utilities and wind power

Wind Integration

Utilities can typically add wind power to their portfolios without major adjustments in the planning, operations, or reliability of their systems, according to studies looking at experience or modeling wind integration scenarios, as well as experience in Europe where wind energy development is much more widespread.   Integration adjustments are lowest when new wind power is being integrated into a broad region with modern, properly-crafted tariffs and a diverse mix of power sources, such as natural gas and hydropower. 

To address wind energy’s variability, some incremental generation may be required for system balancing.  While this is not a reliability issue, it can add a modest amount to the overall cost of electricity service.  The costs of this generation include the costs of keeping the generators available and ready to operate, and the fuel costs of operating them.  The exact costs depend on the mix of generation on a given system and various other factors.  In a document prepared by the Utility Wind Integration Group in coordination with the trade associations of all three utility sectors (investor-owned, public, and cooperative), the studies and experiences with utility wind integration are summarized as follows:

1. "Wind resources have impacts that can be managed through proper plant interconnection, integration, transmission planning and system and market operations.
2. System operating cost increases arising from wind variability and uncertainty amounted to only about 10% or less of the wholesale value of the wind energy.
3. A variety of means – such as commercially available wind forecasting – can be employed to reduce these costs.
4. In many cases, customer payments for electricity can be decreased when wind is added to the system, because the operating-cost increases are offset by savings from displacing fossil fuel generation."

One of the primary conclusion from this survey of studies from different parts of the country is as follows:

"[This study] lays to rest one of the major concerns often expressed about wind power: that a wind plant would need to be backed up with an equal amount of dispatchable generation."

For more information, refer to the Utility Wind Integration Group (UWIG) website at http://www.uwig.org/opimpactsdocs.html

Some of the key Wind Integration studies are summarized here:

Xcel Energy
Xcel North, the former Northern States Power Co., sought in 2003 to determine the ancillary-service costs incurred to accommodate an existing 280-MW wind plant in Minnesota, where the system is summer peaking, with a peak load slightly in excess of 8,000 MW. Calculation of the intra-hour load-following reserve requirement of the Xcel-North control area load and aggregate wind generation data indicated that the addition of 280 MW of wind capacity did not significantly increase the load-following reserve requirement.  Load frequency control simulations produced results showing almost no change in the Area Control Error standard deviation between scenarios including and excluding wind generation, suggesting that wind penetration of 280 MW on an 8,000 MW peak system has no significant impact on the control performance.

PacifiCorp 2003 Integrated Resource Plan (IRP)
At modeled wind penetration levels of 2,000 MW (20%) on the PacifiCorp system, the average integration costs were estimated at $5.50/MWh, and consisted of an incremental reserve component of $2.50 and an imbalance cost of $3.00.

We Energies 2003
We Energies worked with Electrotek to evaluate the impact on ancillary service costs of adding up to 2,000 MW of wind capacity to its system supplies of 5,900 MW of primarily coal and nuclear units and additional capacity purchases to meet peak demands during all seasons. For wind penetration levels varying from 250 MW to 2,000 MW for a 7,000-MW peak load in 2012, Electrotek found ancillary service costs ranging from $2/MWh to $3/MWh, with load and wind variations considered together. Sensitivity studies showed that the increase in regulation reserve for wind integration was small compared to the reserve carried for normal system regulation purposes associated with load variations and load forecast uncertainty.

Xcel North/Minnesota Department of Commerce
A study of a possible 15% capacity penetration (1,500 MW) on the Xcel North system, undertaken by EnerNex for the Minnesota Department of Commerce, showed that the cost impact would not be significant ($0.23/MWH regulation; $0/MWh load-follow; $4.37/MWh unit commitment; $4.60/MWh total impact), and could be further reduced with improved scheduling, forecasting, and markets (http://www.commerce.state.mn.us).

New York Independent System Operator (NYISO) and State Energy Research and Development Authority (NYSERDA)
This study, evaluating the reliability implications of bringing on line 3,300 MW of wind generation (approximately 10% of the NY state peak load), concluded that the current system can accommodate such an increase at no additional cost.  That is because the transmission system is relatively large, the tariff accommodates market-based adjustments when output is variable, and the generation mix is diverse and flexible.  What’s more, there would be net economic benefits to adding this amount of wind energy to the state system.  The executive summary table of conclusions is as follows (Table 2.2, page 2.6 http://www.nyserda.org/publications/wind_integration_report.pdf )
 

For any questions, contact Jeff Anthony, the AWEA Manager for Utility Programs at janthony@awea.org