UCS Blog - Clean Energy (text only)

What Will DTE’s Electricity Future Look Like?

DTE wind energy facility in Huron County, MI Photo: James Gignac

On June 20th, the Michigan Public Service Commission (MPSC) is holding a public forum and information session on an important electricity planning process involving DTE Energy’s electric subsidiary.

This is a key opportunity for residents and business owners to learn about—and share their views and input on—DTE’s long-term proposals for fulfilling customers’ electricity needs.

As Michigan’s largest electric utility, DTE provides electricity to 2.2 million customers in southeastern Michigan. Through a combination of coal, nuclear, gas, hydroelectric pumped storage, and renewable resources, DTE has the capacity to generate over 11,000 megawatts of power.


DTE’s Belle River Power Plant in East China, MI Photo: Flickr/Tgrab

While DTE has taken positive steps by announcing a carbon reduction goal in 2018 and shuttering some of its oldest coal-fired power plants, two of its coal plants have been listed in the top 100 greenhouse gas polluters nationwide. The Monroe and Belle River plants together spewed 23 million metric tons of carbon dioxide pollution into the atmosphere in 2014.

DTE’s Risky Gas Plant Investment

In December 2016, Michigan enacted wide-ranging energy legislation that included a requirement for utilities to develop and submit integrated resource plans, which are intended to be robust studies into the best resources for providing power needs to customers in the future.

DTE, however, sought approval to build a large new gas-fired power plant after the legislation passed but before the integrated resource planning requirement kicked in.

Gas plants are not clean resources and investing in them is a risky proposition for electric utilities. Union of Concerned Scientists and other advocates showed that the cost to build a portfolio of clean energy resources was about $340 million less than the cost to build and run DTE’s proposed $1 billion gas plant.

Unfortunately, the MPSC approved DTE’s gas plant project in April 2018.

An Opportunity for a New Direction

Now that the integrated resource plan requirement is in effect and DTE has longer-term proposals before the MPSC, it is crucial to ensure the company is retiring additional coal plants quickly and replacing them with clean energy resources—not more gas.

Another large Michigan utility, Consumers Energy, filed its integrated resource plan last year that was just approved by the MPSC. Consumers’ plan includes a phase-out of all its coal plants, replacing them with clean energy resources such as energy efficiency, demand response, and a large increase in solar power.

In its integrated resource plan filing, DTE is currently proposing to retire its Belle River and Monroe coal-fired power plants in 2030 and 2040, respectively. The MPSC must closely examine whether continuing to operate these plants for that long is in the best interests of ratepayers. Additionally, DTE’s plans to increase solar power are mostly delayed until after 2025. Earlier investments in solar could avoid the potential need to build another expensive and risky gas plant contemplated in some of the company’s future scenarios.

Stakeholders, residents, and business owners have an opportunity to make their voices heard to the MPSC on June 20th. Let’s make sure DTE moves away from coal and gas and toward a clean energy future for Michigan.

This Crazy Trick Could Help New Orleans Utility Customers Save Money

Image courtesy of Alliance for Affordable Energy

Over the past year or so, a lot of states with renewable portfolio standards (RPS) have opted to double down on that policy mechanism to set a path to 100% clean electricity. However, most jurisdictions in the deep south have been reticent to pass such policies. That might change later this year, as the City of New Orleans considers passing an RPS. And that’s the crazy trick that could save customers money. Passing an RPS.

EQ Research, DSIRE Database

Map of Proposed new RPS/CES (left) and Maps of Current RPS (Right). Click to enlarge.

I’m not saying that an RPS will guarantee more affordable energy; but, by passing a 100% renewable portfolio standard, the city of New Orleans has the opportunity not only to help reduce carbon emission but also make electricity more affordable for its residents.

I had the privilege to work with the Alliance for Affordable Energy in drafting technical responses to questions posed by the city council—which also serves as the local utility regulator—about the cost complying with an RPS. A copy of the comments can be found here. There are two important takeaways I wanted to share:

Protecting New Orleans’s electricity consumers

While state-level RPS policies have proven to be an affordable driver of new renewable energy development, the best policies feature strong consumer protections to help ensure that people can still pay their electricity bills. Nationally, one in every three Americans struggle to pay their energy bills, and that burden is three-times greater on low-income households.

Income inequality plagues New Orleans. Any increase in energy bills could be devastating. As a result, the Alliance for Affordable Energy has suggested some sound strategies for protecting New Orleans’ most vulnerable power consumers as the city seeks to transition to a renewable energy economy. These recommendations include:

  • Exemption for all low-income households from any RPS rider;
  • A special carveout for renewable resources located at low- and moderate-income households;
  • A mandate that excess credits, or RECs, will be sold, and those revenues will be used to offset REC procurement costs or to fund energy efficiency and renewable procurement;
  • Requiring that utility investors (not ratepayers) will have to bear the costs if the utility doesn’t comply;
  • Recommending an increase in energy efficiency funding and targets, to ensure that reduced electricity consumption (and therefore reduces customers’ bills);
  • Allowing low-cost renewables (such as utility-scale wind and solar) from neighboring states to count towards a portion of the RPS goals; and,
  • A call for the utility to wean itself off above-market, affiliate-contracts.

That last one is important…

What is New Orleans’s utility up to with customer’s money?

New Orleans is served by Entergy New Orleans LLC (ENOL) which is owned by Entergy Corp. If you follow energy utilities like I do, you may recognize ENOL’s name from the infamous antics they pulled: pretending to be New Orleans community residents in an underhanded attempt to trick New Orleans City Council into building a new, unneeded gas-fired power plant. Entergy also owns other vertically integrated utilities (like Entergy Mississippi, Entergy Louisiana, and Entergy Arkansas) and independent power providers like System Energy Resources Inc (which owns the Grand Gulf Nuclear reactor in Mississippi). In 2018, ENOL spent over $100 million buying electricity from many of these companies that are affiliated with ENOL’s parent company.

UCS conducted analysis on coal and nuclear power plants and found many of Entergy’s assets are uneconomic compared to market prices. It appears that Entergy may be using bi-lateral contracts with affiliated companies to prop up otherwise uneconomic coal and nuclear power plants.

For example, ENOL buys electricity from Entergy Arkansas at an average price of $49/MWh in 2018, or roughly 64% higher than average Arkansas Hub market prices in 2018. Entergy Arkansas owns and operates the White Bluff and Independence coal plants, two coal-fired power plants in Arkansas that regularly operate when it is uneconomic to do so. One reason these coal plants might be doing this is that a bi-lateral contract could make them indifferent to market prices—they’re guaranteed money either way. As a result, ENOL customers in New Orleans would be subsidizing uneconomic coal plants in Arkansas.

For comparison, other utilities have signed contracts for solar plus storage at $45/MWh. Solar or wind (without storage) comes in even lower, with solar as low as $25/MWh and the average wind PPA last year coming in at $20/MWh.

ENOL also buys electricity from System Energy Resources Inc (another Entergy subsidiary) owner and operator of the Mississippi-based Grand Gulf nuclear power plant. UCS analysis found that the Grand Gulf plant operates at a cost around $40/MWh; if the power plant were reliant on market prices alone, it wouldn’t be economical to own and operate the reactor. ENOL buys electricity from System Energy Resources at an average price of $77 /MWh or over two times the Louisiana hub market average. Over the long run, rooftop solar in New Orleans today would likely cost about $70-$80/MWh.

Is it possible that ENOL customers are funding a nearly 50% profit margin to Entergy and subsidizing an otherwise uneconomic nuclear plant in Mississippi while simultaneously being deprived of rooftop solar?

Yes, it is entirely possible.

This isn’t the first time someone has accused Entergy of turning a blind eye to cheaper resources in favor of operating more expensive plants it owns. This past April, the state of Mississippi argued in court that Entergy Mississippi defrauded customers by not buying cheaper power off the market and demanding the utility repay up to $2 billion to its customers.

Enacting an RPS will force Entergy to wean itself off those above-market contracts and sign contracts for renewable energy, which as outlined above, are likely to come in at or below the costs of existing contracts for coal and nuclear. An RPS in NOLA is probably going to drive energy costs down.

RPS 101 on the 15th

Click to enlarge.

In mid-June, I’ll be heading to New Orleans to join a convening of community members and local leaders to discuss how well-designed RPS policies have helped other drive the US’s renewable energy growth—key to fighting back climate change—while offering local economic benefits, too. If you’ll be in the area, feel free to come on by and join us. Here is the latest flyer:

The event will take place at Tulane Law School 6329 Freret St, New Orleans, Louisiana 70118. For more information: https://www.facebook.com/events/2133373293620782/

Image courtesy of Alliance for Affordable Energy EQ Research, DSIRE Database

La Energía Eólica Marina – 5 Próximos Pasos

Credit: Ad Meskens

El mundo de la energía eólica marina tiene bastante movida estos días.  Nueva legislación, nuevas propuestas para proyectos, nuevos mercados al punto de abrirse. El momento sigue creciendo.

Este viernes pasado, por ejemplo, el estado de Massachusetts se comprometió a aumentar un 100 porciento su meta de energía eólica marina. Ya era el primer estado con una fuerte meta, con un requerimiento de 1.600 MW establecido en el 2016. Luego pasó una ley en el 2018 pidiendo que la administración del Gobernador Charlie Baker evaluara “la necesidad, beneficios y costos” de un aumento de la meta hasta un total de 3.200 MW antes del 2035. Nosotros contribuimos con nuestros comentarios al estudio, y acaban de aprobar el aumento.

Y viene mucho más. Estas son cinco cosas que estoy esperando en el corto plazo.

1. Los primeros 800 megavatios de Nueva York

Un viaje de 9.000 megavatios (MW), se podría decir, empieza con los primeros 800. Gracias al Gob. Andrew Cuomo, Nueva York tiene la meta más ambiciosa de energía eólica marina en los EE.UU. Y el estado está buscando estar a la altura de esas circunstancias.

El progreso incluye una solicitud de propuestas (RFP, por sus siglas en inglés) para esos primeros 800 MW, publicada a finales del 2018, y las respuestas tienen que ser entregadas en febrero.

Los que actualmente desarrollan proyectos en otros países respondieron fuertemente, con cuatro respondientes proponiendo un total de 18 proyectos. Cualquiera de esos posibles participantes traería experiencia importante al mercado estadounidense.

Las decisiones sobre cual proyecto o cuales proyectos avanzarán se esperan tan pronto como esta semana. Así que estaré pendiente de ellas.

2. Una meta de 2.000 megavatios para Connecticut

Photo by Walt Musial / NREL

La cámara de diputados de Connecticut aprobó el mes pasado una propuesta de ley, con fuerte apoyo bipartidista, que obligaría al estado a contratar hasta 2.000 MW de energía eólica marina. Ahora le toca al senado, donde un voto se podría dar en los próximos días.

El Gob. Ned Lamont recientemente anunció un acuerdo público-privado de $93 millones en inversiones para mejorar el puerto de New London, para que sea apto para equipamiento eólico marino. Parece estar listo el gobernador para aprobar la propuesta de ley después de un voto en el senado. Merece nuestra atención.

3. Los primeros 1.100 megavatios de Nueva Jersey

Un poco más al sur, Nueva Jersey ha estado reactivando sus esfuerzos en cuanto a la eólica marina desde que tomó su puesto el Gobernador Phil Murphy en enero de 2018. Eso ha incluido un RFP en busca de los primeros 1.100 MW de la meta de 3.500 MW que ahora tiene el estado.

Igual que en Nueva York, el RFP de Nueva Jersey ha atraído fuerte interés de actores internacionales, con respuestas de tres de ellos. Y, como en Nueva York, se podría tener una decisión dentro de pocos días.

4. Los próximos 800 megavatios en Massachusetts

Mientras tanto en Massachusetts, los primeros 1.600 MW de la ley del 2016, tienen sus propios avances. El proyecto seleccionado para los primeros 800 MW, Vineyard Wind, ha logrado aprobación para sus contratos con las compañías de energía de Massachusetts, y para la línea de transmisión para conectarse con la red eléctrica del estado.

Y ahora se ha publicado el RFP para el resto de los primeros 1.600MW. Así que esperamos propuestas para proyectos de hasta 800 MW antes de la fecha tope en agosto, y la selección del proyecto o de los proyectos ganadores en noviembre.

5. Arrendamientos marítimos de California

Mientras mucha de la atención está sobre el noreste y medio-atlántico, otras partes del país también merecen atención. En California, por ejemplo, la agencia de manejo de energía oceánica (BOEM, por sus siglas en inglés) ha estado considerando tres áreas cerca de la costa. Catorce compañías han indicado interés en la posibilidad de arrendar una o más de esas áreas para desarrollar proyectos eólicos marinos.

De igual importancia, varios interesados se han involucrado para asegurar que el desarrollo de esta tecnología en la costa oeste se haga correctamente.

Y más

Estos son cinco posibles próximos pasos para la energía eólica marina. Pero este no es un listado completo. También vale la pena prestar atención a Maine, Rhode Island, Maryland, Delaware, Virginia, Carolina del Norte y los Grandes Lagos, por ejemplo. Y también a los avances tecnológicos y a los acontecimientos en otros mercados.

Porque como sean y donde sean, los acontecimientos con la energía eólica marina sí merecen atención.

Photo: Ad Meskens Dennis Schroeder/NREL Credit: A. Kommareddi

The Billion-Dollar Coal Bailout Nobody Is Talking About: Self-Committing In Power Markets

Xcel Energy's Sherco Generating Station Coal Power Plant Photo: Tony Webster/Wikimedia Commons

This interview was first published on May 21, 2019, in Forbes

Nearly two-thirds of the United States’ power plants operate in competitive wholesale markets.  Market rules typically prescribe that only the cheapest set of resources may run—nowadays, those are often renewable energy resources. Despite a growing trend of coal losing on cost to renewables and natural gas, coal generation remains a dominant player in many of these markets.

New research by Union of Concerned Scientists Senior Energy Analyst Joe Daniel uncovered the fact that coal plants in “competitive” wholesale electricity markets were being run uneconomically, meaning they accrued significant losses for months at a time. This behavior defied economic logic, but could be explained by regulation. These plants are owned and operated by vertically-integrated utilities (companies that own their generation sources and directly serve retail customers in an area without alternative suppliers), who receive cost recovery for expenses related to these coal plants under regulatory approval outside of the market.

To investigate the size of the problem, Joe analyzed wholesale electricity market data to better understand what drives investment in fossil fuel and clean energy power plants in those markets. Much of this market distortion was happening for plants owned and operated by vertically-integrated utilities which are permitted to “self-commit” their coal plants, forcing them to run at above-market costs. In this way, regulation functions as a subsidy to keep coal plants running, and customers are on the hook.

Energy Innovation’s Director of Electricity Policy Mike O’Boyle interviewed Joe to learn why this is happening, the risks of this practice, and what it means for consumers and clean energy’s future in these markets.

Mike O’Boyle: Can you explain what you mean by coal self-committing?

Joe Daniel: Most people think the system operators that coordinate competitive power markets are centralized decision-makers for the electricity grid. That’s true, in theory. In practice, it’s a bit more complicated. Market rules give participants like utilities and power plant owners a great deal of decision-making authority. For instance, power plant owners can decide when to make their resources available, then offer those resources into the market for others to purchase.

Some owners allow the market to “commit” their resource by specifying what price and output level they are willing to operate at. Market committed resources allow market forces to drive increases or decreases output, or turn off units entirely. In aggregate, these economic bids provide the system operator with enough information to choose the power plants that minimize overall system costs.

However, market participants can bypass this process by self-committing the unit, essentially superseding the market operator’s decision of whether to run that plant. Instead, power plant owners can tell the market that the unit must remain on, which requires that it operate at some minimum level of output. Barring an emergency, the operator can’t tell the unit to turn off even if there’s cheaper energy available on the market.

MO: Please explain how you figured out that self-committing is happening.

JD: A few years back, I was working on a utility proceeding within the Southwest Power Pool (SPP) organized market with a lawyer who noticed that the utility’s coal plant, which previously operated at a high capacity factor, suddenly stopped running. The lawyer and I eventually discovered that the utility-owner had changed its operational paradigm from “self-commitment” to “market-commitment.”

So, I began researching self-commitment, market rules, and hourly coal plant operations across the country to understand why coal plant operators were running at seemingly illogical times, based on the low prices for solar, wind, and other sources in these markets. Originally, my focus was on SPP, but I quickly expanded my analysis to the Midcontinent-ISO (MISO), PJM Interconnection, and Electric Reliability Council of Texas (ERCOT) competitive energy markets, too.

MO: How many coal plants did you examine and where are they located?

JD: Most recently, I completed an analysis screening every coal-fired power plant that operates in PJM, MISO, ERCOT, or SPP, roughly two-thirds of all existing U.S. coal plants.

RTO/ISO markets in the United States

RTO/ISO markets in the United States

Roughly 100 gigawatts (GW) of coal, or nearly half of the coal in organized markets, received additional scrutiny that included analyzing hourly coal plant revenues. These coal plants operated at a loss for at least one month during the study periods; even worse, customers were footing those bills.

Compared to SPP and MISO, PJM and ERCOT had fewer, but still, some bad actors who engaged in self-committing to the detriment of their customer’s wallets.

MO: What has your research on self-committing shown?

JD: This opaque practice undertaken by coal plant owners hurts customers and contributes to climate change.  My analysis indicates that self-committing uneconomic coal costs consumers an estimated $1 billion dollars a year in the regions I evaluated. But I also found that not all coal plant owners engage in this inefficient practice. Rather, the worst offenders are vertically integrated utilities that can lose money in the competitive market and then recover those losses on the backs of retail customers, including those most economically vulnerable to higher electricity costs. Customers of vertically integrated utilities are “captive”—they have no choice but to accept these costs.

My research is ongoing, so it is hard to say with precision what the cumulative environmental impacts are of coal plants that operate like this, but it’s not good. Statistically, an uneconomic coal plant would be replaced by either (a) emissions-free wind energy; (b) a natural gas plant that, while not clean energy, has lower emissions rates than coal; or in a worst-case scenario, (c) a more efficient coal plant with marginally lower emissions rates.

MO: How does this practice affect renewables in wholesale electricity markets?

JD: Markets are supposed to ensure that all power plants are operated from lowest cost to most expensive. Self-committing allows expensive coal plants to cut in line, pushing out less expensive power generators such as wind, depriving those units from operating and generating revenue.

The practice of self-committing also reduces market revenues for all the generators that do get called. Wholesale electricity prices are set by the marginal cost of supplying one unit of energy – the most expensive power plant selected by the operator sets the price. In the absence of self-committing, this price for energy would increase, raising revenues for all selected power plants.

Coal plant self-committing reduces market revenue for all generators.

Coal plant self-committing reduces market revenue for all generators.

Properly functioning markets are predicated on properly functioning price signals. If the market prices are distorted, then what happens to the market? Nothing good.

MO: You’ve called self-committing coal a hidden coal bailout. What do you mean by this, and how does it compare to state subsidies for renewable energy?

JD: Self-committing is regressive, reducing the efficiency of our electricity grid, exploiting customers, and exacerbating emissions when coal plants run more. It also artificially distorts market prices to favor aging technology while limiting investments in low-priced renewables.

On the other hand, renewable subsidies are policy decisions that are proposed, scrutinized, and enacted by democratically-elected representatives. Consequently, the policies—whatever their strengths and weaknesses—are at least the product of a transparent, intentional process, and those who put them in place are accountable for the subsidies’ effects. But that’s not what we have with self-committing.

MO: Is self-committing coal happening in any states with clean energy goals?  If so, is it undermining the energy transition?

JD: Yes and yes. Minnesota, for instance, has set clean energy goals yet has uneconomic coal plants self-committing in the MISO market. This reduces grid flexibility and may force wind farms to curtail output because the electric grid is essentially zero-sum. If a coal plant is finagling the market to take the electricity it produces, it is preventing some other unit from providing that electricity. That might be a wind farm. It might be a gas plant. Regardless, it is hurting consumer pocketbooks and our health.

MO: What can be done about self-committing coal plants?

JD: Self-committing is a choice the utilities are proactively making. In some markets, this is as simple as selecting a different drop-down option. Power plant operators simply have to change their bidding behavior when offering their power plant into the market, which would allow the market operator to more efficiently run the whole system.

Alternatively, utilities could choose to seasonally operate the plants they own, similar to the strategy taken by owners of several coal plants in Texas and Louisiana. Just this past winter, Cleco and AEP subsidiary SWEPCO announced that Louisiana’s Dolet Hills coal facility will switch to operating only four months of the year. The utilities’ own estimations indicate this will save its customers $85 million by the end of 2020.

State regulators have tremendous influence over the utilities they oversee. They can’t assume the controls of power plants but can create incentives or penalties to ensure utilities behave better.  In some states like Washington, Oregon, and Montana, regulators have come up with a better mechanism to allow for cost/profit sharing that aligns price incentives. Alternately, a regulator can disallow the costs associated with running a power plant uneconomically, forcing investors to take a loss rather than forcing customers to bail out those plants.

Photo: Tony Webster/Wikimedia Commons Under Creative Commons Attribution-Share Alike 2.0 Generic License SustainableFERC

Offshore Wind’s Next Steps: 6 to Watch For

Credit: Ad Meskens

Things certainly aren’t dull in the world of offshore wind these days. Between new legislation to kick-start offshore wind markets, new bids to meet states’ demand for projects, and new markets getting set to open up, momentum just keeps building. Here are six near-term things I’m watching for.

1. New York’s first 800 megawatts

The journey of 9,000 megawatts, it might be said, starts with the first 800. Thanks to Governor Andrew Cuomo, the Empire State has the most ambitious target in the nation, and is working to live into that goal. That included issuing a request for proposals (RFP) for the first 800 or so megawatts late last year, with bids due in February.

Developers responded in a big way, with four proposing a total of 18 projects. Any one of those developers would bring some serious overseas experience to bear on the US market.

Decisions about which project or projects to go forward with could come out as early as this week, so I’m definitely watching for those.

2. A 2,000-megawatt target in Connecticut

September 1, 2010 – Siemens 2.3 MegaWatt Offshore Wind Turbine Installation, Baltic 1 Offshore Wind Farm, Baltic Sea, Germany. (Photo by Walt Musial / NREL)

The Constitution State’s house of representatives earlier this month passed a bill, in strong bipartisan fashion, to have the state contract for up to 2,000 megawatts (MW) of offshore wind. Now it’s up to the senate, where a vote could also happen this week.

Gov. Ned Lamont, who recently announced a $93 million public-private partnership to upgrade New London’s port to handle offshore wind, is poised to sign the 2,000-MW mandate when the senate does its thing. Stay tuned.

3. New Jersey’s first 1,100 megawatts

Meanwhile, just down the coast, the Garden State has been busy re-building offshore wind momentum since Governor Phil Murphy came into office in January 2018. That has included NJ issuing its own RFP in January, to find the first 1,100 of the state’s 3,500-MW target.

As in NY, the NJ RFP attracted strong interest from international players, with bids from three developers. And, as in NY, a decision about the first project(s) could be coming any day now.

4. Massachusetts’s next 1,600-megawatt pull

The Bay State was the first out of the gate with a big legislative pull, putting in place a 1,600-MW requirement in 2016. A follow-on 2018 law asked Governor Charlie Baker’s administration “to investigate the necessity, benefits and costs of requiring distribution companies to conduct additional offshore wind generation solicitations of up to 1,600 MW,” and execute if things look good—in other words, to bring the state’s total up to 3,200 MW.

We and many others weighed in during that study, and it’s due to be wrapped up and presented to the legislature shortly.

5. Massachusetts’s next 800-megawatt bid

Meanwhile, Massachusetts’s first 1,600 MW chunk is moving along, with near-term things-to-watch-for of its own. The project selected to satisfy the first 800 MW of that, Vineyard Wind, has recently gotten state approvals for its contracts with Massachusetts utilities, and for the transmission line for connecting to the state’s electricity grid.

And now the RFP for the second half of the first 1,600 megawatts (stay with me now…) is out, released last week. So watch for the bids of up to 800 MW, due in August, and the project selection, ‘long about November.

6. California leases

And, while a lot of the spotlight is on the Northeast and Mid-Atlantic, other parts of the country are well worth keeping an eye on, too. California, for example, where the federal Bureau of Ocean Energy Management (BOEM) is looking at three wind areas off the central and northern parts of the state. Fourteen companies have indicated an interest in one or more of those areas.

And, equally importantly, a broad group of stakeholders is engaging to make sure that as offshore wind happens on the West Coast, it’s done right.

And more

Those are six things I’m watching for in terms of offshore wind’s next steps, but this is far from a comprehensive list. Maine, Rhode Island, Maryland, Delaware, Virginia, North Carolina, and the Great Lakes, for example, should also be on folks’ radar screens, along with technological developments and happenings overseas.

Because however and wherever it’s happening, offshore wind development is well worth watching.

Photo: Ad Meskens Dennis Schroeder/NREL

Energy Collision Coming: Technology Evolved, Why Haven’t Utilities?

Photo: Famartin/Wikimedia Commons

Our modern economy depends on electricity, the miracle technology of the 19th century.  Many old policies and practices of the electric utility industry have stuck with us into the 21st century.  Electricity has had heroes and villains along the way, as well as enormous accomplishments of engineering, public service and safety.  While economics and public attitudes have changed about many things since the first electric bill was sent in January 1883, there are tools and techniques, as well as attitudes in the utility industry that do not change as much.  To serve society and maintain a healthy environment, we need a utility industry open to modern ideas and new approaches.

Maybe because the industry was based on a monopoly business model for 100 years, or because the invisible product requires engineering, or because there is a tension between the public interest and companies shrouding themselves in the name “public service company”… but whatever the reason there is a utility company culture that often appears paternalistic or patronizing.  New technologies owned by consumers could make our energy supply safer and less expensive if customer and public interests and investments were better recognized by the old utilities.

Today in the U.S., many changes are bearing down on electric utilities that demand a modern grid approach, such as state and city clean energy goals, and customers adding rooftop solar and electric vehicles.  But the old utility company tendency remains, with assurances to one and all that the large, sophisticated corporation has society’s best interests in mind, and there’s no need to pay too close attention. Sometimes that doesn’t quite work out.

Exhibit A: PJM

By some measures, the largest and most sophisticated U.S. utility is PJM, the grid operator for the region from New Jersey west to Chicago and south to Virginia, Kentucky and North Carolina. PJM provides the command and control, the market rules, and the financial clearing for wholesale electricity and high voltage transmission used by 65 million people in 13 states plus D.C. PJM is regulated by the Federal Energy Regulatory Commission (FERC).

But when we look at recent developments making headlines for PJM, it seems clear that the public is still getting an arrogant utility that is treading on state policies, with too little care for consumers wallets.

Witness the case of Green Hat, a financial trading firm with a questionable history (and a headquarters addressed to a UPS store). In response to Green Hat’s unusual and ultimately failed financial activity, PJM made a series of mistakes, from misunderstanding collateral and risk management, and then incorrectly believed a Green Hat pledge would suffice, or that the situation could get worse. Green Hat’s unchecked speculation in PJM markets ended in default, which led to the departure of the PJM CFO and some $400 million in financial obligations for consumers. An independent report cited “an unwarranted air of confidence” as a contributing factor to this fiasco.

Witness a level of arrogance when PJM fails to report its political contributions.  This is required by law to allow proper public oversight.

Witness the fight PJM has entered by taking to FERC a request to exclude zero carbon and renewable energy plants from its capacity market. The capacity market creates the inventory of plants that count for reliability and transmission infrastructure.  PJM holds that state clean energy policies that support clean air and climate by helping these plants is an unacceptable interference with the market. (This is the “MOPR” rule, for folks following closely.)

The PJM proposal for changes in rules (known as MOPR”) will move state-supported resources out of the capacity market, resulting in higher costs for consumers.

A particularly old-style approach from PJM is seeking additional revenues for coal plants with a vague argument that “fuel security” is a thing we need. (It isn’t.) PJM continues to push this debate, despite PJM meeting all reliability standards and recently boosting power plant payments already used for reliability. In addition, PJM has rejected ideas that would look at winter needs separate from summer needs, saying over and over that there is ample supply in winter. See graph below.

PJM pays for year-round supplies, even though winter needs are lower.

Change is here, what’s the right thing to do?

Meanwhile, changes abound in the energy landscape. Public opinion favoring clean energy is higher than ever, and states as well as local governments and corporations are adopting policies for higher levels, even 100% clean energy. Homeowners (2 million the US) have taken up solar as a DIY energy policy.  In fact, even PJM anticipates current mandatory Renewable Portfolio Standards will lead the PJM region to add 25,000 MW of wind and 12,000 MW of solar resources, with ~8,000 MW of that total behind the meter, by 2034. Thanks to state policy leadership! The economics and investment in renewable energy, demand response tech, and storage are all on the upswing across the U.S.  But PJM has taken steps to hold each of these down.  As PJM stays with old approaches to issues of fuel supply, a year-round capacity approach that over-supplies in winter, and an embrace of old state-sponsored resources while rejecting new state-sponsored resources, a collision is coming.

Elected officials and public interest advocates are championing lower costs and clean energy with a variety of state policies. These policies often address market failures and unpriced environmental externalities. Energy policy is relevant to local economic development, job creation and pollution-reduction. PJM objects to the states making policies that set priorities in energy production.

The way forward

There will be a public interest, and involvement, in the utility industry. PJM will need the participation of assertive state agencies and public interest groups that can look beyond the screen that PJM offers to through its external affairs efforts. PJM could change, and decide to facilitate the existing state RPS laws and demand-side policies. Change could also be driven in a constructive way by Congress and FERC, it could be a gradual erosion of engagement as local jurisdictions go a different way than the PJM vision.  Policymakers and industry have got to keep up with the times.  Changing public needs, technology and economics cannot be ignored forever.  The record shows that PJM has more to do for consumer protection, transparency, and the enabling of a clean energy transition.  In reference to the words of Martin Luther King, Jr., these are times of challenge and controversy for the utility industry.

Photo: Famartin/Wikimedia Commons

PREPA’s Agreement is Terrible for Puerto Rico

Jose Jimenez Tirado / Getty Images fileLea en español >

A new agreement on Puerto Rico Electric Power Authority’s (PREPA) debt represents a major setback for the future of the island.


It’s not new that PREPA is in bankruptcy and that the priority of Gov. Roselló is its privatization. It’s also not new that Puerto Ricans have been worried about the possible disastrous consequences that the privatization can generate. These include the excessive increase in electricity rates and the exacerbation of public health and environmental problems due to the improper handling of ashes, air pollution and emissions causing the climate crisis.

These concerns are being confirmed with the recent announcement of the agreement reached between the Fiscal Control Board, the majority of PREPA’s bondholders, a PREPA bond insurer and Rosselló’s government.

To explore the implications of this agreement I talked with Dr. Agustín Irizarry, a professor of Electric Engineering at the University of Puerto Rico in Mayagüez.

What is this agreement about?

Through this agreement, a “debt charge” will be required to cover the deficit inherited from PREPA. This charge must be paid by all PREPA users starting this summer until 2067.

Additionally, the debt charge will apply to those who currently have or will install their own generation system in the future.

Why is the PREPA agreement concerning?

For several reasons:

  • Puerto Ricans will pay more than double the value of PREPA’s debt. The agreement establishes that Puerto Ricans must pay the debt charge for 47 years to cover a deficit of close to $9,000 million. The current rate of 22 cents per kilowatt hour (kWh) will rise 2.8 cents/kWh in 2020 (before the election); it will rise 4.55 cents/kWh starting on 2043 and it will remain that way for more than 20 years. This means that for a debt of about $9,000 million, Puerto Ricans will pay more than $23,000 million without including between $100 million and $200 million to cover administrative expenses.
  • Autonomous generation users will also have to pay the debt charge. This is a moment in which people are searching for alternatives to avoid going through what so many had to endure, living months and months without energy after Hurricane Maria. That’s why after Maria everybody wants a solar system on their roof with a battery to store the energy. Hurricane Maria demonstrated the tremendous vulnerability of our centralized electric system. Therefore, autonomous generation systems should be promoted. On the contrary, the agreement establishes that the debt charge will also apply to those who own or install their own generation systems. Those who start generating their own energy with solar panels beginning on September 30, 2020 should pay the charge immediately after installing the system. And those who have installed their own generation systems before this date and are connected to the network, should start paying the debt charge for the energy they produce as of 2040.
Imágenes satelitales de Puerto Rico por la noche antes y después del huracán María.

Puerto Rico a oscuras después de María.

What are the choices?

The agreement guarantees the payment of the debt but does not offer any alternative for:

  • increasing the reliability of the electrical network,
  • reducing air pollution by improving the health of Puerto Ricans, and
  • reducing the emissions that produce the climate crisis.

Since 1989, electricity rates have not risen, contributing in part to the lack of investment in the electricity infrastructure. This has had a negative impact in the quality of the service.

What must happen is that the agreement should not be signed because it only benefits bondholders. Instead, a planned rate increase should serve to settle the debt before 15 years, improve the reliability of the electric grid and help Puerto Ricans in their transition to a decentralized system. This decentralized system should provide an optimal service and respond to the challenges of our time. This will be a key step to increasing the resilience of the system in preparation for natural disasters such as María.

How to prevent PREPA’s agreement from moving forward?

The agreement must first pass through the legislature, the energy commission and the bankruptcy court before being approved. We must alert the public so that they know what is being proposed and act to prevent the approval of this agreement. Only by doing this will we be able to protect our energy future.








Jose Jimenez Tirado / Getty Images file

The Basics of Integrated Resource Planning in California

Photo: Elena Koycheva/Unsplash

Energy experts geek out over a process known as Integrated Resource Planning. It’s not widely followed by the general public, but Integrated Resource Plans (“IRPs”) determine where consumers’ electricity will come from, how clean that power will be, and whether states will meet their clean energy and climate goals. In California, IRPs are key to decarbonizing the electricity sector and turning the state’s climate goals into reality.

Why this process?

The purpose of IRPs is to develop a path forward that meets renewable energy goals and global warming emissions reduction targets. Current law requires 60% of California’s electricity to come from renewable sources, such as wind and solar, by 2030. Current law also requires California to reduce global warming emissions to 40% below 1990 levels by 2030. Electricity providers must spell out in their IRPs how they will meet these goals while simultaneously minimizing costs, ensuring grid reliability, and minimizing the impact of air pollution on California’s disadvantaged communities.

In California, integrated resource planning was mandated by a 2015 state law. The law requires investor owned utilities, community choice aggregators, and almost all electric service providers to develop an IRP every two years and submit those plans to the California Public Utilities Commission for approval. Publicly owned utilities are required to develop a plan every five years and submit them to the California Energy Commission.

How does it work?

To ensure that California achieves all its clean energy and climate goals, the California Public Utilities Commission (CPUC) has developed an integrated resource planning process that repeats every two years. (The California Energy Commission has a separate process for publicly owned utilities that is not discussed here.) The CPUC’s process goes like this:

  1. The CPUC sets a global warming emissions reduction target for California’s electricity sector. The “40% below 1990 levels by 2030” requirement applies to the entire state, and since it is easier to reduce emissions from the electricity sector than from other sectors of the economy (e.g. transportation, agriculture, and industry), the electricity sector contribution to the state-wide requirement must be frequently reevaluated to ensure that California’s emissions reductions remain on track.
  2. The CPUC performs electricity grid modeling of the entire state to determine the amounts and types of new resources (e.g. wind, solar, and batteries) that are necessary to achieve the global warming emissions reduction target while meeting future electricity needs. This modeling is used to develop an overall plan for the state’s electricity sector.
  3. Electricity providers create individual IRPs, illustrating how they will reduce their global warming emissions by providing customers with additional clean electricity while minimizing costs, ensuring grid reliability, and minimizing air pollution in California’s disadvantaged communities. Electricity providers must demonstrate that they are doing their part to reduce emissions as part of the statewide plan.
  4. The CPUC collects all the individual plans from electricity providers and puts all those plans together. The CPUC then compares their original plan (in Step 2) to this new plan to make sure that California will still meet its goals if the state’s electricity providers all follow their individual plans.
  5. Lastly, the CPUC brings all this planning to life by implementing new policies and authorizing electricity providers to develop clean energy projects.

At the end of the day, the last step is the most important part. No matter how much planning you do, planning by itself doesn’t reduce global warming emissions. California’s electricity providers must follow through with their plans and buy more clean energy in order to achieve all the goals of the integrated resource planning process.

The CPUC’s integrated resource planning process has five steps. The entire process repeats every two years.

What’s the latest?

The California Public Utilities Commission recently completed the first two-year cycle of its integrated resource planning process. Importantly, the approved plan does not call for any new natural gas power plants – instead, it paves the way for 12 gigawatts of new, clean resources to come online by 2030, including solar, wind, geothermal, and battery storage. (For reference, California already has roughly 30 gigawatts of renewable generation capacity, which generates approximately one-third of the state’s electricity.)

The CPUC has also set the stage for the next cycle of the integrated resource planning process with a couple new features:

  • Natural gas power plant study: The next cycle will focus more closely on existing natural gas power plants and the extent to which they are required for maintaining reliability over the coming decade. Last year, the Union of Concerned Scientists conducted a study that indicated, out of all the gas plants in the California Independent System Operator territory (which covers 80% of California), roughly a quarter of those gas plants could be retired without negative consequences. This coming integrated resource planning cycle will include a similar study to better understand how many natural gas power plants really need to stay online through 2030.
  • Planning for 100% clean electricity: California passed a law last year that sets a goal for all electricity sold to customers to be 100% carbon-free by 2045. The next cycle of the integrated resource planning process will begin to study the investments necessary to achieve this bold goal.
  • Procurement track: The CPUC has stated their intention to begin a “procurement track” that will run parallel to the integrated resource planning process. The main motivation behind the procurement track is to make sure that California is developing the clean energy projects necessary to meet its renewable energy and decarbonization goals – if progress stagnates, the Commission would be able to mandate more clean energy projects through the procurement track. The procurement track will serve as a safety net that ensures sufficient clean energy progress even if an individual electricity provider fails to follow its IRP, or if, collectively, the IRPs of all the state’s electricity providers do not add up to meet the state’s renewable energy or decarbonization goals.

With the next cycle of the integrated resource planning process already underway, California is continuing to rapidly decarbonize its electricity sector with the integrated resource planning process helping to show the way.

Photo: Elena Koycheva/Unsplash

Acuerdo de Autoridad de Energía Eléctrica Es Pésimo Para Puerto Rico

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Un nuevo acuerdo sobre la deuda de la Autoridad de Energía Eléctrica (AEE) de Puerto Rico representa un gran retroceso para el futuro de la isla.


No es nueva la noticia que la Autoridad de Energía Eléctrica (AEE) se encuentra en bancarrota y que la prioridad para la administración del gobernador Roselló es su privatización. Tampoco es nueva la preocupación de los puertorriqueños sobre este proceso debido a las nefastas implicaciones que puede tener.

Estas incluyen el aumento desmedido en las tarifas de electricidad y la exacerbación de problemas para la salud pública y el medioambiente por el manejo indebido de cenizas, la contaminación del aire y las emisiones causantes de la crisis climática.

Estas preocupaciones están siendo confirmadas con el reciente anuncio del acuerdo entre la Junta de Control Fiscal (JCF), la mayoría de tenedores de bonos de la AEE, una aseguradora de bonos de la AEE y el gobierno de Rosselló sobre la reestructuración de la deuda de la AEE.

Para explorar las implicaciones de este acuerdo hablé con el Dr. Agustín Irizarry, catedrático del Departamento de Ingeniería Eléctrica de la Universidad de Puerto Rico en Mayagüez.


¿En qué consiste el acuerdo?

Por medio de este acuerdo se pondrá un cobro llamado “cargo de la deuda” para cubrir el déficit heredado de la AEE. Todos los usuarios de la AEE tendrán que pagar este cargo a partir de este verano y hasta el año 2067.

Adicionalmente, el cargo de la deuda aplicará a quienes actualmente cuenten con ó quienes instalen en el futuro sus propios sistemas de generación eléctrica.


¿Porqué es preocupante el acuerdo de la AEE?

Por múltiples causas:

  • Los puertorriqueños pagarán más del doble del valor de la deuda de la AEE. El acuerdo establece que por 47 años los puertorriqueños deberán pagar el cargo de la deuda para cubrir un déficit de cerca de $9.000 millones. La tarifa actual de 22 centavos por kilovatio hora (kWh) subirá 2,8 centavos/kWh en el año 2020 (antes de las elecciones); a partir del año 2043 subirá 4,55 centavos/kWh y permanecerá así por más de 20 años. Esto quiere decir que por una deuda de cerca de $9.000 millones, los puertorriqueños pagarán más de $23.000 millones sin incluir entre $100 millones y $200 millones para cubrir gastos administrativos.
  • Los usuarios de generación autónoma también deberán pagar el cargo de la deuda. Este es un momento en el que la gente está buscando alternativas para no volver a quedar meses y meses sin energía como les pasó a tantos luego del huracán María. Por eso es que después del huracán todo el mundo quiere en su casa un sistema solar con batería para almacenar la energía. El sistema eléctrico centralizado ha demostrado tener una enorme vulnerabilidad y por lo mismo se deberían promover sistemas de generación autónomas. Por el contrario, el acuerdo establece que el cargo de la deuda aplicará también a quienes cuenten con ó instalen sus propios sistemas de generación. Quienes generen su propia energía con paneles solares a partir del 30 de septiembre del 2020 deberán empezar a pagar el cargo de inmediato. Y quienes hayan instalado su propia generación antes de esta fecha y estén conectados a la red, deberán empezar a pagar el cargo de la deuda por la energía que produzcan a partir del año 2040.
Imágenes satelitales de Puerto Rico por la noche antes y después del huracán María.

Puerto Rico a oscuras después de María.

¿Qué alternativas hay?

El acuerdo como está concebido garantiza el pago de la deuda, pero no ofrece ninguna alternativa para:

  • incrementar la confiabilidad de la red eléctrica,
  • reducir la contaminación del aire mejorando la salud de los puertorriqueños y
  • reducir las emisiones que generan la crisis climática.

Desde el año 1989 las tarifas de electricidad no han subido y esto en parte ha contribuido a la falta de inversión en la infraestructura eléctrica, con su correspondiente impacto en la calidad del servicio.

Lo que debe suceder es que no se debe firmar un acuerdo que solo beneficia a los bonistas. En lugar de firmar este acuerdo, un aumento planificado de tarifas debe servir para saldar la deuda antes de 15 años, mejorar la confiabilidad de la red eléctrica y ayudar a los puertorriqueños en su transición a un sistema descentralizado que brinde un óptimo servicio y que responda a los retos de nuestro tiempo. Esto será un paso clave para aumentar la resiliencia del sistema en caso de desastres naturales como María.


¿Cómo evitar que el acuerdo de la AEE avance?

El acuerdo debe pasar primero por la legislatura, la comisión de energía y el tribunal de quiebra antes de ser aprobado. Debemos alertar a la ciudadanía para que sepa lo que se está proponiendo y actúe para prevenir la aprobación de este acuerdo. Solo así podremos proteger nuestro futuro energético.





Jose Jimenez Tirado / Getty Images file

Xcel Energy’s Plan to Eliminate Coal and Boost Solar in Minnesota

Photo: Zbynek Burival/Unsplash

Today, Xcel Energy released a preliminary plan to phase out its remaining coal-fired power plants in Minnesota and replace them primarily with wind, solar, and energy efficiency—moving the company forward toward its goal of 100% carbon-free electricity by 2050.

Part of the plan involves a consensus proposal joined by the Union of Concerned Scientists, other clean energy organizations, and the Laborers International Union of North America.

Below are some of the noteworthy items included in the consensus proposal and Xcel’s plan—and how they relate to Minnesota’s clean energy future.

1. Coal plant retirements

Xcel Energy will propose a 2028 retirement date for the Allen S. King coal-fired power plant and a 2030 or earlier retirement date for the Sherco 3 coal unit. Significantly, these plants are the company’s last coal-burning power generators in Minnesota for which Xcel has not yet announced retirement dates.

In the meantime, Xcel will also reduce coal usage at the Sherco 2 unit through committing to seasonal operation of the plant, a concept that my colleague Joe Daniel has written about here. Seasonal operation of coal plants has helped other utility customers save money and promotes grid flexibility to enable Xcel to integrate more renewable energy in the future.

Reducing and phasing out coal burning produces major carbon pollution reduction benefits as well as reducing public health impacts through lower soot and smog emissions (see our Soot to Solar report from last fall on Illinois coal plants).

2. Massive growth in solar power

Minnesota currently has close to 1,100 megawatts of installed solar power statewide. As part of the agreement with clean energy organizations, Xcel will propose the acquisition of 3,000 megawatts of solar power to add to its system by 2030. This is enough to provide 20 percent of Xcel’s energy, powering the equivalent of more than 417,000 homes and furthering reduce carbon pollution from the electric sector. This would add to Xcel’s addition of 1,850 megawatts of wind power by 2022.

3. Big commitment to energy efficiency

According to the Center for Energy and Environment, in 2018 Xcel achieved a record amount of energy efficiency: more than 680 gigawatt-hours of electricity savings, or about 2.35% of sales (well exceeding the state’s 1.5% energy savings target). In the consensus proposal, Xcel commits to include achievement of electric savings above that 2018 amount for the entire decade (2020-2029) in its planning.

This ambitious goal is based on the Minnesota Department of Commerce’s statewide energy efficiency potential study and would allow Minnesota to potentially join other states that are achieving 2-3% per year in efficiency savings.

Investing in energy efficiency helps utilities avoid more expensive measures and helps reduce customers’ energy bills which promotes energy affordability and reduces the energy burden.

4. Support from labor

The Laborers District Council of Minnesota and North Dakota (“LIUNA Minnesota”) joined the consensus proposal alongside UCS and other clean energy organizations. As part of the agreement, Xcel will commit to a request-for-proposals process for solar projects that maximizes local job creation and participation in apprenticeship programs.

5. The role of gas and nuclear

Gas-fired power plants are not clean resources and investing in them is a risky proposition for electric utilities. The Union of Concerned Scientists is part of a group challenging approval of Minnesota Power’s plan to build a new gas plant in Superior, Wisconsin.

However, we and other signatories to the consensus proposal are supporting Xcel’s acquisition of the Mankato Energy Center, an existing gas plant currently owned by Southern Company. Why?

Xcel already buys power from the Mankato plant, and the acquisition is being pursued in combination with the above aspects of an overall plan to decarbonize the company’s generation portfolio. Our analysis is that acquisition of the Mankato plant will not have significant impacts on greenhouse gas emissions and will help Xcel phase out its Minnesota coal plants by:

  • Reducing system costs associated with early coal retirements and incentivizing the decarbonization of sectors outside the electricity sector;
  • Displacing the need for large additions of gas combustion turbine generation in the 2030s and 2040s; and
  • Putting a large carbon emitter (the Mankato plant) under the oversight of the Minnesota Public Utilities Commission, an important step in ensuring beneficial resource planning for a carbon-free future.

Utilities are unfortunately rushing to build new gas infrastructure despite there being enough gas capacity online to meet demand. Still, Xcel Energy is not backing off from its commitment to be net carbon-free by 2050 and emissions from the Mankato plant will fall under that cap if the acquisition is approved and Xcel owns the plant.

With respect to nuclear, while it is not part of our consensus proposal, Xcel’s preliminary plan also includes an expectation of relicensing its Monticello nuclear plant and operating it at least until 2040. (To date, no nuclear reactor in the United States has received approval from the Nuclear Regulatory Commission to extend its operating license beyond 60 years, but three applications are currently pending.) This concept will require close examination by stakeholders and regulators on whether it is the most cost-effective path toward a 100% carbon-free electricity future and whether the plant can continue to operate safely beyond 60 years.

What are the next steps?

The consensus proposal will be reviewed by the Minnesota Department of Commerce and other stakeholders in a proceeding currently pending before the Minnesota Public Utilities Commission.

Stakeholders also can weigh in Xcel’s preliminary plan prior to the company’s integrated resource plan filing slated for July 1, 2019.

Finally, the measures outlined by Xcel Energy show that a low-carbon electricity system is achievable in Minnesota and should further support the legislature’s consideration of clean energy measures that I blogged about earlier this month, including establishing a goal for 100% carbon-free electricity by 2050.

Photo by Zbynek Burival on Unsplash

5 Reason’s Why HB 6, Ohio’s Nuclear Plant Subsidy Proposal, Should Be Rejected

Photo: Nuclear Regulatory Commission

Last November, UCS released Nuclear Power Dilemma, which found that more than one-third of existing nuclear plants, representing 22 percent of total US nuclear capacity, are uneconomic or slated to close over the next decade. This included the Davis-Besse and Perry plants in Ohio that are owned by Akron-based FirstEnergy Solutions. Replacing these plants with natural gas would cause emissions to rise at a time when we need to achieve deep cuts in emissions to limit the worst impacts of climate change.

When we released our report, my colleague Jeff Deyette described how a proposal backed by FirstEnergy to subsidize its unprofitable nuclear plants in Ohio was deeply flawed and did not meet the conditions recommended in our report. By providing a blatant handout to the nuclear and fossil fuel industries at the expense of renewable energy and energy efficiency, ironically, the latest proposal to create a “Clean Air Program” in Ohio (House Bill 6) is bad for consumers, the economy and the environment.

Here are five reasons why this proposal is flawed and should be rejected:

1. HB 6 doesn’t protect consumers

HB 6 would provide incentives to maintain or build carbon-free or reduced emission resources that meet certain criteria. The state’s Legislative Budget office estimates the new program would cost $306 million per year, collected through a dedicated monthly charge on consumer electricity bills. Monthly costs range from $2.50 for a typical residential customer to $2,500 for large commercial and industrial customers.

HB 6 doesn’t require FirstEnergy Solutions to demonstrate need or limit the amount and duration of the subsidies to protect consumers and avoid windfall profits as recommended in our report. It simply sets the starting price at $9.25/MWh and increases that value annually for inflation.  In 2018, Davis-Besse and Perry generated 18.3 million megawatt-hours of electricity, according to the U.S. Energy Information Administration. This means that FirstEnergy Solutions nuclear plants would receive approximately $170 million per year in subsidies, or 55% of the total. As explained below, the rest of the money would likely go to upgrading Ohio’s existing coal and natural gas plants.

2. HB 6 is a bait and switch tactic to gut Ohio’s clean energy laws

But here’s the rub. HB 6 would effectively gut the state’s renewable energy and energy efficiency standards to pay for the subsidies for Ohio’s existing nuclear, coal and natural gas plants. It would make the standards voluntary by exempting customers from the charges collected from these affordable and successful programs unless they chose to opt-in to the standards. This could result in a net increase in emissions and a net loss of jobs in Ohio over time.

This political hit job is outrageous, but not at all surprising. It is just another attempt in a long series of efforts by clean energy opponents to rollback Ohio’s renewable and efficiency standards over the past five years. When combined with stringent set-back requirements for wind projects that were adopted in 2014, these actions have a had a chilling effect on renewable energy development and explain why renewables only provided a paltry 2.7% of Ohio’s electricity generation in 2018 (see figure below). In contrast, renewables provided 18% of U.S. electricity generation in 2018, and wind power provided more than 15% of electricity generation in 11 states.

The sponsors of HB 6 go one step further and make the false claim that their proposal will save consumers money. While the charges appearing on consumer bills might be less, this ignores the much greater energy bill savings consumers have been realizing through investments in energy efficiency. In addition, the cost of wind and solar has fallen by more than 70 percent over the past decade, making them more affordable for consumers and competitive with natural gas power plants in many parts of the country. It also ignores the energy diversity benefits of renewables and efficiency in providing a hedge against natural gas price volatility. Many Ohio legislators continue to put their heads in the sand and refuse to embrace the new reality that renewables and efficiency are cost-effective for consumers.

Energy efficiency programs are especially important for low-income households. By lowering their energy bills, they have more money to spend on food, health care and other necessities. It also reduces the need for assistance in paying heating bills. Unfortunately, legislators like Energy and Natural Resources Committee Chair Nino Vitale are proposing to provide handouts to large corporations at the expense of easing the energy burden for low-income households, which are also disproportionately affected by harmful pollution from coal and natural gas power plants.

3. HB6 creates a false sense of competition

While renewable energy technologies are technically eligible to compete for funding under HB 6, several criteria would effectively exclude them:

  • It excludes any projects that have received tax incentives like the federal production tax credit or investment tax credit, which applies to nearly every renewable energy project.
  • Eligible facilities must be larger than 50 MW, which excludes most solar projects, and wind projects have to be between 5 MW and 50 MW, which is smaller than most existing utility scale wind projects in the state.
  • Eligible projects must receive compensation through organized wholesale energy markets, which excludes smaller customer-owned projects like rooftop solar photovoltaic systems.

When combined with the rollback to the renewable standard, this absurdly stringent criteria would create too much uncertainty for renewable developers to obtain financing to build new projects in Ohio.

4. HB 6 will increase Ohio’s reliance on natural gas

While HB 6 could temporarily prevent the replacement of Ohio’s nuclear plants with natural gas, gutting the renewables and efficiency standards would undermine the state’s pathway to achieving a truly low-carbon future by locking in more gas generation as coal plants retire.  Over the past decade, natural gas generation has grown from 1.6% of Ohio’s electricity generation to more than 34% in 2018 (see figure). A whopping 40,000 MW of new natural gas capacity was added during this time, mostly to replace retiring coal plants. In contrast, the share of nuclear and renewable generation has only slightly increased by 2-3% each.

Ohio’s Increasing Reliance on Natural Gas for Electricity


While natural gas has lower smokestack emissions than coal, the production and distribution of natural gas releases methane emissions—a much more potent greenhouse gas (GHG) than carbon dioxide. To achieve the deep cuts in emissions that will be needed to limit the worst impacts of climate change, Ohio will need to reduce its reliance on natural gas. Gutting the state’s renewables and efficiency standards would take away the most cost-effective solutions for achieving this outcome.

5. HB 6 includes no safety criteria or transition plans

HB 6 does not require FirstEnergy’s nuclear plants to meet strong safety standards as a condition for receiving subsidies, as recommended in our report. While Davis-Besse and Perry are currently meeting the Nuclear Regulatory Commission’s (NRC) safety standards–as measured by their reactor oversight process (ROP) action matrix quarterly rating system–both plants have had problems with critical back-up systems during the past two years that put them out of compliance.

The nuclear industry has been trying to weaken the ROP for years. For example, the industry has been advocating for combining the first two columns of the action matrix, which would essentially put all nuclear reactors in the top safety category. My colleague Ed Lyman, acting director of the UCS Nuclear Safety Project, is working to stop the NRC from changing the ROP to make it a less meaningful and transparent indicator of plant safety. Our report recommends that policymakers monitor the situation and adjust subsidy policies if the NRC weakens its standards.

HB 6 also does not include any transition plans for affected workers and communities to prepare for the eventual retirement of the nuclear plants. These plans are needed to attract new investment, replace lost jobs and rebuild the tax base.

A better approach

On May 2, House Democrats announced an alternative “Clean Energy Jobs Plan” that would address many of the problems with HB 6. The plan would modify the state’s Alternative Energy Standard (AES) by increasing the contribution from renewable energy from 12.5% by 2027 to 50% by 2050 and fix the onerous set-back requirements that have been a major impediment to large scale wind development. It would expand the AES to maintain a 15% baseline for nuclear power. In addition, it would improve the state’s energy efficiency standards, expand weatherization programs for low-income households, and create new clean energy job training programs.

This proposal is similar to the laws recently passed in Illinois, New York and New Jersey that provided financial support for distressed nuclear plants while simultaneously strengthening renewable energy and energy efficiency standards. While our report shows that the subsidies for some of these nuclear plants may have been too generous, these policies have prevented plants from closing and resulted in a wave of new investment in wind, solar, and efficiency projects.

With more than 112,000 clean energy jobs in 2018, Ohio ranks third in the Midwest and eighth in the country. Ohio added nearly 5,000 new clean energy jobs in 2018.  While most of the clean energy jobs are in the energy efficiency industry, Ohio is also a leading manufacturer of components for the wind and solar industries.

To capitalize on these rapidly growing global industries, lawmakers in Ohio should reject HB 6 and move forward with a real clean air program that ramps-up investments in renewables and efficiency and achieves the deep cuts in emissions that are needed to limit the worst impacts of climate change.

Three Ways Federal Infrastructure Policy Can Speed Up Our Clean Energy Transition

Photo: John Rogers

May thirteenth marked the beginning of Infrastructure Week and, as you might have heard, there might be at least one thing that Republicans and Democrats agree on: the need to invest in our nation’s aging infrastructure to remain competitive and build a more resilient, equitable system. This includes the electricity sector, where we must decarbonize our electricity supply, address growing threats to system resilience from climate change, and invest in the research and development of technologies that will power our growing clean energy economy. Here’s three ways a federal infrastructure policy package could help make this happen.

Unlock investments in our electric transmission system

Transmission lines are the backbone of our electricity supply. As we transition to clean energy, we also need to invest in a more efficient and resilient transmission system.

Transmission lines are critical to delivering electricity from where it’s generated to where it’s consumed, and as the nation transitions from centralized fossil-fueled power to more dispersed renewable energy resources, we need to invest in our transmission system to efficiently carry renewable energy to our light switches and build resilience against challenges such as extreme weather events and cyberattacks.

Research shows that these investments provide benefits to consumers that outweigh the costs. But a number of hurdles remain, including complex and often dysfunctional planning and approval processes, and a failure of focused leadership at the top – namely Congress and the Federal Energy Regulatory Commission (FERC).

To address these issues, Congress should declare it a national priority to upgrade our nation’s electricity transmission system and direct FERC, which oversees our bulk electric supply, to prioritize transmission planning in furtherance of a zero-carbon, more resilient electricity supply.

Congress should also authorize and fund the Department of Energy (DOE) to provide technical assistance to state and local authorities that evaluate and approve transmission projects and to develop a national transmission plan that includes recommendations on how to take advantage of existing rights of way like railroad corridors and interstate highways.

Accelerate battery storage deployment

Battery storage can make the electricity system more reliable, affordable, secure, and resilient to extreme events – all while smoothing the way for high levels of renewable energy. This is why experts agree that energy storage should be a top federal priority – both to speed up deployment of current technologies and develop the next generation of this resource.

Current storage technologies are ready for targeted cost-effective deployment to enable renewable energy integration, offset transmission system investments, and replace fossil-fuel-powered plants – particularly those located in urban environments and having significant public health impacts on surrounding communities. To achieve all that battery storage can offer for a clean, resilient electricity supply, Congress should fund tax incentives for battery storage investments to incentivize the private sector while also providing grant programs for deployment in underserved communities where battery storage can displace fossil fuels and reduce local pollution.

Congress also has a role in funding a diverse body of research on the next generation of storage technologies that would put the United States back in a global leadership position, attract private investments, create jobs, and provide significant value to the electricity sector.

Support the infrastructure build out that will fuel the offshore wind boom

The U.S. offshore wind industry about to take off, but federal investment in our infrastructure are necessary to make sure we’re ready.

The U.S. offshore wind industry is experiencing significant growth. Robust winds, relatively shallow waters, and lots of energy demand near the coast combine to make the Central and Northern Atlantic prime for offshore wind development. Several east-coast states – led by New York, New Jersey, Massachusetts, and Maryland – are moving to procure offshore wind, pushing U.S. demand to more than 17,000 megawatts (MW). Recent estimates put the value of the U.S. offshore wind supply chain at nearly $70 billion with the potential to create hundreds of thousands of jobs.

But building out the offshore wind industry requires coordination among federal, state, local, and tribal authorities, and a multitude of interests including commercial and recreational fishing, the Department of Defense, seagoing navigation, compliance with protections for migratory birds and marine mammals – just to name a few. At the same time, U.S. waters offer a new set of technical challenges compared to the European offshore wind industry that has matured over the past several year.s And at this early point in the U.S. offshore wind industry’s growth, we don’t have the ports, ships, and crews necessary to support the industry.

All of this calls for a proactive and robust federal role in the build out of our offshore wind industry. Ongoing coordination of stakeholders to identify prime offshore wind sites and open them for development while maintaining environmental safeguards is necessary. Research and development of the next generation of offshore wind turbines and the transmission grid to carry that clean energy to load centers must be funded. And federal funding to states and local communities is critical to not only build the ships, ports and other equipment necessary for offshore wind development, but to do it in a way that improves the efficiency and lowers the environmental impacts on local communities.

Infrastructure touches nearly every aspect of our lives – including our electricity supply and the potential to transition to a clean, equitable, and more reliable and resilient system. A federal infrastructure package presents an opportunity to pass ambitious climate solutions at the federal level. These should be national priorities, and any federal infrastructure package should reflect this urgent priority.

Photo: John Rogers Photo: James Ferguson/Wikimedia Commons Photo: Derrick Jackson

How Big is Gridlock in our Electric Grid?

Photo: AWEA

Progress in electric power, particularly the growth of renewable energy and consumer choice, is looking like gridlock.  Look closer and we can see three fundamental issues: state policy vs. federal policy; changing perspectives on reliability, and how electric grid planning should accommodate the ongoing transition to renewable energy. We even have gridlock in the appointment and continuity of the Federal Energy Regulatory Commission (FERC) that oversees much of the decision making in these spaces.

Transitions need transmission

From the beginning of Nikolai Tesla’s rivalry with Thomas Edison, the choice of energy supplies has depended on the availability of transmission to flow electricity from one place to another. Any new energy supply needs some kind of conductor or transport from the supply to the demand. The larger the cumulative supply, the more pronounced this need. Adding a lot of offshore wind energy, for example, requires a commensurate plan for safely getting that energy into the existing grid. State policies in the Northeast have brought this innovation, (first studied at University of Massachusetts but first adopted commercially in Northern Europe), to the cusp of commercial-scale deployment off New England and Mid-Atlantic coast. So while we now have commitments for significant offshore wind development, the details of how we’ll effectively move that energy to the onshore grid and ultimately to customer demand remains unresolved.

Transmission lines are the infrastructure of renewable energy.  Planning ahead for these lines enables the addition of the clean energy.  We saw this in Texas, and we need to see it again for offshore wind.   Renewable energy is growing rapidly, replacing fossil fuels and reducing carbon and other air pollution every day.  An infrastructure strategy for carbon reduction and the transition to renewable energy should include electric transmission investment.

More about that gridlock: State policy vs. federally regulated markets

Sitting at FERC is a request by PJM on how federally supported markets will treat power plants that are supported by state policies, like the long tradition of state sanctioned monopoly utilities or the decisions of state legislators to promote innovation or continued operation of zero-carbon power plants.  These policies ultimately pave the way for power plants to receive revenues outside of the FERC-regulated markets – either through checks from captive ratepayers or through alternative revenue streams like renewable energy credits (RECs). This decision regarding how to align these policies with the wholesale markets in PJM has been stuck in a regulatory deadlock at FERC since mid-2018 when one of Trump-appointed Commissioners left, leaving a 2 – 2 split in opinions at FERC.

At stake in that decision are these three fundamental issues:

  1. State policy vs. federally supervised market platform: PJM asked FERC permission to discriminate between the old-style, ratepayer-subsidized plants (usually fossil-fueled) owned by state-regulated monopolies (which would be exempt from PJM’s proposed definition of “improperly subsidized”) when applying new financially impactful rules to renewable power plants that have revenues from state Renewable Portfolio Standards and the nuclear plants that have been given additional payments from legislative actions.  PJM seeks to raise the bids offered by renewables and nuclear plants to counter state supports but allow state-supported old fossil plants to bid low so as to keep them in business. While all of these plants are essentially subsidized by state policy, PJM is proposing to penalize one category of power plant while allowing another to operate in the market at artificially low costs that will ultimately be made up by utility customers.
  2. Reliability in a changing supply mix: The PJM management of the capacity market, which provides utilities with enough resources to meet the peak demand in summer is struggling through repeated and continuous reforms that limit or reduce new types of resources.  The capacity market was also changed to incentivize coal- and gas-burning power plants to be more reliable in cold weather. Demand response and renewable energy have been devalued in the various changes, and are targeted by the proposed reform awaiting FERC decision. These types of reform ultimately create gridlock as older, less efficient resources don’t exit the market because they’re being subsidized by ratepayers while new, more cost-effective resources can’t enter the market because they’re not being properly valued for the services they can provide.
  3. This decision affects the planning and growth of transmission, literally the resolution of physical gridlock limiting renewable energy growth. PJM’s rules for transmission planning use the capacity market results to determine where and how much transmission is built for generation. So if renewable energy resources can’t participate in the capacity market, PJM doesn’t build the transmission necessary to transmit renewable energy to customer demand.

The interaction of these issues can be seen in all the U.S. grids to some degree.  The assumptions based on fossil-fuel plants, and the owners of those plants, work against a transition to renewables, demand-response, or energy efficiency.  Differences among the grid operators NY Independent System Operator serving New York, ERCOT serving Texas, and the Midcontinent Independent System Operator serving 15 states plus Manitoba demonstrate some diversity in attitudes about these issues.

Planning for energy around the whole year, not just a peak demand period, is one positive change MISO is exploring.  NYISO approval of transmission that will “help unbottle clean energy” is a model for our policy goals and the role of infrastructure in achieving these goals. In short, the opportunity is at hand to use infrastructure investments – whether roads, bridges, or electric transmission – to unlock opportunities to achieve a cleaner, more resilient future.

Photo: AWEA

US Solar: 2 Million Systems Strong. And Definitely Growing

The latest good news from the forefront of clean energy makes me think of the old FlintstonesTM vitamins commercials about the number of kids they were reaching: “[X] million strong, and growing,” went the catchy jingle. This good news is about the count of solar photovoltaic (PV) systems in the US, and should be just as catchy: We have just sped past the two-million mark. Two million PV systems, on homes and businesses, over parking lots, beside highways, and in fields and deserts across America.

Gif of numbers

That tally is courtesy of energy market analysis firm Wood Mackenzie (Wood Mac) and the Solar Energy Industries Association (SEIA). While large-scale solar accounts for more of the megawatts, rooftops account for the vast majority of the system count; residential systems alone are 96% of the total.

This momentous occasion is one of the clean energy milestones I’ve been watching for. And it’s just one more sign of a key technology that keeps hitting new heights.

Heights upon heights

That heights-hitting is on vivid display, for example, in the latest year-in-review report from the same team of Wood Mac and SEIA. While the 2018 data shows that annual solar installations were down, with US solar companies installing 2% less than they had in 2017, so many of the other data points are good news. Here’s a taste:

  • Solar megawatts are climbing. Even with the annual total down (a smidge), we still added 10,600 megawatts (MW) of PV to our national power mix. That put the total installed solar tally at more than 64,000 MW—enough to generate the equivalent of 12 million typical US households’ use.
  • Solar’s contributions are growing. Solar’s new heights are particularly visible in the technology’s increasing role in our electricity supply. While only 2.4% of US electricity in 2018, solar generation climbed 24% between 2017 and 2018. And its continued climb over the last decade combined with wind energy’s progress is a marvel to behold.
  • Residential solar is up. Installations of large-scale and “non-residential” (commercial) solar were both lower in 2018 than in the previous year, but gains in residential solar made up for almost all of those drops. Residential solar’s growth, says the report, “exceeded expectations for 2018,” with 7% more megawatts going in during the year than in 2017.
  • Solar isn’t just climbing; it’s spreading. The report authors emphasize how the results suggest major states “have moved past early adopters”: “[G]rowth in low-penetration emerging markets, such as Texas and Florida, continues to add to the geographic diversity of the residential market outside of California and the Northeast.” The Lone Star State, long the undisputed leader in wind power, is finally becoming a factor in solar too, capturing the #2 slot for solar megawatts installed in 2018. And the Sunshine State has finally started talking solar seriously, taking the #3 spot in 2017 and #4 in 2018.
  • Solar costs are dropping (even more). One area where less is more is in the continuation of the amazing downward trend for the cost of solar. Costs for the different market segments dropped another 4-15% in 2018. The report authors credit reductions in hardware costs, including the costs of PV modules—with the Trump solar taxes on imports being offset by Chinese policy changes that led to global oversupply.
And more heights

And the heights keep coming. Solar in California, for example, couldn’t even wait for spring to set a new record for instantaneous solar generation, and large-scale solar plus rooftop solar briefly supplied close to two-thirds of the state’s electricity demand. And California solar set another megawatt record last month.

The two million systems now in, given growth already in 2019, add up to a cool 70,000 MW. Wood Mac and SEIA are projecting that solar installations this year will be 14% higher than 2018, with the residential sector continuing to push forward and large-scale solar bouncing back. That progress looks likely to lead to another recordbreaker in annual installations by the year after next.

Meanwhile, the system count will continue to climb, along with the pace of installation. The news on this latest milestone quotes Michelle Davis, a Wood Mac senior solar analyst (and former colleague), as saying:

“According to our latest forecasts, by 2024, there will be on average, one solar installation per minute. That’s up from one installation every 10 minutes in 2010.”

This two-million mark comes just three years after we hit one million PV systems. And Wood Mac/SEIA project that we’ll hit three million in 2021 and four million by 2023.

Readers of the right vintage will recall that the FlintstonesTM vitamin commercials of yesteryear talked about “10 million strong”. Solar isn’t there yet, but at the rate it’s making progress, we’ll be there before we know it.

Photo: GRID Alternatives Wood Mackenzie and SEIA, US Solar Market Insight, 2018 Year in Review Wood Mackenzie and SEIA, US Solar Market Insight, 2018 Year in Review

Putting Communities First in Deploying Energy Storage

A wide range of stakeholders from across the country met in December 2018 to develop a set of principles to ensure equitable deployment of energy storage technologies. (Photo: Megan Rising/UCS)

UCS convened a select group of stakeholders in December 2018 to discuss policies to spur deployment of energy storage. But this meeting was not your typical policy development session—we focused on how to design policies that put communities first. UCS focused on not only deploying more energy storage, which is an important part of the clean energy transition, but also doing so in a way that involves community members and drives equitable outcomes. The stakeholders present at December’s convening developed a set of consensus principles based on the discussions there and conversations since.

Fully 26 participating organizations have endorsed the principles on equitable deployment of energy storage.

The opportunity

When combined with investments in clean energy, storage has the potential to hasten retirements of coal and even natural gas plants across the country. This is critical not only for our climate and decarbonization goals, but also to improve air quality in frontline communities. Utility-scale storage is already being procured to replace three natural gas plants in California. Experts predict energy storage will be a $3.8 billion industry by 2023.

Energy storage has a wide range of potential applications, and UCS recognizes and emphasizes the potential for storage to benefit disadvantaged communities. Because of the potential community benefits, UCS focused in on a couple of important use cases for storage: replacement of peaking power plants and fossil-fired plants; ability to keep the lights on and bounce back more quickly from  power outages; and accelerating the development and integration of renewable energy on the grid. Our focus on energy storage is not meant to preclude other carbon reduction policies or the need for renewable energy policies, but rather to lift up energy storage deployment policy as a key complementary policy. We also recognize that much work remains to be done to fully capture the value that storage can provide to the market and customers.

Involving stakeholders

UCS convened a group of diverse stakeholders, including environmental justice and grassroots organizations, policy experts, solar and storage industries, labor, consumer advocates, faith groups, and renewable energy advocates, in December 2018 in Chicago, Illinois, focused on the equitable deployment of energy storage. The participants developed a set of consensus principles for storage deployment that elevate the critical importance of community-led clean energy solutions. Together these principles can help state policymakers focus on solutions that ensure that the growth of energy storage improves all communities.

As far as we can tell, this event was the first of its kind. Typically, policy wonks gather in a room to think up ideas about how to drive the outcomes they think are important. And while those expert opinions are obviously important, we wanted to know what affected communities thought about the desired outcomes and how to get there. We see this process as an important contribution to our collective work to drive a transition to a clean energy economy.


The purpose of the convening was to develop policy recommendations, strategic relationships, and political momentum to accelerate the equitable, safe, and low-carbon deployment of energy storage in the US at the state level.

Our goals for the convening were to:

  • Create a core set of policy design elements on equitable, safe, and low-carbon energy storage policy deployment that can influence state legislation in 2019 and beyond.
  • Build momentum in a set of target states with a broader coalition for equitable, safe, and low-carbon storage deployment policies.
  • Produce both short-term and longer-term materials for broad distribution that advance these goals.

This convening on state-level deployment of energy storage built on an earlier convening that UCS held in March 2018 in Washington, DC. That earlier event brought together leading researchers to identify the most important breakthroughs needed to scale up electricity storage as well as ways the federal government can support innovation in this strategically important industry. It was sponsored by the bipartisan House Advanced Energy Storage Caucus and resulted in a policy brief which synthesizes the discussions, including recommendations for federal policy-makers on how to best support electricity storage RD&D that drives innovation, lowers electricity prices, and increases the reliability of the US electric grid.

The principles

Prior to December’s convening, UCS set the stage with some initial thoughts and ideas about what equity might looks like in the context of energy storage deployment. The stakeholders then expanded and shaped the concepts and ultimately outlined six principles of equitable policy design for energy storage. They grappled with the following questions:

  • How can storage be deployed to reduce emissions and improve air quality?
  • How can storage make communities and residents more resilient to disasters and power outages?
  • How can storage promote local economic development and job growth?
  • How can storage help accelerate greater levels of renewable energy on the grid?
  • How can storage help reduce electricity bills?
  • How can policymakers ensure that communities have a seat at the table?

Read the full text of the principles with the list of supporting organizations here.

Outcomes and Next Steps

For this discussion, we focused on three states—Minnesota, Illinois, and Maryland—where we saw opportunities for advancing storage legislation in the near term. Participants represented these three states, and other stakeholders attended who shared perspectives from leading states and nationally.

We know that our convening brought together people who would not otherwise have met, and we saw that dynamic play out in hallway conversations throughout our two-day event. We also know that some of those relationships have continued beyond the convening.

While UCS and many of the convening attendees are focused on advancing equitable energy storage policy in these three states, our hope is that these principles can be used more broadly to inform policy and to shape the way legislators and storage advocates are conceiving of the opportunities afforded by energy storage.