cost or 100 mills/kWh. Variable energy generators that meet or beat a 30-minute persistence schedule are exempt. BPA, at its discretion, may waive part or all of the persistence deviation charge for extraordinary circumstances or if customers acted to avoid or minimize the deviation.

Follows Order 890 protocols.


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.

No centralized ancillary services market. Provide FERC-required ancillary services under Order 890. Also running a pilot where BPA can purchase or transmission customers can self-supply non-federal balancing reserves to limit curtailments. Pilot program in place where BPA purchases non-federal down reserves to balance increases in wind generation.

Provide FERC-required ancillary services under Order 890. Participates in Rocky Mountain Reserves Sharing Group that shares contingency reserves with multiple balancing authorities.


Wind can provide voltage control and reactive support, but no other ancillary services. The IESO will consider the integration of wind resources in ancillary markets where technically feasible in the future.

BPA began generation imbalance pilot in June 2010, whereby Iberdrola Renewables self-provides generation imbalance reserves for 1,390 MW of wind capacity.

Four wind plants in Colorado are equipped to provide regulation-down and will expand to six by end of 2011. See “Eligibility of Wind to Provide Up or Down Regulation.”



No impacts currently but are engaged in studying and monitoring.

Integration impacts of wind handled through integration charge. See Imbalance Settlement for additional details.

Instituted guideline for 30 minute non-spinning reserve to replace wind in case of ramp-down of wind power. Under evaluation.

Eligibility of Wind to Provide Frequency Response And Inertial Response

The IESO will consider the integration of wind resources in ancillary markets where technically feasible in the future.

Proposed requirement: All new wind projects must have frequency responsive capability. Wind projects >20MW provide over- and under-frequency control in the control systems, and may be required to feather for over-frequency, or if able to feather wind generation in advance, to increase generation for an under-frequency event.

Not eligible.


Not eligible. The IESO will consider the integration of wind resources in ancillary markets where technically feasible in the future.

None. Wind can provide down regulation. Xcel equipped four wind plants in Colorado with AGC in June 2011. Xcel’s Energy Management System will send a dispatch to AGC-equipped wind projects if the operating range of other generating resources is exhausted.


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. Penalty can be assessed for not meeting wind forecasting obligations. Centralized forecasting to be implemented in 2012 for distribution-connected wind generators with an installed capacity of 5MW or greater, and all wind resources directly connected to the IESO-controlled grid.

Began wind forecasting in December 2009. BPA moving towards a blended wind power forecasting model. Included is BPA’s internal automated forecasting system and external forecasting subscription services. The internal forecasting system is the bench mark for external vendor performance.

Centralized wind forecasting since October 2009.



Currently, market participant wind generators submit forecasts containing an expected output value or quantity for each dispatch hour. Real-time scheduling done on a 5-minute basis, relying on a telemetry snapshot of wind output from 10 minutes prior to setting the schedule in real time. With the implementation of centralized forecasting, market participant wind generators will have their forecasts provided via a central forecast.

Hourly forecast for next three days, updated hourly. Forecast done on plant-by-plant basis, then rolled up to BPA’s balancing area. Persistence forecast updated every minute and sent to internal and external forecast. Forecast performance evaluated within a forecast prediction interval, and how often forecast is outside that interval.

Receive two forecasts every 15 minutes. One is week-ahead with hourly granularity and updated every 15 minutes. The second is a three-hour forecast with 15-minute granularity. Xcel applies a 75% confidence interval around expected forecast.


Currently operating a decentralized forecasting system, where wind generators submit a forecast of expected generation output. Forecast accuracy is subject to compliance requirements; wind generators required to provide updates if actual output is reasonably expected to differ from original forecasts by 2% or 10 MW, whichever is greater. Decentralized forecasting will eventually be replaced by centralized wind power forecasting in 2012.

Moving towards blend of the three forecasts. BPA’s internal forecast mostly automated and pulls in NOAA, weather and wind production data. Aggregate wind forecast posted on BPA’s web site. BPA also uses data from 20 BPA-owned met towers, also posted on BPA’s web site.

Uses mix of public and private weather forecasts to produce wind forecasts. Forecast is weighed by past performance.


None. No specific ramp forecast; expect ramp prediction to be part of regular forecast.

Ramp forecast under research and development but not using ramp forecast now.


A monthly charge will be assessed to all withdrawals (mostly load) from the IESO grid to pay the centralized forecasting service provider when centralized forecasting is in place.

BPA paying for wind forecasts currently, but will incorporate wind forecasting costs into the variable generation rate for the next BPA rate case for 2014.

Xcel Energy pays for the wind forecasting services and R&D.



Day-ahead forecasts aid assessment of expected system conditions leading up to real-time. Forecasts are included in pre-dispatch every hour; results used to aid decisions on day-ahead unit commitment, spare generation on-line, and intertie transaction scheduling. Real-time scheduling uses persistence wind forecasts. Will use centralized wind forecast for dispatch in 5-minute increments.

Used for forecasting small amount of wind that serves BPA load (about 20%); for determining amount of balancing reserves that is needed, both up and down; real-time situational awareness; short-term planning, and wind event alerts.

Forecasts used for day-ahead planning, including need for day-ahead natural gas purchases. Also used in real-time by system operators for short-term commitment and dispatch but not integrated into EMS.


No capacity market. No capacity market. No capacity market.


21.3% in 2011 21.8% in 2012 18.7% in 2013 18.7% in 2014 19.8% in 2015 Note: The figures are based on a 2010 reserve margin study. Updated numbers will be available by end of 2011 for 2012 to 2016.

Information not provided. Information not provided.


No capacity market. No capacity market. No capacity market.



Model considers simulated and actual wind data, selecting the lesser value of the two data sets for each winter/summer season and shoulder period month, for the top five contiguous daily peak demand hours. Applied deterministically and/or probabilistically as needed, and distributions are used as inputs into the GE-MARS model, which randomly generates a probability value to determine wind capacity contribution to the forecast daily peak demand.

Zero value set for wind for both winter and summer.

PSCO uses a 12.5% capacity credit for wind in planning process.


No capacity market. None. Counts wind as 12.5% in integrated resource planning process.


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.

BPA requires wind generators to reduce actual output to the scheduled amount plus their reserve allocation, once 90% of dec balancing reserves have been utilized. BPA curtails wind schedules to the wind generators’ actual output plus reserve allocation once 90% of inc balancing reserves have been utilized. Requirement: All new wind projects >20 MW must have ramp rate limitation capability and governor response capability.

In certain power purchase agreements, Xcel holds the ability to curtail wind a particular number of hours per year. Beyond that, it will compensate for lost energy and the lost value of the production tax credit.


Upon its implementation, will use centralized wind forecast for dispatching wind in 5-minute increments.

Not applicable, other than the wind power management explained above.

Four wind plants in Colorado equipped with AGC and can be dispatched down. Will expand to six wind plants by end of 2011.

Documents

Wind in Market Stable Oct 2011