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Month: April 2018

← EVENTS: Clean Energy Meets the Electric Utility Industry

UILITY DIVE: April 24, 2018  May 10, 2018  • Washington, DC

Visit the Event Page

We are back in DC at Utility Dive’s offices for a one-day workshop covering how clean energy is impacting the electric utility industry. Don’t worry, it’ll be fun! When it’s over, you’ll understand the difference between clean, green, renewable, as well as advanced energy choices; how the electric grid functions and how grid operators are handling greater penetrations of renewable energy; why utility regulation models may not encourage change; how solar changed everything; the challenges and promises of electrifying the transportation industry and so much more! Throughout the day we will simplify the overly complex industry jargon and help you gain better insights into the changes, challenges, and opportunities for you in today’s new energy marketplace. Ask questions along the way…it’s worth a day of your time.

If you are new to the industry or you communicate, do business development or marketing, finance, legal, or IT around the electric utility industry for suppliers, utilities, clean energy companies, new service companies, associations, or policy makers, this is the program for you to get a strong grasp of the whole picture and your opportunities in an enjoyable, interactive workshop setting.

 

 

admin April 24, 2018 Uncategorized

ABB launches what it says is world’s fastest EV charger

The Terra High Power charger can charge an electric vehicle (EV) in just eight minutes, thus adding up to 200 km of range, says ABB, which launched the new model at this year’s Hannover Messe.

APRIL 23, 2018 PV MAGAZINEY

From left to right: German Chancellor Angela Merkel, Mexican President Enrique Peña Nieto, ABB CEO Ulrich Spiesshofer, First Lady Mrs. Angélica Rivera, Managing Director of ABB Germany Hans-Georg Krabbe, Managing Director of ABB Mexico Vicente Magana.

Image: ABB

The Swiss power electronics giant unveiled its new super charger yesterday, at the Hannover Messe 2018, which runs from April 22 to 27.

“By operating at powers of up to 350 kilowatts, the newest model from ABB, Terra High Power charger, adds up to 200 kilometers of range to an electric vehicle in just 8 minutes,” said ABB in a statement released. This is said to add seven times more range in the same time than current models on the market.

German Chancellor, Angela Merkel, and Mexican President, Enrique Peña Nieto, were present at a demonstration of the charger yesterday, which is primarily for use at highway rest stops and petrol stations.

ABB added that it has recently been selected for use by Electrify America, which announced last week that it will install electric vehicle chargers at more than 100 Walmart locations across 34 states by June 2019.

“The Electrify America charging systems located at Walmart stores will offer the first-ever certified cooled-cable 150 to 350 kilowatt (kW) DC Fast Chargers. Electric vehicle chargers that offer this kind of power deliver energy for up to 20 miles of range per minute, which is seven times faster than today’s 50kW DC chargers,” said Electrify America in a statement released at the time.

Overall, Electrify America aims to invest a total of US$2 billion over the next 10 years in electric vehicle infrastructure and education, deploying over 2,000 chargers across 484 sites. All the chargers will be installed or under construction by the end of 2019, it said.

Hola

admin April 24, 2018 Uncategorized

Utility monopolies keep their power by keeping elected officials in their pockets. It’s time we fight back!

 Posted : April 21,2018
 
 These powerful utilities rely on elected officials to support market barriers that make it harder for us to take control of where our electricity comes from. They secure this support not by persuasive arguments, but with paid lobbyists and campaign donations. Since 1990, utilities have given close to one-quarter of a billion dollars ($239,556,420) to federal politicians, and hundreds of millions more on lobbying and campaign donations to state-level candidates.1

Enough is enough! We can no longer tolerate our elected officials supporting utilities who deny us our rights.

If you believe that monopoly utilities should not be able to buy and influence their way towards bad policies, that our elected representatives should be independent from private utilities, and that politicians should shape energy policy to benefit all ratepayers and the public interest, please urge your state representatives to declare their independence by signing the “Represent Us, Not Utilities” Pledge:

To maintain independence from monopoly utility interests and to avoid the perception of undue influence on my positions concerning state energy policies, I will take no campaign contributions from utility corporations, their Political Action Committees, lobbyists and executives.

Want to help spread the word? Click here to print out a pledge for your local candidates to sign. Scan it or take a picture and email it to us at: pledge@solarunitedneighbors.org.

Additional resources

UtilitySecrets.org, (a joint project of the Energy and Policy Institute and the Center for Media and Democracy, tracks electric utility anti-solar lobbying and campaign contributions. These include:

  • Report on Utility Campaign Against Rooftop Solar
  • Documents Reveal Edison Electric Institute Campaign Against Solar
  • Paying for Utility Politics: How ratepayers are forced to fund the Edison Electric Institute and other political organizations
  • Information about American Electric Power Lobbying
  • Information about Arizona Public Service Lobbying
  • Information about Berkshire Hathaway Energy Lobbying
  • Utility Anti-Solar Lobbying in Florida
  • An Energy and Policy Institute analysis of the Republican Governors Association, Republican Attorneys General Association, Republican State Leadership Committee, Democratic Governors Association, Democratic Attorneys General Association, and Democratic Legislative Campaign Committee found over 70 utility holding companies and subsidiaries contributing to anti-solar lobbying groups for a total of $36.4 million from 2008 through 2017.
  • An Energy Policy Institute analysis of spending by Florida utilities Duke Energy and Florida Power and Light.

Rooftop Solar Dims Under Pressure From Utility Lobbyists – The New York Times reports on efforts by utilities to slow the development of rooftop solar.

1. Source: Center for Responsive Politics; www.opensecrets.org. To find out if state candidates and elected officials in your area are taking money from utility interests, go to www.followthemoney.org.

admin April 21, 2018 Uncategorized

Solar for All: How we got here and what’s next

Solar United Neighbors of D.C. was live.on Saturday  

The District has an ambitious plan to cut electric bills in half for low- and moderate-income residents while making solar accessible to everyone. We’ll take a deep dive into the #Solar4AllDC program’s past, present, and future with Nora Hawkins from Department of Energy & Environment and Jacqueline Brown, the first qualified #Solar4AllDC grant recipient in our 51st State Solar Co-op!

Solar for All: How we got here and what's next

The District has an ambitious plan to cut electric bills in half for low- and moderate-income residents while making solar accessible to everyone. We'll take a deep dive into the #Solar4AllDC program's past, present, and future with Nora Hawkins from Department of Energy & Environment and Jacqueline Brown, the first qualified #Solar4AllDC grant recipient in our 51st State Solar Co-op!

Posted by Solar United Neighbors of D.C. on Saturday, April 14, 2018

admin April 18, 2018 Uncategorized

Solar Energy, Equity, and Health at 2018 D.C. Solar Congress – David A. Clarke School of Law

Solar United Neighbors of D.C.was live.on Saturday  April 14,2018 UDC
 Solar power brings economic benefits to those who can participate, but it also does much more. Our first panel of the day is titled “Solar Energy, Equity, and Health” and features Yinka N. Bode-George from Maryland Environmental Health Network, Edward Yim from Department of Energy & Environment, Denise Fairchild from Emerald Cities Collaborative, and Ron Bethea from Positive Change Purchasing Co-operative LLC to explore these diverse community benefits!

Solar Energy, Equity, and Health at 2018 D.C. Solar Congress

Solar power brings economic benefits to those who can participate, but it also does much more. Our first panel of the day is titled "Solar Energy, Equity, and Health" and features Yinka N. Bode-George from Maryland Environmental Health Network, Edward Yim from Department of Energy & Environment, Denise Fairchild from Emerald Cities Collaborative, and Ron Bethea from Positive Change Purchasing Co-operative LLC to explore these diverse community benefits!

Posted by Solar United Neighbors of D.C. on Saturday, April 14, 2018

admin April 18, 2018 Uncategorized

New York agencies propose shifting EV fast chargers to non-demand charges

Author:Robert Walton@TeamWetDog PUBLISHED April 17, 2018

Dive Brief:
The New York Power Authority and other state agencies have asked New York regulators to make changes to the rate structures of public electric vehicle DC fast charging stations to eliminate demand charges aimed at developing these stations.
According to NYPA, the stations’ low utilization rates combined with the use of demand charges “renders any business model for DCFCs infeasible.” Other state agencies joining NYPA on the proposal are: the New York State Department of Environmental Conservation; New York State Department of Transportation; and the New York State Thruway Authority.
The New York agencies have also asked the Public Service Commission to direct direct utilities to develop broad plans to encourage the adoption of electric vehicles, similar to proceedings opened in Oregon and California.

New York is aiming to have 800,000 electric vehicles on its roads by 2025. But with seven years left, the state has a ways to go with this year a “crucial inflection point,” NYPA told the Public Service Commission.

At the end of November 2017, cumulative zero emission vehicles sold in New York was just over 30,000. In order for adoption to accelerate, the state must address consumers range anxiety; the proliferation of DC fast charging stations, which allow for rapid charging, is one way.

But because DC fast chargers are not highly utilized right now, combined with demand charges used in their tariffs, it is infeasible to develop a business model that would encourage growth. As a result, NYPA requested regulators “immediately shift all customer accounts for public direct current fast charging equipment” to non-demand metered rates, and to consider longer term rate modifications for DCFC that “align with their low load factors and sporadic usage.”

Last year, Rocky Mountain Institute published research that concluded public chargers and demand charges simply didn’t work together.

“Public chargers should not feature demand charges,” Chris Nelder, a manager with RMI’s electricity practice, told Utility Dive. “There’s no reason the utility can’t recover the cost through that volumetric rate while still offering a DC fast charger a business case.”

admin April 17, 2018 Uncategorized

North Carolina approves solar rebate, coal ash fine for Duke

Author: Robert Walton@TeamWetDog PUBLISHED April 16, 2018

Dive Brief:
Duke Energy scored a pair of wins in North Carolina, agreeing to a relatively mild fine for coal ash contamination while also convincing regulators to approve the utility’s $62 million solar rebate program.
Associated Press reports the utility agreed to pay a $156,000 fine for polluting ground and surface water at three plants with coal ash in North Carolina. Critics called it a “paltry sum.”
In Kentucky, the Public Service Commission allowed Duke an annual rate increase of $8.4 million. The utility had initially requested $48.6 million and later lowered that to $30 million after changes to the federal corporate income tax rate.

It’s a financial mixed bag for Duke, particularly in Kentucky where regulators say they “substantially reduced” the utility’s rate increase, ultimately approving just 28% of the request.

In North Carolina, however, regulators supported Duke’s solar rebate program, under which residential customers will be eligible for a rebate of $0.60/watt for solar energy systems 10 kW or smaller. The program is required under a law the state passed last year.

Duke says that in it currently has more than 6,000 net metering customers, with total capacity of just over 50 MW. The rebate program is expected to increase the private solar market 200% over the next five years, according to Duke. The utility also agreed to a relatively modest fine in North Carolina, related to the cleanup and closure of its coal ash ponds.

Sierra Club’s David Rogers said told Associated Press, “I think it’s a paltry sum. It’s not going to be any sort of deterrent for Duke Energy.”

The utility says agreeing to the fines means it can begin to move forward with the cleanup of the sites. In February, the North Carolina Utilities Commission allowed Duke Energy Progress to raise customers’ fixed monthly charges by 25% and granted the utility rate increase of $232 million to pay for coal ash cleanups.

admin April 17, 2018 Uncategorized

Exelon, FE nuke closures would reverse PJM wind, solar benefits: Brattle report

AUTHOR: Peter Maloney@TopFloorPower PUBLISHED April 17, 2018

Dive Brief:
If FirstEnergy Solutions and Exelon follow through on plans to close a total of four nuclear power plants in Ohio and Pennsylvania, it would harm the environment and result in significantly higher electricity prices for consumers, according to a report by The Brattle Group. The closures would likely result in an annual increase of more than 20 million metric tons of carbon dioxide emissions and tens of thousands of tons of incremental air pollutants, according to the report, which Brattle prepared for the advocacy group Nuclear Matters.
The closures would also increase annual electricity costs by as much as $400 million annually for Ohio residents and $285 million for Pennsylvanians, the report found.

FirstEnergy Solutions (FES) has become the latest lightning rod in the battle over nuclear power subsidies.

The FirstEnergy subsidiary has been lobbying for some form of support for its nuclear plants for years. States such as Illinois, New York, Connecticut and, most recently, New Jersey all have passed some form of zero emission credit (ZEC) subsidy program that pays nuclear generators for their emissions-free electricity. But FES has not had success in Ohio and Pennsylvania, where its nuclear plants operate, and is now trying to win support from the Department of Energy under section 202c, a little used provision of the Federal Power Act. Section 202c orders are designed to keep plants running after natural disasters or other unexpected grid conditions.

In the wake of its request to the DOE, FES also filed for Chapter 11 bankruptcy court protection. The economically challenged nuclear plants account for about 6% of the electricity generated by FES.

Absent some form of subsidy FES said it plans to close its 908 MW Davis-Besse nuclear plant in Oak Harbor, Ohio, in 2020; its 1,268 MW Perry nuclear station in Perry, Ohio, in 2021; and its 1,872 MW Beaver Valley station in Shippingport, Pa., in 2021.

Exelon last summer said it plans to close its Three Mile Island nuclear plant in 2019 because of “severe economic challenges.”

In the report, Brattle analysts Mark Berkman and Dean Murphy said the closure of the nuclear plants would reverse the environmental benefits of all the wind and solar resources developed in the PJM Interconnection region over the past 25 years. At the current growth rate of renewable resources, it would take another 15 years to replace the zero emission output of the four nuclear plants, the analysts calculate.

In addition, Berkman and Murphy estimate that removing the nuclear plants from the market would raise power prices in Ohio by up to $2.43/MWh and in Pennsylvania by up to $1.77/MWh. Their estimates of cost impacts do not take into account the potential costs to consumers of a potential nuclear subsidy.

“I’m not aware of an explicit proposal, so I don’t know what the ZEC cost would be,” Murphy said in an email to Utility Dive. “The electricity price effect and resulting customer savings from keeping the plants that we report is [the] gross [amount]; you would need to deduct ZEC cost from this to see the net cost effect on customers,” he wrote.

Under Illinois’ ZEC program, two Exelon nuclear plants will receive customer-funded payments of $235 million a year for 10 years.

Meanwhile, the American Petroleum Institute on April 13 sent a letter to President Donald Trump urging opposition to the use of section 202c to support nuclear plants. Granting such a request “would be at odds with your stated goals of energy dominance, economic growth, and improving America’s infrastructure,” Jack Gerard, API president and CEO, said in the letter. Granting emergency relief to the nuclear plants would undermine the operation of competitive markets, he said.

Sounding the same theme, the Electric Power Supply Association on April 13 also sent a letter to Trump, arguing that a 202c intervention would be equivalent to placing “a thumb on the scale” and would “needlessly raise electricity costs by billions of dollars annually.”

In a rare alignment of interests, the Sierra Club is taking the same side in this battle as API. In late March Mary Anne Hitt, director of Sierra Club’s Beyond Coal campaign, said that the environmental group would “challenge and defeat the administration in court,” if it were to bailout FES’ nuclear plants.

Recommended Readi

admin April 17, 2018 Uncategorized

U.S. Secretary of Energy Rick Perry Announces $105 Million in New Funding to Advance Solar Technologies

Published: Tue, April 17, 2018 “DOE_Solar_Energy_Technologies_Office”

DOE to focus on early-stage research to improve the affordability, flexibility, and performance of solar technologies on the grid

WASHINGTON, D.C. – Today, U.S. Secretary of Energy Rick Perry announced up to $105.5 million to support America’s continued leadership in energy innovation through solar technology. Under the Department of Energy’s (DOE’s) Solar Energy Technologies Office (SETO), DOE will fund about 70 projects to advance both solar photovoltaic (PV) and concentrating solar thermal power (CSP) technologies, as well as facilitate the secure integration of those technologies into the nation’s electricity grid. Funding will also support efforts that prepare the workforce for the solar industry’s future needs.

“American ingenuity is the engine of our energy economy,” said Secretary Perry. “Investing in all of our abundant energy sources, including solar technologies, will help to drive down costs and ensure that the nation leads the world in energy production and innovation.”

This funding opportunity announcement (FOA) will further the Administration’s goals to drive economic and technological leadership in solar energy by supporting innovative research that improves energy choice and affordability. These research projects will address the earliest stages of technology development, enable significant improvements to the current fleet of solar technologies, and maintain U.S. leadership in solar energy.

The 2018 SETO FOA will combine all of SETO’s technology areas into one request. By creating a more streamlined and consolidated funding strategy, DOE seeks to accelerate the cycles of learning in solar research and reduce government overhead costs.

The funding program will focus on four main areas:

TOPIC 1: Advanced Solar Systems Integration Technologies (up to $46 million, ~14 projects)

These projects will advance research on technologies that enable the seamless integration of solar energy onto the nation’s electricity grid. By supporting advances in power electronics, solar plus storage, and PV-integrated sensor technologies, the work will help ensure a smooth transition to a secure, reliable, and resilient grid of the future.
TOPIC 2: Concentrating Solar Power (CSP) Research and Development (up to $24 million, ~21 projects)

These projects pursue innovative CSP concepts and technology solutions that enable the solar industry to reach DOE’s 2030 levelized cost of electricity (LCOE) targets for CSP, including $0.05 per kilowatt-hour for systems with greater than 12 hours of onsite storage. Research in CSP will focus on advancing elements found in CSP subsystems, including collectors and thermal transport systems for advanced power cycles, while pursuing new methods for introducing innovation to CSP research.
TOPIC 3: Photovoltaics Research and Development (up to $27 million, ~28 projects)

These projects support early-stage research to increase performance, reduce materials and processing costs, and improve reliability of PV cells, modules, and systems. These projects support DOE’s efforts to lower LCOE to $0.03 per kilowatt hour from utility-scale systems by 2030, which is half the cost of utility-scale solar today.
TOPIC 4: Improving and Expanding the Solar Industry through Workforce Initiatives (up to $8.5 million, ~4 projects)

These projects will pursue innovative initiatives that prepare the solar industry for a digital future while also increasing the number of veterans and participants in the solar industry.
Within each of the technology areas, DOE will fund projects that develop and test new ways to accelerate the integration of emerging technologies into the solar industry value chain and expand private sector engagement supporting energy innovation, especially those related to financing and commercialization.
Sign up HERE to learn more about this funding opportunity at an upcoming webinar.

For more information on the Solar Energy Technologies Office, visit their website HERE.

admin April 17, 2018 Uncategorized

The 2018 Community Power State Scorecard

BY JOHN FARRELL The Institute for Local Self-Reliance | DATE: 2 MAR 2018 |

Each year, the Institute for Local Self-Reliance provides a score for each state’s energy policies based on how they help or hinder local clean energy action. In 2018, 21 states had a failing grade, 17 were mediocre, 11 had a passing grade, and just 2 excelled at enabling residents to act individually and collectively to take charge of their energy future.

Alabama has a Community Power score of 2 out of 36. The state allows communities to provide energy financing to commercial properties with property assessed clean energy, but lacks any other significant policy to support local renewable energy development, including net metering, shared renewables (e.g. community solar), simplified grid interconnection policies, requirements for utilities to purchase distributed renewable energy resources, or opportunities for communities to pick their power supplier.

Alaska has a Community Power score of 6 out of 36. Although the state has a net metering policy and allows communities to set building energy codes, it lacks a wide range of policies to support distributed renewable energy and local authority.

Arizona has a Community Power score of 11 out of 36. The state offers net metering and requires utilities’ renewable energy procurement to include distributed resources, and also allows cities to set building energy codes. It doesn’t allow communities to provide financing with property assessed clean energy, to pick their energy suppliers, or encourage shared/community renewables. The state’s grid interconnection policies also hinder distributed energy resources like rooftop solar.

Arkansas has a Community Power score of 8 out of 36. Although the state has a net metering policy that allows customers to reduce energy costs against all their meters and allows communities to provide energy financing to commercial properties with property assessed clean energy, Arkansas doesn’t allow communities to set stretch building energy codes or pick energy suppliers. The state doesn’t require utilities to develop distributed renewable energy resources, has poor interconnection policies that hinder connection of distributed energy resources like solar, and has no policy supporting shared or community renewable energy projects.

California has a Community Power score of 27 out of 36. The state has many policies encouraging local power, including net metering and simplified interconnection to encourage distributed energy resources like solar. It also allows shared/community renewable energy, communities to pick their energy suppliers, and allows communities to provide financing to residential and commercial properties with property assessed clean energy. California is one of a few states to provide a standard offer contract for distributed energy across the state. The state only lags in requiring utility renewable energy procurement to include distributed resources and in lacking a stretch building energy code for cities to go further than the state standard.

Colorado has a Community Power score of 21 out of 36. The state has several policies encouraging local power, including net metering (and aggregate net metering) and above average grid interconnection rules, a renewable standard requiring utility renewable energy procurement to include distributed resources, a shared/community renewable energy law, and it allows communities to provide financing to commercial properties with property assessed clean energy. Colorado also allows cities to set building energy codes. Colorado lacks a policy to allow communities to pick their energy supplier or a standard purchase contract for renewables.

Connecticut has a Community Power score of 15 out of 36. The state has a few policies encouraging local power, including net metering and above average grid interconnection rules, a renewable standard requiring utility renewable energy procurement to include distributed resources, and rules allowing communities to provide financing to commercial properties with property assessed clean energy. The state lacks local flexibility to set higher building energy codes, a policy to allow communities to pick their energy supplier, or a standard purchase contract for renewables.

The District of Columbia has a Community Power score of 22 out of 36. The state has several policies encouraging local power, including net metering and above average grid interconnection rules, a renewable standard requiring utility renewable energy procurement to include distributed resources, rules allowing communities to provide financing to commercial properties with property assessed clean energy, and a shared renewables or community solar program. Because it’s both city and “state,” the District also scores highly for setting its own building energy code. The District lacks community choice energy that would enable the city government to opt out of service from the incumbent investor-owned utility, PEPCO, as well as lacking a standard purchase contract for renewables.

Delaware has a Community Power score of 13 out of 36. The state has a few policies encouraging local power, including net metering allowing meter aggregation and above average grid interconnection rules, and a renewable standard requiring utility renewable energy procurement to include distributed resources. The state lacks local flexibility to set higher building energy codes, to use property tax bills to finance clean energy, a policy to allow communities to pick their energy supplier, shared renewable energy (like community solar), or a standard purchase contract for renewables.

Florida has a Community Power score of 10 out of 36. The state has just two policies encouraging local power, including net metering and allowing communities to provide financing to residential and commercial properties with property assessed clean energy. However, it’s grid interconnection rules are below average and the state lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, local flexibility to set higher building energy codes, a policy to allow communities to pick their energy supplier, shared renewable energy (like community solar) or a standard purchase contract for renewables.

Georgia has a Community Power score of 9 out of 36. The state has just two policies encouraging local power, including net metering and allowing communities to provide financing to residential and commercial properties with property assessed clean energy. However, it’s grid interconnection rules are abysmal and the state lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, local flexibility to set higher building energy codes, a policy to allow communities to pick their energy supplier, shared renewable energy (like community solar) or a standard purchase contract for renewables.

Hawaii has a Community Power score of 19 out of 36. The state has several policies encouraging local power, including net metering and above average grid interconnection rules, a shared/community renewable energy law, a standard purchase contract for renewables, and it allows communities to provide financing to residential and commercial properties with property assessed clean energy. Hawaii lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, a policy to allow communities to pick their energy supplier, or local flexibility in setting building energy codes.

Idaho has a Community Power score of 5 out of 36. The state offers net metering with meter aggregation, but little else. It doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources and it lacks policies allowing communities to provide financing with property assessed clean energy, to pick their energy suppliers, or encourage shared/community renewables. It also lacks local flexibility in setting building energy codes or a standard purchase contract for renewables. Idaho also has abysmal interconnection policies for distributed energy like rooftop solar.

Illinois has a Community Power score of 26 out of 36. The state has many policies encouraging local power, including net metering and simplified interconnection to encourage distributed energy resources like solar, as well as requiring utility renewable energy procurement to include distributed resources. It also allows shared/community renewable energy, communities to pick their energy suppliers, and allows communities to provide financing to commercial properties with property assessed clean energy. Illinois doesn’t allow aggregate net metering or offer a standard contract for distributed renewable energy projects or a stretch building energy code for cities to go further than the state standard.

Indiana has a Community Power score of 5 out of 36. The state offers net metering and above average interconnection policies, but little else. It doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources and it lacks policies allowing communities to provide financing with property assessed clean energy, to pick their energy suppliers, or encourage shared/community renewables. The state also lacks local flexibility in setting building energy codes or a standard purchase contract for renewables.

Iowa has a Community Power score of 7 out of 36. The state offers net metering and has above average interconnection policies, but little else. It doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources and it lacks policies allowing communities to provide financing with property assessed clean energy, to pick their energy suppliers, or encourage shared/community renewables. It also lacks local flexibility in setting building energy codes or a standard purchase contract for renewables.

Kansas has a Community Power score of 6 out of 36. The state offers net metering and provides local flexibility in setting building energy codes, but little else. The state doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources and it lacks policies allowing communities to provide energy financing with property assessed clean energy, to pick their energy suppliers, or encourage shared/community renewables. Kansas also lacks a standard purchase contract for renewables and has abysmal interconnection policies for distributed energy like rooftop solar.

Kentucky has a Community Power score of 8 out of 36. The state offers net metering and allows communities to provide energy financing for commercial properties with property assessed clean energy, but little else. The state doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources, or laws letting cities pick their energy suppliers, or encouraging shared/community renewables. Kentucky also lacks a standard purchase contract for renewables, local flexibility in setting building energy codes, and has below average interconnection policies for distributed energy like rooftop solar.

Louisiana has a Community Power score of 7 out of 36. The state offers net metering and allows communities to provide energy financing for commercial properties with property assessed clean energy, but little else. The state doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources, or laws letting cities pick their energy suppliers, or encouraging shared/community renewables. Louisiana also lacks a standard purchase contract for renewables, local flexibility in setting building energy codes, and has abysmal interconnection policies for distributed energy like rooftop solar.

Maine has a Community Power score of 12 out of 36. The state has a few policies encouraging local power, including net metering and above average grid interconnection rules, a shared renewables program, and local flexibility in setting building energy codes. Maine lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, community choice energy that allows communities to choose their energy supplier, a standard purchase contract for renewables, or rules allowing communities to provide energy financing with property assessed clean energy.

Maryland has a Community Power score of 18 out of 36. The state has several policies encouraging local power, including net metering and above average grid interconnection rules, a renewable standard requiring utility renewable energy procurement to include distributed resources, a shared renewables (community solar) program, and rules allowing communities to provide financing to commercial properties with property assessed clean energy. Maryland lacks community choice energy that allows communities to choose their energy supplier, a standard purchase contract for renewables, and local flexibility in setting building energy codes.

Massachusetts has a Community Power score of 30 out of 36. The state has many policies encouraging local power, including net metering and simplified interconnection to encourage distributed energy resources like solar, as well as requiring utility renewable energy procurement to include distributed resources. It also allows shared/community renewable energy, communities to pick their energy suppliers, and allows communities to provide financing to commercial properties with property assessed clean energy. Massachusetts is also one of just two states to set a state building energy code with a standard “stretch” code for communities to go further than the state standard. The state only lacks a standard contract for distributed renewable energy projects, residential PACE, and aggregate net metering.

Michigan has a Community Power score of 14 out of 36. The state has a few policies encouraging local power, including net metering, a renewable standard requiring utility renewable energy procurement to include distributed resources, and it allows communities to provide financing to commercial properties with property assessed clean energy. Michigan lacks community choice energy that allows communities to choose their energy supplier, a standard purchase contract for renewables, a shared renewables program, or local flexibility in setting building energy codes.

Minnesota has a Community Power score of 18 out of 36. The state has a few policies encouraging local power, including net metering with meter aggregation, a renewable standard requiring utility renewable energy procurement to include distributed resources, a shared renewables (community solar) program, and it allows communities to provide financing to commercial properties with property assessed clean energy. Minnesota lacks community choice energy that allows communities to choose their energy supplier, a standard purchase contract for renewables, or local flexibility in setting building energy codes. It has average interconnection rules for distributed energy like rooftop solar.

Mississippi has a Community Power score of 7 out of 36. The state offers net metering and has above average interconnection rules for distributed energy like rooftop solar, but that’s it. The state doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources, or laws letting cities pick their energy suppliers, or rules allowing shared/community renewables. Mississippi also lacks a standard purchase contract for renewables and local flexibility to offer energy financing via property taxes or in setting building energy codes.

Missouri has a Community Power score of 14 out of 36. The state has a few policies encouraging local power, including net metering, a renewable standard requiring utility renewable energy procurement to include distributed resources, it allows communities to provide financing to commercial properties with property assessed clean energy, and it provides local flexibility in setting building energy codes. Missouri lacks community choice energy that allows communities to choose their energy supplier, a standard purchase contract for renewables, or a shared renewables (or community solar) program. It has abysmal interconnection rules for distributed energy like rooftop solar.

Montana has a Community Power score of 6 out of 36. The state offers net metering and has average interconnection rules for distributed energy like rooftop solar, but that’s it. The state doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources, or laws letting cities pick their energy suppliers, or rules allowing shared/community renewables. Montana also lacks a standard purchase contract for renewables and local flexibility to offer energy financing via property taxes or in setting building energy codes.

North Carolina has a Community Power score of 21 out of 36. The state has many policies encouraging local power, including net metering and above average interconnection to encourage distributed energy resources like solar, as well as requiring utility renewable energy procurement to include distributed resources. It also allows allow shared/community renewable energy and allows communities to provide financing to residential and commercial properties with property assessed clean energy. North Carolina doesn’t allow communities to pick their energy suppliers or offer a standard contract for distributed renewable energy projects or a stretch building energy code for cities to go further than the state standard.

North Dakota has a Community Power score of 4 out of 36. The state has net metering and allows cities to set building energy codes, but lacks any other significant policy to support local renewable energy development. The state’s policy shortcomings include abysmal grid interconnection policies, no shared renewables (e.g. community solar), no requirements for utilities to purchase distributed renewable energy resources, no option for communities to pick their power supplier, and no choice for cities or counties to offer energy financing via property taxes.

Nebraska has a Community Power score of 4 out of 36. The state has net metering, but lacks any other significant policy to support local renewable energy development, including simplified grid interconnection policies, shared renewables (e.g. community solar), requirements for utilities to purchase distributed renewable energy resources, opportunities for communities to pick their power supplier, and no choice for cities or counties to offer energy financing via property taxes.

New Hampshire has a Community Power score of 18 out of 36. The state has several policies encouraging local power, including net metering allowing meter aggregation, above average grid interconnection rules, and a renewable standard requiring utility renewable energy procurement to include distributed resources. The state also allows shared renewable energy (like community solar) and lets communities to use commercial property tax bills to finance clean energy. New Hampshire lacks local flexibility to set higher building energy codes, a policy to allow communities to pick their energy supplier, or a standard purchase contract for renewables.

New Jersey has a Community Power score of 25 out of 36. The state has many policies encouraging local power, including net metering (plus aggregate net metering) and above average interconnection to encourage distributed energy resources like solar, as well as requiring utility renewable energy procurement to include distributed resources. It also allows communities to pick their energy suppliers, and allows communities to provide financing to residential and commercial properties with property assessed clean energy. New Jersey doesn’t allow shared/community renewable energy or offer a standard contract for distributed renewable energy projects or a stretch building energy code for cities to go further than the state standard.

New Mexico has a Community Power score of 16 out of 36. The state has several policies encouraging local power, including net metering, excellent grid interconnection rules, and a renewable standard requiring utility renewable energy procurement to include distributed resources. The state also allows communities to provide energy financing via property taxes to commercial properties. New Mexico doesn’t allow shared renewable energy (like community solar), local flexibility to set higher building energy codes, a policy to allow communities to pick their energy supplier, or a standard purchase contract for renewables.

Nevada has a Community Power score of 16 out of 36. The state has several policies encouraging local power, including net metering allowing meter aggregation, above average grid interconnection rules, and a renewable standard requiring utility renewable energy procurement to include distributed resources. The state also allows communities to use commercial property tax bills to finance clean energy. Nevada lacks shared renewable energy (like community solar), local flexibility to set higher building energy codes, a policy to allow communities to pick their energy supplier, or a standard purchase contract for renewables.

New York has a Community Power score of 29 out of 36. The state has many policies encouraging local power, including net metering and simplified interconnection to encourage distributed energy resources like solar, as well as requiring utility renewable energy procurement to include distributed resources. It also allows shared/community renewable energy, communities to pick their energy suppliers, and allows communities to provide financing to residential and commercial properties with property assessed clean energy. The state only lacks a standard contract for distributed renewable energy projects and a stretch building energy code for cities to go further than the state standard.

Ohio has a Community Power score of 23 out of 36. The state has many policies encouraging local power, including net metering, excellent interconnection rules to encourage distributed energy resources like solar, as well as requiring utility renewable energy procurement to include distributed resources. It also allows communities to pick their energy suppliers, and allows communities to provide financing to commercial properties with property assessed clean energy. Ohio doesn’t allow shared/community renewable energy or offer a standard contract for distributed renewable energy projects or provide a stretch building energy code for cities to go further than the state standard.

Oklahoma has a Community Power score of 7 out of 36. The state’s limited rules include net metering and allowing cities to provide energy financing to commercial properties via property taxes. The state has abysmal interconnection rules for distributed energy like rooftop solar, and lacks many other good local power rules. The state doesn’t have a renewable standard requiring utility renewable energy procurement to include distributed resources, or laws letting cities pick their energy suppliers, or rules allowing shared/community renewables. Oklahoma also lacks a standard purchase contract for renewables or local flexibility to set building energy codes.

Oregon has a Community Power score of 24 out of 36. The state has several policies encouraging local power, including net metering with meter aggregation, excellent interconnection rules for distributed energy like rooftop solar, a renewable standard requiring utility renewable energy procurement to include distributed resources, and a shared renewables (community solar) program. It also allows communities to provide financing to commercial properties with property assessed clean energy and to set a stretch building energy code above the state standard. Oregon lacks community choice energy that allows communities to choose their energy supplier or a standard purchase contract for renewables.

Pennsylvania has a Community Power score of 13 out of 36. The state has a few policies encouraging local power, including net metering, above average interconnection rules for distributed energy like rooftop solar, and a renewable standard requiring utility renewable energy procurement to include distributed resources. It lacks a shared renewables (community solar) program or provisions allowing communities to provide energy financing via property taxes. Pennsylvania also lacks community choice energy that allows communities to choose their energy supplier, a standard purchase contract for renewables, or local flexibility in setting building energy codes.

Rhode Island has a Community Power score of 22 out of 36. The state has several policies encouraging local power, starting with net metering and above average interconnection to encourage distributed energy resources like solar. The state also allows communities to pick their energy suppliers, allows shared renewables (like community solar), and allows communities to provide financing to residential and commercial properties with property assessed clean energy. Rhode Island doesn’t allow require utility renewable energy procurement to include distributed resources, offer a standard contract for distributed renewable energy projects, or provide a stretch building energy code for cities to go further than the state standard.

South Carolina has a Community Power score of 13 out of 36. The state has a few policies encouraging local power, including net metering, excellent grid interconnection rules, and a renewable standard requiring utility renewable energy procurement to include distributed resources. The state doesn’t allow communities to provide energy financing via property taxes, shared renewable energy (like community solar), local flexibility to set higher building energy codes, communities to pick their energy supplier, or provide a standard purchase contract for renewables.

South Dakota has a Community Power score of 3 out of 36. The state allows communities to set their own building energy codes and has average grid interconnection rules, but lacks any other significant policy to support local renewable energy development, including net metering, shared renewables (e.g. community solar), simplified grid interconnection policies, requirements for utilities to purchase distributed renewable energy resources, or opportunities for communities to pick their power supplier.

Tennessee has a Community Power score of 1 out of 36. The state allows communities to set their own building energy codes, but lacks nearly every other possible policy for supporting local energy action. It is one of just a few states to prohibit net metering, has significant barriers to grid interconnection, has no state renewable standard for distributed resources, doesn’t enable shared/community renewable energy, and doesn’t allow communities to choose their energy supplier. It also lacks a standard contract for distributed energy resources and doesn’t allow communities to provide energy financing to commercial properties with property assessed clean energy.

Texas has a Community Power score of 5 out of 36. The state allows communities to provide energy financing to residential and commercial properties with property assessed clean energy, but lacks any other significant policy to support local renewable energy development, including net metering, shared renewables (e.g. community solar), simplified grid interconnection policies, requirements for utilities to purchase distributed renewable energy resources, or opportunities for communities to pick their power supplier.

Utah has a Community Power score of 12 out of 36. The state has a few policies encouraging local power, including net metering, excellent grid interconnection rules, and it allows communities to provide energy financing to commercial properties with property assessed clean energy. Utah lacks other significant policies to support local renewable energy development, including shared renewables (e.g. community solar), requirements for utilities to purchase distributed renewable energy resources, opportunities for communities to pick their power supplier, or local flexibility to set higher building energy codes.

Vermont has a Community Power score of 21 out of 36. The state has several policies encouraging local power, including net metering, above average grid interconnection rules, a renewable standard requiring utility renewable energy procurement to include distributed resources, shared renewable energy (like community solar), a standard offer contract for distributed renewable energy, and it allows communities to use commercial property tax bills to finance clean energy. Vermont lacks local flexibility to set higher building energy codes or a policy to allow communities to pick their energy supplier.

Virginia has a Community Power score of 15 out of 36. The state has a few policies encouraging local power, including net metering allowing meter aggregation, excellent grid interconnection rules, shared renewables (e.g. community solar), and it allows communities to provide energy financing to commercial properties with property assessed clean energy. Virginia lacks other significant policies to support local renewable energy development, including requirements for utilities to purchase distributed renewable energy resources, opportunities for communities to pick their power supplier, a standard offer contract for distributed renewable energy, or local flexibility to set higher building energy codes.

Washington has a Community Power score of 16 out of 36. The state has a few policies encouraging local power, including net metering allowing meter aggregation, above average grid interconnection rules, a renewable standard requiring utility renewable energy procurement to include distributed resources, and a standard offer contract for distributed renewable energy. Washington lacks shared renewables (e.g. community solar), permission for communities to provide energy financing to properties with property assessed clean energy, opportunities for communities to pick their power supplier, or local flexibility to set higher building energy codes.

West Virginia has a Community Power score of 8 out of 36. The state has just two policies encouraging local power, including net metering allowing meter aggregation, and above average grid interconnection rules. The state lacks lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, shared renewable energy (like community solar), the option for communities to pick their energy supplier or to offer energy financing via property taxes, local flexibility to set higher building energy codes, and a standard purchase contract for renewables.

Wisconsin has a Community Power score of 8 out of 36. The state has just two policies encouraging local power, including net metering and permission for communities to offer energy financing to commercial entities via property taxes. The state has below average grid interconnection rules, and lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, shared renewable energy (like community solar), the option for communities to pick their energy supplier, local flexibility to set higher building energy codes, and a standard purchase contract for renewables.

Wyoming has a Community Power score of 9 out of 36. The state has a few policies encouraging local power, including net metering, permission for communities to offer energy financing to commercial entities via property taxes, and local flexibility in setting building energy codes. Wyoming has abysmal grid interconnection rules and it lacks a renewable standard requiring utility renewable energy procurement to include distributed resources, shared renewable energy (like community solar), the option for communities to pick their energy supplier, or a standard purchase contract for distributed renewables.

admin April 10, 2018 Uncategorized

This College Wants To Be The First 100% Renewable Campus In The U.S.

Author: Eillie Anzilotti WORLD CHANGING IDEAS: Published  3/19/18

After a long process of implementing energy-efficiency measures and installing solar arrays and battery storage, Maui College is ready to cut ties with fossil fuels forever.

In 2015, the state of Hawaii committed to converting 100% of its energy supply to renewables by 2045. It’s a steep undertaking, and one that will involve utilities coordinating resources across a network of grids that span the island. And at the same time, the Hawaii Legislature and the University of Hawaii system established a joint goal: The entire university network, which comprises 10 campuses across the islands, will be “net zero” by 2035, meaning that the system would generate as much renewable energy as it consumes.

And now by 2019, UH’s Maui College will be among the first campuses in the nation to generate 100% of its energy from an on-site solar installation, coupled with battery storage.

[Photo: University of Hawaii]

Johnson Controls, a multinational tech and energy company, designed the solar array, which covers the whole campus, and will enable Maui College to completely eradicate fossil-fuel-based energy when it becomes operational in 2019.

The path to this point, though, began in the 1980s, when Michael Unebasami, now an associate vice president at UH, was serving as the director of admin services at Leeward Community College in Honolulu (2018 is Unebasami’s 50th year in the UH system). An energy company approached the University of Hawaii with a pitch to do performance contracting for the network of campuses. Performance contracting is an approach to energy efficiency in which an energy service company partners with a building to both implement energy-efficiency measures (like reducing water usage and optimizing lighting) and converting from fossil fuels to renewable energy. The energy company pays for the upgrades but also gets paid from the cost savings that come from being more efficient.

Unebasami was intrigued, he tells Fast Company, “but at the time, the university and the state were not ready to enter into that kind of arrangement.” So the idea was tabled, but Unebasami kept it in the back of his mind as he moved up the ranks of the UH system.

Which was likely to the entire university’s benefit: By waiting several decades to implement energy-efficiency measures, UH has been able to benefit from the massive advancements in solar energy and storage that have occurred in the intervening years. And in that time frame, the state of Hawaii had gotten on board the idea of performance contracting, and released a statute in 2010 mandating that government agencies contract with energy companies to implement energy-efficiency retrofitting measures.

Shortly after the state issued that statute, it put out a solicitation for energy companies to apply to do performance contracting for government agencies. At UH, Unebasami bought into that list to access qualified companies who could do work for the university–now that the state had embraced performance contracting, the UH system had the go-ahead. Unebasami’s director of facilities was getting ready to retire that year, but when Unebasami told him of his plan, he postponed his retirement so he could assist on the project. “He got really enthused about it,” Unebasami says. The University of Hawaii campuses were, at the time, facing a backlog of deferred maintenance projects, many of which included repairs to their heating and cooling systems. “Many of our buildings are very old and needed upgrades,” Unebasami says. By entering into a performance contracting agreement, they could tackle those needed upgrades–while going far beyond them.

[Photo: University of Hawaii]

Johnson Controls’ proposal for performance contracting at the UH system won out, and the company got to work in 2010, first conducting audits of the university’s campuses and implementing energy-efficiency measures. During phase two of the project, which began several years ago, Johnson Controls built out and installed an array of on-site solar panels in the form of shade canopies and rooftop installations, and connected them up to batteries, which will be able to store enough energy to power the entirety of Maui College’s campus on solar; other community colleges within the system will see reductions in fossil-fuel energy use from 70% to 98%.

While the new energy efficiency measures and solar arrays will save the UH system around $78 million, that’s not what makes it unique: Johnson Controls and UH have also partnered on an educational program, featuring curriculum, an internship program, and workshops for faculty and students, that will roll out alongside the new energy systems. “Typically, these performance contracts are strictly construction, but we’re a community college,” Unebasami says.

Ronald Bethea April 9, 2018 Uncategorized

Outsider Club

Editor: Gerardo Del Real : Junior Mining Monthly Apr. 09, 2018 – Baltimore, MD

It’s a surprising fact: the #1 material in electric car batteries is… graphite?

Yes, graphite.

Electric car batteries are often called “lithium-ion batteries,” but that’s a misleading term…

As Elon Musk recently said: [there’s] a little bit of lithium in there, but it’s like the salt on the salad.”

Only 2% of a lithium-ion battery is actually lithium.

And only 18% of the battery is made up of cobalt and other materials.

That’s because a whopping 80% of the battery is made from one single, hard-to-find resource — graphite.

Lithium Ion Battery Composition

Now, you’re probably not used to seeing headlines about this often-forgotten material…

But that’s going to change.

Graphite is in everything from your computer… to your cell phone… to the hundreds of other electronic devices in your home.

And the electric car market is growing so fast that it’s eating up the entire world’s supply.

Demand is soaring — and graphite producers are seeing record profits. Especially now that two Tesla executives have left to build a battery Gigafactory of their own, further straining global graphite supplies.

This unexpected material is at the center of the electric car boom… let me explain why it can make you at least 826% in the weeks ahead.

To your wealth,

gerardo-sig

Gerardo Del Real
Editor, Junior Mining Monthly

Ronald Bethea April 9, 2018 Uncategorized

DOE offers $1.8B for new supercomputers at national labs

Author: Gavin Bade@GavinBade : Published  April 9, 2018

Dive Brief:

  • The Department of Energy on Monday announced a request for proposals (RFP) worth up to $1.8 billion for two new exascale supercomputing facilities that officials say could advance machine learning and artificial intelligence capabilities across a number of industries.
  • The RFP offers funding for two new exascale facilities at the agency’s Lawrence Livermore and Oak Ridge laboratories, as well as potential upgrades to an project already underway at Argonne National Laboratory. The systems would be delivered between 2021 and 2023.
  • Faster processing times achieved by the computers could help assist utilities with automating management of distributed resources and enhance the output of renewable generation and storage, DOE Undersecretary Paul Dabbar told Utility Dive.

Exascale computing facilities represent the “next wave” of ultra-fast supercomputers, Dabbar said, capable of processing information 50 to 100 times faster than current systems.

That speed could advance data analysis and modeling capabilities across a number of industries. At utilities, the new computing power could help make sense of the deluge of data delivered by distributed resources like rooftop solar and electric vehicles, Dabbar said, as well as assist in planning infrastructure upgrades.

“Utilities do a pretty good job of understanding how to model the requirements of transmission systems because there’s not many of them,” he said. “However when you go down to the house level for distribution lines, the modeling requirements for that are vastly more complicated.

“Right now utilities do not have the capabilities to be able to model where the capital should go on the distribution level,” he said. “We’re actually working with utilities to build [models] down to the individual home on these systems and exascale will allow us to do it … on much larger utility systems.”

DOE officials told Congress in January exascale computing would be a “main priority” for the agency in 2018, spurred by new competiton from overseas.

China currently has the most supercomputers on the Top500, a list that ranks high-performance computers on speed, including the two fastest computers. Officials there say they will have an exascale project online by 2020, while Japan and the European Union have their own projects underway.

DOE last summer selected six technology vendors to receive $258 million through its PathForward program to deliver the Aurora exascale facility at the Argonne National Lab by 2021. The new RFP looks to build on that project, Dabbar said, but will aim to include new suppliers to give “additional diversity and flexibility” in exascale technology.

“There has been more of a competition here in the past 5 to 7 years and both the Aurora machine currently going on and this RFP for the next two [facilities] are vitally important for us as a country,” he said. “We’re helping … fuel the next wave of computer technology that will end up throughout the whole economy.”

Ronald Bethea April 9, 2018 Uncategorized

What’s next for South Carolina’s embattled utilities?

Author:>Herman K. Trabish:PUBLISHED: April 9, 2018

A failed investment in nuclear puts the futures of SCE&G and Santee Cooper in danger

To keep electricity flowing at affordable prices, South Carolina faces difficult choices about its debt-burdened electric utilities. Public power utility Santee Cooper and South Carolina Electric and Gas (SCE&G), the state’s dominant investor-owned electric utility (IOU), have a combined obligation of more than $13 billion. It was incurred when the expected $9.8 billion cost to jointly finance two new units at the V.C. Summer nuclear facility ballooned to more than $20 billion and the project had to be abandoned.

There are five choices for Santee and six for SCE&G, according to new papers. Among the choices, both utilities could attempt to meet their debt by economizing, but the debt is too large for that approach to be effective. They could pass the obligation to customers or taxpayers, but many of the lawmakers responsible for the ultimate decision on the utilities’ fates have declared it unacceptable to shift the financial burden to those who did not create it.

A new Palmetto Promise Institute paper says the responsibility should fall on the utilities and investors in the uncompleted nuclear facility.

SCE&G, as an IOU, could aid itself and its customers by cutting dividends to shareholders, according to a study done for the state senate by Bates White, a financial consulting firm. Both utilities could sell out if they can find buyers; Dominion Energy has made an offer for SCANA. but completion of the deal is far from certain. Or both could default on the debt, shifting the burden to bondholders and driving the question to bankruptcy courts.

The dilemma is complicated by the fact that the utilities’ decision to expand the nuclear facility was made in good faith during the “nuclear renaissance” of the early 2000s. Many in South Carolina (SC) believed it was the right decision. But it was a wrong decision and now somebody must take “a haircut” — a financial world euphemism for a loss.

Complicating the matter, the Central Electric Power Cooperative has filed a legal action against Santee. It is intended to legally validate Central’s contractual right to walk away from its obligation to buy 60% of Santee’s generation, should the final decision impose the haircut on customers. That could ruin Santee financially.

The more legislators discuss options for the utilities, the more unlikely a viable way forward that avoids bankruptcy or sale of the utilities seems.

The right decision at the time?
Around 2005, demand for electricity was rising, the price of natural gas hit $16/MMBTU, renewables had barely entered power markets, and there was talk of a “nuclear renaissance.”

Clemson University Economics Professor Emeritus Mike Maloney, a co-author of the Palmetto paper, saw the opportunity in nuclear power then but warned against it. “Nuclear power is very risky because a delay in construction of a few years can double the cost of the plant’s generation,” he told Utility Dive.

“Most people in the nuclear renaissance thought the regulatory hurdles created by the 1970s anti-nuclear movement would not be a problem, Maloney said. “They were. And the plants were delayed.”

Santee Cooper spokesperson Mollie Gore said the decision to build the nuclear units was reasonable at the time. “We had co-owned the first V.C. Summer unit with SCE&G since 1984,” she told Utility Dive. “It had been a reliable, low cost part of our generation.”

Spokesperson Rhonda O’Banion of SCE&G parent SCANA Corp declined Utility Dive’s request for an interview.

New federal regulations for fossil fuel pollutants and transport sector greenhouse gas emissions were imposed in 2007-08, as the utilities’ commitments to the nuclear project were being finalized, Gore added. “That is another important reason why nuclear power seemed like the best decision for our customers.”

In 2006, the SC General Assembly passed a resolution endorsing new nuclear development for the state. The next year it passed the Base Load Review Act, which allowed utilities to include in rates the costs of in-construction nuclear plants and allowed cost recovery through rates for uncompleted projects.

The first addition to rates for the project was in 2008. In 2009, construction was scheduled to begin in 2012, the first reactor was scheduled to go online in 2016, and generation from the second reactor was expected by 2019.

The first delay was announced at the end of 2011. A further one-year delay was announced in mid-2013. Late in 2014, a $1.2 billion cost increase was announced. Toshiba/Westinghouse stepped in as contractor in late 2015 and agreed to pay all additional costs above $7.7 billion. At the same time, a third one-year delay was announced.

In early 2016, an independent assessment reported failures by Toshiba/Westinghouse and inadequate oversight by the utilities. Late that year, an $831 million cost increase was added, but further costs became the responsibility of Toshiba/Westinghouse.

In March 2017, Westinghouse filed for bankruptcy. The utilities agreed to continue construction but reassess. In July 2017, the utilities abandoned the project.

In September 2017, the state Attorney General issued an opinion that the Base Load Review Act is “constitutionally suspect.” The AG also indicated lawmakers could prevent further cost recovery by the utilities and require refunds. Serious debate by regulators and lawmakers about the fate of the utilities began then and is ongoing.

“They had to know better”
Santee customers have paid $540 million in rate increases, according to the Palmetto paper. But the utility remains financially sound, retains an A+ credit rating and will not raise rates through 2020, according to Gore.

Mark Cooper, Senior Research Fellow at Vermont Law School’s Institute for Energy and the Environment, an authority on the economics of nuclear power, was an expert witness in several SC regulatory proceedings on the Summer project.

“By 2012, they had to know better,” he told Utility Dive. “In September 2012 testimony, I told them the good business decision was to abandon the project. The loss would have been $1.4 billion, but not $10 billion.”

Proposed utility-led nuclear projects in Florida and North Carolina were abandoned or cancelled at the time, he added. “The new nuclear at Summer was 100% excess capacity for those utilities and there were cheaper alternatives.”

According to Cooper’s 2017 summary of events, “prudent management would have recognized that the project was doomed by mid-2016 and pulled the plug.”

Gore acknowledged that “there were issues,” but insisted the utilities addressed them through the fixed cost increase agreement with Toshiba/Westinghouse. “That shifted the risk to Westinghouse. But it declared bankruptcy.”

Gore said the utilities’ detailed analysis at that point, using “inputs we did not have access to before,” showed a Santee rate increase of 41% would be needed to complete the project. “That is when construction was suspended,” Gore said.

“It was a completely different world back in 2007,” Gore concluded. “And the thing we couldn’t fix was Westinghouse’s bankruptcy.”

Southern Environmental Law Center Attorney Blan Holman said the argument that the Westinghouse bankruptcy was unforeseeable will be litigated as lawmakers and the courts review this history.

Santee and the co-ops
Electric Cooperatives of South Carolina (ECSC) represents the Central Electric Power Cooperative (Central), which purchases approximately 60% of Santee’s generation at wholesale rates for its 20 member-co-ops.

Central just filed a legal “cross-claim” against a previously filed SC circuit court case concerning the nuclear project. It contains three elements. The first asks the court to rule it cannot be charged by Santee for a nuclear project that is not “used” or “useful.” Charges for a power plant not generating power are “unjust and unreasonable,” according to ECSC.

The second element asks the court to rule Central’s contract with Santee, which runs through 2058, has been breached because the rates are not “just and reasonable.”

In the third element, Central argues that because it covers 70% of Santee’s capital costs, it should be awarded 70% of Santee’s $831.2 millon share of the bankruptcy settlement with Toshiba/Westinghouse.

ECSC spokesperson Lou Green acknowledged that Central’s role as Santee’s dominant customer gives its decision to file this cross-claim “a lot of weight.” But in the ongoing debate about the utilities’ fates, proposals are being made that are economically threatening for Central, he told Utility Dive. “The cross-claim had to be filed, to protect our legal options.”

Central understands its proposals could impose an insurmountable financial burden on Santee, Green added. “We are anxious for guidance from the legislature.”

What now?
The Bates White analysis found that removing the $445 million per year being charged to SCE&G customers to protect shareholder dividends would reduce rates 18%. But eliminating shareholder dividends could cause a stock sell-off. The analysis concluded a 13% rate cut would protect dividends enough to prevent the sell-off. The legislature just mandated that rate cut until a long-term solution is found.

As a publicly-owned utility, Santee pays no shareholder dividends. Palmetto’s analysis found a 13.62% rate increase would allow the debt to be repaid over its remaining 38-year term. But it would add $194.49 per year to the average customer bill through 2056.

“Having ratepayers pay the debt would be nearly criminal,” Palmetto added. Therefore, “Santee Cooper must be sold” and it is the legislature’s responsibility to find a “willing” buyer.

SC Republican Governor Henry McMaster wants both utilities sold, to protect ratepayers and taxpayers, according to multiple local reports.

Santee’s Gore said the Palmetto paper overestimates the utility’s financial needs and underestimates its ability to refinance cost effectively. “We will build cost recovery into rates, but our projection is for a total increase for the nuclear debt of 7% to 8% over a period of several years, and not until after 2020.”

Institute for Energy and the Environment’s Cooper agreed it is criminal for both utilities to recover costs through rates, but said it is misguided to assume the utilities can be sold. “No private entity will buy them unless somebody takes a haircut,” he said.

Regarding its SCANA offer, Dominion Energy VP Dan Weekley wrote to the SC Senate promising “reduced rates up front” and “no rate increases for at least three years.”

Weekley neglected to mention that the initial $1,000 per customer rebate would be followed by rate increases totaling $3.8 billion, beginning after 2020 and lasting two decades, according to regulatory filings reported by SC’s Post and Courier newspaper.

Bankruptcy the best choice?
Clemson’s Maloney argued the best choice is defaulting on the debts. Defaulting would send all the questions to a bankruptcy court, where a judge would consider arguments on how to resolve them, he said.

“Bankruptcy is the right way to fix this because investors financed the project and took on the risk,” Maloney said. “The ratepayers and taxpayers didn’t have a say, but investors earn interest for good outcomes, and absolving them of the cost for a bad outcome is giving away money.”

But the sale of the utilities is the most likely outcome because it is the most politically expedient, Maloney acknowledged. It is expedient because legislators could select a buyer, like Dominion, who could “kick the can down the road” by deferring higher rates until they become less politically volatile.

The Central Electric Power Cooperative will be a “pivotal” player “because they seem determined to not be the can that gets kicked down the road,” he added. “If they pull out, it does not seem possible that Santee Cooper can avoid defaulting, and if it defaults, SCE&G will be forced near bankruptcy.”

ECSC’s Green said the decision is up to the legislature. “The co-ops might, under the right circumstances, consider making a bid for Santee Cooper, but we would need to know more about what the legislature wants,” he added.

Southern Environmental Law Center’s Holman said the bleak situation created by this project’s failure “demonstrates the risk of centralized traditional generation, especially when renewables are fast becoming cost-competitive.”

Cooper said nuclear power is “a technology whose time never comes” because “any society that has the technological and economic resources to build a safe reactor has the resources to meet its needs for electricity with much lower cost, less risky, clean resources.”

Ronald Bethea April 9, 2018 Uncategorized

Illinois regulators adopt ambitious renewables plan

Author: Robert Walton@TeamWetDog Published: April 5, 2018

Dive Brief:

  • State regulators this week approved the Illinois Power Agency’s long-termrenewables procurement plan, including making changes hailed byrenewables advocates to broader the program.
  • Among the changes, the Illinois Commerce Commission included language to ensure that projects within the boundaries of municipally-owned utilities and rural electric cooperatives in the state will be able to participate in programs under the plan.
  • The procurement plan implements 2016 legislation targeting 25% renewables. The Future Energy Jobs Act included support for Exelon nuclear plants, expanded the state’s energy efficiency programs and made changes to the state’s renewable portfolio standard. The power authority is expected to update the plan in 2019.

The ICC made several changes to an administrative law judge’s proposed order approving the renewables plan, aimed at ensuring broad participation in the program.

The changes specify that projects within the boundaries of municipally-owned utilities and rural electric cooperatives in the state, largely in Central and Southern Illinois, will be able to participate in programs under the Plan. The changes ensure cooperative and municipal customers can take part. Commonwealth Edison had argued that customers of those utilities should not participate in the solar renewable energy credits program.

The plan lays out how the Illinois Power Authority will implement a variety of programs and procurements to purchase Renewable Energy Credits (RECs), and includes the Illinois Solar for All Program which aims to provide a solar market for low-income households and communities.

The plan also includes auditing procedures to ensure Illinois residents benefit from the plan; provisions to maximize Illinois’ benefit from the clean energy economy; and eliminates all spot REC procurements to increase investment in new renewable resources that will help meet Illinois’ long-term renewable energy goals.

The ICC said the first two procurements under the plan for utility-scale wind and brownfield solar development are
expected to occur this summer. Solar procurements under the plan will take place after an program administrator is hired.

Ronald Bethea April 9, 2018 Uncategorized

The two key questions about going to 100% renewables in Los Angeles

Author: Herman K. Trabish    Published:   April 5, 2018

Will it be solar or more solar in Hollywood? And can solar star without fossil fuel backup?

 In Hollywood  big stars can sell a movie by themselves and Hollywood’s utility wants to know if renewables are ready for stardom. In 2016, the Los Angeles City Council asked the Los Angeles Department of Water and Power (LADWP) to study the possibility of moving to a 100% renewables resource mix. For renewables, this could be what Hollywood calls a “marquee moment.” Many see in renewables the ‘star’ quality to run the ‘show’ on their own. Others worry that co-stars, in the form of backup fossil generation, will be needed into the 2040s if LADWP is to guarantee reliable electricity for its 1.5 million-plus customers. That’s because if renewables get casted, LADWP faces a big challenge: Limits on regional transmission constrain LA’s renewables choices largely to solar and more solar.

 

To answer the questions raised by the city council’s order, LADWP formed a high-powered advisory group that is winning rave reviews from renewables advocates. It includes technical experts, commercial and industrial customers, policymakers and community interest groups, according to LADWP. It is led by National Renewable Energy Laboratory researchers. The group has begun familiarizing itself with the details of LADWP operations. Its conclusions are due by the fall of 2019. In the meantime, to create a “roadmap” to 100% renewables and help inform the debate, local advocacy group Food & Water Watch (FWW) commissioned “Clean Energy for Los Angeles”, released March 7 by Synapse Energy Economics.

 

The Synapse paper has been welcomed by advocates for a more rapid transition to 100% renewables. It found the city’s transition to 100% renewables by 2030 is “feasible” and “will be cheaper for LADWP ratepayers” than business as usual, according to FWW Executive Director Wenonah Hauter. Synapse also offers new co-stars for renewables. Instead of fossil fuels and hydropower delivered on costly new transmission, the co-stars can be energy efficiency, demand response and battery energy storage, Synapse says. Synapse associate and paper co-author Spencer Fields said the study has one very important takeaway.

 

The biggest change for LADWP in the coming transition will not be its resource mix. It is already more than 30% renewables and quickly adding more to meet its clean energy mandates. The biggest change in moving to 100% by 2030 will be how the utility operates its system.

A transmission-constrained load pocket              

The Los Angeles basin is a transmission-constrained load pocket. The bulk of LADWP’s 4,000 MW to 6,000 MW load is met by out-of-basin nuclear, coal and hydropower generation delivered through four transmission lines. When demand spikes beyond the carrying capacity of that limited transmission, the utility calls on three in-basin natural gas plants. The basin’s Harbor, Haynes and Scattergood plants have allowed LADWP to maintain reliable delivery of electricity. But their water-cooling systems harm the local ocean environment. And they cannot ramp generation up quickly to meet recently increasing demand fluctuations caused by higher renewables penetrations on LADWP’s system.

To sustain reliability while meeting environmental regulations, the utility got approval to repower the plants. Upgraded, air-cooled Scattergood and Haynes units protect system reliability because they can ramp to full power within 10 minutes, according to LADWP. But they do not fit into a 100% renewables resource mix, which is why the upgrading of the other Scattergood and Haynes units and all of the Harbor units has been delayed.

In a preliminary clean energy future summary paper prepared by LADWP, the first “key” consideration explicitly raises the utility’s concern with maintaining system reliability without flexible natural gas plants. The rest of the paper’s key considerations implicitly raise similar concerns. One of those concerns is about meeting federally mandated reliability standards while expanding renewables. Another is that new transmission expenditures can only be avoided with more storage but relying on battery storage for reliability could be difficult with current battery costs and chemistries. Either way, there is a concern about how the transition to 100% renewables could impact rates.

Southern California Edison (SCE) serves just over 5 million customers in regions adjacent to LADWP’s territory. It has similar concerns about a 100% renewables mix in the transmission-constrained basin. SCE spokesperson Robert Laffoon Villegas declined to comment directly on its neighbor utility’s 100% target. But SCE continues to oppose Senate Bill 100, which would increase California’s renewables mandate to 60% by 2030 and target 100% by 2045, he said. SCE’s concern is that the bill does not adequately “consider the potential impacts to utility customers and system reliability,” it wrote to regulators.

From LADWP (used with permission)

The ramping challenge

LADWP’s preliminary clean energy future paper labels its reliability concern a “ramping challenge” that has accelerated with the addition of high volumes of renewables. To meet the ramping challenge, the remaining Haynes, Harbor and Scattergood units were scheduled for repowering by 2029. Those repowerings are all “paused” now.

“LADWP is reassessing all planned repowering projects until a system-wide, in-depth, and independent study is completed,” LADWP’s preliminary paper reported.

“The biggest difference between just meeting the current targets and getting to 100% [renewables] is learning to operate the system a new way.”

Spencer Fields

Associate, Synapse Energy Economics

Synapse’s Fields said LADWP will have about the same amount of renewables capacity in 2030 whether it is at 100% renewables generation or the City Council-mandated 60% renewables generation. This is because the 60% renewables mix would be supplemented by traditional generation, but the 100% renewables capacity would require a new operating paradigm and new resources.

“The biggest difference between just meeting the current targets and getting to 100% is learning to operate the system a new way,” he told Utility Dive. Instead of investing in repowering the in-basin plants and relying on natural gas peakers to balance the system, LADWP would need to learn to use energy efficiency, demand response and battery energy storage.

Sierra Club Beyond Coal Campaign Deputy Director Evan Gillespie said the “central question” for LADWP is what to do about the 1,682 MW of in-basin natural gas.

“The question is whether the plan to repower the remaining units is the best plan, given the rapid growth of alternative technologies,” Gillespie told Utility Dive.

The biggest challenge in moving to 100% renewables by 2030 could be “stretching the cultural and operational limits of a utility that has been operating independently for a hundred years. But [LADWP] is not resisting. Its leaders are trying hard to pivot and challenge themselves.”

Evan Gillespie

Beyond Coal Campaign Deputy Director, Sierra Club

To answer that question, LADWP’s study must determine if reliability can be sustained with the operations plan proposed by Synapse, Gillespie said. The Synapse report was not intended to answer that question, he added. “It was to show how retired fossil plants could be replaced with renewables and distributed energy resources megawatt for megawatt. That is the essential first step.”

The biggest challenge in moving to 100% renewables by 2030 could be “stretching the cultural and operational limits of a utility that has been operating independently for a hundred years,” Gillespie said. “But the utility is not resisting. Its leaders are trying hard to pivot and challenge themselves.”

The next, and very difficult, questions are about how to balance the system in even the most extreme contingency scenarios, Gillespie said. LADWP “seems really committed to this planning effort.”

Though transmission constrained, the LA basin has the Castaic pumped hydro storage facility on its distribution system, which could be expanded, Gillespie said. Expanded transmission on the eastern side of the basin could deliver more utility-scale renewables.

The next set of questions are about the cost-effectiveness of battery storage and the room for it within the basin, Gillespie said.

There is also an unquantified opportunity in demand response because 70% of LADWP’s load is commercial-industrial customers who often see opportunity in demand response programs, Gillespie said.

Farther out, there is enormous potential in transportation electrification, because the city’s huge bus fleets and over half-a-million cars are expected to be electric by 2030, he added. “That is a lot of potential electricity storage.”

The decision on completing the repowering of the Scattergood, Haynes and Harbor units is “the whole ballgame for the transition to 100% renewables by 2030,” Gillespie said. If LADWP concludes they are not vital to reliability in the 2020s, the utility “can be at 100% by 2030 or soon after.”

Los Angeles is a transmission-constrained load pocket.
from the LADWP’s Briefing Book 2017-2018

Solar or more solar?

Synapse’s Fields said the biggest difference in the renewables choices LADWP faces is whether to use a plan dominated by utility-scale solar or a plan with even more solar, but dominated by distributed solar.

Synapse modeled a “reference case” in which the utility meets its existing city council-mandated targets for generation capacity, storage, GHG reductions and its other policy-imposed obligations, along with two other cases. In the reference case, the utility would double its renewables capacity by 2030 by adding 4 GW of solar capacity, 500 MW of wind capacity and 450 MW of storage capacity.

In Synapse’s 100% renewables “utility-scale case,” LADWP would add the same amount of wind and solar as in the reference case, but would also add almost 2 GW of storage capacity. In the “distributed case,” the utility would have 4.3 GW of distributed solar and 5.7 GW of total solar capacity.

It would also need to add 2.7 GW of storage because “distributed solar has a lower capacity factor” and “more storage capacity is necessary,” Synapse reports.

Demand response would play an increasing role in balancing the system, Synapse adds. At the utility’s targeted 60% renewables in 2030, demand response would meet 10% of load. It would be 11% of load in the distributed solar case, and 12.5% in the utility-scale case.

Both solar cases would result in “significant curtailment of renewables,” Synapse notes. Tha’s because without new transmission, there would be limits on selling LA’s excess renewables generation into other markets.

As the renewables penetration rises on its system and solar dominates midday generation, it’s anticipated that LADWP will be forced to respond to more dynamic fluctuations. In the reference case, it will have natural gas peakers for balancing and will continue to use traditional resources to meet its evening peak, Fields said.

In the utility-scale and distributed cases, solar is almost the entire daytime generation source and much would either be stored or unused, he said. “Much more stored solar and more [demand response] would be used than in the reference case to meet the evening peak. In the distributed case, much much more stored solar and more [demand response] would be used” than the reference case.

Synapse’s 100% cases use a resource mix that is “heavier on curtailment and storage,” than other potential resource mixes but there are “many potential generation and capacity mixes,” it acknowledges.

The mixes Synapse chose were “optimized” using “current cost trends for various renewable technologies,” the study adds. “It is possible that in future years the costs of renewable and storage technologies may change, making a different 100% renewable scenario more cost-effective and feasible.”

From the Synapse study (used with permission)

A further word about cost

“LADWP will need to spend money, no matter what, to meet existing targets,” Synapse’s Fields said. “Through 2030, the utility-scale case is more expensive than the reference case and the distributed case is less expensive than the reference case.”

Synapse estimated the cumulative net present value (NPV) of the reference case from 2017 to 2030 at $49 billion. The utility scale case has an estimated $56 billion NPV and the distributed case has an estimated $47 billion NPV.

The utility-scale case’s higher cost is because it requires storage and geothermal capacity and energy efficiency and demand response investments not required by the reference case. The distributed case’s lower cost is because much of the distributed solar is built by customers and those costs are not included in its calculation, Synapse acknowledges. Customer-owned electric vehicles and water heating could also reduce costs, the study adds.

An important factor for planners to notice is that the cost for both solar cases rises significantly in 2029 and 2030 “as LADWP finalizes its push to 100% renewable generation in each hour,” Synapse reports.

The spike is “when the last fossil plants or nuclear plants come offline,” Fields acknowledged. “That does not happen by 2030 in the reference case, but it is likely the difference in overall costs for the reference and solar cases would close as the utility moves toward 100% renewables farther out,” he added.

Ultimately, “this is a transition LADWP must make to meet existing targets, and this study shows getting all the way to 100% renewables does not require any more renewable generating capacity,” Fields said. “They just need to adjust to a new system operating paradigm.”

Ronald Bethea April 9, 2018 Uncategorized

Florence-based group helps host clean-energy rally

SC NOW MORNING NEWS Feb 28, 2018

The Rev. Leo Woodberry speaks at a rally in Columbia for clean energy.

FLORENCE, S.C. – A group based in Florence, the New Alpha Community Development Corporation, was one of the main organizers for a recent rally in Columbia to promote legislation for clean energy.

The Rev. Leo Woodberry, pastor of Kingdom Living Temple, is executive director of the corporation. Woodberry’s group of approximately 35 people joined the Sierra Club and the Dogwood Alliance as hosts of the rally.

“In light of the failed V.C. Summer Nuclear Plant, we have an opportunity to recalculate how we generate energy in a just and equitable manner for our state and for future generations,” Woodberry said.

“No longer can we give utilities a blank check when it comes to dipping into the incomes of South Carolina residents, particularly those who can least afford it. Today, we are coming together so that the voice of everyday people, the residents of South Carolina, can be heard. It’s time to chart a course to more clean and renewable sources of energy for all people here in South Carolina.”

More than 100 South Carolinans participated in the event, including representatives from several of the state’s environmental justice and religious groups as well as conservation and clean energy advocates.

The South Carolina legislature is considering bills that would expand access to clean energy like solar, while protecting consumers across the state from costly energy such as the burden of paying for the failed V.C. Summer nuclear plant. The coalition is urging state elected officials to support the package of legislation.

“South Carolina communities want a clean, renewable energy future that truly works for them,” said Jodie Van Horn, director of the Sierra Club’s Ready for 100 campaign. “Sierra Club’s Ready for 100 campaign looks forward to supporting our partners in communities across South Carolina as they bring forward this vision of a just and equitable transition to 100 percent clean energy for all people.”

CONTRIBUTED PHOTO/SIERRA CLUB
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admin April 5, 2018 Uncategorized

Home Solar Dims as Tesla, Others Curb Aggressive Sales

Author:By Russell Gold Russell.Gold@wsj.com April 4, 2018 5:30 a.m. ET BLOOMBERG NEWS/THE WALL STREET JOURNAL

The number of U.S. homeowners putting solar panels on their roofs declined last year after leading installers including Tesla Inc. abandoned aggressive sales practices that had helped drive breakneck growth. Residential solar had been on a tear, averaging 49% annual growth between 2010 and 2016, but the number of megawatts added last year dropped by 16% compared with the year before, according to new data from GTM Research, a firm that tracks renewable energy. It was the first annual decline since at least 2000, which is as far back as GTM tracks figures.

Industry executives and energy experts said the slowdown was driven by a sharp retreat by national solar installers, including Tesla’s SolarCity and Vivint Solar Inc. VSLR +4.45% Those big outfits had deployed large sales forces to pitch homeowners on the benefits of rooftop solar, and heavily marketed deals to lease panels that required little to no money down.

The race to build a dominant national solar brand led companies to burn through cash. Unable to maintain that pace, companies scaled back and focused on profits over growth, or in some cases, got out of the rooftop solar business altogether.

SolarCity, purchased by Tesla in 2016, posted the largest declines. Once the clear-cut leader among solar installers, with one-third of the national market two years ago, it ended door-to-door sales last year and cut customer-acquisition spending. Its sales, as measured by megawatts deployed, fell by 38% in 2017, according to company figures, which include both residential and commercial installations.

Solar Eclipse Residential-solar installations fell in 2017,after years of rapid growth. Tesla said it was moving away from no-money-down leases and toward sales. It appears to have been passed by rival Sunrun Inc. RUN +1.32% in recent months as the top solar installer in the country, according to GTM. “We expect growth to resume later this year,”

Other companies also retreated from heavily marketing their home solar businesses, including NRG Energy Inc., NRG -0.07% which shut its business last year, and Vivint, which posted a 17% drop in residential sales volume in 2017 as it moved to prioritize profitability. Sungevity Inc. filed for bankruptcy protection last year after an aggressive growth strategy resulted in too much debt, the company said in a court filing.

The industry’s sales strategies have attracted scrutiny by regulators in some states, including New Mexico, where the state attorney general, Hector Balderas, filed a lawsuit last month claiming that Vivint used “false, misleading and fraudulent statements” to sign customers up for long-term deals. Rob Kain, Vivint’s vice president of investor relations, said the company disagrees with the allegations and plans to contest them in court.

Heard on the Street: For Tesla, Deliver, Don’t Promise, in 2018 (Dec. 30)
“Could we have had a salesperson who was aggressive? I wouldn’t be surprised,” Mr. Kain said, adding that the company would have fired a salesperson for misrepresentations. SolarCity grew with help from a hard-charging sales culture. Before being acquired by Tesla, the company, which was run by Lyndon Rive, the cousin of Tesla founder Elon Musk, tapped salespeople from the mortgage industry and Las Vegas casinos to sell solar panels, and gave them aggressive quotas, according to current and former managers and employees interviewed by The Wall Street Journal.

Last year, Tesla changed course and began selling solar panels through the same stores that sell its cars. Other sales approaches were shut down in order to “focus on projects with better margins,” the company said.Eric White, president and chief executive of Dividend Finance , a San Francisco-based company that provides loans to homeowners putting solar on their roofs, said many solar companies acted too much like Silicon Valley firms, pursuing growth at all costs in hopes of becoming leaders in a nascent market.

Mr. White said that while the industry’s prior growth is “not sustainable and leaves bodies in its tracks,” 5%-to-15% annual increases are achievable.Solar energy grew rapidly in recent years as the cost of solar panels declined. The all-in cost of a typical rooftop solar system fell by 61% between 2010 and 2017 to $2.80 per watt, or roughly $16,000 for the average home system, according to the federal government.

Solar executives and industry analysts believe annual residential solar growth will resume in 2018. But two developments risk hurting sales in coming years, say industry analysts. First, new Trump administration tariffs on imported solar modules, mostly from China, are expected to marginally raise costs. Second, a federal government tax incentive to homeowners worth 30% of the value of the solar array is set to end by 2021.

Lynn Jurich, chief executive of Sunrun, said rising utility electricity rates and falling solar panel costs will drive increased interest in solar. “We saw an unnaturally high growth rate because there was a lot of capital coming in to spend on advertising and customer origination, and not a lot of discipline on focusing on profitable growth,” she said of the sector as a whole. “You suck all the advertising out of an industry and it shrinks.” Still, companies continue to spend considerable amounts acquiring customers. Sunrun estimates it spends about 28 cents on marketing for every dollar spent on purchasing and installing panels. Sophie Karp, an analyst at Guggenheim Securities, said industrywide customer-acquisition costs were higher. “Solar is not a product that you buy,” she said. “It is a product that gets sold.”

—Kirsten Grind contributed to this article.

admin April 5, 2018 Uncategorized

Electric vehicles to dominate Hawaiian roads by 2045, HECO predicts

Author:Robert Walton@TeamWetDog Published April 2, 2018

Dive Brief:

Hawaiian Electric Cos. last week laid out its broad long-term vision for electric vehicles on the islands, predicting most cars in its service territories will be electric by 2045.

The utility company filed its “Electrification of Transportation Strategic Roadmap” with the state’s Public Utilities Commission, outlining how it will utilize growing EV adoption to lower system costs, bring more rooftop solar onto the grid and ultimately help meet the state’s 100% renewables goal.

Hawaii trails only California in electric vehicle adoption, and expects the island’s electrification of the transportation sector to result in a majority of light duty vehicles being powered by solar, wind, biofuels, geothermal and other renewable resources.

Electric vehicle adoption will drive higher demand in Hawaii and across the United States, but utility officials say the trend may be key to reaching the state’s all-green energy goals.

Hawaii has at times struggled to bring rooftop solar onto its system, as customer enthusiasm for panels outstripped the grid’s capabilities. But in the plan filed Thursday with the PUC, HECO officials say charging cars, trucks, buses and heavy equipment will help to integrate nearly 200,000 new private rooftop solar systems, along with grid-scale renewable projects.

The utility in a statement said its plan “foresees Hawaii in 2045 with most personal light duty vehicles” powered by renewable energy. And in route to that tipping point, officials say the transition can help bring lower costs to all customers of Hawaiian Electric, Maui Electric and Hawaii Electric Light.

Brennon Morioka, Hawaiian Electric’s general manager of electrification of transportation, said the roadmap lays out the steps to meet customer needs while “adapting to the new technologies we know are coming.”

The utility foresees $60 million in benefits to Hawaiian Electric customers over the next 27 years, including avoided gasoline and vehicle maintenance costs. On Oahu, the transition could benefit the broader economy by more than $200 million. And those benefits could rise significantly if the utility can convince drivers to charge during the day when solar is abundant.

There are already almost 7,000 electric vehicles in Hawaii, and adoption could be extended to busses, railways and other industries.

The report lays out several near-term steps HECO will take:

The utility plans to work with automakers, dealerships and EV advocates to lower vehicle prices and educate consumers.
HECO will partner with third-party providers to build out the state’s charging network, with a particular focus on charging at workplaces and multi-unit residences. HECO also wants to expand the network of utility-owned fast-chargers and public Level 2 chargers.
The plan also calls for creation of “grid service opportunities” which include demand response incentives to shift vehicle charging to times when solar is abundant.

HECO will also continue grid modernization efforts to smooth the rise in vehicles on its system and maximize use of renewable energy.
In total, HECO said its plan could create $550 in benefits per electric vehicle to every utility customer over the next 27 years — and up to three times that benefit if charging is managed. Managed charging has become a key concept when discussing EV adoption in order to avoid exacerbating peak demand and utilize renewable energy.

Last year, HECO announced it would shift to time-of-use rates at the DC Fast Charging stations it operates, aiming to adjust customer use of the stations to encourage shorter use times and greater access. Over the next three years, HECO says it will develop “more advanced rates” in response to growth. For residential customers, the PUC recently approved a suite of solar and demand response programs, and the utility is exploring time-of-use, location-based and dynamic pricing.For commercial fleets, the utility says it will investigate bulk discounts for off-peak purchase of electricity at public chargers and depots.

admin April 3, 2018 Uncategorized

NextEra Energy strikes $1.27B deal to sell Canadian renewables assets

BRIEF Author:Robert Walton@TeamWetDog Published April 2, 2018

Dive Brief:

NextEra Energy Partners has reached a deal to sell its Canadian portfolio of renewable generation, as the company seeks to move the capital back into the United States to take advantage of the lower corporate tax rate. Canada Pension Plan Investment Board will pay $582 million and assume $689 million in debt, for approximately 400 MW of wind and solar generating facilities located in Ontario.
President Trump’s push to lower the corporate tax rate has led several energy companies to make adjustments, including utilities lowering rates. Beginning this year, the corporate rate dropped from 35% to 21%.

NextEra floated the idea of selling its Canadian assets during its January earnings call and has since moved quickly. The company says it expects the sale to close during the second quarter of this year. With the funds returned to the United States, the lower corporate tax rate will boost the funds available for distribution.

NextEra CEO Jim Robo said the assets were sold at a 10-year average cash available for distribution (CAFD) yield of 6.6%. Included in the sale are six fully-contracted wind and solar assets, with an average contract life of approximately 16 years and 10-year average CAFD of $38.4 million.The sale includes four wind generating facilities totaling more than 350 MW and a pair of 20 MW solar generating facilities.

The corporate tax cut will be a double-edged sword for utilities, reducing their tax burden as well as their revenue. But for customers, the benefits are more clear, evidenced by a trend of states pushing utilities to return savings to customers. Earlier this year, Florida Power & Light announced it would use federal tax savings to repair $1.3 billion in damage caused by Hurricane Irma last year and to avoid a rate increase. Regulators in Kentucky cited the lower rate in approving a smaller-than-requested rate increase for Kentucky Power Co. Virginia lawmakers rolled back a Dominion Energy rate freeze to return some funds to customers.

admin April 3, 2018 Uncategorized
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