Utilities outline challenges to wind integration

Managers from three utilities described the challenges their companies face as they consider adding increased amounts of wind and other renewable resources to their generating portfolios during a session May 24 at Windpower in Dallas.

Displacing two-cent coal
David Rich , renewable energy development manager for the Nebraska Public Power District, said “displacing two-cent coal becomes a challenging event with 4.5-cent wind.”

His state ranks third in wind potential, but 27th overall in terms of net installed capacity. That’s because laws adopted in the 1930s gave condemnation rights to public power authorities, enabling them to take over generation assets. That law, which was modified in early April, discouraged most wind developers from working in Nebraska, the only state where public power authorities are the exclusive providers.

Rich said the economic downturn left Nebraska with an excess of capacity. He said it will be another decade before new baseload capacity is added. Around 85 percent of the state’s electric generation is nuclear and coal.

Nebraska’s newly enacted Wind Export Priority Bill stipulates that 90 percent of any wind energy developed in the state must be exported. The remainder must be offered to public power authorities through power purchase agreements. The law also gives public power authorities condemnation power for transmission projects.

Not as favorable
Tim Kawakami, who directs purchased power deals for Xcel Energy, said renewable energy standards in states where his company operates is the primary force driving wind development. Ten years ago Minnesota, Colorado and Texas had just under 300 MW of installed wind capacity on the Xcel system. In 2009 that number stood at 3,200 MW.

“Gas makes wind not as favorable as in the past,” he said, referring to natural gas prices, which some analysts see as entering a period of low volatility. He said wind project financing challenges are greater than in the past and that power purchase agreements (PPAs) often contain “more difficult concessions.”

Another challenge is that some states requrire so-called “carve-outs” for renewable resources other than wind. Colorado, for example, has a 4 percent set-aside for distributed generation. Other states have solar carve-outs.

Kawakami listed as some primary challenges transmission, price stability, uncertainty over extending the federal performance tax credit, turbine availability and system integration. He said Xcel is working to improve integrating wind into its system through data sharing requirements, turbine and meteorological towers, turbine, wind speed direction, turbine outages, as well as temperature and air pressure and density.

“Tested and tried”
Michelle Arenson, who directs wind energy development for Alliant Energy, said utilities such as hers are more comfortable owning wind resources as technology risk has eased. “Utilities recognize the equipment infrastructure could be trusted,” she said, and that manufacturers are “tested and tried.”

At the same time, however, she cautioned that PPA risk has increased. She noted a “significant” price disparity between developments and that utilities carry PPAs on their books as debt rather than as an asset. That makes it increasingly difficult for developers to put together successful projects. “PPA = equal debt; ownership = asset,” a presentation slide read.

“Utilities want to control their own destiny,” she said. Many prefer to control relationships with landowners who are also their retail customers.

Turning to transmission, Arenson said substantial upgrades are needed in MISO, the region where Alliant operates. She said unresolved cost alloction issues related to transmission are a “major driver” in determining wind power’s ability to penetrate the market.