The need for additional generation to compensate for wind variations is disappearing.
Utility-based studies have laid to rest the concern that a wind plant needs to be backed up with an equal amount of dispatchable generation. Even at moderate penetrations, ancillary services to back up new wind power need not be more than is required of a system as a whole.
An initial report on utility integration of wind, compiled by the Utility Wind Interest Group (UWIG), an organization of more than 50 utilities with wind power on their systems, looked at a series of studies from Xcel Energy, PacifiCorp, Bonneville Power Administration, We Energies, and consultant Eric Hirst, and concluded that the need for additional generation to compensate for wind variations by backing up a wind plant with an equal amount of dispatchable generation "is substantially less than one-for-one and often closer to zero."
The 162-MW Colorado Green wind farm, completed in 2003, illustrates not only that wind can be economic against other fuels, but also that the need for additional generation to compensate for wind variations is, as the UWIG report says, much less than one-to-one.
The Colorado Public Utilities Commission (PUC) and Xcel Energy scrutinized the economics of the proposed wind project in Lamar, Colo. The PUC ruled that the wind power bid was "justified on purely economic grounds, without weighing other benefits of wind generation that could be considered under the IRP rules" (). Three important results emerged in particular from the analysis.
First, new wind generation was predicted to cost less than new gas-fired generation, assuming gas costs of more than $3.50 per million BTU or thousand cubic feet (mcf).
The Colorado commissioners decided that the price of natural gas likely would rise beyond the utility's base case (about $3 per million BTUs and declining) over the 15-year purchase contract. What's more, they found that "even if the company's base forecast of natural gas prices turns out to be accurate, the Lamar bid is still economic unless ancillary service costs are at the high end of the estimates" (). The PUC staff also testified that the Lamar wind-farm bid was the lowest of all the bids submitted in the entire request for proposals, except for one small hydro proposal.
More broadly, the following graph shows the levelized cost (capital costs, fuel costs, operation and maintenance costs, divided by output) of wind and natural gas, at different levels of natural gas price ().
All other things being equal, at about $3.50 or more per million BTU natural gas, and assuming wind projects in good locations, it makes economic sense to analyze the economic contribution that wind can make. Wind is likely to be the most competitive option for new generation on a levelized-cost basis.
Second, wind power received a fair capacity value based on the utility's method and data. In the Colorado case, the utility conducted a reliability analysis to estimate any firm capacity value for the 162-MW Lamar project, and it determined that the project would provide reliability benefits equivalent to 49 MW of conventional generation. At issue was the question of value. The commission evaluated the utility's "Preferred Portfolio + Wind" option solely on a capacity and energy basis and found that the capacity benefit was approximately $36 million (1999 net present value).
Assigning capacity value for wind, once a contentious issue, is now an increasingly well-documented exercise. Geographic diversity from wind farms built in new areas will ease wind integration into utility systems by smoothing out wind-power production. Depending on the wind resource, added wind-plant geographic diversity could contribute to utility peak-hour production needs (capacity value).
PJM Interconnection LLC, the regional transmission organization (RTO) that operates utility transmission and balances electricity supply and demand in seven states and the District of Columbia, allows wind-based generators to receive capacity credits based on a three-year rolling average of a unit's output during PJM's peak-use hours. For units with less than three years' operating experience, a "class average" credit applies, which PJM defines as 20 percent of a wind turbine's rated capacity. The average-updated periodically as more wind generation is added to the PJM system-is based on the operating experience of wind turbines in use in the region.
Third, and perhaps most important, ancillary services to back up new wind power were not a major cost. In the Colorado case, the PUC staff witness based calculations of these costs on the spinning reserve levels required by the Western Systems Coordinating Council, a body that oversees reliability in the region's grid. That decision was made because allocating system-wide ancillary service costs to a particular resource such as wind is both arbitrary and uncommon.
Moreover, evidence from various utilities with wind on their systems shows that the need for additional generation to compensate for wind variations is negligible, even at moderate penetrations. Pacific Gas and Electric Co., for example, has operated an integrated utility system with as much as 10 percent of its generation coming from wind, without any increase in ancillary service costs.
Articles found on this page are available to subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.