Developers push for purchase contracts
Much of this year's United States wind power development is supported by the major utility powerhouses, such as PacifiCorp with its 1100 MW solicitation in the Pacific Northwest and Xcel Energy, which recently issued a 500 MW solicitation for renewable energy development in Colorado. But in states where utilities are not as accommodating, developers have turned to an old and little used law in order to get their projects built.
Last year, the Idaho Public Utilities Commission (IPUC) gave its approval to two small wind farm contracts totalling 19.5 MW submitted to Idaho Power as qualifying facilities (QF) under a provision of a 1978 federal law. And in the Midwest, a Houston-based wind developer, having given up on getting a power purchase agreement (PPA) with a coal-based Dakota utility, is filing its 31.5 MW wind farm as a QF project.
Passed by Congress during the 1970s energy crisis, the Public Utilities Regulatory Policies Act (PURPA) was enacted to encourage independent power producers to develop renewable and alternative energy technologies. It required utilities to purchase the output of QF projects and to pay the utility's avoided cost of energy, which is the price it would have had to pay to generate the power itself or purchase it from another source.
right conditions
Much of the 1980s build up of wind capacity in California was due to the QF provisions in PURPA. In fact, 25% of Pacific Gas & Electric's and 30% of Southern California Edison's current power purchases are from QF projects, including wind, geothermal and cogeneration projects. Even today, given the right set of conditions -- length of the contract and size of the project -- the QF rate can be more favourable for a wind developer than is the more common PPA. And, because a utility must take power from QF projects, it can be used as a tool to integrate wind resources into the systems of utilities reluctant to do so on their own.
In April 2004, the IPUC approved the first Idaho wind generation agreement between Idaho Power Company and United Materials for the 9 MW, six turbine Horseshoe Bend Wind Park near Great Falls, Montana. In late November it approved a second agreement between Idaho Power and Exergy Development Group of Missoula, Montana, to build the 10.5 MW, seven turbine Fossil Gulch Wind Park near Hagerman along the Snake River in southern Idaho. Exergy is building both projects.
The utility's Dennis Lopez says Idaho Power is set to integrate far more wind energy than just these two projects. It is awaiting acknowledgement from the IPUC of its integrated resource plan, which includes 350 MW of wind capacity, nearly 38% of the 900 MW of capacity the company will need through 2013 (“uåX˜äŠÊ˜·³Ç, September 2004), and about five per cent of the company's total energy sales. Lopez says it likely will release a solicitation for the first 200 MW of wind capacity this month and anticipates the projects coming online in 2006.
But that, apparently, wasn't soon enough for James Carkulis of Exergy. He filed the projects as QFs and effectively forced Idaho Power to accept the output for both projects while the federal production tax credit (PTC) is still in effect. The PTC, worth $0.018/kWh, is set to expire December 31, 2005.
"His projects appear to have been ahead of our curve," Lopez says. Carkulis declined to comment.
advantages
Not all utilities are as agreeable as Idaho Power. John Callaway of Superior Renewable Energy in Houston says that Montana-Dakota Utilities (MDU), with headquarters in Bismark, North Dakota, has resisted signing a PPA for more than two years and his company is now in court to get MDU's records on its avoided cost. Callaway wants to build the 30.4 MW project this year near MDU's transmission lines in north central South Dakota using Vestas V80 1.8 MW turbines, but MDU has strung his company along too long, he says. South Dakota has no QF projects after 27 years of PURPA, which shows how entrenched coal is in the state, Callaway says.
Going the QF route has advantages, he says. "I think we'll get a better deal. It appears we'll get capacity payments, we get to keep the green tags and we'll get a better price than we could negotiate with MDU." After a formal hearing in March, he hopes to begin construction this summer. But there can also be drawbacks. Callaway chose the PPA route first because it is generally a simpler process, while the QF route can be fraught with legal issues.
They can also be limited in other ways. Both Idaho Power projects received 20 year contracts and $55/MWh energy prices, and project owners retain ownership of environmental attributes and the value of the PTC. But according to the PUC order, each project must deliver no more than 10,000 kWh in an hour, averaged over the month, or Carkulis would have to settle for an avoided cost lower than the $55/MWh. That will force Exergy to scale back a bit on the 10.5 MW Fossil Gulch project. In addition, project owners must reimburse Idaho Power when production from the facilities falls below 90% of the promised delivery amount and the replacement power exceeds the contract price. Idaho Power must pay the owners a market-based price when production exceeds 110% of projected output.
Still, this is a much better deal than that offered to Northern Alternative Energy (NAE) early in 2003 by Northwestern Energy in Montana, says NAE's John Jaunich. After NAE's 50 MW Golden Sunlight project lost a Northwestern's renewables solicitation, the Montana Public Service Commission (PSC) suggested that NAE file its project as a Qualifying Facility and force Northwestern to buy the project's output anyway (“uåX˜äŠÊ˜·³Ç, February 2003). NAE's original bid was for $28/MWh, but the PSC ruled Northwestern would have to pay only its short term cost of power at the "ridiculously low price of $10/MWh" if the project was built as a QF, Jaunich says. "The $55 (Idaho Power is paying) is more in the ball park."
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