Energy prices might be going down, but public power utilities — and customers — are seeing transmission costs go up and are facing policies and regulations that might lead to further increases.
Randy Howard, general manager of the Northern California Power Agency, a joint powers agency serving 16 public power utilities in California, said that transmission costs are the fastest growing component of members’ and customers’ bills. Over the past decade, NCPA members have seen transmission costs increase more than 10% per year. In real terms, Howard said that means some California customers have seen transmission costs go up from about 8%-12% of their bill to about 25%-30% of their bill.
Customers in Oklahoma have also seen transmission costs become the fastest-growing component of their bill, said Dave Osburn, general manager of the Oklahoma Municipal Power Authority. He estimated that the joint action agency has seen average annual increases of about 9%-10% per year since 2012. For OMPA, Osburn said, that amounts to about $12 million per year in new transmission expenses, and it has not seen an equivalent offset from decreased energy costs.
“That has certainly got our attention, because over that same period, we have seen virtually no load growth, because of energy efficiency programs and natural improvements in energy efficiency,” said Osburn.
In Missouri, Jeff Knottek, director of transmission planning and compliance at City Utilities of Springfield, also reported an average increase in transmission costs of about 10% per year for the last seven years, although he expects those increases to level off for the next several years.
Factors affecting costs
Osburn and Knottek both pointed to the robust transmission build-out that has occurred in the Southwest Power Pool, to which both entities belong, which has totaled about $10 billion in expansion costs in recent years.
Osburn said the buildouts have allowed for a vast amount of wind power to move around the region, have relieved congestion, and have supported some of SPP’s economic projects.
Tom Kent, president and CEO of the Nebraska Public Power District, described the cyclical nature of transmission development, where the system expands to support increased load, improvements need to be made, and then capacity grows to the point where system capabilities need to expand again.
NPPD is the largest transmission owner and operator in Nebraska, overseeing more than 5,000 circuit miles. Kent said that NPPD is in an expansion phase with its transmission system, most of which has been done under SPP’s transmission planning and expansion process. He estimated that about $750 million in recent transmission system investments has gone toward new facilities.
“Utilities located in western wind-rich areas, where many of the transmission upgrades have occurred, generally experience more benefits than utilities located along the eastern edge of the footprint,” said Knottek.
Knottek said that City Utilities faces high congestion costs and higher locational marginal prices. He estimated that City Utilities pays about $5 per megawatt-hour more than the average SPP transmission customer, and almost $10/MWh more than some members in the western part of SPP.
“We’ve been on the short end of the stick of the transmission buildout,” said Knottek, who explained how the costs have compounded. “We’re paying for these assets over 40 years. Annual new construction projects get added to your prior year, so the total end cost continues to grow and multiply; it keeps going up each year.”
In California, Howard pointed to the uptick in wildfires as contributing to added transmission costs in a number of ways.
“One in 10 wildfires are started by power lines, but 10 out of 10 are damaging our infrastructure,” he said. The cost to replace and recover these assets has been expensive, and he estimated that wildfire insurance costs have also gone up about 500% over the past few years. On the operations side, NCPA members also have implemented enhanced vegetation management efforts, which Howard said have doubled or sometimes tripled those costs. Members have also taken a hit when the public safety power shutoffs have occurred at the transmission level, cutting off entire communities.
“While we have taken a number of measures to try to mitigate costs occurring year after year, the expectation is that we will see transmission cost adders of 15%-25% increases per year for the next few years due to wildfires,” he said.
Howard said that most of his members are principally dependent on transmission assets owned by Pacific Gas and Electric. As such, the investor-owned utility’s transmission cost structure has a major impact on the public power utilities’ rates.
Howard believes that IOUs have turned to transmission as a key component of gaining a rate of return on investments, especially since many have divested from generating assets and instead rely on power purchase agreements that don’t offer a rate of return.
“We see what appears to be gold plating and a transfer of capital structure to transmission — probably more so than necessary,” he explained.
In 2016, NCPA made a claim with the Federal Energy Regulatory Commission in regard to about $1.8 billion of annual capital expenditures that do not go through any stakeholder process. Although the initial claim did not turn out favorably for NCPA, an appeal to include NCPA members as part of a stakeholder process over transmission expenses received a favorable decision. However, due to backlogs at FERC, Howard said that there are currently three outstanding rate proceedings (NCPA has since made the same case in subsequent years), which have yet to be approved.
“It’s quite frustrating that with these rate cases, they have been able to collect the rates, even though we have shown that they aren’t prudent rates, there are over-collections and our members are due these refunds,” said Howard. “It is quite problematic, because it gives an incentive for a transmission owner to seek more than they know they are going to get, just because they have the ability to derive the revenue for several years before they have to give some of it back.”
Howard said that NCPA members are due several hundred million dollars in refunds if FERC approves the rate case settlements, which, given PG&E’s current status, means that they might have to pursue the funds through a bankruptcy proceeding, adding another layer of complication.
Osburn said that OMPA has been “pretty aggressive” in finding ways to offset rising transmission costs. OMPA filed a complaint with FERC to lower the return on equity, which was successful in lowering some of its transmission costs. He said that it is helpful to be able to challenge the high rates of return that transmission owners receive, which he said can be about 10%-12%. Economic effects from the Tax Cuts and Jobs Act of 2017 also helped to slightly lower OMPA’s transmission costs, according to Osburn.
“We’re not always successful, but it helps to be engaged,” said Osburn. “A lot of it gets down to the transmission planning models used, and what assumptions are used. Try to get input on those assumptions.”
He said that having staff engaged or working through a joint action agency or at the national level is important, particularly if there are any committees or working groups that focus on cost allocation.
OMPA has also implemented robust energy efficiency programs, which Osburn said has helped to lower its peak by anywhere from 12 megawatts to 18 MW.
Despite the costs City Utilities has seen from transmission expansion over the past decade, Knottek said the utility continues to push for further builds along SPP’s eastern seam as a way to relieve congestion and increase customer benefits. “The way you can do that is by building additional lines or increasing the ratings of facilities,” he said. “Obviously, there’s a cost to do that, but part of the beauty of being in an RTO is that you’ll have 18 or 19 other transmission owners that are also contributing. You don’t have to bear all of the cost of trying to build the transmission and plan it all.”
“The underlying goal is to ensure that everyone who is using the system is paying their fair and appropriate share of costs,” said Kent. “The challenge can come from the different view of the same coin.”
In 2019, Kent led an effort among SPP members called the “holistic integrated tariff team,” which examined SPP’s transmission planning process and cost allocation, as well as other issues. He noted that the team provided SPP with several recommendations on cost allocation.
In SPP, members are divided into pricing zones, and costs are allocated on a license plate basis within each zone.
“As new entities come into those pricing zones or as zones change, sometimes you can get unintended cost shifts that can be problematic,” Kent said. He mentioned that the holistic tariff team made some recommendations for how SPP could ensure that changes to pricing zones were more equitable.
“The rules may be slightly different from region to region, but the underlying fundamentals are very similar — to put the costs on who is benefitting from the expansion,” said Kent. “For new generation, if the developer wants to build, and if a study determines that transmission needs to be upgraded to reliably support that generation, then the beneficiary is the generation developer, so they are tasked with the cost.”
“We built generation so that we didn’t really rely on others to provide our resources, but it seems that those days are long gone,” said Knottek. “It is cost prohibitive. You need to take advantage of a pool where you have more access to a diverse mixture of resources.”
OMPA explored the possibility of building its own transmission assets but found that the rules, which Osburn said have been established in large part by major transmission owners, have made the effort difficult.
When it comes to transmission development, “there’s sort of a double standard,” said Osburn, who explained that there doesn’t seem to be uniform criteria for when projects get built for reliability purposes, and when costs can be shared. He also noted the risk of developing assets that might become stranded due to increased development of distributed generation.
“If more and more load is going to be served at the local level, who is going to pay for the transmission system?” asked Osburn.
He brought up FERC’s recent notice of proposed rulemaking regarding transmission incentives, which suggests increases to incentives for transmission owners to build.
“We’re very concerned by that — you don’t need to incentivize folks to build more transmission or to gold-plate it,” said Osburn, who noted that such a move would further increase transmission expenses.
“I personally don’t see a lot of need for incentives for a transmission owner to be in an RTO/ISO or a lot of need for incentives to build new transmission,” said Howard. “Where incentives are needed is with transmission owners to optimize the utilization factor of their transmission assets.”
“If we can have more megawatt-hours flowing over the lines during more hours of the day, we could reduce the cost and provide benefit to our end use customers directly in doing so,” added Howard.
“It’s rarely just one issue that drives the need to expand transmission,” said Kent. “Usually, you have a combination of economic benefits or reduced congestion, as well as reliability benefits or some other quality benefit, such as more renewable generation that could be added.”
Knottek described the cost-benefit analysis of transmission projects as subjective and noted that societal or environmental benefits, such as gaining access to more clean energy, can be weighed differently from community to community.
Kent agreed that evaluating costs and benefits of transmission builds is complex and nuanced, which is why, he said, it is important for utilities to actively participate in the process. “At the end of the day, the just and reasonable standard has gray in it.”
He added that the planning process is helpful in identifying the economic value of projects and the cost-benefit ratio to system users, and that having a planning process helps ensure regional transmission organization funds are being used appropriately to benefit the consumers of the area.
Kent acknowledged that NPPD is a large public power utility, and therefore has the ability to be more engaged within the RTO. He advised that smaller utilities voice their concerns through a state association or joint action agency that can give the issue attention and represent any concerns about transmission costs or planning.
Knottek echoed that many complaints stem from those who do not have a role in transmission planning. “If you are small, you might not have the wherewithal to build transmission or generation; there’s a real benefit to being part of an RTO.”
To stay engaged with a lot of the activity happening at the regional or national levels, Howard said that NCPA is part of the Transmission Access Policy Study group and is an active member of the American Public Power Association. He noted that he’d like to see more involvement by other joint action agencies in the proceedings, and he commended APPA for its efforts to bring various public power parties together and get in front of the Commission.
“Our voice needs to be heard; we need to be at the table. And many times at FERC, we’re not well represented on these cases,” said Howard. “FERC proceedings are complicated and expensive, and the extent to which we can join in with TAPS or APPA is critical.”
“We have to tell these stories and to talk about these costs,” said Osburn. “Not all of these investments come through RTOs. Quite often, they are built by the transmission owner with no oversight, no rate case.”