ERCOT: Hurricane Harvey knocked out power to 300K Texas customers

AUTHOR Krysti Shallenberger@klshall
PUBLISHED Aug. 28, 2017
Dive Brief:

Category 4 Hurricane Harvey slammed the Texas Gulf Coast from Corpus Christi to Houston, and at its peak, knocked out power for 300,000 customers on Saturday, according to the Electric Reliability Council of Texas (ERCOT).
ERCOT noted the number of customers without power decreased slightly as the storm wore on, but reports widespread transmission outages, particularly near the Corpus Christi and Victoria areas.
The grid operator issued an emergency status late Friday night as Harvey made landfall, and noted more than 70,000 customers were without power already. Lineworkers are working 16-hour shifts to turn on power.
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Dive Insight:

Hurricane Harvey made landfall late Friday night, knocking the lights out for hundreds of thousands as it moved up the state. State officials and the grid operator issued warnings days in advance. Researchers from the University of Michigan forecasted as many as 350,000 customers could lose power — landing right in the ballpark of actual numbers.

ERCOT reported roughly 300,000 customers lost power in the peak of the storm. The most recent storm coming close to that was Winter Storm Stella, which left about 200,000 customers on the Eastern Seaboard in the dark in March.

A 2015 report from the Union of Concerned Scientists said the central Gulf Coast was especially vulnerable to severe storms. Hurricane Katrina’s aftermath illustrated that, but the report noted the region was still slow to adapt to the risks to climate change — which include increasingly severe storms.

Nearly 68,000 MW of capacity was at risk or lay directly in Hurricane Harvey’s path, SNL Energy reported. NRG Energy owned the most at-risk capacity, followed by Calpine Corp. and Houston-based CenterPoint Energy.

Recommended Reading:

Battery storage startup Romeo Power secures $30M in seed funding

AUTHOR:Robert Walton@TeamWetDog
PUBLISHED Aug. 25, 2017

Dive Insight:

California-based Romeo Power, a startup energy storage manufacturer expected to begin shipping products next year, has secured $30 million in seed financing.
Founded by engineers and designers from SpaceX, Tesla, Apple, Amazon and Samsung, the company will develop lithium-ion battery packs for electric vehicle and stationary storage applications.
The company began sales this year and has logged $65 million in initial orders for 2018. It is developing a manufacturing facility near downtown Los Angeles.

Despite hiring engineers that previously worked at Tesla, officials at Romeo Power told Forbes the company does not see Elon Musk’s company has a direct competitor.

According to founder Michael Patterson, the difference is in the application. While Tesla’s battery cells will be used in its own vehicles and energy storage products, “we’re just making the pack, and making it for more people and for more applications,” he told the financial magazine.

The company expects its modular battery packs to be used in cars, power sport vehicles, motorcycles, trucks, buses, and forklifts. Romeo revealed that current contracts and design agreements for the company span U.S. and European automakers, manufacturers of motorcycles and forklifts, and include companies like Power Designers and Robotic Assistance Devices.

“We’ve seen incredible momentum in a short period, and we’re scaling manufacturing as fast as we can to meet demand,” Patterson said in a statement. “There’s a massive market opportunity for energy storage technologies.

Tesla kicked off operations at its first development site in Nevada earlier this year at the much-heralded Gigafactory. The company expects to produce 35 GWh/year of lithium-ion battery cells by 2018.

Romeo says its own 13,000 square-foot manufacturing facility is on track to be complete by the end of the year. Its battery packs range in size from 1 kWh to 1 MWh.

Duke Energy warns ITC against solar panel tariff

AUTHOR:Robert Walton@TeamWetDog
PUBLISHED: Aug. 25, 2017

Dive Brief:

Duke Energy has joined the lobbying effort against potential tariffs on imported chrystalline silicon photovoltaic solar modules, warning in a letter that higher prices could lead to a slowdown in the development of solar projects — just as the resource is approaching price parity with other forms of energy.
In May, the United States notified the World Trade Organization that it was considering imposing emergency tariffs on imported solar cells, following a request by manufacturers SolarWorld Americas and Suniva (which has filed for bankruptcy).
Duke’s warning to the U.S. International Trade Commission joins more than two dozen other companies opposed to the possible tariff. A decision on whether to proceed investigating the proposed tariff and floor-price is expected next month.
August 21, 2017

Diane V. Denton
Managing Director
Federal Policy
526 S. Church Street
Charlotte, NC 28202

Lisa R. Barton
Secretary to the Commission
U.S. International Trade Commission
500 E Street SW.
Washington, DC 20436

Re: Statement of Duke Energy Corporation to the United States International Trade Commission Investigation No.TA-201-75

Dear Secretary Barton:

Pursuant to 19 CFR § 207.26, on behalf of Duke Energy Corporation, I submit the following letter to the U.S. International Trade Commission and request the Commission consider this information in making its determinations in the above-referenced investigation.

With respect to this investigation, Duke Energy respectfully requests the Commission consider the potential adverse effects of a finding of injury for the petitioner in this investigation, and any recommendation for an associated remedy of import relief, on the delivered prices of imported Crystalline Silicon Photovoltaic (“CSPV”) modules for those industries responsible for powering the nation’s electricity sector. Duke Energy urges the Commission to
evaluate such potential impacts and avoid making a determination that will negatively disrupt the growing
and developing clean energy marketplace within our service territories and throughout the country. Such a
disruption potentially harms our customers, our company, our employees and the larger power sector as a

As the Managing Director, Federal Policy for Duke Energy, I am responsible for policy
development of all federal government actions impacting our regulated and commercial renewable energy
operations. Duke Energy is one of the largest energy providers and electricity-sector employers in the
nation, serving approximately 7.5 million retail electric customers in seven states in the Southeastern and
Midwestern regions of the country. Duke Energy has approximately 30,000 employees and operates
50,000 megawatts of electricity generation, one of the largest fleets in the nation. Additionally, our
commercial operations acquires, develops, builds and operates renewable generation throughout the
country, which includes nonregulated renewable energy and storage assets.

As a company, we have invested more than $5 billion in renewable energy, and just within the
last five years have procured and invested in approximately 800 megawatts (“MWs”) of solar generating
facilities, with more than 250 MWs located within our regulated footprint. As prices for solar have
declined, more of our large business customers like the military, larger universities and data centers are seeking to incorporate more solar energy as part of their sustainability or energy security goals.

These customers are particularly vital to the economic growth of our communities and identifying economic
solutions for them is important to enable them to focus on their core mission. Additionally, over the next
five years, we have plans to procure at least 2,500 MW of solar within our regulated jurisdictions,
including significant investments in the Carolinas and Florida particularly, where the continued growth of
renewable generation is a key tenant of state policy.

As an active market participant in this sector, Duke Energy relies on access to solar CSPV
modules at globally-competitive prices to provide cost-competitive solar power to our customers.
Competitive module pricing is critical to justify future investment to our regulators and is directly
correlated to our ability to grow our renewable portfolio for the benefit of customers and shareholders.
Over the next five years, Duke Energy plans to invest more than $1 billion in additional solar generation

Competitive module pricing has driven the robust growth of solar generation across the country,
both for our company and the power sector at large. Historically, demand for solar modules has
responded directly to its relative market price and modules typically represent 25% to 30% in the overall
installed cost of solar generating capacity. In the event that imported CSPV modules are subject to an
artificial floor price or significant import tariff as requested by the petitioners in this case, the module
market, and therefore Duke Energy’s plans to procure modules, will likely be significantly disrupted. If
such a remedial floor price or tariff is imposed, we expect that the installed cost of solar projects will
increase 30% or more and that demand for modules would contract, perhaps even precipitously. As solar
energy is just approaching parity with the traditional grid resources in a number of states, a significant
reduction in demand for new solar projects could deliver a serious blow to continuing development and
evolution of this market.

For utilities situated similarly to Duke Energy’s operating companies, which must select costcompetitive
resources (whether they be fuel-based or renewable) when determining new generation to
meet customer demand requirements, such cost increases may eliminate solar generation from its
evaluation processes entirely. In this way, the cascading impact of decreases in demand for modules and
solar facilities would ultimately harm the very domestic solar manufacturing industry the petitioner is
attempting to protect.

Duke Energy urges the Commission to consider the potential adverse effects of a mandate and
disruptive change in imported CSPV module price on the power sector. Solar power has become an
increasing important part of our generating portfolio and it is an integral element to our future plans to
serve our customers. The delivery of reliable, affordable, and increasingly clean energy relies upon
international trade policies that increase supply chain stability, not policies that destabilize it.

Respectfully submitted,
Diane V. Denton

Vogtle owner asks DOE for $1.6B more to finish project

Author:Kristi E. Swartz,
E&E News reporter Energywire:
Friday, August 25, 2017

glethorpe Power Co., which owns 30% of the Vogtle nuclear plant, requested $1.6 billion in additional support from the Department of Energy during a quarterly meeting on Thursday, E&E News reports.
The power cooperative has already secured a $3 billion loan guarantee from the DOE to finish the nuclear project, which is years behind schedule and already billions over original cost estimates. The request could potentially reduce the overall price tag of the project, which is now slated to cost as much as $27 billion, well above its original estimate of $14 billion.
The request comes after Georgia Public Service Commission signaled support last week for the project, provided it could be completed economically. The PSC approved $222 million in expenditures for Southern Co. subsidiary Georgia Power and directed the company to determine if it would continue with the project in its next construction monitoring report.
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Dive Insight:

Vogtle is the last new nuclear project standing after utilities recently abandoned South Carolina’s VC Summer nuclear plant construction. SCANA and Santee Cooper said Summer’s project costs could reach more than $25 billion, a sizable leap up from the initial price tag of $11.5 billion.

Both Vogtle and VC Summer ran into deeper trouble after construction firm and Toshiba subsidiary Westinghouse filed for bankruptcy in March. In June, parent company Toshiba agreed to pay the Vogtle owners $3.68 billion whether the plant is completed or not.

Yet there appears to be doubt over whether Toshiba will follow through with those payments. To continue the project, Southern is arguing for an acceleration or increase in federal loan payments. The utility is also pushing Congress to extend federal tax credits for nuclear construction.

E&E News reports that a Freedom of Information Act request revealed Southern CEO made roughly six visits to the DOE between February and July. The outlet also reported that an email from Westinghouse obtained by E&E revealed that Southern’s Nuclear Board did not make a decision on whether or not to continue construction on Wednesday as expected.

Georgia Power is expected to file its 17th Vogtle Construction Monitoring report on Aug. 31. The company has said it anticipates paying between $6.7 billion to $7.3 billion for its share of the nuclear project after accounting for Toshiba’s guarantee obligations. Oglethorpe is slated to pay $5 billion, but will need to increase that amount, according to a recent Securities and Exchange Commission filing.

Recommended Read

It’s no longer about power outages: Utilities are finding new ways to communicate with their consumers

AUTHOR:Robert Walton@TeamWetDog June 19, 2017

Remember when no one wanted to talk with their utility? That’s not the case anymore By now it is a cliche that the utility industry has been “slow to change.”

It makes sense, of course: Monopoly providers selling a standard product have scant reason to innovate. And when there is little difference between products and no choice, customers aren’t going to ask for more.

But if you’ve been paying attention to the industry in the last several years, you see this is changing quickly. Gone are the days when utility calls were only bad, the result of either an outage or a high bill. Now, power companies reach out more frequently and communications are beginning to closely resemble those from the retail and tech spaces. And customers are … happier.

J.D. Power has tracked four years of consecutive improvement in residential customer satisfaction. On a 1,000-point scale, the customer research firm’s 2016 survey pegged overall utility satisfaction at 680 — up 12 points and consistently rising, but still trailing auto insurance and banking. The firm’s new survey is expected out next month.

“Consumer engagement has become a real thing,” said Seth Frader-Thompson, co-founder and President of EnergyHub. “It used to just be Opower and a bunch of others. It was somewhere between ‘squishy’ and ‘ineffective.’”

Opower was the cloud-based efficiency and engagement company that made a name for itself innovating behavioral demand response programs that leveraged big data to subtly cue customers to reduce energy usage. The company launched a decade ago, aiming simply to create a better power bill, but rapidly morphed into a thought leader in the space and was acquired by Oracle last year for more than $500 million.

The acquisition created the largest cloud services company in the utility sector, and company officials said the goal was to create an end-to-end solution for energy management.

If all of that explanation blurred together—from bill inserts to cloud-based demand management in 10 years and a half dozen paragraphs—that is essentially the pace of change which has swept over the industry. Alongside rapid advances in distributed energy, you can blame or credit Amazon, Google, Uber, online banking and the airline industry.

Electric utilities are finally moving beyond a narrow focus on delivering power, said Patty Durand, president and CEO of the Smart Grid Consumer Collaborative (SGCC). They are leveraging their knowledge of the industry with new tools and communications channels, and “they are repositioning themselves to be the energy experts,” she said.

That means efficiency, self-generation, and a focus on renewables. And the trend is likely to continue, according to Durand, as a new generation of power customer becomes even more engaged. SGCC recently completed research on consumers born between 1982 and 1999, and will produce additional analysis this summer focused on engagement surrounding Millennials.

“The shift we’re anticipating is more engagement around electricity and sustainability,” she said. “The electricity industry is well-positioned to take advantage of that higher sense of value.”

Engagement is being driven by choice and technology

There are two key aspects to the rapid growth in customer engagement: new ways of communicating and new products. Allowing customers more control over the energy they purchase leads to higher engagement, while an array of sales channels and feedback systems means they can choose what works best for them.

“There is a really strong overlap with those who embrace a digital lifestyle and some of the green champion segment,” Durand said. “That is a big implication for utilities to pursue.”

SGCC’s “Consumer Pulse and Market Segmentation Study,” grouped consumers into broad categories reflecting their interest in energy products and comfort with technology. While some customers simply want to be left alone (Durand recommends that you do), and others are already highly-engaged, there is a significant middle ground that can be reached with the right message.

“The real opportunity (and challenge) for those creating programs and wanting to increase consumer engagement is the ‘Selectively Engaged’ middle,” the report concluded. But the research also warned, “they will listen selectively and they will act only when an offer is clearly aligned with their values.”

About 40% of those customers will make contact once or twice in any six-month period, SGCC found. “Be sure you have an offer that addresses their values and interests,” the report suggests.

Having that offer ready means knowing the customer. Electric utilities have access to enormous amounts of customer data, and increasingly they are turning to outside for help in leveraging it. Utilities can look at generational cohorts, whether they live in an urban or rural area, household income and home ownership, information that the report points out is available “from publicly available information sources to identify communities and consumers when targeting offers.”

“There are companies that help utilities do that,” said Durand. “They will take a utility customer database and score it, field by field, and append onto each record what is publicly known about the consumer.” That could include magazines subscribed to, how frequently they vote, or examining tax exempt donations for environmental interests.

“There is a lot of public information that other industries spend money on to better understand consumers,” said Durand.

Connected devices, connected customers

Energy-monitoring devices have been around for a decade, but it is only in the last few years that they have broadly moved beyond a a niche category. Carol Stimmel, founder of Manifest Mind, has a phrase for it: “Mean time to kitchen drawer.” The first generation of devices simply didn’t do much, and consumers quickly lost interest.

But the Internet of Things has changed that, and getting customers to engage with their utility through some kind of a device is a growing and important trend. In a 2015 report, Stimmel estimated the home energy management market would reach an annual value of $2.2 billion in North America by 2022.

According to SGCC’s research, traditional communication methods are in decline and digital is on the rise in the staid utility industry. Website visits are up, telephone communication and home visits are down. About 7% of customers are using a smartphone app to communicate with their utility, roughly the same number are texting their power provider, and social media is a small but growing segment as well.

“Social media has seen very high growth,” Durand said. “Every utility has launched a social media platform.They’re into Twitter and Facebook … because that’s where consumers are.”

Close to 10% of homes in urban areas have some kind of a connected device, according to Frader-Thompson. Most commonly that’s a thermostat, and the number is growing about 40% year-over-year.

“Delivery channels have become very digital,” he said. “If a customer has some sort of device, the best way to reach them is through their phone.”

A full two-thirds of enrollments for utility Bring Your Own Thermostat (BYOT) programs are done via a smartphone, Frader noted, and a lot of this evolution remains in the early stages. “We’re only 10 years into the smartphone,” he said, and their functionality is growing.

The BYOT model is a popular and growing method for utilities to attract customers to demand management programs, allowing choice and control within the home as utilities link their systems with more manufacturers’ devices.

“A big change was being able to leverage the devices already in homes,” Frader-Thompson said.

And the ability to connect with more and smaller customers, and to see them as granular resources, is broadly changing the way the entire system works, he explained.

“The key changes were modern software platforms and communication technology that allows utilities to be more surgical: they can target only the areas where they need load relief, they can run shorter and more frequent events, they can shift load throughout the day, and they can have load follow renewable supply both up and down,” Frader-Thompson said. “And obviously they can still reserve capacity for operational emergencies

“What you used to see, demand response was an emergency resource, and utilities would put it in and hope they didn’t have to use it,” Frader said. “Part of that was because of the technology they were putting in people’s houses. The technology wasn’t as capable, but has gotten better. … Now, instead of only running demand response territory-wide, utilities are moving into ‘operational demand response’ and might be doing some kind of demand response every day.”

More communications, more ways

In general, as long as utilities are targeting their message and tailoring it to a customer, more communication may be better.

Salt River Project, for example, sends out 1.5 million customer emails each month to its 1 million customers. And while much of the engagement focus is on residential customers, the same ideas apply to other sectors. J.D. Power’s survey of business customers, released earlier ths year, also came back with indications of sustained improvement to satisfaction.

“Utilities are really beginning to understand the importance of engagement with their business customers, which is reflected in increased communication,” John Hazen, director in the utility & infrastructure practice at J.D. Power, said in a statement.

The firm concluded that utilities are communicating with “more of their business customers, more often and in more ways, and their efforts are resulting in record-high levels of satisfaction.”

5 trends to watch in utility customer engagement

AUTHOR:Robert Walton @TeamWetDog PUBLISHED June 19, 2017

From smart thermostats to energy marketplaces, these are the trends shaping consumer engagement in the power sector
Utilities have a range of reasons for wanting to better engage their customers, from staving off retail choice threats to more efficiently managing their distribution system. But as technology rapidly evolves, and consumer expectations , power companies are broadly getting on board with several trends that allow them to better connect with customers.


Utilities can’t do it all. Their primary functions are maintaining power lines and delivering energy—not designing web sites, smart phone apps and cellular networks. But as those ancillary tasks play a larger role in how they connect with customers, utilities are reaching out to specialized tech companies to build the interfaces and products they need.

“Partnering is the name of the game these days,” said Nest’s head of energy partnerships, Jeff Hamel.

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Nest is probably the most well-known smart thermostat on the market, a sleek and modern product now owned by Alphabet (formerly Google). “Our core focus is technology and customer experience,” Hamel said, explaining why utilities turn to the company.

Seth Frader-Thompson, co-founder and President of EnergyHub, says it may be one of the most important trends in the space now. “Partnerships are huge—they’re kind of everything, going forward,” he said. “As recently as a couple of years ago, a lot of utilities were worried they were going to be pushed out. And they’re now realizing it’s a huge opportunity.

Those partnerships can include any range of services, from integrating a smart thermostat to building an app, or developing the backbone infrastructure to tie it together. Cellular and tech companies are now partnering to offer dedicated spectrum for utilities to build their networks, as utility’s quickly move away from older, one-way paging devices on their system.

Knowing the customer

It sounds simple, but utilities with better customer information are more successful in marketing programs. Some are calling it a “360 view” of the customer, while others just refer to it as segmentation. Regardless, it comes down to arming customer contacts with the most useful and complete information.

Austin Energy, for instance, has about 460,000 customers and created a program giving service representatives access to preferences and history.

“When someone calls in, we have a program we kind of developed in-house that gives us a pretty good sense of what that customer really prefers, and it creates a much more personal relationship with our customers,” Deborah Kimberly, Austin Energy’s Vice President of Customer Energy Solutions, told Utility Dive.

“Whether it’s a billing issue, outage management, a move or disconnection, that’s where the utility can engage those customers if they know a little about them,” said Smart Grid Consumer Collaborative President and CEO Patty Durand. “That’s where they need to invest a little more.”

Connected devices

The internet has helped connect a wide range of devices to the web, from televisions to security cameras, and sprinkler systems to phones. From an energy and home perspective, the most significant is the smart thermostat.

“Smart thermostats are probably the best gateway to engage consumers,” said Durand. “If you’re going to pick one thing, the research points towards thermostats. It’s something everyone is already aware of. Very high numbers of people want one.”

Austin, Texas, is now requiring all new home construction to include smart thermostats, putting more customers in closer connection with the city’s utility and demand management programs.

But connected devices go far beyond smart thermostats. By 2021, internet-connected devices will account for more than half of the world’s 27 billion gadgets, according to Cisco. In the energy space, those will include water heaters, electric vehicle chargers, pool pumps and more—anything that consumes energy which can possibly be used to shift demand to off-peak and less-expensive times.
Big data

The ability to collect and utilize large amounts of data is helping utilities not just market services and programs more effectively, but also to operate their system more effectively and reliably.

The industry will need to invest more in reaching customers, said Durand. “It’s a bit too fast, too soon, to imagine the electricity can go from not marketing to their customers to understanding them on an individual basis. There needs to be step-wise growth.”

Companies like Axiom and MSI can “score” a utility’s database field by field, using publicly available data that other industry’s are already using to better understand customers. “It doesn’t have to be expensive,” said Durand, “though it can be, depending on how much information you gather.”

On a larger scale, tech-focused energy companies can help other organizations manage their data. Walgreens tapped EnerNOC in 2015 for its energy intelligence software and ability to manage the chain’s utility accounts. And utilities are using the processing power behind their demand management programs to help keep the grid running smoothly.

“What you used to see, demand response was an emergency resource, and utilities would put it in and hope they didn’t have to use it …part of that was because of the technology they were putting in people’s houses. The technology wasn’t as capable, but has gotten better,” said Frader-Thompson. “Now, instead of only running demand response territory-wide, utilities are moving into ‘operational demand response’ and might be doing some kind of DR every day.”

Energy marketplaces

As utilities seek to enroll customers in demand management programs, help retrofit inefficient homes, replace older lighting, or provide any other service, many are bring all of those offerings together in one place.

Commonwealth Edison introduced an online marketplace of energy-saving devices just before the holidays last year, using Simple Energy’s platform to power the ComEd Marketplace. ComEd’s President and CEO Anne Pramaggiore, in announcing the move, said it would be a “key step to building a premier, trusted customer experience.”

Pramaggiore added that ComEd is expecting the marketplace to evolve over time, eventually becoming a place where “our customers can transact with us and other parties for a wide range of energy-related products and services.”

Georgia Power’s marketplace is also powered by Simple Energy, and offers LED lighting, thermostats, water-saving devices, a security camera and power strips. And California’s Pacific Gas and Electric offers everything form efficient water heaters to air purifiers and sound bars.

“I know of almost no utility that isn’t investigating or hasn’t launched an ecommerce site,” said Durand.

Utility customer engagement — what you need to know

AUTHOR:Gavin Bade @GavinBade PUBLISHED June 28, 2017

More and more, utilities are realizing they’re in the customer service business.

It wasn’t always that way. Power companies used to refer to the individuals on the other side of the meter as “ratepayers” or even just “load.”

But as the digital economy increases choices in all industries, power customers are demanding the same of their electric utilities. While many are still content with a default power service package, increasing numbers want additional options to make their electricity consumption cleaner and more affordable.

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The shift represents both an opportunity and problem for utilities. If they do nothing, customers could look to alternative service providers, like rooftop solar and community aggregators, leading to load defection and decreased utility revenues. And as more corporations embrace sustainability targets, they may opt for direct contracts with alternative energy suppliers, bypassing utility service.

But if power companies act, they can use these new customer desires to strengthen their relationships. Partnerships with third party vendors can provide customers with efficiency upgrades, smart devices and distributed generation, allowing utilities to use the behind-the-meter resources for grid services. And in some states, regulators are building in performance-based incentives that allow extra revenue earning if utilities meet customer engagement goals.

How can utilities navigate this new world of customer service? That’s what we endeavor to answer in this Spotlight, highlighting best practices and emerging ideas for customer engagement in the power sector.

5 trends to watch in utility customer engagement
From smart thermostats to energy marketplaces, these are the trends shaping consumer engagement in the power sector. Read More >>
Utilities are finding new ways to communicate with their consumers
Remember when no one wanted to talk with their utility? That’s not the case anymore. Read More >>
Utility customer engagement goes digital
Utilities find the best engagement experience involves meeting customers where they are — online and on mobile devices. Read More >>
For utility customer satisfaction, J.D. Power says communication, control are key
Customers are happiest when their utility engages before there’s a problem, a new industry survey shows. Read More >>
What do utility customers want? There’s an app for that
The energy app landscape is expanding fast as more vendors and utilities tackle energy efficiency and customer relationships via the mobile device. Read More >>
Corporate demand pushes new generation of utility green tariffs
Utilities are rolling out more sophisticated, lucrative green tariffs to satisfy corporate sustainability goals. Can they prevent key accounts from defecting to independent suppliers? Read More >>
Inside Austin Energy’s customer-focused business strategy
By offering its customers an aggressive lineup of energy products to match their needs, interests and values, the utility is lowering customer bills at the same time. Read More >>

DC Circuit rejects FERC approval of Southeast pipelines project over climate concerns


Robert Walton

Aug. 23, 2017
Dive Brief:
The court’s decision could have wide-ranging implications for infrastructure, as it directs FERC to examine climate impacts of how the gas is being used.

Sierra Club Staff Attorney Elly Benson, in a statement, said that even though the pipeline is intended to deliver natural gas to Florida power plants, “FERC maintained that it could ignore the greenhouse gas pollution from burning the gas. … Today’s decision requires FERC to fulfill its duties to the public, rather than merely serve as a rubber stamp for corporate polluters’ attempts to construct dangerous and unnecessary fracked gas pipelines.”

The Sabal Trail pipeline would run more than 500 miles through Alabama, Georgia and Florida and would supply gas to Florida Power and Light and Duke Energy of Florida. The project is a joint venture of Spectra Energy Partners, NextEra Energy and Duke Energy.

While President Trump has issued an executive order to ease the siting of major infrastructure, Karp said the court’s decision strongly indicates “that courts still consider a federal agency’s thorough evaluation of the impact of GHG emissions to be an essential element of [National Environmental Policy Act] compliance.”

InsideClimate News points out that this is the second federal court to rule this month that downstream impacts must be taken into account. Earlier in the month, a District Court judge rejected a Montana coal mine expansion in Montana Environmental Information Center v. U.S. Office of Surface Mining.

Richard Revesz, director of the Institute for Policy Integrity, said the two rulings show how Trump’s executive order “is misguided and shortsighted.”

“The executive order gives federal agencies a false sense of security that they can ignore the cost of greenhouse gas emissions in their policy decisions,” Revesz said in a statement. “But as these recent rulings show, agencies will lose legal challenges when they don’t appropriately consider climate change impacts. Rather than speeding the process of infrastructure and energy development, the Trump administration has risked slowing it down.”

The EPA was supposed to respond to Maryland’s petition by July 15th—but failed to carry out its responsibility to act.

Published by:Environmental Defense Fund EFD August 23, 2017.

Pollution doesn’t stop at state borders. And in the case of Maryland, smokestack pollution from states like Pennsylvania, Ohio, Indiana, West Virginia, and Kentucky is blowing downwind—putting you and your community in harm’s way.

Even worse: The power plants responsible have already installed pollution controls that can help—they’re just not using them. That’s why Maryland joined with other downwind states to petition to EPA to do its job and enforce its “Good Neighbor” protections under the Clean Air Act that tackle this problem.

The EPA was supposed to respond to Maryland’s petition by July 15th—but failed to carry out its responsibility to act.Don’t stand for inaction: Take action today, and tell EPA Administrator Scott Pruitt to step up, do his job, and protect public health


Administrator E. Scott ‘Scott’ Pruitt
Send Message


Please enforce the EPA’s “Good Neighbor” Provision

Dear Administrator Pruitt,

* Personalize your message

I am writing today to strongly urge you to enforce the EPA’s “Good Neighbor” Provision. The deadline to respond to the Good Neighbor petition filed by Maryland and other downwind states last year has come and gone, without any response from your agency. These states and the communities afflicted by coal plant smokestack pollution deserve an answer, now more than ever.

We are in the midst of peak ozone season when poor air quality is at its most dangerous levels and putting people’s health–especially the health of children, the elderly, and those with asthma–at risk. Pollution impacting local communities and crossing over state borders only exacerbates the problem, and leaves those downwind states without any recourse to help their residents.

Yet these coal plants have already-installed pollution controls on their smokestacks meant to lessen the negative effects to air quality in communities and states downwind of their plants; they’re just not turning them on.

Please enforce the reasonable and common-sense “Good Neighbor” Provision, and protect public health and vital ecosystems threatened by this dangerous smokestack pollution.

Ronald Bethea
7614 15th Avenue
Takoma Park, MD 20912-7052
United States

SEIA Opposes Section 201 Petition

Wednesday, April 26, 2017
WASHINGTON, D.C. – Following is a statement from Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association (SEIA), on Suniva’s filing today of a Section 201 petition with the International Trade Commission:
“The Solar Energy Industries Association, representing 1,000 member companies across the entire solar supply chain, seeks to promote and protect the interests of the 9,000 U.S. companies engaged in the solar industry and the more than 260,000 American workers they employ. SEIA supports fair and free trade of solar equipment to grow the American solar industry, which is strengthening our national security and driving local and national economic growth.
“While we have not had a chance to fully review Suniva’s petition to the International Trade Commission, we strongly urge the federal government to find a resolution that bolsters the competitiveness of American solar cell and panel manufacturing, which employs approximately 2,000 people in the U.S., without erecting new trade barriers. SEIA opposes any resolution that restricts fairly-traded imports of solar equipment through new tariffs or other barriers that endanger the livelihoods of the 260,000 American solar workers and their families living in every state in the Union.”
About SEIA®:
Celebrating its 43rd anniversary in 2017, the Solar Energy Industries Association® is the national trade association of the U.S. solar energy industry, which now employs more than 260,000 Americans. Through advocacy and education, SEIA® is building a strong solar industry to power America. SEIA works with its 1,000 member companies to build jobs and diversity, champion the use of cost-competitive solar in America, remove market barriers and educate the public on the benefits of solar energy. Visit SEIA online at
Media Contact:
Alex Hobson, SEIA Senior Communications Manager, (202) 556-2886
International Trade
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Bipartisan Group of 69 Lawmakers Urge Feds To Oppose Punitive Tariffs That Would Gut U.S. Solar Industry

House, Senate members say tens of thousands of U.S. jobs at risk in Suniva case before the International Trade Commission
Friday, August 11, 2017
WASHINGTON, D.C. – Today, a bipartisan group of 16 senators and 53 members of the House of Representatives sent open letters to U.S. International Trade Commission (ITC) Chairman Rhonda Schmidtlein urging the ITC to reject a petition that would slap tariffs on imported solar panels and cells.
“Solar companies in our states believe the requested trade protection would double the price of solar panels,” the Senate letter to the ITC said. “Increasing costs will stop solar growth dead in its tracks, threatening tens of thousands of American workers in the solar industry and jeopardizing billions of dollars in investment in communities across the country.”
The ITC is evaluating a petition that Chinese-owned solar company, Suniva, filed with the agency in April shortly after declaring bankruptcy. It was later joined by German-owned SolarWorld, also in bankruptcy. The agency is considering whether these two companies out of more than 8,000 across the U.S. solar industry deserve tariff relief that would impact the entire market.
The letters come just days before the ITC holds its first public hearing on the petition on Aug. 15. Hundreds of solar workers from all over the country, including California, Maryland, North Carolina, New Jersey, New York, Florida, Minnesota, Massachusetts, Rhode Island, Pennsylvania and Virginia, will converge in Washington to explain the personal impact this case could have on their livelihoods.
The American solar industry is growing 17 times faster than the rest of the economy, and created 1 out of every 50 new jobs in the U.S. last year. Implementing trade barriers would double solar prices, grinding growth to a halt and forcing 88,000 Americans — one-third of the U.S. solar workforce today — to lose their jobs just next year.
Lawmakers who led the letter effort to the ITC include: Senators Thom Tillis (R-NC) and Martin Heinrich (D-NM) and Representatives Mark Sanford (R-SC), Mike Thompson (D-CA), Pat Meehan (R-PA) and Matt Cartwright (D-PA).
“This letter shows that trade tariffs are not a red or blue state issue,” said Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association (SEIA). “If these barriers are implemented, one of the fastest growing U.S. industries will be halted in its tracks, thousands of Americans will lose their jobs and billions of dollars of private investment will dry up.”
“We are thankful these lawmakers, on both sides of the aisle and both sides of the Capitol, recognize the solar industry’s massive impact on their states’ economies, and the irreparable harm this case could bring to families and businesses across our country,” Hopper said.
SEIA is leading the industry’s fight in the case. The association opposes any resolution that restricts fairly-traded imports of solar equipment through new tariffs or other barriers that endanger the 260,000 American solar workers and families in every state in the Union.
About SEIA®:
Celebrating its 43rd anniversary in 2017, the Solar Energy Industries Association® is the national trade association of the U.S. solar energy industry, which now employs more than 260,000 Americans. Through advocacy and education, SEIA® is building a strong solar industry to power America. SEIA works with its 1,000 member companies to build jobs and diversity, champion the use of cost-competitive solar in America, remove market barriers and educate the public on the benefits of solar energy. Visit SEIA online at
Media Contact:
Morgan Lyons, SEIA Communications Coordinator , (202) 556-2872

Federal court rejects Allco’s rehearing request in challenge to Connecticut’s renewable RFP

AUTHOR:Peter Maloney@TopFloorPow Published Aug. 21, 2017

Dive Brief:

The U.S. Court of Appeals for the Second Circuit on Thursday rejected a request for a rehearing of a case in which the plaintiff challenged Connecticut’s renewable energy procurement program.

In denying a request for an en banc rehearing of Allco Finance Ltd. v. Klee, the appeals court let stand a lower court ruling that upheld Connecticut’s right to engage in renewable energy solicitations.

The Allco case was closely watched by both sides in recent court battles involving states’ legal rights to craft policies aimed at fostering clean energy goals.

In the Connecticut case, plaintiff Allco Financial argued that the state’s renewable portfolio standard violated the Federal Power Act by compelling a wholesale power transaction and violated the U.S. Constitution’s dormant Commerce Clause.

Both arguments have been invoked in legal challenges to zero emission credit (ZEC) programs that Illinois and New York have set up to provide subsidies for nuclear generators to compensate them for their emissions free output.

Opponents say those programs skew the outcome of wholesale power markets that are under federal jurisdiction.

The Allco case was also viewed as the first interpretation by a federal court of the Supreme Court’s Hughes v. Talen Energy Marketing decision, in which the high court upheld federal jurisdiction over wholesale power markets against state energy policies, but under a tight definition.

The Allco case adds another win for ZEC adherents who last month welcomed district court rulings that upheld nuclear subsidies programs in Illinois and New York. Supporters argue that the same laws that give states the right to conduct solicitations for renewable energy resources give them the right to create ZEC programs.

“The federal appellate court has yet again affirmed Connecticut’s bedrock authority to provide for expansive clean energy that protects public health and environment for Connecticut’s families and communities,” Michael Panfil, senior attorney for the Environmental Defense Fund, said in a statement.

Valuing storage: A closer look at the Tucson Electric solar-plus-storage PPA

AUTHOR: Peter Maloney@TopFloorPower PUBLISHED Aug. 8, 2017

It may not be 1.5¢/kWh for the storage component, but the Tucson Electric PPA is still low

The power purchase agreement Tucson Electric Power signed with NextEra Energy for an “all-in cost significantly less than $0.045/kWh over 20 years” has become the new benchmark for combining solar power with energy storage, but at least one industry expert says the math is not as simple as it seems.

According to Tucson Electric, the 100 MW solar portion of the project came in at under $0.03/kWh, putting the 30 MW, 120 MWh energy storage piece in the ballpark of $0.015/kWh.

“Just because you’re being paid 4.5 cents, doesn’t mean the system costs 4.5 cents,” James Lazar, senior advisor at the Regulatory Assistance Project in Olympia, Wash., told Utility Dive in an interview.

Lazar assumes the 100 MW solar system in Arizona produces electricity for 10 hours a day and yields 1,000 MWh a day of energy. But the batteries store only 120 MWh or 12% of the solar output.

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Lazar then takes the difference between the cost with storage and the cost without storage, i.e., 1.5 cents, and divides it by the percentage of energy stored, in other words, 12%. The result is 1.5 cents divided by 12% which comes out to $0.083/kWh. When you add in a 20% discount for round-trip efficiency losses, the total cost comes to $0.089/kWh. “That is still a good deal,” Lazar said, but it is not $0.01/kWh.

The utility is still paying $0.045/kWh over the life of the contract, but “it is deceptive to call it $0.015/kWh. You have to look at what you are getting,” Lazar said.

In Lazar’s analysis, the Tucson Electric PPA does not set a new benchmark for low cost solar-plus-storage projects, though it is cheaper than two other recent projects in Kauai, Hawaii.

In one, Kauai Island Utility Cooperative is paying AES Corp. $0.11/kWh for a 28 MW solar array with a 20 MW, 100 MWh battery system. In the other, Tesla signed a $0.14/kWh PPA with the same utility for a 13 MW solar project tied to a 13 MW, 52 MWh battery system.

In both of those deals, the storage component of the combined system is more closely sized to the solar portion of the project. Applying his same analysis, Lazar comes up with a $0.17/KWh for the storage portion of the Tesla deal and $0.12/kWh for the storage portion of the AES deal. Discounted for round trip efficiency, that comes to $0.19/kWh for the Tesla deal and $0.13/kWh for the AES deal.

Lazar also points out that the costs and benefits of a project are locational. For an island system like Kauai, the solar-plus-storage projects are a good deal because they are still lower than the cost of generating power using diesel fuel, the mainstay of Hawaii’s conventional generating fleet. Those deals will definitely reduce consumers’ costs on Kauai, he said.

The Tucson Electric PPA “may be a good deal,” Lazar said. It falls in the range between on-peak and off-peak power prices and when viewed as an alternative to gas-fired peaking resources, it is becoming competitive. “This is a sea change for the industry,” he said.

Ravi Manghani, director of energy storage at GTM Research, agrees with Lazar that the storage component of the Tucson Electric project is undersized. When looking at any of these recent deals, “you have to be careful about how you apply them as benchmarks,” he told Utility Dive in an interview. GTM uses two metrics: the ratio of storage to the system and a comparison of the total energy output of both components.

Comparisons that use a single number to measure storage can be misleading, Manghani said. But “we are seeing specific examples of storage looking at competing with natural gas-fired peaking plants,” he said. Those comparison often are with fully depreciated gas peakers, but in a comparison between two greenfield projects, solar-plus-storage could be competitive, he added.

Austin Energy targets 65% renewables by 2027

AUTHOR:Robert Walton@TeamWetDog PUBLISHED Aug. 21, 2017
Dive Brief:

The Austin City Council last week voted to target 65% renewable energy by 2027, one of the most ambitious clean energy goals in the nation and a step up from the previous 55% by 2025 goal.
The Austin Monitor notes that the city’s utility is on track to meet the 55% goal, and considered even higher targets — including 100% by 2030.
Austin Energy will study additional aspirational clean energy goals, including 75% to 80% renewable energy by 2027.
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Dive Insight:

Austin Energy will now target almost two-thirds renewable energy in its mix, but the progressive city clearly has its sights set even higher.

According to the Austin American-Statesman, hundreds spoke earlier this month in favor of 100% clean energy goal, but a less aspirational target was adopted amid concerns of rising energy prices. However, amendments to the plan direct the utility to examine the possible impacts of using more carbon-free energy.

“We are so fortunate that we are a community that debates stretch goals,” Council Member Leslie Pool told the Austin Monitor. “We challenge ourselves to do more.”

As more renewable energy comes online, Austin Energy has been adding battery storage to help with the integration. Earlier this year, Younicos signed an agreement with Austin Energy for a 1.75 MW, 3.2 MWh energy storage system. The storage system will be part of a Distributed Energy Resource Management System that aims to maintain grid reliability while allowing high levels of distributed solar PV penetration.

Austin Energy has a customer-focused business strategy that has been successful in helping keep rates low, thus far. In 2015, the utility’s residential customers had the second lowest energy bills of any utility in Texas.

The utility is targeting almost 1 GW of solar by 2025, including 750 MW of utility scale renewables as well as distributed generation.

Recommended Reading:

How rural co-ops are shifting to a cleaner power mix

Driven by wind credits, low gas prices and consumer demand, rural co-ops are finding new ways to grow renewables

AUTHOR:Herman K. Trabish PUBLISHED Aug. 21, 2017

The generation mix of rural electric cooperatives is changing at the same swift pace as the the United State’s power system, with wind power, natural gas and technology innovation dominating growth. But the biggest change in their respective power mixes appears to be wind energy and natural gas investment.

“Wind is set to remain the largest non-hydro renewable resource deployed by cooperatives, with more than 850 MW of new wind PPAs planned over the next two years, accounting for nearly two-thirds of planned additions,” according to the National Rural Electric Cooperative Association’s 2016 outlook.

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For example, rural electric cooperatives added more than 900 MW of new wind capacity in 2016, according to the American Wind Energy Association (AWEA). To make room for the new generation resources, co-ops shuttered or converted 700 MW of coal between 2014 and 2016, and are estimated to shutter or convert an additional 1,344 MW by 2028, eliminated roughly 8% of coal capacity from co-ops.

“Co-ops have significantly expanded their wind energy capacity in the last ten years, and in the process developed ways to integrate this intermittent resource into the grid,” NRECA recently reported. Their utility-scale wind development “is now second only to hydro in the co-ops’ renewable portfolio.”

Credit: NRECA

The main growth drivers for co-ops, just as for the market at large, is the federal production tax credit (PTC) and state renewables mandates, according to Tracy Warren, a spokesperson for NRECA. Another major factor are rapidly falling costs for new technologies, as reported by DOE.

The combination of these factors has driven power purchase agreement (PPA) prices from and average $70/MWh in 2009 to an all-time low $20/MWh in 2016, making wind an offer co-ops can’t refuse. And low gas prices have spurred a shift from coal-fired generation, which has typically dominated co-ops’ power mixes.

But those are not the only solutions co-ops are examining to boost a cleaner power mix. Some co-ops are shifting to natural gas in light of the low prices. And still some are advocating for policy changes to encourage investment in electric vehicles and water heaters. Regardless, it’s clear the trend among all utilities, from cooperatives to investor-owned utilities, is one of fundamental resource transformation.

How co-ops are making the transition to cleaner energy resources

Generation and transmission co-ops made up the top 10 wind builders in 2016. But some are looking beyond wind energy to electric vehicles and water heaters to better integrate renewable energy. And in some areas, natural gas prices are still low enough to threaten wind energy development.

Basin Electric Power Cooperative

North Dakota’s Basin Electric Power Cooperative, has a nearly 6,700 MW load serving 2.8 million customers in 11 states, and is by far the biggest co-op user of wind. Basin Electric can claim 1,360.6 MW of installed wind capacity, according to Curt Pearson, director of media relations, which is more than 20% of its generation capacity. Basin Electric owns 285.7 MW of wind capacity and holds PPAs for the remaining 1274.9 MW.

The main drivers behind its wind growth have been a 10% renewables co-op “directive” and the economic advantages to Basin from low-cost, long-term fixed-price wind, Pearson said.

PPAs in particular offer a unique opportunity for co-ops. As member-owned non-profits, they cannot take advantage of the PTC, except through a PPA. In that case, the wind developer to use the tax credit and pass its value back to the co-op in the contract terms, according to NRECA’s 2016 generation, capacity, and markets outlook.

Many generation and transmission co-ops are joining organized markets in response to potential resource adequacy and reliability threats represented by rising levels of variable resources.

Basin Electric was one of them. As the co-op’s wind penetration rose, it joined the Southwest Power Pool (SPP) to increase its capability for integrating wind, Pearson said.

In recent wind acquisitions, Basin has consistently used PPAs. Not only does the developer pass on the PTC through the PPA, it also bears the burden of siting and is responsible for transmission through the interconnection agreement, Pearson noted.

Golden Spread Electric Cooperative

Golden Spread Electric Cooperative, located in the Texas panhandle with a 1,400 MW total generation capacity, has a different take on the low wind prices. Low natural gas prices are at present a threat to wind’s competitiveness, DOE reported. But wind’s average future stream from 2014 to 2017 vintage PPAs “compares very favorably to the EIA’s latest projection of the fuel costs of gas-fired generation extending out through 2050.”

To take advantage of low electricity market prices from this combination of factors, Golden Spread is adding natural gas units and building transmission capacity along with their wind investments. The co-op owns a 78.2 MW wind project and holds two PPAs for an additional 200 MW, making it “economically driven,” said vice president John Eichelmann.

Golden Spread also added more than 700 MW in fast-start natural gas units between 2011 and 2016.

“They were built to take advantage of our wind and the very low-cost wind available on both the Electric Reliability Council of Texas (ERCOT) and SPP systems,” Eichelmann said. “The overall market is saturated with wind. When the wind stops blowing, we can quickly start the natural gas plants to avoid high prices.”

All the natural gas units are at the same physical location and Golden Spread has installed grid-switching technology to be able to serve either ERCOT or SPP and “take advantage of the price swings in either market,” Eichelmann added.

Great River Energy

Great River Energy (GRE), is a Minnesota generation and transmission co-operative with a 2,800 MW load serving 28 distribution co-ops and 685,000 customers. It was the fourth biggest co-op wind user in 2016, with 463.75 MW. An additional 400 MW is expected to be online by 2021.

Like Basin and Golden Spread, GRE leveraged the Midcontinent Independent System Operator (MISO) for much greater transmission and dispatch reach of a regional system

And, in a similar fashion to Golden Spread, GRE is using its natural gas to accommodate wind and other variable resources. It has “modified” Coal Creek Station, its biggest coal unit, “to better adjust its output in response to market signals,” according to the the utility’s most recent IRP.

Instead of working at “a very high capacity factor,” Coal Creek will be “providing reliability to the market and serving as a backup for growing wind energy in the region,” the IRP added.

Gary Connett, director of member services and marketing for GRE, said the co-op also has a “load side strategy to better accommodate wind,” which is using 110,000 customer-owned water heaters as “a giant battery.”

GRE heats customers’ water between the hours of 11 p.m. and 7 a.m. with low-cost, MISO market energy, which is dominated by wind. “Buying the low-cost kWh at night and using the hot water the next day, when the kWh are more expensive, is a sort of arbitrage,” Connett said.

Drawing on MISO’s wind-heavy off-peak resources also allows GRE to boost its percentage of renewable energy, which in turns helps it meet Minnesota’s 25% renewables by 2025 mandate, he added.

More recently, the utility is developing a program that will manage electric vehicle (EV) charging during the same off-peak hours during which it heats water. “That is part of a long-term vision,” Connett said.

Associated Electric Cooperative

Associated Electric Cooperative is a generation-only co-op with six transmission co-op members and 51 distribution co-op members, Spokesperson Robin Harrison said. Its 5,700 MW generation capacity serves 875,000 customers across most of Missouri, northeastern Oklahoma, and a small part of Iowa.

Associated’s 750 MW of wind, obtained entirely through PPAs, puts it second among U.S. co-op users of wind. But load has been flat recently, Harrison said. Associated’s last wind addition was the 150 MW Osage project, which went online in 2015, nor has it made any recent natural gas capacity additions and is not planning, developing, or building new capacity.

Associated is not part of a regional market but its “fast-start peaking natural gas units are one factor that enabled us to add wind generation in the past,” Harrison said.

Taking advantage of the tax credits through PPAs with developers is another key factor in its wind buildout, Harrison said.

Associated’s biggest reason for building wind, however, was member demand for renewables, she added. “We voluntarily stepped forward, without a renewables mandate, to add wind to our resource mix.

Wind’s future after the PTC phasedown

The PTC still remains the core motivator behind co-ops investing in wind energy. But that credit is designed to phase out completely by 2021, and begins stepping down this year. For instance, a project that started construction in 2016 qualifies for the full credit, but projects starting this year will only get 80% of the credit and so on.

Luckily, a ruling from the Internal Revenue Service ensures projects that go online within four years of starting construction are eligible for the PTC. State renewables mandates also played a part in driving deployment of 51% of all installed wind capacity in the U.S. between 2000 and 2016, according to the DOE.

But that wind growth could encounter roadblocks if new transmission buildouts are stifled. Currently there are 14 projects, if completed, could “carry 52 GW of additional wind capacity,” the agency noted. But a policy led by co-ops could also help support wind growth.

The National Renewables Cooperative Association PPA plan started in 2009 “to assist its owners in the development and/or acquisition of renewable generating resources,” said spokesperson Todd Bartling.

At the end of 2016, NRCO members had over 2,500 MW of installed wind capacity, Bartling said. Approximately 40% of the 800 MW came through an aggregated off-taker PPA plan, which allows multiple co-ops to back a wind project that no single one of them could individually afford.

The ability to aggregate is important when no single off-taker can “provide enough revenue certainty for the developer to move the whole project forward,” Bartling said.

It is not an entirely new concept, he said. The aggregation is on the load side and the wholesale level, using normal market mechanisms to ensure that each co-op pays for the part of the project’s output for which it contracted.

Another policy initiative, backed by NCREA, is an effort to encourage the Federal Energy Regulatory Commission (FERC) to “adopt wholesale market policies which encourage resource diversity,” according to testimony by Michael Cocco, senior director of RTO and regulatory affairs for Old Dominion Electric Cooperative. NRECA wants FERC to endorse principles or issue guidance supporting state-level policies by RTOs.

The association wants FERC to reduce RTOs’ “repeated, reactionary revisions to market designs” and to support market policies that “accommodate legitimate state policy objectives” and “allow regional flexibility.”

GRE’s Connett advocated for a different type of policy that would support more use of renewables for “beneficial electrification” such as heating water and charging electric vehicles during off-peak hours. This is a similar argument outlined in a white paper from the Regulatory Assistance Project describing beneficial electricification.

“Traditional energy efficiency metrics are increasingly obsolete,” the white paper says. Using only “kWh saved” as a metric for reduced emissions misses opportunities “in fuel conversions from fossil energy to efficient electric technologies powered by an increasing clean generation fleet.”

Connett argued that “if the kWh come from renewables, we should encourage their use.”

A policy is urgently needed recognizing “that using electricity generated from renewables is a good thing,” he added. “And it is needed as soon as possible because the purchase of things like water heaters and EVs are long term decisions.”

US grid untroubled by total eclipse despite plunge in solar output

August 22, 2017 Solar Eclipse

Robert Walton @TeamWetDog
PUBLISHED Aug. 22, 2017
Dive Brief:

A total eclipse made its way across the United States yesterday, bringing millions outside to witness the event as solar output plunged in some key areas. By all accounts, however, the nation’s power grid managed the event well and there were few if any issues.
Bloomberg reported California saw utility-scale solar output plunge 3,400 MW — less than the 4,200 MW that had been expected. While California has the most solar capacity in the nation, its plants did not lie along the eclipse’s path of totality.
In North Carolina, a state with a significant amount of solar in the path of totality, Duke Energy lost about 1,700 MW of capacity during the height of the eclipse but the system reacted as planned and there were no outages.
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Dive Insight:

Yesterday’s eclipse enthralled the nation, leaving two things in short supply: eclipse glasses and solar energy. But at least on the energy front, utilities successfully planned for the event, giving some insight into the growing reliability systems with large amounts of of intermittent energy.

“We were able to balance the Duke Energy system to compensate for the loss of solar power over the eclipse period,” Sammy Roberts, Duke Energy director of system operations, said in an emailed statement to Utility Dive. “Our system reacted as planned, and we were able to reliably and efficiently meet the energy demands of our customers in the Carolinas.”

Duke Energy has 2,500 MW of solar capacity connected to its system in North Carolina. Given the weather conditions yesterday, utility officials said they would normally expect 1,808 MW of solar output during the afternoon, but were getting only about 109 MW during the eclipse’s peak.

In the PJM territory, the grid experienced a drop of approximately 520 MW of wholesale solar generation from just before the eclipse reached its peak. The grid operator also estimated that electricity from behind-the-meter solar generation decreased by approximately 1,700 MW.

PJM Interconnection also said other factors made dealing with the drop-off of solar power easier. The operator said it had expected a reduction in power from rooftop panels, but several factors — including lower cooling loads, increased cloud cover and changes in behavior related to the eclipse — resulted in a net decrease in demand of about 5,000 MW throughout the eclipse.

According to the U.S. Energy Information Administration, more than 21 GW of solar capacity was expected to be impacted. Europe experienced a total eclipse in 2015 that impacted 90 GW of solar capacity — with 40 GW in Germany, supplying 40% of that country’s electricity demands.

Utility-scale solar provides less than 1% of the United States’ electricity use, and there were less than 20 utility-scale generators in locations where the sun was wholly obscured yesterday. But state renewable portfolio standards, falling costs and interest in rooftop generation means the country’s grid will continue to add carbon-free, intermittent generation.

Utilities and ISO officials were closely watching yesterday’s event to prepare for the next total eclipse in the United States in 2024.

California utilities plot ways to prep the grid for the coming EV boom

Utilities are rolling out comprehensive pilot programs to integrate EVs onto the grid and prepare for the coming load

Herman K. Trabish

Aug. 22, 2017
Electrifying the transportation sector is no easy task. But, as with many innovations occurring in the power sector, California is leading the way.

The California Public Utilities Commission recently approved two rounds of pilot proposals to electrify transportation from the state’s investor-owned utilities (IOUs). These pilots will cost a combined $1.3 billion and go beyond Gov. Jerry Brown (D)’s plan to have 1.5 million zero emission vehicles (ZEVs) on the road by 2025.

The pilot projects would cover the gamut of possible ways to boost electric vehicle deployment including rate designs, smart charger buildout, public education efforts, and help utilities avoid upgrade costs aid Jim Lazer, senior advisor for the Regulatory Assistance Project (RAP). But these particular projects are not just focused on cars — they also focus on school and transit buses as well.

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The evolution of this pilot project closely follows the growth and innovation in the transportation sector — in the first quarter of 2016, 97 makes and models of plug-in hybrid and battery EVs composed the market. At least 181 such models are forecast for the last quarter in 2018, according to Brett Hauser, CEO of charging station software provider Greenlots.

Utilities are examining rate design as another way to integrate electric vehicles into the grid, and use them as a way to shift load. All told, these pilot projects could pave the way for utilities across the United States to boost deployment of electric vehicles while leveraging their grid benefits.

Plugging in cars

In 2016, the CPUC approved $197 million in light-duty EV charging infrastructure pilots for California IOUs. They included $22 million for SCE’s Charge Ready pilot; $45 million for the San Diego Gas and Electric (SDG&E) Power Your Drive program; and $130 million for the Pacific Gas and Electric (PG&E) charger installation program.

In 2017, the IOUs proposed a series of projects, that include $553.8 million for SCE’s charging infrastructure buildout; $225.9 million for SDG&E’s residential charging; and $233.2 million for two projects for PG&E. These investment are expected to seed significant EV growth, and allow utilities to be prepared.

Brett Hauser, CEO of charging station software provider Greenlots, said it’s important to manage charging now because EVs are in for “hockey stick growth.

An EV can increase a home’s electricity consumption 60%, Hauser added. For instance, three homes with new EVs could impose the need for utility expenditures on new infrastructure. But if the utility can control that load, it can avoid those expenditures and keep the system stable. The utility could even use the load to its advantage, adding to ratepayer savings.

Utilities’ ability to control charging effectively has been demonstrated in recent pilots but the savings to customers remain uncertain, Hauser added.

Customer savings

But Jim Lazer, senior advisor for the Regulatory Assistance Project (RAP) showed how savings are plausible with smart charging. He compared three utilities that had comparable average $0.16/kWh rates but very different rate structures.

The only constraint that charging be done during non-peak hours. Eversource, in New Hampshire, for instance, has a “high demand charge app applied on a ‘non-coincident with peak’ basis,” he said. In contrast, the Sacramento Municipal Utility District (SMUD) has a small “non-coincident with peak” demand charge and a medium-sized “coincident with peak” demand charge with a time-of-use [TOU] energy rate. And Burbank Water and Power has only a TOU energy rate.

The rates vary. Eversource can claim a $0.57/kWh cost of charging. The SMUD rate results in a $0.21/kWh cost of charging. And the Burbank rate is even lower, resulting in a $0.16/kWh cost of charging, Lazar said. “Intuitively, a load during off-peak hours ought to be lower but that was only true for the Burbank rate design.”

Based on these results, Lazar concluded the time-of-use rate, similar to Burbank’s, is the better than the other options, but the ideal scenario is smart charging that is controlled to benefit the grid. That control could be by the utility, the vehicle manufacturer or even an algorithm, he added.

Greenlots’ Hauser agreed rates alone are not adequate and utility control is necessary. “Things that go as planned can be handled by algorithms but someone has to have an overall system view so interventions can come when needed.”

But the present hurdle is implementing communications standards and protocols and pilots, according to Dave Packard, vice president for utility solutions for EV charging station provider ChargePoint. ChargePoint is participating in will advance the effort, he added.

ChargePoint’s Packard said his company has always had technology in place to allow managed charging, and its protocols and pilot projects will advance the effort.

“But getting it right takes time,” he added.

Those pilots include approved SCE and SDG&E plans and and another approved pilot for submetering accuracy involving all three California IOUs, Packard added.

The big question for ChargePoint is whether smart charging provides enough value to drivers. “We have taken great pains to get the tools in place,” Packard said. “But is it worth the $20 a driver gets for allowing the utility to turn off the charging station during a few demand response events each year?”

ChargePoint is confident of its ability to scale and manage its charging network to maintain the driving experience, and to give utilities the control they need, Packard said. ‘But is the value there?”

For utilities, it is a matter of whether the savings from managing the load in a way that integrates renewable generation and distributed resources is greater than the cost of new generation, he said.

Greenlots’Hauser said it depends on how value is defined. “There is value to all customers if the system is more cost-effective because the utility avoided or deferred expenditures,” he argued. “Participating drivers may earn a monthly fee or a utility-provided charge station. That will vary by utility and state policy.”

RAP’s Lazar said the process could be completely cost- and involvement-free for drivers if charging is managed so it does not impose on them and they can opt out whenever necessary. “The science of smart charging is evolving quickly.

Moving on to buses

PG&E proposals to boost electric vehicle deployment this year included $210 million program that would serve buses along with other vehicles.

The utility also proposed a $3.35 million “priority” review project that would convert an operating fleet of transit buses or delivery vehicles to electricity. Another $3.35 million priority investment would deploy electric school buses and test incentives and rate designs to encourage charging that takes advantage of renewables.

Motiv CEO Jim Castelaz said school buses have the potential to deliver power to buildings or the grid whenever needed. “But that is only in theory,” he added. “There are not today mechanisms or a volume of vehicles in place to do it.”

The economics are also uncertain, he said. “But it looks like during the summer months when the buses are not being used, it could be revenue positive to use them to provide grid services or help meet the late afternoon peak demand.”

More interesting ways to monetize vehicle fleets will come when “regulation and the technology catch up with the theory, and it is moving that way,” Castelaz added.

On SCE’s list of priority pilots for this year includes a proposed $3.98 million investment to serve electric commuter buses in its service territory. Its $553.82 million standard review proposal includes a buildout of infrastructure to serve buses and other large vehicles.

SCE also asked CPUC to approve a new demand charge-focused rate design to support the transit bus industry’s growth, especially as major metropolitan areas in its service area begins investing in electric transportation.

The Los Angeles Metropolitan Transit District recently purchased 95 electric buses and has plans to be at 100% zero-emission buses by 2030. Other transit districts served by SCE have similar or more aggressive commitments.

SCE’s Garwacki said the new rate design is needed because of the many financial factors, and California policies are quickly moving the utility’s power mix to renewables, distributed resources, and electric transportation.

Energy costs are now reflected in time-varying rates, Garwacki said. But distribution costs are covered by a non-time-differentiated demand charge, even though they are a combination of grid infrastructure costs and peak-time-related costs.

Because of the rising need for flexibility and fast ramping, “both energy and distribution rates need to have a peak time varying component rather than a straight fixed demand charge,” he said.

Demand charges allow utilities to recover capacity-related costs, Garwacki said. “The biggest utility fear is that customer-sited resources will create zero net energy customers who can bypass capacity costs if they are recovered only in volumetric energy charges.”

With a demand charge, the utility gets paid for capacity and reduces the volumetric charge, he said. The result is economically efficient consumption, which encourages load growth. “It works pretty well for the typical range of load factors, but early adopter electric transportation has a very low load factor.”

Load factor is actual usage compared to potential usage. SCE’s innovative rate design would allow early adopter transit districts to avoid demand charges.

Early adopter transit districts with few buses, erratic charging patterns, and low load factors still have high peak demand, Garwacki said. “We want to avoid the demand charge billing impact.”

Why Minnesota’s Community Solar Program is the Best

John Farrell | No Comments | Updated on Aug 9, 2017

The content that follows was originally published on the Institute for Local Self-Reliance website at November 2016: From now on, we’ll keep the most recent data on the program’s development in this post

I’ve been asked a lot of questions about Minnesota’s community solar program over the past couple years and it’s time to make one thing clear: Minnesota’s program is the best in the country.

Why? Because there 10 times more community solar projects in the queue—400 megawatts—in Minnesota than have been built in the history of community solar in the United States (40 megawatts).

Minnesota’s program (see infographic) is a comprehensive approach that makes developing community solar projects economically viable and—most importantly—that does not cap the development of community solar projects. The latter is the key.growth in community solar installations usa

Colorado’s landmark community solar legislation, for example, caps the program at 6.5 megawatts per utility per year (although there’s hope it may increase in the future). Massachusetts has just revamped their solar renewable energy credit program to make community solar a better investment. No other state has had significant community solar development, despite 11 states that have some form of virtual net metering that allows for sharing electricity output from an off-site solar energy project.

How big is Minnesota’s projected success?

Xcel Energy’s queue for community solar already has 20 times more solar in it than the state had installed at the end of 2014. If it all gets built, it would be enough to rank second in the country in annual solar installations in 2014.

I recently wrote that a state’s solar market can’t really launch without third party ownership—leasing or power purchase agreements that allow home and business owners to install solar with zero upfront cost, hand off maintenance concerns, and save money from day one. Indiana was the only potential exception, due to a (now defunct) feed-in tariff program operated by Indianapolis Power and Light. Minnesota may be the second.

I’m no stranger to community solar programs. I worked closely with advocates in Minnesota on the legislation, as part of a suite of pro-solar policies that passed in 2013. I’ve written extensively on community solar policies, from a 2010 report on the obstacles and opportunities to podcasts with leaders in the community solar movement. I’ve testified on community solar proposals in California and Maryland, and lent my advice in other states.

If the projects develop as expected in Minnesota, there will be no contest. To say it like a local, “Minnesota’s community solar program is not too bad.”

minnesota community solar infographic 2 – ILSR

Photo credit: Michael Hicks via Flickr (edited by John Farrell, CC BY 2.0 license)

This article originally posted at For timely updates, follow John Farrell on Twitter or get the Democratic Energy weekly update.

TAGS: community solar / distributed solar / electricity / minnesota / solar energy / utility

About John Farrell
John Farrell directs the Energy Democracy initiative at the Institute for Local Self-Reliance and he develops tools that allow communities to take charge of their energy future, and pursue the maximum economic benefits of the transition to 100% renewable power. MORE

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Florida utilities spend millions to make case to limit rooftop solar

Herald/Times Tallahassee Bureau NOVEMBER 01, 2016 2:49 PM
Read more here:

Lost in the tumultuous presidential election and the down-ballot fears, something big has been happening quietly in Florida this year: Electric companies have dropped $29.3 million into political campaigns.

Since January 2015, $20 million of the industry’s profits went to finance and promote Amendment 1, the ballot initiative that attempts to frustrate the expansion of consumer-owned rooftop solar in Florida. And another $9.3 million more went to fuel the campaigns of a select group of powerful legislative leaders in an effort to prepare for a prolonged war against rooftop solar. (Note this number is updated after a significant miscalculation of the total in initial reports.)

The bulk of the money is being used to promote Amendment 1 but, if that effort fails, the industry is also investing heavily into the Legislature to create favorable conditions in Florida, as utilities have in other states, to push back against the proliferation of rooftop solar. (The money the companies are allowed to use to finance campaigns does not come directly from consumer bills but from utility company profits, which are guaranteed as regulated monopolies.)

In other states, that effort has included attempts to make solar less economically feasible by reducing the amount the utility spends to reimburse customers for generating excess electricity to the grid through “net metering,” imposing new fees on solar users and pre-empting local governments from opening the door to more solar competition. 

Former Florida U.S. Sen. Bob Graham blasted the amendment on Tuesday as “deceptive” and unneeded. He warned that if the measure is approved, it would be a harmful step “backwards” for the state’s energy future.

“I’m discouraged as a citizen how far we have slipped and see Amendment 1 as a means of accelerating that decline in solar in Florida,” he said during a conference call with reporters.

According to Division of Elections reports, the biggest spender on the effort is Florida Power & Light, the state’s largest electric utility, which has poured $14.1 million into political campaigns this cycle — $6.1 million into state legislative campaigns, and $8 million to Consumers For Smart Solar, the utility-backed political committee promoting the amendment on the Nov. 8 ballot.

Duke Energy, the St. Petersburg-based company and the state’s second largest utility, spent $8 million, including $6.7 million promoting Amendment 1. Tampa Electric Co., the third largest utility, has pumped $4.7 million into the political system, including $3.2 million for the amendment; and Gulf Power has invested $2.5 million, including $2.2 million to the political committee backing the amendment.

The committee has raised more than $26 million, including $6 million from nonprofits and special interest political committees that have received substantial funding from the utility industry. By comparison, records show Florida’s sugar industry spent $57.8 million over 20 years to dominate legislative policy. The electric utilities will have spent more than half of that in a single year.

The candidates whose political committees benefited most from the money were all Republicans: Agriculture Commissioner Adam Putnam, who accepted more than $381,000; Sen. Bill Galvano, who got $101,000; and Sen. Wilton Simpson, who received $98,000.

The utility-backed political committee and its surrogate spokespeople have promoted Amendment 1 as a “pro solar” initiative. But rather than open the state to more solar, the amendment asks voters to inject new language into the Constitution that will serve as a barrier to entry for any company that attempts to compete with the utility giants in providing solar energy in Florida.

Graham, a Democrat, suggested that by rejecting the amendment, voters could send a message to the Legislature that they want the utilities to join with solar advocates “to have a constructive discussion” and use the vote “as a springboard for a positive, better energy future for Florida.”

But, he warned, if the amendment passes, “it will discourage the expansion of solar by psychologically strengthening the position before an already compliant Legislature and Public Service Commission to erect barriers to solar.’’

The utilities argue that homeowners with solar panels still rely on the grid for electricity at night and on cloudy days but don’t compensate the utilities enough to maintain their power plants, transmission lines and maintenance crews. The emerging argument is that net metering laws that allow homeowners to be reimbursed for the excess energy their solar panels generate, and tax rebates to solar customers, are unfair subsidies intended to benefit solar users at the expense of non-solar users.

“We are opposed to subsidies that are unfair and regressive,” Rob Gould, a spokesman for Florida Power & Light, said in an email to the Herald/Times. “There’s a difference between governmental tax break/credit subsidies [such as the property tax credits for solar installations] and subsidies that benefit certain customers on the backs of other customers [rebates, net metering, etc.].”

Gould wouldn’t say explicitly what the legislative agenda would look like to oppose these “subsidies.” In documents filed with state regulators, and in public statements, many officials at Florida’s utilities have made it clear that they want to roll back the current net metering law as utilities have in other states.

Suzanne Grant, spokeswoman for Duke Energy, said in an email that the utility believes “the current net metering policy needs updating, and we believe customers who use the power grid continuously, like solar customers, should pay for grid access, grid services and the backup power they use.”

But Graham called the subsidies concept “a false argument.” He cited studies commissioned by regulators in states such as Nevada and Mississippi and compiled by the Brookings Institution that conclude that costs associated with more rooftop solar are generally outweighed by the benefits.

“The installation of solar saves customers money because it avoids having to build additional generating capacity, the cost of which in Florida not only gets passed along to ratepayers once those plants are in operation but, as we learned with Duke Energy on the Gulf Coast, they got paid in advance for building nuclear plants that were never constructed,” Graham told reporters.

Solar advocates argue that it also provides a net benefit to other utility customers because it alleviates the need to fire up expensive “peaker” power plants when utility use is at its peak, reduces demand for energy delivered by power plants that emit carbons, and offsets the need to construct new power plants.

Graham said Florida should follow Georgia’s lead and pass laws that make it easier for property owners to allow third parties to install solar panels on their roofs, not discourage them, and that require utility companies to increase the amount of electricity they generate using solar power.

He echoed the argument of other solar advocates that Amendment 1 is deceptive because it leaves the impression that solar could expand in Florida.

“This is deceptive in that all the things the advocates could say could happen with this amendment can happen without this amendment,” he said. “You don’t have to have a constitutional amendment to have adequate regulatory power over solar. You don’t have to have a constitutional amendment to have safety.”

According to utility industry records, the electric industry fears that a surge in rooftop solar also will reduce profits for the investor-owned utility industry, which has benefited from price competition as a regulated monopoly.

“The longer-term threat of fully exiting from the grid [or customers solely using the electric grid for backup purposes] raises the potential for irreparable damages to revenues and growth prospects,” wrote the Edison Electric Institute, the investor-owned utility trade group, in a 2013 report.

The 2013 EEI report on “disruptive challenges” suggested that as prices drop for rooftop solar panels, and demand increases, the electric utilities industry faces a “loss of customers.” Its business and regulatory models, which depend on a regulated monopoly, face “potential obsolescence,” and that the ability of rooftop solar owners to generate excess power, sell it back to the grid or to their neighboring properties poses the “technological obsolescence of existing infrastructure.”

The report also compared the electricity industry’s existential threats from battery storage, solar power and distributed energy from rooftop solar and other renewable sources to the demise of Kodak and its dependence on film cameras in the age of digital technology, or the U.S. Postal Service, and the threat it faces from delivery companies.

In an earlier 2012 presentation, the trade group warned that the “industry must prepare an action plan to address the challenges.” Among the suggestions was to portray the emergence of solar power as a subsidy on non-solar users, as the language in Amendment 1 does.

This story has been updated to correct errors in calculations and updates in official campaign finance reports.

Mary Ellen Klas can be reached at Follow her on Twitter @MaryEllenKlas

Florida four largest electric utilities have spent $29.3 million so far this election cycle, including $20.7 million for Consumers for Smart Solar, CSS, the political committee promoting Amendment 1. (The committee has raised another $6 million from non-profits and special interest political committees that have received substantial funding from the utility industry.)

Top utilities’ contributions

▪ FPL: $14.1 million total political contributions, $8 million to CSS

▪ Duke Energy: $8.0 million total, $6.7 million to CSS

▪ Gulf Power: $2.5 million total, $2.2 million to CSS

▪ Tampa Electric Co: $4.7 million total, $3.2 million to CSS

Energy and Policy Institute Exposes Three Ways Electric Utilities Stomp Innovation and Competition

John Farrell | No Comments | Updated on Aug 15, 2017

The content that follows was originally published on the Institute for Local Self-Reliance website at

If you work to secure Americans’ rights to solar energy or to accelerate the deployment of inexpensive renewable energy, you understand that not everyone is in favor. In particular, incumbent electric utilities tend to oppose competition in their (often monopoly) share of the electricity market.

Where competition exists, it is plagued by unfairness. Below, we share three resources from one remarkable organization — the Energy and Policy Institute — to help advocates, regulators, and legislators understand the advantages of incumbent utilities and the ways they use their market and political power to undermine fair competition.

Political Deception
In Florida last year, incumbent utility Florida Power & Light and its allies bankrolled a campaign for a constitutional amendment to limit competition from customer-owned solar power, but with language designed to make it seem pro-solar. The utility incumbents spent nearly $30 million in the effort. The campaign might have succeeded, but for the release of an audio clip of a utility lobbyist describing its deceptive nature. In the end, 60% of Floridians rejected the Trojan horse solar amendment, but still lament that the “Sunshine State” ranks just 13th for installed solar energy — despite ranking 3rd in solar potential.

Financial Hijinks
This year, the Energy and Policy Institute exposed another dark secret: many utilities use money from their customers to pay dues to a trade organization — the Edison Electric Institute — that frequently produces research and policy defending utilities’ monopolies in the face of market competition. One such example? An Edison-funded campaign against rooftop solar.

Buried Liabilities
Utilities’ first warnings about climate change came in the late 1960s, and they actually used customer money to finance climate science studies through the 1970s and early 1980s. But by 1990, many utilities had opted to bankroll climate doubt rather than change their business model to incorporate renewable energy. The disinformation campaign leaves utility companies open to lawsuits for the environmental damages of power plants built or retrofitted since this time, with billions of dollars in potential liabilities –and utility customers may be on the hook.

The disruption of new distributed renewable energy technology offers an opportunity for innovation in the electricity sector that has already begun to lower energy costs and reduce pollution. But incumbent utilities still have enormous market and political power, and Energy and Policy Institute helps expose the ways they wield that to tilt the playing field to their advantage.

Photo credit: Shawn Carpenter via Flickr (CC BY-SA 2.0 license)

This article originally posted at For timely updates, follow John Farrell on Twitter or get the Energy Democracy weekly update.

TAGS: competition / electric utility / electricity / florida / investor-owned utility / lobbying / monopoly / solar energy