News
The cost to integrate wind started low, but will more than double as wind generation approaches 30% of the resources mix, according to BPA. Preliminary estimates, excluding some costs, are that the cost of integrating wind at 5% of peak load costs $1.90/MWh but rises to $2.40/MWh at 10%, $3.70/MWh at 20% and $4.60/MWh at 30%. Integration costs are comparatively low when integrating wind with hydropower, which has substantial flexibility, but rise as more wind is added and ultimately reach a plateau at the cost of integrating wind with natural gas-fired power plants.
Bonneville says it will integrate 650 MW of wind in 2007 alone for a total of 1,400 MW in its control area. That will be 15% of the agency's 9,000-MW peak load, but the ratio is going up year after year, with projections for 1,300 MW of wind to be added in 2008 and 1,500 MW in 2009.
BPA intends to develop a rate to be effective Oct. 1, 2008, that recovers the costs of providing within-hour balancing services for wind generators connected to BPA's system, according to an Aug. 27 open letter from Transmission Services Policy and Strategy Manager Elliot Mainzer. A workshop was held Sept. 11 and two more are slated for Sept. 27 and Oct. 25 as the agency seeks to collaborate with its customers and wind generators to develop the rates.
BPA said it may make a policy decision to offer resource support services under its tiered rate design, with five levels of "Tier 2" service. Services for resources offered above its "high water mark" level would fall into the higher Tier 2 rates. BPA must build or reserve capacity equal to the average amount of energy produced by a resource minus that resource's lowest hour of expected generation. The reserved capacity must be charged at a rate equivalent to the fixed capital costs of the marginal capacity resource at around $8.50/kW per month.
Tier 2 rate pool costs will include the costs of resource shaping services specific to each set of resources underlying power purchase agreements for the output from specific resources. The costs of each power purchase agreement are unique and may vary by rate period, with embedded escalation provisions.
The agency must also be able to absorb the highest hour of expected generation because it runs the risk that its existing resources cannot absorb the added energy. In the case of hydro or pumped storage, the agency would have to spill water rather than use it to generate power or use it at a less efficient time. Therefore, the agency will have to assess a sink charge.
The need for these services and a specific rate to pay for them was identified in the Northwest Wind Integration Action Plan completed earlier this year.
Because wind output varies, other generation capacity must be available to meet variations.
To develop the rates, the additional balancing service required for wind generation must be forecast, along with methods for determining costs and a rate design to recover those costs. BPA plans to issue an initial rate proposal in February and a record of decision in May 2008, and FERC approval will be sought next summer.
Ancillary services include generation-supplied reactive and voltage control, operating reserves, regulating reserves, generation and supply imbalance needs.
Wind generation affects both near real-time regulation and the balance-of-the-hour requirements. For 4,000 MW, that would increase the balancing requirement by about 50 MW over the 80 MW otherwise required, BPA said.
The balance of the hour for wind output fluctuations would increase about 200 MW over the 500 MW otherwise required, the agency continued. That does not count extreme wind ramp events, which, if included in balancing requirements, could double the amount of balancing required and more than double the cost of providing additional balancing. Wind ramps are large unscheduled changes in output of a wind farm or collection of wind farms, and extreme ramps could greatly add to operating reserve requirements and costs. Large wind farms have fewer ramps due to spatial and directional placements. Studies continue on balancing requirements.
While larger wind farms spread over a wide, geographically diverse area smooth the impacts, dramatic swings in wind output sometimes still occur. Ramp controls are being considered as alternatives, but would only be imposed for system reliability events. Estimated costs of lost wind generation with ramp controls will have to be worked out.
In addition, integration of large amounts of wind will require dynamic voltage control at wind farm sites or available transmission capacity, and grid performance will be reduced, according to the agency.
Costs to support wind and reshape it for flat annual block products would add to within-hour and hour-to-hour and ramping costs.
BPA is studying various options for its rate design. Under one option, the agency would treat resources the same as load, with charges for production of less energy than forecast and credits for performance higher than forecast. Another way would be to address over- and under-performance through periodic true-ups of customer rates in resource pools. A third means would be to use a forecast guarantee with updates.
| < prev | next > |