Transmission: The unsung hero of the DOE grid reliability study
New and better power lines can help integrate clean energy resources, but insiders say longstanding planning issues are blocking expansion
Much of the media scrutiny on the Department of Energy grid reliability study focused on its treatment of generation resources, but just as important to ensuring clean and reliable electricity supply is the grid that connects them.
Annual spending on U.S. transmission is expected to peak at $22.5 billion in 2017 before declining, according to a recent Edison Electric Institute (EEI) review of projects. But increasingly, sector insiders are concerned that may not be enough to meet the needs of a changing power system.
“We spend a lot of time looking at the merits of individual projects but we also need to integrate the grid as a whole,” said James Hoecker, former chairman of the Federal Energy Regulatory Commission (FERC). “An integrated system can meet the needs and manage the changes that are out there waiting but are hard to predict.”
The DOE study also acknowledged the need for “major transmission additions to connect the remote generation to the rest of the grid and to load centers.” It recommends a review of “regulatory burdens for siting and permitting” of generation and transmission infrastructure and “actions to accelerate the process and reduce costs.”
For transmission developers, the review cannot come fast enough. Jon Jipping, COO of leading transmission developer ITC Holdings, said system planners often fail to see the urgency of rebuilding the electricity delivery system.
“We are demanding that our infrastructure do things it was not designed to do,” Jipping said. “Never has both the need for reliability and the change in energy generation been so great. Transmission is central to both.”
Transmission needs and costs
Annual investment in U.S. transmission was $20.1 billion in 2015 and $21.5 billion last year, according to EEI. The utility trade group projects $22.5 billion in spending this year and cataloged “over 150 projects totaling approximately $41 billion in transmission investments through 2019.”
More investment could come due to “continued retirements of traditional baseload coal-fueled and nuclear power plants and a greater reliance on new natural gas-fueled plants,” the EEI review reports. A more “robust and flexible” system will be needed “to accommodate drastic changes in flows and dispatch” from variable renewables and to integrate plug-in electric vehicle and battery technologies.
Over 24,000 miles of new transmission was built from 2012 to 2017 at a cost of $102 billion, the DOE study reported. Well-planned transmission is “critical” to reducing costly system congestion and easing local over-generation issues.
But not all transmission investments are good ones, DOE cautions. Some spending can “increase customers’ retail bills to the extent that they are not offset by savings attributable to access to lower-cost generation or reduced congestion costs.”
System operators and transmission builders face “time-consuming, involved, and complex” challenges in developing or upgrading lines, DOE reported. First, a rigorous planning process must demonstrate the need. Then, costs must be equitably allocated and state and federal regulators must approve the line’s siting and permit its construction.
The whole process can often take over a decade as developers contend with landowner opposition, court challenges and environmental concerns.
Rocky Mountain Power (RMP) spokesperson David Eskelsen said his company contended with any of those issues in the ten-year development of its Energy Gateway transmission project, still ongoing.
The first challenge was “the complexity of the permitting process,” Eskelsen wrote in an email. The second was “the acquisition of private rights-of-way once federal land-use approvals are received.”
Even with those difficulties, a number of transmission developers in the nation’s organized power markets have found business in recent years building out new lines to serve the expansion of renewable energy. But that success in individual markets has been difficult to replicate across regions, leaving some to conclude additional policy guidance is needed to allow new lines to be strung.
Regional transmission successes
ITC Holdings has interconnected almost 3,000 MW of renewable generation into its four-state ITC Midwest system since buying out Alliant Energy ten years ago, Jipping said. Transmission “enables new technologies as effectively as it enabled the older technologies it was built to serve."
ITC developed several of the 17 Multi-Value Projects (MVPs) built in the Midcontinent ISO (MISO) service area since 2011. They will provide $13 billion to $50 billion in net benefits, or $275 to $1,000 per each current MISO customer, over the next 20 to 40 years, the system operator reported. That’s expected to work out to 2.6 to 3.9 times more benefit than cost.
The MVPs and similar projects in the Southwest Power Pool were important achievements, Jipping said, but there remains additional need.
“We know coal and nuclear plants are scheduled for closure and there are thousands of renewable megawatts in the MISO and SPP queues without transmission to take them to market,” Jipping said. “That is where the future is.”
Jipping said inadequate planning processes have not generated needed inter-regional projects. “It is urgent that we continue planning for a grid to handle all the scenarios we can foresee.”
Jipping’s urgency contrasted with more measured comments from Eric Thoms, interregional planning manager at MISO. Joint studies on inter-regional transmission show “how the process can be improved to increase the likelihood of future interregional transmission projects,” he said via email.
As stakeholders debate potential changes to transmission planning between the regions, ITC is moving forward elsewhere. The company is completing permitting and nearing construction on its merchant high voltage direct current (HVDC) Lake Erie Connector project, Jipping said. The line would connect Ontario’s wind- and hydropower-rich system with PJM.
“We are moving fairly rapidly compared to other contracted projects,” Jipping said. “But working within a regional planning process to develop a single plan that builds the right infrastructure is still the right way to go.”
Barriers to inter-regional transmission
FERC Order 1000, issued in 2011, requires regional and inter-regional transmission planning. “The explicit goal was to plan regional transmission and regional markets and they accomplished that,” Hoeker said. But regional system stakeholders “have only begun to think about inter-regional integration. It’s one of the failings of Order 1000.”
In the ruling, FERC was “very deferential” to regional systems, Hoecker said. It allowed for “planning procedures and criteria and tariff provisions that suited each region.”
Order 1000 does not require regional systems to collaborate, Hoecker said. The unintended consequence is that 2011’s patchwork system is now “bigger patches.”
The DOE grid report acknowledges the issue, citing a WIRES study that calls for transmission planning to consider “a broader range of plausible market conditions, system contingencies, and public policy environments” that could capture “short- and long-term flexibility benefits and insurance value that a more robust inter-regional transmission infrastructure can offer.”
The nation’s organized markets say they are already on the way. Like MISO, SPP has a methodical, stakeholder-based approach to inter-regional transmission planning, David Kelley, SPP director of seams and market design, said. The grid operator has worked with MISO and co-ops in its territory on multiple joint studies and each iteration “has resulted in meaningful process improvements,” he said.
But merchant transmission developers often see it differently. Officials from Clean Line Energy Partners (CLEP) say they have encountered barriers both inside and outside regional system operators' jurisdictions. The company’s proposed Grain Belt Express HVDC line, slated to deliver renewable energy across SPP’s service territory, was just delayed by the Missouri Public Service Commission (PSC).
The PSC voted unanimously last month against granting CLEP the vital power to use eminent domain in siting.
A previous 4 to 1 PSC vote acknowledged Grain Belt “meets all the criteria of being in the public interest,” CLEP President Michael Skelley told Utility Dive. But the regulators were obligated to comply with a Missouri court ruling requiring approval from every county through which the line runs.
"It would be essentially impossible to get every county to approve a transmission line or any kind of infrastructure,” Skelley said. “This country is creating significant obstacles to infrastructure investment.”
CLEP’s Rock Island HVDC line, which would carry Iowa wind power to eastern utility customers, is now contesting a separate regulatory ruling in the Illinois Supreme Court. And CLEP’s Plains & Eastern HVDC line, which would carry Texas wind power to the Southeast, obtained its necessary final approvals because the developer was granted federal authority.
Both the Grain Belt and Rock Island lines may require CLEP to request DOE authority, Skelley said, “but the federal mechanism is slow and expensive.”
“We are not pursuing it now but it is an option,” he said.
The real barrier is the lack of an inter-regional planning process, leaving new inter-regional projects “entirely to merchant developers,” Skelley said. “There is plenty that Congress or FERC or the administration could do but I am not optimistic they will act.”
One fix would be a ruling from FERC obligating regional system operators to do real inter-regional planning, he said. “There is no question that we have a sub-optimal grid and we will continue to have one until we change the way we do this.”
FERC holds the keys
The fundamental solution to transmission planning, Hoecker said, would be FERC guidance to resolving inter-regional differences. Both SPP’s Kelley and MISO’s Thoms agreed.
Disconnects between regional and inter-regional planning processes produce results that “don’t align,” SPP’s Kelley said. “Three projects approved in the SPP-MISO inter-regional planning process have recently failed to win regional approval.”
Benefit metrics, schedules, thresholds, and hurdles between the two processes also need to be addressed, he added. “Regional cost allocation policies should support, not deter, the selection of mutually beneficial inter-regional transmission projects.”
Thoms said new ways of evaluating seams projects are emerging, but he welcomed more federal input.
“FERC should allow the natural evolutionary process in aligning transmission planning and cost allocation practices between regions,” he said. “Having more seams operations standardization would help minimize regional differences.”
Paul DeCotis, a former utility executive who is now a senior director with power sector consultant West Monroe Partners, offered an alternative solution. Several New York utilities formed a joint LLC “to deliver wind in upstate to downstate load centers without jurisdictional constraints,” he said.
The joint company, New York Transco, has already built three new inter-jurisdictional projects, its website reports.
DeCotis said the joint venture streamlined permitting and made cost allocation under FERC rules easier. “It is an example of how transmission can be built despite the regulatory burden.”
But federal leadership is still needed, DeCotis said. “Hurricane Harvey in Texas is, like Hurricane Katrina and Superstorm Sandy, going to be a shock to the system that will start a new dialogue on solutions at local levels."
Where local jurisdictions do not see local benefit, as in Missouri and Illinois, federal guidance may help them accept the premise that the project is for the greater public good,” he said. “Maybe we should be thinking about energy the same way we thought about the interstate highway system. Except instead of moving cars and goods, interstate transmission moves electricity for the public good.”