As clean energy advocates urge retirement of fossil fuel power plants, securitization has become a billion-dollar word with huge implications for who will pay for and who will own the clean energy future.
Already, securitization has shown up in several state clean energy laws. Colorado legislators have been refining a power plant securitization bill (HB 1037) several times this session. In New Mexico, the “Energy Transition Act” signed in April 2019 includes securitization of retiring Public Service Company power plants. In Florida, Duke Energy has cut the costs of paying off retired power plants with securitization powers enacted over a decade ago. The Colorado bill sponsor is “‘actively talking‘ to colleagues in Minnesota, Utah and Montana about the proposal.”
So, what is securitization, and how does it play a role in a clean energy transition?
Update 5/21/19: an expert reader got in touch to suggest my estimated utility cost of capital (5 to 6 percent) was too low because I underestimated the utility’s borrowing rate and ignored how tax liability increases costs. The text has been corrected to 8 to 9 percent. For more on this calculation, see page 55 of RAP’s Electricity Regulation in the US: A Guide (Second Edition).
Refinancing to Lower Costs
Securitization is a fancy term for loan refinancing. It works much like mortgage or student-loan refinancing does, addressing both the outstanding principal owed and the interest rate. If done right, it can lower costs for utility customers and encourage early retirement of coal or other fossil fuel power plants.
Securitization works because utilities tend to have a high costs. An investor-owned utility in good financial health can raise money from shareholders and banks for a combined interest rate of about 8 to 9 percent. Although securitization methods differ, they often involve substituting customer-backed or government-backed dollars for utility equity and debt, with interest rates closer to 3 or 4 percent.
The following graphic from the Sierra Club (annotated by ILSR), shows potentially significant savings by using securitization to retire costly fossil fuel power plants and finance new renewable energy resources.
The savings are more than theoretical. “An analysis by [the Rocky Mountain Institute’s Uday] Varadarajan of possible Minnesota coal plant closures found that using the standard accounting tools of accelerated depreciation over five years and a regulatory asset would cost $29 a megawatt-hour (MWh), while securitized 20-year bonds would cost $5 a MWh—a savings of $45 million.”
In some cases––like the Colorado bill mentioned earlier––savings aren’t just passed through to customers. Colorado’s law would use 15% to set aside funds to smooth the transition for power plant communities that lose a major employer. Writing for Greentech Media, Justin Gerdes explains that, “Under the bill, 15 percent of the net present value of savings generated by the closure of a power plant — such as fuel not burned, as well as avoided maintenance and operating costs — would be directed to a new seven-member, governor-appointed body, the Colorado Energy Impact Assistance Authority, to be used for transition assistance for workers and communities.”
How Much to Pay Utilities for Past Investment?
While few disagree with the notion of lowering interest payments with customer- or government-backed bonds, a major concern is how much principal––how much of the remaining value of a power plant––to refinance. In other words, how much are aging coal power plants worth?
The size and timing of power plant improvements complicates this calculation. Unlike a house, where adding a deck might change the value but the mortgage stays the same, utilities effectively take out a new mortgage on every improvement they make. Since a plant opened, utilities likely have replaced turbines, installed pollution controls, or made efficiency upgrades. Each time, as shown in the following chart, it sets a new schedule for retiring debt that may extend for years or decades beyond the present day.
The key question is, in utility regulator speak, “prudency.” Should customers have to pay for ill-advised or imprudent investments? The law obligates customers to pay the cost of grid infrastructure built by monopoly utilities only if it can be shown to be a wise investment.
For example, was it a wise investment for Xcel Energy to pour nearly $1.2 billion into pollution controls and a new generating unit at its Comanche coal-fired power plant in 2010? With the energy market evolving rapidly at the time, how much of the $200 million that Xcel utility executives chose to spend on the aging units should be paid for by customers, and how much should be chalked up to a poor investment decision?
Securitization may allow for “socialized risk.” Whereas most entrepreneurs or companies making a business decision take on the risk that their investment will fail, most utilities being considered for securitization refinancing are government-regulated monopolies. If regulators allow, Investor Owned Utilities can push the cost of poor utility investment decisions onto utility customers by asking for customers to pay for the full value of bad investments.
Critics of the New Mexico Energy Transition Act have highlighted this very issue. New Energy Economy called the securitization deal that the state passed into law in March 2019, a “blank check,” noting that it provided the utility 100% recovery of the remaining value of all their assets, including profits for shareholders. Securitization laws in other states allow state regulators to review the amount of reimbursement utilities receive. The New Mexico law strips regulators of that oversight role.
Do Utilities Deserve a Profit Guarantee?
In securitization discussions, lobbyists for investor-owned utilities frequently request special treatment. Namely, they want guaranteed utility ownership of any power plant built to replace the refinanced and retiring power plants. Remember the third note from the chart illustrating how securitization works? Retirement of costly power plants saves customers money, but it means “the utility no longer has an asset on which to earn profits.”
An ownership guarantee means profits for utility shareholders, but it can come at a hefty price premium for electricity customers. Mariel Nanasi of New Energy Economy shared analysis with New Mexico legislators suggesting that utility-owned replacement renewable energy will cost customers 50 percent more than competitively bid power. Despite this warning, legislators allowed the company to own all of the necessary replacement power for retiring coal power plants.
Listen to John Farrell’s interview with Mariel Nanasi of New Energy Economy about the New Mexico Energy Transition Act
In Colorado, legislators have drawn up a compromise. In his coverage for Greentech Media, Gerdes writes, “As a sweetener for the utility to give up the equity in a rate-based power plant, HB 1037 permits utilities to own at least some of the replacement generating capacity.” Specifically, it sets a range of permissible amounts. At a maximum, the utility can own energy generation equal to the size of the retiring power plant, sometimes called its “nameplate capacity.” If a 700-megawatt power plant was retired, the utility can at most own up to 700 megawatts. The minimum ownership amount is then based on the capacity of the refinanced part of the power plant. So, if the principal owned on a 700-megawatt power plant was equal to 1/7th of its original cost, the utility would be allowed to own 100 megawatts of replacement power. The following chart illustrates.
Unless securitization legislation also changes the utility business model, shareholders of any utility covered under this statute––or in the similar 30 states with regulated monopolies––will likely earn a 9 to 10 percent rate of return on any of its capital spent on that replacement power. Under this model, shareholder-owned utilities stand to make a lot of money even if there are less expensive options to expand clean energy.
Where Securitization is Up
With a dubious securitization bill passed in New Mexico and a slightly more nuanced one in Colorado, where else is this policy on the table?
Twenty states already have laws on the books. EUCI reports that power plant securitization laws have been used in several ways in recent years. “Entergy Louisiana and Entergy Gulf States, for example, sold $1.65 billion in bonds to cover storm costs in the last few years. Duke Energy used $1.3 billion in utility cost-recovery bonds to retire its Crystal River Unit 3 nuclear plant in Florida. Michigan Consumers Energy used $390 million in securitized bonds to retire a 950-megawatt coal-fired plant.”
Analysis is underway of how securitization might work for a power plant owned by Minnesota Power in Minnesota. Bills are pending in Kansas and Missouri, but not expected to pass. But with millions of dollars in stranded costs at soon-to-retire fossil fuel plants and millions more to be made in developing their renewable energy replacements, expect securitization to be heard at a state capitol near you.
- Ron Lehr and Mike O’Boyle have two excellent policy briefs on Depreciation and Early Plant Retirement as well as Debt for Equity Utility Refinance
- Sierra Club has a nice overview of securitization (source of our first graphic)
- Midwest Energy News covers recent policy debates and the tensions over utility ownership of replacement power
- The Grid Geeks podcast with Uday Varadarajan of the Climate Policy Initiative and Harriet Moyer Aptekar of Crest Consulting also provides a nice securitization overview
This article originally posted at ilsr.org. For timely updates, follow John Farrellor Marie Donahue on Twitter or get the Energy Democracy weekly update. Also check out over 70 episodes of the Local Energy Rules podcast!
The cost of cutting coal — Xcel is backing away from coal power, but who pays?
By Mark Harden, May 15, 2018
Today, rumbling conveyor belts feed a stream of coal to units 1 and 2 at Xcel Energy’s Comanche Generating Station, just outside Pueblo. But the endless flow of coal and the roaring boilers could begin to go quiet in the next four years under a plan before Colorado regulators.
But in shuttering the two 1970s-vintage power units 10 years earlier than scheduled, there will be costs and questions: Who pays, how much and how? Xcel has put the cost figure at $193 million, although that number is in dispute.
These aren’t simply local questions. Across the country, utilities are shutting coal-fired power plants, in some cases because they are old and no longer market competitive, and in others because to continue running them requires expensive pollution control equipment—akin to adding a new catalytic converter to a 1988 Chevy Nova.
Since 2009, 268 U.S. coal-fired units have closed, leaving 262 operating plants, according to the Sierra Club’s Beyond Coal Campaign.
In 2018, another 12.5 gigawatts of coal-fired generation is expected to close, according to energy analyst Bloomberg New Energy Finance. That is equivalent to closing 40 Comanche 1 units.
Many of those plants will close ahead of their projected operating life, before the investment in building them has been amortized, making each a “stranded asset.” In the case of a regulated utility, like Xcel, it has the right to recoup that money from customers.
“Stranded assets are high on the list of problems, especially for regulated utilities,” said Zach Pierce, a spokesman for the Beyond Coal Campaign. “This is a big challenge all over the West.”
It could be a big challenge in Colorado, where Xcel still has an estimated $1.9 billion in coal plants still operating. “We have to find a way to pay,” Pierce said. “There is no simple solution.”
The Comanche story is, however, a bit different since the idea of closing the two plants isn’t based on the immediate need for investment in the units, which went on line in 1973 and 1975, or a lack of market competitiveness.
The closures are part of a plan to radically reposition Minneapolis-based Xcel’s Colorado subsidiary, Public Service Company of Colorado , as a predominantly renewable energy-generating utility.
“We are very committed to decarbonizing when the technology and policy choices make it possible to do so,” said David Eves, Xcel’s top executive in Colorado, said in announcing the plan last September. “It’s all about the economics.”
The utility’s “Colorado Energy Plan” (CEP) would retire the two Comanche units, with a combined 660 megawatts of generating capacity, and seek bids from developers for 1,000 MW of wind power, up to 700 MW of solar facilities and 700 MW of natural gas-fired generation or energy- storage projects.
The CEP would also involve the construction of a new switching station for a southern Colorado transmission “energy resource zone” to foster development of renewable-energy power resources in rural Colorado.
A third Comanche unit — the $1 billion Comanche 3 unit, which went online in 2010 — would continue to operate; it alone can generate up to 750 MW.
The plan, the company said, could lead to $2.5 billion in clean-energy investments. It could result in Xcel producing 55 percent of its electricity from renewable resources, and cut the utility’s carbon emissions 60 percent below 2005 levels by 2026.
In 2016, coal provided 46 percent of Xcel’s electricity, followed by natural gas at 25 percent and wind at 23 percent. Solar and hydropower provided the rest.
The CEP isn’t an act of corporate altruism, as testimony to the Colorado Public Utilities Commission shows. The plan is in response to customer calls for more clean energy, the risk that there could be future regulations on emitting carbon, and the fact that it is likely the two Comanche units would need $190 million in pollution controls to operating operate through 2035.
Xcel’s caveat is that it would not go ahead with the project if it didn’t create savings for customers or at a minimum, not cost them any more than they already pay.
At the outset, the plan looks promising as Xcel issued its request for projects and received 430 proposals for non-coal power development — about eight times as many as in its 2013 call for new projects.
The rates quoted were some of the lowest in the country, including 96 wind projects with a median price of at $18 a megawatt-hour (MWh) and 152 solar photovoltaic projects with a median cost of $29.50 a MWh. The price of 28 stand-alone battery-storage projects averages $11.30 a MWh and 11 wind-plus-storage projects average $21 a MWh.
By way of comparison, Xcel’s estimate for the all-in costs of operating the two Comanche units is about $31 a MWh.
Xcel packaged the CEP plan to the Colorado PUC in a “stipulation” that was supported by 14 other parties, including labor groups, big industrial customers, consumer advocates, environmentalist, the solar energy industry, and independent power producers who sell electricity to Xcel. The PUC staff also signed on.
“This is an opportunity to removed 4.5 million tons of carbon dioxide a year. In 10 years, that is a lot,” said Erin Overturf, an attorney with Western Resources Advocates, which supports the stipulation.
“It has clear environmental benefits and does that without raising customers’ bills,” she said. “It is a win-win, and it is voluntary on Xcel’s part.”
Xcel had hoped that with such broad backing, the PUC would approve the stipulation giving the utility a green light to proceed. But it didn’t, and here is where the complex question of costs and who pays reared its head.
The first question of who pays is the simplest. Customers will pick up the cost of closing the coal plants and building or buying the new renewable energy. How they pay and how much are more bedeviling questions.
The PUC did not give Xcel’s stipulation a blanket approval. Instead, it asked for more information and figures, in part because of challenges by the Coalition of Ratepayers, a group of businesses and citizens lead by the libertarian Independence Institute. The coalition contends it will be cheaper to keep the two coal plants running.
The coalition questioned some of Xcel’s accounting techniques, arguing they overstated the value of the renewable-energy plan.
“Xcel has the ability to put its thumb on the scale,” said Amy Oliver Cooke, the Independence Institute’s executive vice president. “We went into this being skeptical of a utility saying that is going to make a profit and save customers money. We are just asking is there truth in advertising.”
The PUC asked Xcel to run its numbers stripping away some of the accounting techniques, and even the PUC staff said the annuity method Xcel used as one measure could “skew” the numbers and should be “given little weight.”
Xcel was set to present several scenarios for the adoption of renewable resources, but said it wouldn’t provide a “least-cost” option unless it offered a minimum of $50 million in savings. The commission said it wanted to see a least-cost analysis whatever the savings.
The coalition also called for an annual cost-impact report, which the commission also adopted. “I think the coalition raised a good point,” Commissioner Wendy Moser said, before the commission voted on Xcel’s plan last March.
Xcel had go back to the drawing board on some measures and also had to evaluate the bids it has received for renewable resources. It was supposed to deliver a report to the PUC later this month, but was granted a delay till June by the PUC.
“Things are up in the air in regard to the Colorado Energy Plan,” said Mark Stutz, an Xcel spokesman.
As for the cost of closing the Comanche plants, that was split off into a separate and even more arcane case, or in PUC parlance, “docket.” Here, the accounting and regulatory jungle grows thick. As daunting as it is, a little tweak here or there can redirect millions of dollars from customers’ pockets to corporate coffers, so it is worth venturing into the weeds.
A lot of the complexity stems from the fact that, unlike a standard corporation, a utility that has been granted a monopoly over a service area is regulated by a government utility commission — in this case, the Colorado PUC — with the goal of making sure investments are prudent, rates are reasonable and the company is economically viable.
The process is ponderous. A utility must apply for an OK to build a plant or lines, which requires a docket. A request for a rate increase requires a docket and commission approval. Many dockets take a year or two to complete.
It can take millions of dollars and years to build a new plant, but a utility can’t include that plant in its rate base until it is “used and useful.”
“It is a completely archaic system,” said Leslie Glustrom, who as a private citizen has intervened more than 20 Xcel dockets, including the Comanche case. “It dates back to the beginning of the 20th century.”
Since everything takes so long, a variety of provisional measures that allow a utility to collect some revenue has developed, such as the General Rate Schedule Adjustment (GRSA), a sort of interim rate; the Construction Work in Progress, which allows some construction cost to be recouped before a plant is running; and the regulatory asset, a way for gathering the costs for a new plant or project in one place.
It is in this thicket of accounting gizmos that the battle over the cost of closing the units is being fought. Xcel has proposed setting up a regulatory asset for the closure that would be where the $192.9 million would be banked between 2022 and 2028. It is also proposing that it get a return on the regulatory asset through a GRSA.
Xcel proposes diverting half of the 2 percent charge each customer pays on the monthly bill for solar-energy projects, the Renewable Energy Standard Adjustment, to pay off and decommission the Comanche plants.
Sound complicated? That’s what intervenors in the case objecting to the proposal say.
“This approach is needlessly complex,” Kevin Lucas, director of rate design for the Solar Energy Industries Association, said in PUC testimony.
Lucas and Glustrom have both called for a separate charge on Xcel’s bills for closing the plants. There is already an item charge on the bill for closing six plants under the state’s Clean Air Clean Jobs Act that comes to about $2 on the average monthly bill.
Scott Brockett, Xcel’s director of regulatory administration, said in an email that the company’s approach has been used before in accounting for other units that have been retired early and that using a separate GRSA helps manage the costs so rates do not jump.
Still, Energy Outreach Colorado, which helps low-income households with their energy bills, is also against the approach.
“We are opposed to GRSA because that goes into fixed costs, and one of our goals is to keep fixed costs down,” said Andrew Bennett, Energy Outreach Colorado’s director of advocacy. “Before you flip on a light switch, (your) electricity bill would be higher.”
The state Office of Consumer Counsel was a signatory to the stipulation, but opposes Xcel’s plan to get — in addition to the funds to amortize and close the Comanche plants — about 7 percent return on the regulatory asset. “This was not part of the agreement,” Cindy Schonhaut, director of the OCC, said.
When a regulatory asset is used to keep track of costs for building a new project, the utility is spending money, and a return on the cost of that capital is appropriate, Schonhaut said. But this asset is being used to retire an existing plant. “There is no steel in the ground,” she said.
Xcel, Brockett said, is seeking a return on “prudently incurred costs,” and that “because the proposal represents a compromise made in order to benefit customers,” the uncollected depreciation for the plants remains in the rate base, even after the plant closes, until they are paid off. Xcel calculates savings customers as a result of closing the plants of $223 million.
Each one of these accounting arguments could translate into big dollars. The proposed mechanism could lead to a “windfall” of $14.1 million, Charles Griffey, the Coalition of Ratepayers’ expert witness, said in testimony.
The tax rate used for carrying costs in the Xcel proposal was 35 percent, even though the federal corporate rate was reduced to 21 percent last year, a group of rural cooperatives that buy wholesale power from Xcel pointed out in testimony, increasing the capital requirement by $8.3 million.
“The $8.3 million referenced is not correct,” Brockett said. “The company will update the tax rate in its 120-day report and rebuttal filing.”
The testimony, the supplemental director testimony, the answer testimony, the motions, and rebuttal filings will continue to pile up, thousands of pages. There are already six months’ worth of paper in the docket and more to come.
“The issue is transparency,” said Cooke. “We are just asking for honesty and transparency in these numbers and then let everyone decide. But the way they’ve packaged it, calling it creative accounting is kind.”
A recent study showed utility-owned solar power plants cost New Mexico customers nearly 50 percent more than independently-owned generation. The utility’s 9 percent shareholder return on its capital expenses — a common expectation of utility monopolies in 30 states — is mostly to blame for this enormous difference. PNM inflates costs by demanding shareholder return not just on its power plants, but also on the land under them (this proposal is currently pending in front of the New Mexico Supreme Court).
“There’s an incentive, a perverse incentive for them to make as much money because when they charge us more, they make more money,” says Nanasi.
The bill also offers the utility a way to retire its financial ties to old coal plants, a process called “securitization.” The policy works like mortgage refinancing, allowing the utility to get a lower interest rate on its remaining costs and save customers money. Or, that’s how it’s supposed to work. Securitization experts testified that the Energy Transition Act’s favoritism to utility shareholders — by stripping public regulators of the right to review the amount the utility is reimbursed, among other things — is “unprecedented.”
Lawmakers don’t have to accept PNM handcuffs proposed in this policy — an alternative public interest securitization bill is also circulating.
All for One And… Just for One
Despite historically high costs, the Energy Transition Act also doubles down on monopoly ownership of power generation, allowing PNM to replace the dirty, refinanced power plants solely with utility-owned generation. In the past, Pueblos or independent power producers have bid in less expensive resources to supply New Mexicans with clean electricity. In the Energy Transition Act, that practice would be prohibited.
New Mexico customers would get their power from PNM at whatever price.
The bill has echoes in other states, like in Minnesota, where the proposed “Clean Energy First” legislation would be more aptly named “Clean Energy and Utility Shareholders First,” leaving independent power producers out in the cold, and customers holding the bag.
The 18th Dirtiest Coal Plant
The Energy Transition Act’s centerpiece is the San Juan coal-fired power plant, built in what former President Nixon called an “energy sacrifice zone” on Navajo land. The power plant holds the title of the 18th dirtiest of 500 coal plants in the country. The adjacent mine that supplies the plant creates a methane cloud the size of Delaware hanging over the Four Corners region. Just four years ago, PNM finally agreed to close half the plant, but shifting economics in the energy sector have made operating San Juan too costly, and now the company wants to close it by 2022.
The catch is an accounting oddity. Despite most coal plants retiring at 50 or 60 years of service, PNM had financed the plant on an 85-year mortgage. The utility company now wants to collect on the remaining payments for two decades after the plant ceases to provide any electricity. As in most states, New Mexico law says that the financial burden of large assets like an expensive power plant should be shared between the utility and customers. Nanasi explains how PNM doesn’t care to share in these costs and is using its political muscle to avoid doing so:
“When there is a financial burden like this or like an unexpected boiler breaks and it’s a lot of money. There’s a law that says there should be a sharing of the burden between investors and customers. Sometimes it’s just straight up determined as a 50-50 split and sometimes after a hearing maybe it’s 70-30 or 20-80, depending on the situation. But here PNM is running to the legislature — by the way, they give a lot of money to those legislators for their election campaigns — and saying ‘hey, just give us 100 percent without any vetting whatsoever.’”
The Moment Calls for Local Choice, Not Monopoly
Nanasi is adamant about the way the proposed legislation undercuts the opportunity of this moment to address climate change by deploying local, clean energy that builds wealth in New Mexico communities.
“Now, we have a new way. The new way is that we can have distributed energy, especially in place like New Mexico, where we can put solar up next to the biggest cities, or we can even put up wind, but much closer to where the load centers are. To double down on the old, old way which is centralized plants. It’s kind of like–yeah, dial up phones were great compared to calling an operators, but no one who has a cell phone today would want to go back to dial up,” she points out.
“These bills that double down and increase, enlarge, enhance, exacerbate the utility monopoly structure cheat us, cheat the people of lower cost, decentralized energy,” says Nanasi. “It’s sort of like a 1 percent – 99 percent issue. Why do we still want to give all the money to the monopoly utility instead of investing in all sorts of cool, local choice energy situations.”
Nanasi went on to describe another piece of pending legislation that would move New Mexico toward “local choice” energy instead — community solar. Modeled on Minnesota’s nation-leading policy, but improved, this bill would make it easier for the average electricity customer to supply some of their own electricity from solar energy, hedge against rising electricity prices, and enable communities to keep their energy dollars local.
A Call to Regulators to Do Their Job in the Public Interest
While the problems of the Energy Transition Act stem from the utility monopoly having too much power to influence policy, Farrell shares why state officials are also culpable. Drawing on perspective from regulatory expert Scott Hempling, Farrell explains how public regulators are exercising too little power on behalf of the public interest.
The problem is that public regulators too often see themselves as judges deciding between the private interest of utilities and public interest of advocate organizations, forgetting that their charge is instead to represent and defend the public interest, period. Nanasi couldn’t have agreed more, insisting regulators do their job:
“They’re supposed to be regulating on behalf of the public. What’s really been sacrificed here in New Mexico is the common good,” says Nanasi on her state’s utility regulators. “That’s what’s gotten us to this moment of a climate crisis and a crisis of income inequality. In order to make major changes…in order to support the people…means taking away, removing the license of these monopolies to run ramshod over our environment, our health, and our economy.”
For more information on the Energy Transition Act, SB 489, check out coverage by New Energy Economy. For another example of a monopoly utility milking the legislature for resources, check out our commentary on the Becker, Minn., coal plant replacement in 2017 and also John Farrell’s tweet thread on utility monopoly.
This is the 72nd edition of Local Energy Rules, an ILSR podcast with Energy Democracy Director John Farrell that shares powerful stories of successful local renewable energy and exposes the policy and practical barriers to its expansion.
Kansas, Missouri among latest states to debate refinancing for aging coal plants
Bills surfaced in both states that would let utilities refinance uneconomic power plants using ratepayer-backed bonds.
After gaining traction in the West, proposals to help utilities finance early retirement for coal-fired power plants have moved into the Midwest.
State lawmakers introduced bills in Kansas (SB 198) and Missouri (SB 289) this year to facilitate a type of refinancing for aging power plants known as securitization. While the legislation isn’t expected to pass, it has opened the door to discussions.
Securitization works similar to refinancing a home. A utility that’s still paying off what it borrowed to build a power plant is allowed to repackage the debt as bonds backed by a ratepayer guarantee. The result is a significantly lower interest rate, typically around 3%-4% compared to 7%-8% for conventional debt.
The tool was first used by utilities during the 1990s to help clean up financial books in advance of deregulation in several states. Today, it’s resurfaced as a potential solution to help lessen the financial sting of closing coal-fired plants.
New Mexico recently passed a bill approving the use of securitization for an uneconomic coal plant, and Colorado is considering something similar.
“That’s the new twist on it,” said Jeremy Richardson, a senior energy analyst for the Union of Concerned Scientists who has made the case for securitization to help communities transition from coal.
Despite the potential, ratepayer-backed bonds never have been used to refinance coal plants, according to Jeremy Fisher, a technical adviser with the Sierra Club. However, he predicted that day is drawing nearer. The New Mexico legislation specifically targets using securitization to finance early closure of the San Juan Generating Station.
Utilities have used the bonds for a variety other of purposes including financing pollution-control equipment and repairs after massive storms. Duke Energy Florida issued ratepayer bonds a few years ago to retire a nuclear plant damaged by some repair work.
Zack Pistora, who lobbies the Kansas Legislature for the Sierra Club, is keen to see securitization become a tool for Kansas utilities.
“By refinancing existing capital asset loans, we can save ratepayers money and transfer capital away from outdated energy infrastructure to new, lower-cost conservation and renewable energy projects,” he said.
Utilities generally may issue ratepayer-backed bonds only with the approval of their state utility regulator. The sale of bonds transfers outstanding debt on certain utility assets to a third party, which lists as a separate item on utility bills. Because of the lower interest rate, utility customers should see costs reduced.
The implications for utilities are less clear cut. A substantial portion of utility profits in regulated states come in the form of a “rate of return” on money invested in assets, usually for either generating or distributing power. At a Kansas legislative committee hearing in March, representatives from two utilities made clear that securitization would not serve the utility’s interests.
“Securitization as proposed in SB 198 … would fundamentally alter the regulatory compact upon which utilities and their customers have relied for a century,” Chuck Caisley, senior vice president for marketing and public affairs for Evergy, told the committee. The company resulted from the recent merger of Westar and Kansas City Power & Light. The bill, he continued, “could negatively impact investor-owned utilities’ ability to cost-effectively attract capital needed to fund current and future investments in generation and the electrical grid.”
Although the bill went no further than a committee hearing, Pistora said several legislators were intrigued by what securitization might do for constituents.
“They like the idea of immediately cutting electric rates,” he said. “Refinancing can happen immediately compared to some other ways to bring down rates.”
The Legislature did approve a bill that will provide funding to hire a consultant to study the high price of electricity and ways — including securitization — to reduce it.
The sale of ratepayer bonds to cover debt payments would mean that portion of a power plant or other asset no longer would count as part of that utility’s current capital investments which, in turn, are the basis for a large part of a regulated utility’s profit.
However, the utility would have access to newly available investment funds that it could put into a different, more economical asset such as a wind farm or solar array. That could raise other issues, though, according to Richardson.
“When a power plant closes, the utility might want to own whatever replaces it,” Richardson said. “They don’t want capital sitting around. They want to invest in something. Some people say they shouldn’t have guaranteed ownership. That is also a point of contention.”
The rapid changes in energy technology, and the tumbling prices of wind and solar energy relative to power from coal, have left utilities in a difficult spot, said the Sierra Club’s Fisher. “If you’re holding onto something that is not in the ratepayer’s best interest,” he said, “you have three options — and none of them is especially attractive.”
A utility can accelerate the depreciation on the asset, which would lead to a spike in rates. Or the utility could spread the cost over many more years than it actually plans to use the asset, which could be challenged by customers or regulators. Or the utility could just take the power plant off the books — meaning that shareholders would have to cover the cost of an unused power plant.
“It leaves you in a pickle if you’re a utility or the regulator or, frankly, the consumer. Securitization takes some of the problematic aspects and softens them substantially.”