Joseph Krist

Publisher

This week our issue is devoted totally to developments in the electric utility sector. As the smoke from the western fires blew east, it served as a reminder to all of the dominant role of climate change in the current political debate.

We highlight a number of situations illustrative of the many challenges that climate change and its management present to producers, distributors, and investors in the utility industry. As is always the case, municipal providers and issuers will be at the center of those debates. Every level of government – state, federal, local – is involved in them.

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MULTI STATE REGULATION AND CLIMATE CHANGE

The Kentucky Public Service Commission issued an order Thursday rejecting Kentucky Power’s request for a certificate to implement and recover costs for federally required environmental upgrades at the Mitchell plant near Moundsville, WV that would keep the plant operational for another 19 years. Instead, the commission approved completing only enough environmental upgrades to keep the plant federally compliant and operating through 2028. Kentucky Power had contended that making the necessary environmental upgrades to keep the 50-year-old Mitchell facility operational through 2040 was the most economical option, noting that the company will have a substantial capacity shortfall if Mitchell is retired in 2028.

The total estimated cost of allowing Mitchell to operate through 2040 was $133.5 million. The total estimated cost of allowing only implementation of and cost recovery for complying with rules regulating handling and disposal of coal combustion residual materials was $35.1 million, excluding the cost of capacity that Kentucky Power will need to obtain once Mitchell is retired. Kentucky Power and Wheeling Power each own 50% interest in Mitchell.

And that complicates the process of closing coal plants with joint owners and different regulatory jurisdictions having oversight of those owners. Add in the fact that Kentucky Power and the West Virginia owners presented differing viewpoints as to the potential overall financial impact of closing Mitchell in 2028 vs. 2040. Appalachian Power and Wheeling Power said in their December filing with the West Virginia Public Service Commission that performing only the coal combustion residual compliance work at Mitchell and retiring the plant in 2028 has “comparable costs and benefits” to making the additional wastewater compliance investment to allow the plant to operate beyond 2028.

It is not a cost-free decision as to the plant’s future. There were 214 people employed at the Mitchell plant that were compensated a combined $26.8 million in wages in 2020, according to Appalachian Power and Wheeling Power.

GROWING PAINS OF AN ELECTRIC FUTURE

We came across stories recently about what can best be described as growing pains experienced by one mass transit system as it attempted to add all electric buses to the vehicle mix. We found one that puts a municipal transit agency right in the center of the issue.

SEPTA is the mass transit provider for Philadelphia and its surrounding metropolitan area. In 2016, it announced that it would purchase a fleet of 25 electric buses. The goal was to gradually add to the electric fleet with the intention of replacing all 1500 of SEPTA’s buses with electric vehicles. The first of the buses went into service in 2019. They cost some $1 million each so it was a substantial investment even with federal aid. So, it is all the more troubling that those 25 buses no longer operate but may turn out to be a major impediment to the development of all electric public transit fleets.

Proterra is the nation’s largest manufacturer of electric buses. More than 100 public transit customers throughout the U.S. and Canada have purchased Proterra buses. So, it is a problem when a system like Philadelphia reports structural issues with the buses. It turns out that the problem may not be manufacturer specific. The problem in Philadelphia is that the issues include cracked chassis and other defects, some discovered before operation.

Proterra buses were also taken out of service in Duluth, Minnesota, after officials realized that hilly routes and heaters were draining batteries too quickly. Proterra buses were also taken out of service in Duluth, Minnesota, after officials realized that hilly routes and heaters were draining batteries too quickly. It would seem to be a quality and warranty issue specific to the manufacturer.

But wait, a battery fleet from Chinese manufacturer BYD was taken out of service in Indianapolis for upgrades due to range issues, while officials in Albuquerque, New Mexico, returned 15 BYD buses for similar reasons.  BYD is the manufacturer in House Minority Leader McCarthy’s district.  The issue seems to be more related to the weight of electric vehicles. The battery technology used is quite heavy, so manufacturers naturally seek to reduce the weight of vehicles through the use of plastics and the like.  Logic says that cracking should not be a surprise.

The pandemic and its impact on the demand for mass transit has already left many systems in a vulnerable financial position. Now as the politics of climate change get more intense, transit agencies see themselves in the position of having to accept some level of operating risk as electric vehicles develop. That risk translates into potentially significant financial risk if capital investments in rolling stock do not satisfy service requirements. It’s just one more hurdle for mass transit providers to overcome.

GREEN NEW DEAL AND JOBS

One of the primary issues impacting the debate over how to best address climate change is the issue of economic displacement. The closure of older existing power plants always causes disruptions to local economies and workers. It is one of the main arguments that supporters of the status quo in terms of the environment cite when explaining opposition to the transition to cleaner energy. Proponents of the Green New Deal always claim that it will provide “good-paying” union jobs to replace those lost at existing generation facilities.

Unfortunately, initial indications are that this will simply not be the case. An electricity plant powered by fossil fuels usually requires hundreds of electricians, pipe fitters, millwrights and boilermakers who typically earn more than $100,000 a year in wages and benefits when they are unionized. So far at least, those jobs do not have comparable replacement roles for workers on renewable generation facilities. This is especially true for solar installations. It takes far more people to operate a coal-powered electricity plant than it takes to operate a wind farm. Many solar farms often make do without a single worker on site.

A NY Times article illustrated one example. In 2023, a coal- and gas-powered plant operated by Consumers Energy in Michigan, is scheduled to shut down. The plant’s 130 maintenance and operations workers, who are represented by the Utility Workers Union of America and whose wages begin around $40 an hour plus benefits, are guaranteed jobs at the same wage within 60 miles. The utility, Consumers Energy, concedes that it doesn’t have nearly enough renewable energy jobs to absorb all the workers.

The staffing industry says that about two-thirds of the roughly 250 workers employed on a typical utility-scale solar project are lower-skilled. They can make $20 an hour. That’s a far cry from $60 an hour at a union site.  It is a significant obstacle to generating political support for the Green New Deal. And it is typical of how the environmental movement has constantly understated the true overall costs of the changes it wants. It’s not just about the price of power to the customer. There are also issues associated with worker displacement. When all of those costs are included in the analysis, the economics of the Green New Deal are much less appealing.

That may account for why the Times chose to publish its article on a Saturday, the traditional landing date for bad news.  An announcement this week from the Department of Commerce’s Economic Development Administration (EDA) highlights a Coal Communities Commitment, which allocates $300 million in American Rescue Plan funds to coal communities. This investment will ensure that they have the resources to recover from the pandemic and will help create new jobs and opportunities, including through the development or expansion of a new industry sector.

The U.S. DOE reports that Electric Power Generation declined by 63,300 jobs from 2019 to 2020 for a total of 833,600 jobs. Not all types of generation declined. Wind added 2,000 jobs, an increase of 1.8%. Solar, which includes both Concentrating Solar Power and Photovoltaics, shed the most jobs, declining by 28,700. The largest year over year percent decline was in coal, which decreased 10%, or 8,300 jobs.  

Employing 937,700 workers in 2020, the Fuels sector declined 211,200 jobs from 2019. This 18% loss was the highest out of any of the five categories. Job losses were concentrated in oil and gas, with oil declining by 121,300 and gas decreasing 66,000. Job losses in biofuels were the lowest, ranging from 1,000 for Woody Biomass to 1,400 for Corn Ethanol.  

NUCLEAR

Earlier this year we commented on a proposal for the development of “modular” nuclear generating units. The Carbon-Free Power Project was to build 12 interconnected miniature nuclear reactor modules in Idaho to produce a total of 600 megawatts. It would be the first small modular reactor in the United States. The plan was to have the plant owned largely by members of the Utah Associated Municipal Power Agency.

The initial plan was not supported by all of the UAMPS members even though it would provide carbon free power to replace coal fired power. So, the project’s sponsors went back to the drawing board. “After a lot of due diligence and discussions with members, it was decided a 6-module plant producing 462 MW would be just the right size for (Utah Associated Municipal Power Systems) members and outside utilities that want to join,” according to UAMPS.

The reactor is planned to be built on the DOE’s 890-square mile desert site west of Idaho Falls at Idaho National Laboratory. The plant is expected to be running by 2029. Initially, the plan did not have unanimous support from all of the UAMPS members. The downsizing reflected a more reasonable assessment of the level of financial risk with which the project would be viewed. Right now, 28 UAMPS participants have committed to a total of 103 MW. 

Downsizing the project reduces the project’s costs and the amount of power it can produce, overall. The energy cost that project partners will pay rose from $55 per megawatt-hour to $58 per megawatt-hour. And the amount of power each of the six modules can produce has risen from 50 to 77 MW. The project is currently working toward submitting an application to the NRC in 2024 to build and operate the reactor. Even project proponents are concerned about the lack of commitments for more project capacity however.

UNDERGROUNDING TRANSMISSION

There are many costs to be considered when you look at the cost of grid resiliency investments by electric systems. One of them is the cost of undergrounding transmission lines. The demand for these actions is best reflected in the ongoing saga of California wildfires. One major transmission network has been under threat from the massive Oregon fire. Now, one of the newest California fires may be able to claim PG&E transmission lines as its source.

As a state report assigning that blame came out, the company announced a plan to bury at least some of its transmission infrastructure. Today, PG&E maintains more than 25,000 miles of overhead distribution power lines in the highest fire-threat areas (Tier 2, Tier 3 and Zone 1)—which is more than 30% of its total distribution overhead system. Now it has announced a multi-year effort to underground approximately 10,000 miles of power lines. Based on underground power line proposals that PG&E has previously submitted to state regulators, the project could cost about $4 million per mile

About 18 percent of the country’s electric distribution lines are buried, including those for nearly all new residential and commercial developments, according to the Edison Electric Institute. As one might expect, most of the negative reaction to the plan reflects a desire to see ratepayers unaffected by the cost of these investments. It’s hard to argue against wildfire mitigation but as is the case with so many aspects of climate change, it has to be paid for. The expectation of some ratepayer impact is not unreasonable.

The significant public ownership of much of the electric grid in the NorCal and Northwest regions is where municipal debt exposure to fire is. Joint action transmission issuers as well as the many Oregon/Washington public utility districts can be exposed as well.

TRI-STATE GENERATION

Last month (6/28) we outlined issues facing the large rural electric provider Tri-State Generation Co-op. Now, the story moves to its next phase. As we discussed $136.5 million prior, Tri-State was under pressure to provide estimates of projected “exit fees” for Tri-State participants who wished to leave the Co-op. Now, Tri-State has provided this information to two such participants and the reaction has been negative.

Tri-State said that its exit fees are based on the higher number of two calculations: the exiting cooperative’s share of the utility’s debt, or the present value of all the electricity Tri-State would have sold the co-op to 2050, minus any sales of the departing member’s share of the association’s electricity in wholesale markets. Tri-State’s total debt at the end of 2020 was $3.3 billion, according to a federal filing. 

The resulting numbers for United Power and Durango-based La Plata Electric Association — were $1.5 billion and $449 million. In contrast, two other members who left Tri-State – the Kit Carson Electric Cooperative, in Taos, New Mexico, which left in 2019 and paid fees of $37 million and the Delta-Montrose Electric Association in 2020 which paid $136.5 million. Should those fees stand, local co-op participants could see their financial standing quite negatively impacted.

OHIO CORRUPTION AND THE ELECTRIC INDUSTRY

Over the recent months, we’ve followed the ongoing fallout from the nuclear power industry’s efforts to derail clean energy policies and legislation in the State of Ohio. The House Speaker has been indicted, aides have taken pleas, and utilities have faced charges. Now,  FirstEnergy agreed to a $230 million penalty for bribing former House Speaker Larry Householder and former Public Utilities Commission of Ohio chairman Sam Randazzo.

FirstEnergy and its affiliated companies had hoped to see passed a $1 billion bailout for two FirstEnergy Solutions-owned nuclear plants, secure money for FirstEnergy Corp. through a decoupling Between 2017 and March 2020, FirstEnergy Corp. and FirstEnergy Solutions, now called Energy Harbor, donated $59 million to Generation Now, a dark money group controlled by Householder. The $230 million fine will be split 50-50 between federal and state government. Ohio’s $115 million will go toward a program that helps Ohioans pay their utility bills.

And in spite of the guilty pleas from the bribe payer, the Speaker still insists that the payments were legal campaign donations. In the meantime, renewable development took a hit when Ohio became a bit of an outlier in terms of preemption. A new law says county governments can pass resolutions to ban large wind and solar developments, or say that certain parts of their counties are off-limits to wind and solar projects. Developers need to give county governments at least 90 days’ notice before filing an application with the state regulator, the Ohio Power Siting Board, so that county officials have time to review the plan and take action before the state board begins its review.

This follows enactment earlier this year of a law which bans local governments from restricting the use of natural gas. Local governments already are barred by the state from taking actions that would limit oil and gas production.

MMWEC

The Massachusetts Municipal Wholesale Electric Company (MMWEC) plans to build a 55-megawatt natural gas-powered peaking generation plant in Peabody, MA at the site of an existing plant. That 20 MW facility will be closed and replaced by the 55 MW plant. The decision to retire the older, less efficient plant was made after hearing the concerns of ratepayers and analyzing new census data which shows an increase in the number of “environmental justice areas” surrounding the plant.

Local residents had cited health concerns as well as what are broadly characterized as equity or economic justice issues. Originally, the new plant would operate as well as the older plant. Recently, the old plant’s owner Peabody Municipal Utility reviewed 2020 census data showing the number of at-risk communities living in the areas surrounding the industrial park. The decision to not operate the old plant followed quickly thereafter.

It is just one example of the range of potential obstacles facing developers of new generation in the current political environment. In urban areas, economic justice and equity issues will drive opposition. In rural areas, concerns about aesthetics and land usage will drive opposition. The road to clean energy remains bumpy.

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