Last week's announcement of a new federal proceeding on transmission planning comes as time gets short to overcome regulatory obstacles and build the modern transmission system needed to beat the climate crisis, developers, former federal regulators and analysts said.
New transmission projects can take five to ten years to site, permit and build. Given that, requests for wires to deliver clean energy are stacking up on wait lists for utilities and system operators, and may not be in place when needed to help meet U.S. policy goals.
Current transmission planning is "reactive" and "addresses expansion one customer at a time," Rob Gramlich, Grid Strategies founder and president, said. Gramlich, who has contributed to several studies on transmission planning, said the current model "is not planning for the future resource mix that everybody knows is coming. We need best practice planning guidelines."
On July 15, the Federal Energy Regulatory Commission (FERC) announced an Advanced Notice of Proposed Rulemaking (ANOPR) to develop reforms to improve transmission planning and cost allocation and generator interconnection processes that could answer Gramlich's and others' concerns. FERC's action follows guidance from Congress on taking up transmission planning reform.
"We are very excited to see the unanimous support of FERC Commissioners," Gramlich said of FERC's plans to take up transmission reform. "We look forward to participating in the process with other stakeholders."
The FERC announcement is "a huge step forward" because it calls for best practices in portfolio management, scenario planning and will allow "costs to be allocated among all those who benefit," said Nora Mead Brownell, who served as FERC commissioner from 2001 to 2006.
"But first," she added, "we should deploy new grid technologies like those recognized in the FERC ruling that provide verifiable independent data instead of relying on the limited data by incumbent transmission owners to make planning decisions."
Planning reforms could be disruptive and costly, some current transmission owners have warned. But many different stakeholders have acknowledged a need for a "best practices" planning process that protects reliability at just and reasonable customer rates, and addresses the increasingly overburdened transmission interconnection queues across the country.
FERC called for stakeholder input to identify next steps, which should begin by recognizing a backlog in transmission queues that is holding back deployment of clean energy, said a joint statement from FERC Chair Richard Glick and Commissioner Allison Clements accompanying its ANOPR.
The backlogged queues
Generation interconnects to transmission through queues managed by the seven regional transmission and independent system operators (RTO/ISOs) and utility transmission owners. And capacity in those queues "is growing year-over-year," according to an analysis by Lawrence Berkeley National Laboratory (LBNL) of an estimated 85% of U.S. electricity load at the end of 2020.
Over 750 GW of generation, including over 680 GW of wind and solar, and an estimated 200 GW of storage capacity was in queues at the end of 2020, LBNL reported. That is "over 70%" of the new renewables and nuclear capacity needed to meet the 2030 clean energy targets," according to LBNL report co-author Ryan Wiser's assessment of the April 2021 Goldman School-GridLab 2030 Report.
Benefits from the needed new transmission could be three times the "at least $100 billion" cost, according to a February white paper from the Energy Systems Engineering Group's power system analysts and Energy Department research.
Not all proposed capacity is built, but "completion percentages appear to be declining, and are even lower for wind and solar than other resources," LBNL added. And "the typical duration from connection request to commercial operation increased from about 1.9 years for projects built in 2000-2009 to about 3.5 years for those built in 2010-2020."
Before approval for interconnection, each project in the queue undergoes "a system impact study," LBNL said. Project developers pay for needed new or upgraded transmission infrastructure to protect system safety and reliability. Because of the approval delays, "there are growing calls for queue reform," LBNL added.
"It is a vicious circle because the longer the delays in processing, the longer the delays in the queues," LBNL researcher and report lead author Joseph Rand added.
Landmark FERC rulemakings like Order 1000 made incremental progress by "encouraging" new planning approaches, said GridPolicy Founder and Principal Jon Wellinghoff, the FERC Chair who oversaw Order 1000's passage. "But it could have been more directive."
Now "the political and real climates have changed, and FERC planning reform is needed," Wellinghoff added. "Data-based, coordinated transmission planning and interconnection would eliminate many problems that keep renewables in the queue."
"Transmission planning processes have evolved in a fragmented, siloed way, but they should inform each other," said Concentric Energy Advisors (CEA) Senior Project Manager Julie Lieberman, co-author of a March paper identifying transmission planning best practices. "Integrated planning is needed."
Nine former FERC commissioners agreed a new FERC rulemaking on transmission planning and interconnection is needed in a January 27 webinar moderated by Gramlich.
"There is no serious climate plan without it," FERC 2001 to 2005 Chair Pat Wood III, now Hunt Energy Network CEO, told the webinar.
"But FERC does not have a lot of time to act because building transmission takes time," added FERC 2015 to 2017 Chair Norman C. Bay, now a Wilkie Farr and Gallagher partner.
With best practices planning, "utilities and third-party developers will build new lines where they are needed," said Gramlich, a former FERC economic advisor to Wood. He, Brownell, Wellinghoff and others endorsed the March CEA paper's best practice proposals.
The need is for "centrally coordinated" planning with a "holistic" approach that optimizes for cost-effective solutions, CEA reported.
Developers, to avoid Order 1000's proposals, have built mainly smaller "local reliability" projects, CEA reported. That suggests centrally coordinated planning may be "beyond immediate reach," but a FERC rulemaking could improve transmission planning enough to alleviate today's constrained queues, it added.
First, inter-regional and regional models should align "objectives, assumptions, benefit metrics, and cost allocation methodologies" with national policy, CEA said. And they should include "forecasts for future storage, renewables and gas generation" and "fossil fuel plant retirements."
Benefit metrics must be expanded beyond the commonly used Adjusted Production Cost savings, CEA said. "A too-stringent concept of benefits is a big part of the problem," CEA's Lieberman said. "There are avoided capacity and carbon costs, reliability and resource adequacy benefits, and economic, environmental, and public policy benefits."
Finally, FERC rulemaking should address ways to share costs for infrastructure upgrades among all generators and power suppliers who benefit, CEA said.
The "current cost allocation practice" defines those applying for interconnection as "cost causers" and requires them to pay for "most, if not all," of needed upgrades, CEA reported. This "participant funding approach" drives up costs and leads to "more gridlock" in the queues, which leads to "more projects dropping out of the queues."
The way current costs are allocated results in sharing "under 10% of most projects' costs" and it "has increased some developers' costs 50% to 100%," Gramlich added.
But FERC action to impose changes "is likely to be controversial and contentious," Lieberman said. "The consultation and compromise process may not reach ideal best practices, but it could start toward them."
The right direction
Completely successful examples of best practices are few and far between, Lieberman, Gramlich, former FERC commissioners, transmission builders and stakeholders agreed.
A planned SPP-MISO joint study to align their planning models for inter-regional transmission and MISO's Renewable Integration Impact Assessment (RIIA) work have some of the needed elements, CEA's Lieberman said. SPP and PJM stakeholder workshops could add to the momentum, but FERC support will be needed, she added.
Order 1000-driven projects in MISO, Texas and SPP were examples of what is possible but were limited and were not repeated, Gramlich said.
There have also been limited successes with planning process improvements in California and New York, according to an April 2021 Brattle Group transmission planning study. But California overlooked benefits like allowing "retirement of aging power plants" and New York omitted risk mitigations like "protection against extreme market conditions" and "storm hardening and resilience," Brattle said.
Key barriers to best practices are "lack of aligned leadership" between policymakers, and "mistrust" and division about jurisdiction among states, system operators, utilities and customers, Brattle said. Another is regulation that imposes "overly-prescriptive tariffs and joint operating agreements."
Though transmission developers agree with the former commissioners and analysts about many of the needed improvements in planning, they also reported barriers.
Transmission builders react
The last, and still open, FERC proceeding (RM16-12-000) on planning raised concerns about the interests of smaller-scale local transmission for the American Public Power Association (APPA). The interconnection queue problem is the "most destabilizing factor" for transmission development, its filing acknowledged.
But FERC action to expand planning authority would "encroach on state and local authority," APPA spokesperson Tobias Sellier emailed. New bulk transmission is needed now, but recently proposed FERC policies could increase customer costs. "FERC must be diligent in adopting and enforcing policies that ensure transmission rates are reasonable" and that "authorized equity returns" are not "excessive."
Planning must more specifically consider the needs of load serving entities like APPA members, an APPA statement supplied by Sellier said. On cost allocation, a "plausible reason" is needed for changes, it added.
Developers who own local transmission see some value in better large scale transmission planning. "Expanding the evaluation of benefits could be a positive step," AEP spokesperson Tammy Ridout said. And cost allocation obstacles might be avoided by changes like allowing "transmission owners to invest in and own network upgrades associated with generator interconnection."
Transmission developers that are focused on regional and inter-regional transmission are more supportive of FERC planning reforms.
Without FERC action, "the long lead time needed to build transmission infrastructure could prevent delivering significant emissions reductions," said developer ITC Holdings' VP for Regulatory and Federal Affairs Nina Plaushin. Still "polarized" cost allocation debates are of particular concern, she said.
Cost allocation has a "free-rider problem" because not all that benefit are willing to pay, Plaushin said. A FERC order must identify broader "quantitative and qualitative benefits" and move away from project-by-project planning that impose "significantly higher costs over the long run."
FERC 2010 to 2014 Commissioner John Norris witnessed polarized debate in "concerted state commission-level efforts by utilities to block Order 1000," he said. "And they continue to stall reforms, with requests for unnecessary re-studies or planning revisions."
But "incumbent transmission owners are acting perfectly rationally, given the regulatory incentives to grow the rate base through capital investment," FERC 2005 to 2009 Chair Joseph Kelliher said. "FERC sets the priorities and must decide between transmission growth and cost."
There is, however, a key first step toward resolving the polarized debates, former FERC commissioners said. Get the data.
Basing decisions on verified analysis
"The first thing we could do is make decisions based on verified data," former FERC Commissioner Brownell stressed. "Almost all data used in planning decisions is provided by incumbent transmission owner filings and it is not independently verified, but new technologies like those recognized in the FERC ANOPR can deliver independent data that can optimize system performance for planning decisions, and Department of Energy labs can verify it."
New grid enhancing technologies can provide unprecedented levels of real-time data on performance factors like system congestion, Brownell said. That data will reveal "the cost to the economy of having a transmission system built for another day, another purpose, another set of generation resources, and another set of customers," Brownell said.
LBNL found "remarkably different levels of transparency and data," LBNL's Rand agreed. And "data from utilities was generally more deficient, especially on the costs of interconnection upgrades, which limited our understanding of what is causing the queue backlogs."
"A planning process that incorporates independent data would simplify cost allocation by making it better informed," Brownell added. And data can justify FERC-authorized financial incentives, like small tariff adders based on performance-based metrics.
"We need more transparent data," former FERC Chair Wellinghoff agreed. It could also be used for a FERC-ordered "shared savings" incentive, he said. "An RFP for congestion reduction could reward the bidder who proposes the lowest price and highest congestion reduction with a share of the congestion reduction savings, as verified by the new technologies."
The planning process "doesn't work anymore, but we learned a lot about best practices from the Order 1000 implementation," Gramlich said. "There is also a lot more information about the system and the future resource mix that we could use."
FERC has "clear authority strongly affirmed in the courts, and Chair Glick said initiatives for planning reform are coming this summer," Gramlich added. Such FERC action may include technical conferences, a Notice of Inquiry and recommendations from Staff, and "always a Notice of Proposed Rulemaking with comments before the final rule, so it could easily take a year or more."