A Southern utility conglomerate, a vertically integrated Pacific Northwest company, and a rural Midwestern IOU have very different takes on renewables but transmission is the key for each, their representatives agreed at WindPower 2014, the annual industry event.

Minnesota Power

Transmission in North Dakota made Minnesota Power’s (MP) success possible, according to Project Development Manager William Sawyer.

The small IOU realized in 2006, when 95% of its 1,800 megawatt capacity came from coal, there was a bargain in North Dakota wind for its ratepayers, especially because 43% are 24/7 industrial customers.

MP recognized its western neighbor has one of the best U.S. wind resources. Soon after, it recognized its northern neighbor, Alberta, has one of the best hydro resources. A unique transmission and trading system now allows the utility to import low-priced North Dakota wind and Alberta hydropower and to store wind as hydropower in Alberta.

By 2013, MP’s Energy Forward program was at 20% renewables and 80% coal. By the end of this year, it will be at 25% renewables, which meets the state’s 2025 mandate. MP’s 2030 IRP targets 33% renewables, 33% natural gas and biomass, and 33% coal.

A small utility can integrate renewables without complexities, Sawyer said. But not all U.S. regions are created equal. The right mix of renewables “depends on the availability of natural resources and the ability to deliver those resources.”

Southern Company

Southern Company, one of the biggest U.S. electricity suppliers with over 46,000 megawatts of generation capacity and retail customers in four states, is heralded by wind advocates for four power purchase agreements to import 654 megawatts of Kansas and Oklahoma wind into the Southeast.

That wind is part of a portfolio of “reliable and affordable energy for our customers,” Retail, Renewables, and Planning Manager Chris Habig explained. The company also funds wind forecasting and modeling programs, Georgia offshore wind studies, small wind demonstration projects, and resource assessment projects in Georgia, Mississippi, and Florida.

There are significant challenges and risks in developing wind in the Southeast because forecast uncertainty and intra-hour variability can be difficult for grid operators, Habig said.

But there are also drawbacks to importing wind, he added. Transmission systems may curtail wind in response to distant conditions irrelevant to the offtaker. A market or balancing authority response to local conditions can interfere with delivery. And the many potential congestion costs and market dynamics along the delivery route create more layers of uncertainty.

“We don’t have any wind offerings right now,” Habig said. “But solar is the buzz, especially in Georgia.”

Portland General Electric

Portland General Electric (PGE), a vertically integrated Oregon generation, transmission, and distribution provider serving Portland and Salem, is on the verge of a major transition. It is planning to go from the twentieth century’s hourly scheduling, trading, and dispatch of energy and capacity via telephone to state-of-the-art intra-hourly dispatch, according to Merchant Transmission and Resource Integration Manager Ty Bettis.

With over 700 megawatts of wind and 25 megawatts of solar built and another 300 megawatts of Variable Energy Resources (VER) planned to meet Oregon’s 25% renewables by 2025 mandate, PGE has outgrown its reliance on Bonneville Power Association.

It is planning technology upgrades, more VER integration, and a fifteen minute marketplace. “In the future there will probably be an Energy Imbalance Market, either NWPP or CAISO, and more energy and capacity resources, Bettis added. “The future is more dynamic dispatch.”

The objective is a Real Time Dispatch Tool (RTDT) that increases the efficiency of dispatch and automates decision-making in VER integration.

There is a gap between what is scheduled for base load and what is scheduled for load, Bettis explained. Before PGE’s increased VER, a “less complex portfolio” allowed “single unit dispatch” of either hydro or thermal resources that could be done in an hourly framework.

Humans can make hourly decisions from spreadsheets, he said. But assessing physical, administrative, and transmission constraints and fuel costs and making decisions about energy and ancillary services every fifteen minutes requires an RTDT.

Balancing wind with hydro worked for PGE just as it did for MP, Bettis said, until abundant wind drove prices so low that the still vital thermal generation became uneconomic. “Wind had to be curtailed and that added a whole other layer of complexity.”

The big picture: Utilities and renewables

Both Bettis and Sawyer said their companies are working toward EPA emissions regulations compliance with more renewables and less thermal generation.

“Rules are not necessarily the decision point for us. Cost is,” Habig said, “because we operate in states without renewables mandates.”

Responding to a question, Sawyer said MP has not developed new pumped hydro. “The economics haven’t been there. But it is coming around.”

“New pumped hydro storage doesn’t pan out economically,” Bettis said. But PGE will “probably use batteries to balance the impacts of solar on feeders.”

“Further down the penetration path we will probably have to rely more on our pumped storage,” Habig said. “Our research on batteries show they are still cost prohibitive but they will probably be used to support feeders.”

 “When we open feed-in tariff programs for solar, they sell out in twenty minutes,” Bettis said. “We will need batteries in the distribution system to keep it from falling apart from wear and tear.”