Since the company announced its plans to construct the line this summer, Duke has said the lines will help strengthen the electric grid and manage a burgeoning need for electricity in the company’s western service territory, which has much less generation capability than other parts of Duke’s system. The lines would run from Asheville to Campobello, S.C.
Each year, Duke is required by the North Carolina Utilities Commission to file an Integrated Resource Plan, a long-range planning document detailing infrastructure needs for forecasted electricity requirements for the next 15 years, including transmission infrastructure needs.
In Duke’s September 2014 IRPs for both Duke Energy Progress and Duke Energy Carolinas service territories, the company does not list a planned transmission project similar to the proposed Foothills Transmission Lines.
It does, however, allude to a potential project in the Asheville area and the shortcomings of the transmission capability there, and a Duke spokesman said plans for the transmission lines came about when the opportunity arose to convert the Asheville plant to natural gas.
In the IRPs, Duke explains that the company “monitors the adequacy and reliability of its transmission system and interconnections through internal analysis and participation in regional reliability groups.” Internal analysis “looks 10 years ahead at available generating resources and projected load to identify transmission system upgrade and expansion requirements.”
Certain reliability groups assess the system’s ability to handle large transactions, ensure that future transmission system improvements don’t adversely affect neighboring systems and ensure the system is in compliance with North American Electric Reliability Corp. standards.
Those groups look at peak season in the next five -and 10-year periods, the IRP states, and perform computer simulation tests to “verify satisfactory transfer capability.”
Both IRPs then state that after careful review of the company’s transmission systems, both are “expected to continue to provide reliable service to its native load and firm transmission customers.”
This statement seems to contradict repeated claims by Duke officials, including Glenn Snider, Duke’s director of resource planning and analytics for the Carolinas. Snider told the North Carolina Utilities Commission Public Staff and a packed crowd of roughly 1,000 at Blue Ridge Community College on Sept. 3 that “we alluded to the need for the new transmission line in our 2014 IRP as a potential project that we were looking at to help deal with growing needs in our western service territory.”
What really sparked the transmission line project, Snider said in a phone interview, was the possibility of using transmission in lieu of building oil-fired turbines known as “peakers” at the Asheville generating plant. The turbines are inefficient and only fired up during times of high need.
The transmission lines were alluded to in the IRP as a potential alternative to building those peakers, he said, allowing Duke to provide the additional capacity through transmission.
And, indeed, under Appendix A: Quantitative Analysis, the IRP for the Duke Energy Progress region states, “Additional fast start generation capacity is projected to be needed in the Asheville area in the 2019 timeframe if the electrical transmission constraints into the region are not addressed. There is currently a project under consideration to bring additional transmission into the Asheville area that could eliminate the need for additional fast start CTs (combustion turbines).”
A lot of the work that goes into creating IRPs, which are filed in September, happens in early to mid-summer, Snider explained.
Since then, as the company was studying the Asheville plant, complying with North Carolina Coal Ash Management Act and “a host of federal and state environmental standards” that influence the cost of running the coal plant, an opportunity arose in the expansion of PSNC’s natural gas pipeline along Interstate 26.
Duke had to act fast on the pipeline or miss the opportunity, and decided to convert the Asheville plant, company officials have said.
“So the option became ‘Oh, if we move quickly we can avoid spending money at the coal plant and can participate in this pipeline opportunity,” Snider said, adding that low natural gas prices were the third part of the equation.
But, “the wires were always a solution for load growth,” Snider said of the transmission line project.
Coal versus natural gas
In planning models up through and including 2014, Duke planned on having the coal assets including the Asheville plant in operation until 2030. The transmission lines were being considered, whether the Asheville plant was converted to gas or not, he said.
Snider explained that the lines are needed to help meet peak demand, which last winter reached roughly 1,200 megawatts, though the system currently has an import capability of 750 megawatts, with a generation capability in the region of about 865 megawatts.
Just meeting that peak demand is not enough, though, he said.
“You have to have levels of redundancy in both transmission and generation,” Snider said.
For example, if a rock slide knocked out a tower holding transmission lines or the flow of a natural gas pipeline was interrupted, there needs to be enough capacity in the system to cover the gap and meet that peak demand, avoiding blackouts, he explained.
“The transmission helps to serve the load, but some has to be left un-utilized to be able to handle one of those units (going) offline,” Snider said.
When it closes the Asheville coal plant, Duke will retire approximately 380 megawatts of coal generation, Snider said, and scrap plans to build 126 mW in oil-fired turbine capacity. With the subtraction of that roughly 500 mW in generation capability and the addition of the 650-700 mW that will be produced at the new gas plant, only about 200 mW of generation is being added to the region.
In essence, Snider said, Duke is taking 500 out and putting in 650-700.
The 2014 IRP for Duke Energy Carolinas region states a consumption and annual growth rate for all customers at 1.5 percent, and Snider said it holds true for Duke Energy Progress as well. However, those numbers are system averages, Snider said, and the west has historically grown more in the 2-3 percent range.
The Duke Energy Progress West region encompasses Avery, Buncombe, Haywood, Madison, Yancey and Mitchell counties and partially serves Henderson, Transylvania, Jackson and McDowell counties.
The transmission line project is slated to run primarily through the Duke Energy Carolinas region, which partially serves Henderson, Transylvania, Jackson and McDowell counties and includes all of Polk County and Upstate South Carolina.
Generation and transmission support one another in serving load growth, Snider said, adding that if peak demand is currently at 1,200 mW and the growth rate is 2 percent, then next year, the peak will be about 25 mW higher, and in four years 100 mW higher.
So the couple hundred megawatts of added generation capability must be paired with the transmission capability to meet needs down the road, he said. Duke’s not planning just to meet 2020 needs, but wants to build for years to come.
“This couple hundred (megawatts) keeps us from coming back” with another plan to meet growing demand, Snider said. “We could be coming back in one or two years saying, ‘what do we do for 2022, 2023?’”
Weighing the facts
Chris Ayers, executive director of the North Carolina Utilities Commission Public Staff, said the weight that those previous assessments will hold in the approval process is left up to the North Carolina Utilities Commission. The commission will weigh all input after Duke files its Certificate of Environmental Compatibility and Public Convenience and Necessity to decide whether the transmission line is warranted.
“We think right now that this provides probably the most reliable, most robust, lowest-cost solution for the long run,” Snider said. “We’re going to work hard not to let lights go out, no matter what.”
If the transmission line project is denied, Snider said he can’t say whether that means the coal plant will continue to operate. The company will be developing contingency plans, but doesn’t have one firm plan in place yet.
“We don’t want to leave you with the impression that we’re going to let the lights go out,” he said.