NewEnergyNews: 06/01/2016 - 07/01/2016/


Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...

The challenge now: To make every day Earth Day.



  • TTTA Wednesday-ORIGINAL REPORTING: The IRA And The New Energy Boom
  • TTTA Wednesday-ORIGINAL REPORTING: The IRA And the EV Revolution

  • Weekend Video: Coming Ocean Current Collapse Could Up Climate Crisis
  • Weekend Video: Impacts Of The Atlantic Meridional Overturning Current Collapse
  • Weekend Video: More Facts On The AMOC

    WEEKEND VIDEOS, July 15-16:

  • Weekend Video: The Truth About China And The Climate Crisis
  • Weekend Video: Florida Insurance At The Climate Crisis Storm’s Eye
  • Weekend Video: The 9-1-1 On Rooftop Solar

    WEEKEND VIDEOS, July 8-9:

  • Weekend Video: Bill Nye Science Guy On The Climate Crisis
  • Weekend Video: The Changes Causing The Crisis
  • Weekend Video: A “Massive Global Solar Boom” Now

    WEEKEND VIDEOS, July 1-2:

  • The Global New Energy Boom Accelerates
  • Ukraine Faces The Climate Crisis While Fighting To Survive
  • Texas Heat And Politics Of Denial
  • --------------------------


    Founding Editor Herman K. Trabish



    WEEKEND VIDEOS, June 17-18

  • Fixing The Power System
  • The Energy Storage Solution
  • New Energy Equity With Community Solar
  • Weekend Video: The Way Wind Can Help Win Wars
  • Weekend Video: New Support For Hydropower
  • Some details about NewEnergyNews and the man behind the curtain: Herman K. Trabish, Agua Dulce, CA., Doctor with my hands, Writer with my head, Student of New Energy and Human Experience with my heart




      A tip of the NewEnergyNews cap to Phillip Garcia for crucial assistance in the design implementation of this site. Thanks, Phillip.


    Pay a visit to the HARRY BOYKOFF page at Basketball Reference, sponsored by NewEnergyNews and Oil In Their Blood.

  • ---------------
  • WEEKEND VIDEOS, August 24-26:
  • Happy One-Year Birthday, Inflation Reduction Act
  • The Virtual Power Plant Boom, Part 1
  • The Virtual Power Plant Boom, Part 2

    Thursday, June 30, 2016

    BREXIT And The Climate Fight

    5 ways Brexit will transform energy and climate; A post-Brexit UK will still have energy ties to the EU, but there will be big changes.

    Sara Stefanini, June 24, 2016 (Politico)

    “Britain’s departure from the EU will force broad changes to the bloc’s energy and climate policies, and remove a crucial ally for Central Europeans — but it will also give London far more freedom to pursue nuclear projects…But there’s a lot to lose on both sides of the Channel…A post-Brexit U.K. will still be tied to the rest of Europe through gas and electricity links and an emissions trading market it is unlikely to ditch, but it will have less influence on the bloc’s decisions. The EU, instead, will lose a strong pro-free market voice, which has historically helped tone down some more statist schemes coming from Continental capitals…

    "...[Post-Cameron leadership could] scrap the country’s renewable energy targets and tax on high-polluting power plants…[and] change the country’s approach to the Paris climate agreement…[Brexit could weaken the U.K.’s access to Russia’s] oil and gas…Both sides of the Brexit debate argued their position would ensure lower household power and gas bills…[but an independent National Grid report found leaving] the EU could cost the U.K. up to £500 million per year in the 2020s…Central and Eastern Europe nations lose an ally in the debate] over how much say the Commission, and other members, should get in a country’s climate and energy policies…[and the loss of long-term predictability] will likely cause upheaval for businesses planning to build renewable energy plants or drill for shale gas…” click here for more

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    The Bet On Solar

    Why Solar Energy Has Explosive Potential for Investors

    Afrasiab Mian, June 27, 2016 (Zacks via Yahoo Finance)

    “…[G]lobal energy generated from [solar photovoltaic power (PV)] is expected to grow from 2% in 2016 to 13% in 2030…[with expected cost reductions of] 60% over the course of the next decade…[PV now] costs roughly 5 to 10 cents per kilowatt-hour (kWh)…[and the price of electricity varies from Louisiana’s 9.2 cents per kWh to Hawaii’s] 27 cents per kWh…[With the threat of climate change is increasing and PV technology advancing, signs are emerging of] PV’s rise to prominence…Though Tesla’s stock value dropped 11% after the announcement of its proposed merger with SolarCity, the deal has] a lot of potential and could pay off significantly…[Investors should consider Hanwha Q Cells…[and] Renesola…which both currently sit at a Zacks Rank #1 (Strong Buy)…[and] have received upward earnings estimate revisions for Q1…” click here for more

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    The Birth Of Hawaii Ocean Wind

    Hawaii offshore wind projects get boost from Obama administration

    James Pritchard, June 23, 2016 (Pacific Business News)

    “…[A] call for information to gauge the offshore wind industry’s interest in acquiring commercial wind leases in two areas encompassing a combined 485,000 acres of submerged federal lands off Oahu…[initiated efforts by the Obama Bureau of Ocean Energy Management and the Hawaii Intergovernmental Renewable Energy Task Force] effort to develop the state’s ocean wind potential…[It will help Hawaii reach its mandate for] 100 percent clean-energy generation by 2045…[ Progression Hawaii Offshore Wind and Alpha Wind Energy] have expressed an interest in developing [wind energy farms of about 400 MW in the early 2020s], each at an estimated cost of $1.6 billion, in federal waters off Oahu…” click here for more

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    Geothermal Plus Solar Investment Pays Off

    Geothermal + Solar = Expensive but Often Worth it; Combination systems often result in net-zero consumption

    Joanna R, Turpin, June 20, 2016 (The News)

    “…[For homeowners] looking to take energy conservation to the next level, many contractors are encouraging the installation of a combination geothermal heat pump and solar [photovoltaic (PV)] energy system…[A $100,000 investment can take a home’s energy consumption to net-zero if sized and designed properly…While combination geothermal/solar systems still comprise a small number of installations, there are fears that when the tax credits for geothermal expire at the end of the year, interest will dry up completely…[but that is only expected to be a short term glitch because the combination is likely to] eventually be adopted into the mainstream of home construction and renovation due to policies that favor the environment and the concern over climate change as well as the cost of fossil fuels…”click here for more

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    Wednesday, June 29, 2016

    ORIGINAL REPORTING: Some Numbers Behind The Solar Boom

    What solar's latest growth numbers say about the sector's future; Solar growth is likely to set more records — until the federal tax credits expire

    Herman K. Trabish, September 24, 2015 (Utility Dive)

    Editor’s Note: Thanks to a long term extension of the federal Investment Tax Credit described in this story, solar numbers continue to rise.

    2015 has been a sunny year for the solar industry so far, but some stormclouds are beginning to appear on the horizon, according to a recent report.

    Despite strong projected growth in residential and utility-scale solar for the upcoming year, industry leaders are increasingly questioning why the business community remains hesitant. And power companies are also uncertain over their future roles.

    “There are still a lot more questions than answers in non-residential solar,” said Cory Honeyman, Senior Solar Markets analyst at GTM Research and lead author of the Q2 2015 U.S. Solar Market Insight Report published by GTM and the Solar Energy Industries Association (SEIA).

    “That is the segment we are watching to understand what the biggest bottlenecks are and what solutions are being tried to make that market rebound," he said.

    The most recent numbers

    Installation numbers for residential and utility-scale solar for the second quarter showed solid growth compared to the same period last year.

    Installation of residential photovoltaic (PV) solar in Q2 2015 was up 6% over the previous quarter, and up 70% over the same time in 2014.

    Utility-scale PV installation increased by 729 MW in Q2 2015, comprising about 52% of all the capacity installed in the quarter. And it was the ninth consecutive quarter that the utility-scale segment of the market grew by about half a gigawatt.

    But non-residential PV, however, was down 20% from the previous quarter, and down 33% from 2014's Q2. Installation for the quarter dropped below 200 MW, the least activity since 2011. The sector's numbers may be somewhat compromised because corporate procurements — an increasingly important factor in U.S. renewables growth — are included in the utility-scale solar category.

    While much of the current 1 GW corporate solar pipeline is in projects larger than 50 MW, the report notes, that capacity could be included in the non-residential total.

    Rate design depresses non-residential solar growth

    Some of the difficulties of the non-residential segment could be explained in the report’s assessment of the solar policy landscape, Honeyman said.

    At least 39 states have seen utilities consider or "approved or implemented various reforms to net energy metering (NEM) or rate design relevant to solar compensation,” he said. Until now, the most common reform has been proposals for a solar customer fixed charge. But regulators have rejected or reduced the vast majority of those proposals.

    More recently, utilities are proposing the kind of peak demand charges for residential solar customers now primarily imposed on utilities’ non-residential commercial-industrial customers. “That is a type of reform that is increasingly going to be on the table,” Honeyman said.

    At the same time, upfront incentives (UFI) and performance-based incentives (PBI) from states and utilities are being phased out in proportion to the growth of solar penetration. That decline in solar incentives has tracked a “roughly 70% to 120%” drop in installed costs for solar, according to a recent Lawrence Berkeley National Labs study, indicating the success of policymakers’ deliberate strategy to use such incentive reductions to push solar installers to drive prices down further.

    But explaining the difficulties of the non-residential market comes down mostly to rate design, Honeyman said.

    NEM policies reimburse both residential and non-residential solar at the full retail rate of electricity. But the volumetric rate components composes the majority of the residential bill, which is offset by the NEM reimbursement.

    Demand and higher fixed charges required of non-residential customers, however, could make up 50%, 60% of the bill, so "less of it is offset by solar,” Honeyman said.

    “When that non-residential customer also loses state and utility UFIs and PBIs, project economics are more compromised.”

    The overall levelized cost of energy (LCOE) for both residential and non-residential solar increase with state and utility incentives, Honeyman asserted.

    “But the homeowner’s LCOE is still below retail, while the LCOE for the non-residential system is not," Honeyman said. "That lengthens the payback period non-residential solar and limits the solar value proposition.”

    Now, solar advocates are concerned about utilities requesting that regulators impose similar kinds of value proposition charges on residential solar owners.

    “The broader trend is that the debate has evolved to more complicated and sophisticated rate reforms, like peak demand charges, value of solar studies, attempts to revisit the value of solar in ways that does not make it a blanket fixed charge," Honeyman said.

    Yet few proposals have won support from both industry stakeholders and utilities, he added. The one exception is proposals for minimum bills, which have at least been “tolerated” by both sides in debate hotbeds like Massachusetts and California, making such bills a "politically palatable compromise,” Honeyman said.

    Looking ahead

    Even with the ongoing debates, solar's strong growth could continue if the right policies and regulations align on the national level.

    The report uses its comprehensive and granular numbers to form a three-stage view of the U.S. solar market over the next ten years.


    To the end of 2016, there will be “an unprecedented boom in solar installations" impacting all three market segments and most states.

    Improving project economics, continued low interest rates, and a secure 30% federal investment tax credit (ITC) through the end of 2016 will drive continued growth, in addition to a rush to complete solar projects ahead of the ITC credit decrease at the end of 2016, the report predicts.

    From July 2015 to December 2016, the report forecasts the U.S. solar PV market will add 18 GW, which is more than the cumulative capacity built by the industry up to the middle of 2014.


    But more uncertainty over solar's growth lies between 2017 and 2019. Given the political inclinations of the current Congress, it is likely — though not certain — that the ITC will not be extended. The report identifies “five macro factors” that could swing the market one way or another:

    A drop-off in new larger-scale projects from the beginning of 2017, when the ITC drops to 10%.

    Tighter residential and non-residential project economics once the ITC plummets to 10% An eventual interest rate increase making project capital more expensive Delayed state support for renewables since Clean Power Plan (CPP) compliance is not required until 2022

    Dropping project costs allowing undeveloped new markets to ripen after 2020

    Between 2020 and 2025, as installed costs reach new lows, imminent CPP compliance requirements will drive “a new era of growth for solar.” State incentives will spur more renewable energy growth to meet CPP standards. And solar will be on “a strong competitive playing field with both retail electricity and alternative sources of wholesale generation.”

    Uncertainty will dissolve and there will be an “extended period of consistent expansion” across all 50 state markets. States are likely to redesign their electricity markets to bring in distributed energy resources, following the lead of initiatives now being worked out through California’s AB 327 and New York’s Reforming the Energy Vision proceedings.

    And for utilities, seizing solar opportunities will help the resource expand its reach.

    For utilities seizing solar opportunities

    Honeyman points out that utilities are beginning to seize the solar opportunities. “The low-hanging fruit for utility-holding companies is to use the deregulated arms to develop and own utility-scale solar assets, which they should move on before the end of December 2016.”

    Dominion, NRG Energy and Duke Energy are all working aggressively towards those goals, not just in California and the Southwest, but also in emerging solar markets in the Southeast, he added.

    Honeyman used Duke Energy’s purchase of a majority stake in REC Solar as one such example.

    “Providing their low cost of capital and deep balance sheet to a company experienced in originating and developing commercial projects is the next, easy approach to solar for a utility,” he said.

    The more complicated question, though, is how to develop solar in a utility’s service territory, Honeyman added. Regulatory constraints complicate how “to justify rate basing ownership of solar.”

    It has worked for Arizona-based utilities like Tuscon Electric Power (TEP) and Arizona Public Service (APS) because “you had pre-existing capacity allocated to a utility ownership of solar program that was justifiably repurposed for rooftop solar,” Honeyman said.

    Regulators also responded to those utilities’ intention to locate their rooftop solar where it bolsters grid reliability, he added.

    Another justification for utility ownership is to provide solar to under-served segments of the community. Many homeowners don’t have south-facing roofs that maximize production or credit scores high enough to support low interest rate loans. Houses with west-facing roofs support grid reliability, potentially warranting utility ownership. Utility-bill secured loans could justify engaging with low FICO score customers. Both are ideas being discussed in utilities' board rooms, Honeyman said. Finally, he said, community-shared solar offerings located at sites that boost grid reliability are increasingly recognized as a solar ownership opportunity for utilities. And it's a avenue opening up access for lower income and other under-served customers.

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    ORIGINAL REPORTING: The Utility Of The Future Takes Shape

    How to become the 'Utility of the Future?' Industry experts weigh in; Former FERC Chair Wellinghoff joins a panel of power sector experts at SPI 2015

    Herman K. Trabish, September 28, 2015 (Utility Dive)

    What does it take to become a "utility of the future"?

    A panel of experts from around the power sector addressed that question earlier this month at Solar Power International 2015 (SPI), the industry's largest annual conference.

    “What the utility of the future needs to do is replace today’s grid with the grid of the future,” said Ronald Litzinger, president of the Edison Energy Group, the holding company for Edison's competitive power developers. “That is a more networked grid with much more advanced controls that allows for two-way power flows.”

    That grid offers “a good growth opportunity for the utility,” Litzinger added.

    “I don’t care where you get your power," he said. "We are just here to provide a grid to facilitate the delivery of the power.”

    Consumers, on the other hand, will increasingly care where they get their power, said Jon Wellinghoff, a former chairman of the Federal Energy Regulatory Commission (FERC).

    “We have to look not at what the utility of the future is but at what the utility customer of the future is. That customer now has a customer-centric set of choices," Wellinghoff, now a partner at the law firm Stoel Rives, said.

    Emerging efficiency and home energy management technologies have changed how customers interact with their electricity and the company that provides it. Customers can now control their loads in response to prices and/or signals from a grid operator, as well as owning their own generation or storage. And they can choose to use those products or offer them to the grid, according to Wellinghoff.

    “With those abilities, the utility now has to look at those residential, commercial, and industrial customers differently and figure out how to partner with them to extract as much value as possible, both for the customer and for the grid, and to optimize the operation of the grid itself," Wellinghoff said.

    Postcards from the future

    Hawaii is the poster-child for the evolving utility sector, said Lorraine Akiba, a commissioner with the state's Public Utilities Commission, sending "postcards from the future" to the the other states about renewable energy, the utility transformation, disruptive technologies, customer choice and empowerment.

    But Hawaii’s grid faces a double challenge, she explained. It has the highest penetration of renewables in the United States, in part due to high electricity prices, while lacking adjacent electricity markets to export over-generation or to obtain peak demand support.

    But, "in all challenge lies opportunity,” Akiba said. The commission has embraced change and regulatory reform, while identifying new avenues to incentivize the evolution of utilities, noted in its landmark “Inclinations on the Future of Hawaii’s Electric Utilities” white paper.

    One of the Hawaii commission's landmark rulings was to clarify energy efficiency, demand response, and energy storage as distributed energy resources, so they could be treated as generation resources for planning and cost recovery, Akiba said.

    “For savvy utilities and savvy third parties, that should open up a whole new area of revenue generation, especially in the area of third party aggregators of demand response being able to partner with utilities.”

    Hawaii's so-called vision of the future empowers customers, making them full participants in the state's portfolio, Akiba added.

    The electricity transformation in Hawaii and elsewhere can be boiled down to a "gradually escalating spiral of technology, Tom Starrs of SunPower said.

    Starrs, vice president of market strategy and policy for the solar company, added that "technology innovation is not going to drive disruptive change on its own ... We have to see a corresponding evolution in the regulatory framework.”

    States like Hawaii, California, and New York are upping their game, Starrs said, because "they have policy goals that differ materially from places satisfied with the status quo.”

    Even so, the drivers of change are different in those three states with more mature solar industries. In Hawaii, it's the “near crisis” of high renewables penetration. In California, it's the commitment to cut greenhouse gas emissions. In New York, it is "a deep-rooted commitment in the wake of Superstorm Sandy" to grid reliability and resilience.

    “Those three different drivers share the same set of technical solutions,” Starrs said. He listed examples such as distributed solar, battery storage, energy management capabilities, and the ability to do demand response, noting that they all require the distribution system.

    “We are not going to do away with the distribution system tomorrow or next year or in the next decade,” he said. The challenge is to "figure out how to allow utilities to continue doing what they have done well for a hundred years without putting obstacles in the way of deploying the technologies consumers want.”

    Who runs the distribution system?

    Utilities will likely overcome the hurdle of providing many new products and services in the competitive marketplace, Wellinghoff said. Even so, there must be an owner and operator of the distribution grid and "that is a monopoly service.”

    Because competition to provide distribution system services is impractical, the monopoly provider must be regulated, though minimally, to prevent “unlimited rents,” Wellinghoff explained. He believes the solution is anIndependent Distribution System Operator (IDSO) that operates but does not own the distribution system.

    The system, owned by a utility, would only have the responsibility of ownership, invest in and maintain that asset, similar to transmission owners in ISOs and RTOs, Wellinghoff said.

    Distribution system planning would integrate with FERC’s planned bulk transmission system, but would still rest under state commissions, Wellinghoff said.

    “The utility owner would be guaranteed a return on whatever investments were recommended by the independent entity to the regulator," he said. "It would mean a lot less potential for stranded assets and for risk on investments in the asset.”

    Though Litzinger expects there will eventually no longer be a need for a centralized distribution system, utilities now "need something to take away the excess power during the heat of the day or customers would be very disappointed at what happens to their electronics,” he said. Additionally, customers need power during night or overcast days.

    Litzinger said power companies should simplify how they support the grid and used Edison's utility — Southern California Edison — as an example of using a single fixed charge to run the wires.

    "Community choice aggregation is fine," Litzinger said. Everything else should be competitive, including the retail and energy services sectors.

    Best bang for your bill

    That leads into the next evolution: the best service for your bill.

    At present, the utility bill is not transparent, Akiba said.

    “People pay for the services they get over their cell phones," she said, "but they don’t know the value of what they get from the grid because it is in one service."

    It will be necessary to “unbundle” the services customers get from the grid, she explained. Once customers understand the value of their electrical services, time-varying rates will be effective signals to alter behaviors.

    If the value customers bring to the grid with distributed solar, battery storageand the other emerging technologies is balanced with services they obtain from the grid in a transparent exchange, they will “see value and want to be dynamic providers to the grid,” Akiba said. Rate cases could be key to pushing that change forward, but is also an important balancing act.

    Thanks to his extensive experience in rate cases, Litzinger is keenly aware of the conflicting pressures on utilities to optimize both spending and operations.

    "The thing that keeps spending in check is that the overall rate has to be acceptable for regulators and consumers to buy into," Litzinger explained. “Inrate cases, everybody always says they are willing to take an outage instead of the spending but I don’t know where all those people go during the storms.”

    The better way to minimize costs for the grid, he said, “is to send the right price signals so the distributed resources locate where we don’t have to do much.”

    But customers have shown with large investments in distributed solar, battery storage, and advanced energy management capabilities that they are indeed willing to spend for value, SunPower's Starrs asserted.

    “If we send the right price signals, we are giving incentives to customers to make their own investments,” Starrs explained.

    Price signals “give customers the ability to arbitrage whatever rate designthey are facing and an incentive to invest in accordance with their own desires and an opportunity to invest to save money.”

    The answer to overcoming the challenge of midday over-generation from solar, he continued, is a "price signal that says 'energy is cheap and abundant in the middle of the day so turn on your appliances, charge your EVs and your home battery storage in the middle of the day and sell it back to the grid during peak demand periods when the price is high.'"

    "It is not complicated," Starrs said.

    A combination of fixed and demand charges that reflect the actual cost of service will also help, Litzinger said, alongside real-time pricing.

    But Wellinghoff wasn't so sure.

    The basic cost of service rate model “is a very blunt instrument,” Wellinghoff noted. The rate base process “is not going to get investment in new technology.”

    Customers will invest if they have the right signal for the value of their investment and if that value can be extracted through market-based mechanisms, he said.

    “That can make it easier for [utilities] to earn money on the distribution system at lower risk and make it easier for customers to extract value for their investments on their side of the meter in an optimum and cheaper way for everybody,” the former FERC chair said.

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    Tuesday, June 28, 2016

    TODAY’S STUDY: Utilities And New Energy – The Good, The Bad And The Others

    Benchmarking Utility Clean Energy Deployment: 2016 Ranking 30 of the Largest U.S. Investor-Owned Electric Utilities on Renewable Energy & Energy Efficiency

    June 2016 (Ceres and CleanEdge)

    Executive Summary

    Benchmarking Utility Clean Energy Deployment: 2016 reflects clean energy progress by the largest electric utilities in the United States at a time when worldwide momentum toward clean energy has never been greater. The historic Paris Climate Agreement, forged by 195 countries in December 2015, punctuated a year in which global clean energy investments and renewable energy installations in the U.S. reached all-time highs.

    The year was also marked by record high global temperatures and several of the strongest hurricanes and typhoons on record, providing yet more evidence of the economic and human cost of climate change and the urgency of accelerating clean energy use globally.

    This report provides a window into how the global transition toward clean energy is playing out in the U.S. electric power sector. Specifically, it reveals the extent to which 30 of the largest U.S. investor-owned electric utility holding companies are increasingly deploying clean energy resources to meet customer needs.

    The 30 holding companies evaluated in the report represent 87 electric utility subsidiaries located throughout the U.S.1 Collectively, these companies accounted for nearly 60 percent of total U.S. electric industry sales in 2014, the most recent year for which data is available and the reporting year in which these companies are benchmarked.2

    While these utilities differ widely in size, geography, resource profiles and ownership of generation assets, they all share an obligation to provide the public with safe and reliable service at reasonable rates, and a responsibility for maintaining and modernizing the electric distribution grid. As such, their role in enabling widespread U.S. clean energy deployment is vital.

    The report assembles recent data from more than 10 sources, including state Renewable Portfolio Standard (RPS) annual reports, U.S. Securities and Exchange Commission 10-K filings, and Public Utility Commission reports, to show how some of the largest U.S. electric utilities stack up on renewable energy and energy efficiency performance. To our knowledge, it is the only single source of information on how U.S. electric utilities rank in terms of their actual deployment of clean energy solutions.

    Benchmarking these companies provides an opportunity for transparent reporting and analysis of important industry trends. It fills a knowledge gap by offering utilities, regulators, investors, policymakers and other stakeholders consistent and comparable information on which to base their decisions. And it provides perspective on which utilities are best positioned in a shifting policy landscape, including likely implementation of the U.S. EPA’s Clean Power Plan aimed at reducing carbon pollution from power plants.3

    Key Developments

    Here are just a few of the major developments affecting utility deployment of clean energy since Ceres published the first edition of this Benchmarking report in 2014:

    ! World leaders have committed to act on global warming. The targets and timetables established in the Paris Agreement represent an unprecedented level of international cooperation and commitment to avert the worst impacts of climate change. Achieving these ambitious goals will require worldwide clean energy investment to increase by an additional $1 trillion per year through 2050—what Ceres calls the “Clean Trillion.” A significant component of this investment is needed to build new renewable power generation.

    ! Policy support for clean energy in the U.S. is stronger than ever. Recent five-year extensions of the federal investment tax credit (ITC) and production tax credit (PTC) will drive tremendous additional deployment— and further cost reductions—of wind and solar power regardless of how EPA’s Clean Power Plan is implemented.4 Further, several states including California, Hawaii, New York, Oregon and Vermont have strengthened already-robust renewable energy commitments, with new RPS targets ranging between 50 and 100 percent.

    ! U.S. clean energy deployment has reached all-time highs. The U.S. added a record 7.3 gigawatts (GW) of solar photovoltaic (PV) capacity and 8.6 GW of wind in 2015, bringing total installed capacity to 25.6 GW for solar PV and 74.4 GW for wind.5 In other words, U.S. solar PV and wind capacity grew by more than 28 percent and 11 percent, respectively, in a single year. Looking specifically at utility-scale resources, solar and wind represented more than 60 percent of U.S. total net capacity additions in 2015.6 Further cost declines in renewable technologies, particularly solar PV, are expected to reinforce and accelerate this trend. Similarly, investment and savings from U.S. electric sector energy efficiency programs have reached unprecedented levels.7

    ! Energy storage—a potentially grid-transforming technology—has grown by leaps and bounds. California’s first-in-the-nation energy storage mandate helped to catalyze nearly 250 percent growth in U.S. energy storage deployments from 2014 to 2015, with eight-fold growth predicted over the next five years.8 Energy storage could play a critical role in enabling utilities to add much greater levels of variable renewable energy resources to the grid.

    ! State policy approaches to address the recent rapid expansion of distributed solar PV have become a toptier concern. All but four U.S. states took some type of solar policy action in 2015. Twenty-seven states considered or enacted changes to net metering policies, which compensate customers for the rooftop solar energy they provide to the grid, while 61 utilities in 30 states requested increases in monthly fixed charges for residential customers.9

    ! Some state utility regulators have begun actively exploring new regulatory models to enable new utility business models. The best known of these, New York’s Reforming the Energy Vision (REV) initiative, has taken a ground-up approach to reinventing the state’s electricity marketplace, with utilities serving as “distribution system platform providers” that increasingly rely on demand-side management, efficiency improvements, and distributed energy resources to meet consumer needs.

    ! While this report benchmarks clean energy performance at the holding company level, it’s important to note that some utility subsidiaries are achieving even higher levels of renewables penetration. Berkshire Hathaway’s MidAmerican Energy, for example, currently gets 41 percent of its generation capacity from wind power (at year-end 2015) and has announced a vision of getting to 100 percent renewables.10

    ! Corporate and consumer demand for clean energy and continually improving economics are driving utility clean energy procurement above and beyond policy requirements. With power purchase agreement (PPA) prices for utility-scale solar PV falling to all-time lows, utilities are beginning to procure larger amounts of solar based simply on its economic merits.11 (Utilities have procured cheap wind power for years.) Surging corporate demand for renewable energy—marked by a nearly three-fold increase in corporate renewable deals between 2014 and 2015—has also urged utilities in this direction

    Company Rankings

    This report compares utility holding companies on three key indicators of clean energy deployment:

    1) Renewable energy sales: The total amount of renewable electricity sold to retail customers during the reporting year, including from owned power plants, power purchase agreements (PPAs), and retired Renewable Energy Certificates (RECs).13

    2) Incremental energy efficiency savings: All reportingyear energy savings from i) new participants in existing programs, and ii) all participants in new programs.

    3) Life Cycle energy efficiency savings: Estimated savings from all energy efficiency programs put in place during the reporting year, including reporting year savings and all future anticipated savings.14

    All three indicators are provided as a percentage of annual retail sales to allow for comparison across utilities of different sizes. This report focuses on the amount of renewable energy delivered from electric utilities to their customers, and does not cover independent power producers. Since states have different approaches to defining and tracking renewable energy, the renewable energy sales findings in this report aren’t intended to reflect utility compliance with state RPS targets. Nevertheless, the renewable energy sales data provided in this report are a useful indicator of the utilities’ clean energy deployment.

    Our analysis finds wide disparities in the extent to which the power providers are utilizing renewable energy and energy efficiency. For example, just four of the 30 companies included in the report accounted for more than half of total renewable energy sales.

    Sempra Energy, PG&E, Edison International and Xcel Energy ranked the highest for renewable energy sales,with renewable resources accounting for more than 20 percent— and, in Sempra’s case, nearly 36 percent—of their retail electricity sales in 2014. SCANA, PPL, American Electric Power and FPL ranked at the bottom, with renewable energy sales accounting for less than two percent of their total retail electricity sales.15

    Eversource Energy, PG&E, Portland General Electric, National Grid and Pinnacle West performed the best on incremental energy efficiency savings. Each achieved annual savings of at least 1.5 percent of their total retail electric sales. In doing so, they are helping their customers save on their energy bills while also helping avoid the need to build costly new power generation capacity. The weakest performers, with minimal or no energy efficiency savings, were Southern Company, Entergy, Dominion Resources and FPL. Similarly, leaders in life-cycle energy savings include most of the same companies, but with Exelon bumping Portland General Electric out of the top five.

    Top-performing utilities on renewable energy and energy efficiency are located almost entirely in states with more ambitious clean energy policy goals such as California, Illinois, Massachusetts, Minnesota, New York, and Oregon, while utilities with poor results are typically in states with weak policies, many of them being in the Southeast.

    Overall, these 30 companies provided more than 136,000 GWH of renewable energy to their retail customers in 2014, and achieved incremental annual energy efficiency savings of more than 19,000 GWh. This represents year-on-year growth of 13 percent for renewable energy sales and 9 percent for energy efficiency savings as compared with 2013.

    Other Key Findings

    ! State policies remain a key driver in utility clean energy deployment. The top-performing utilities on renewable energy sales are typically based in states and regions with more ambitious policy goals, while utilities delivering the lowest amounts of renewable energy to their customers are mostly located in the Southeast, which historically has had weak state-level support for clean energy.16

    ▪ Similarly, all of the top-performing utilities on energy efficiency are located in states with policy support for utility energy efficiency programs, including Arizona, California, Connecticut, Illinois, Massachusetts, Oregon and Rhode Island.

    ▪ Implementation of EPA’s Clean Power Plan would provide further impetus for states to increase utility clean energy deployment.

    ! Two of the Clean Power Plan’s key approaches to compliance—energy efficiency and renewable energy— are increasingly economically feasible options for electric utilities. Energy efficiency is often the lowestcost energy resource, while the cost of renewable energy continues to decline dramatically and is often costcompetitive with fossil fuels.

    ! Renewable energy will represent most new U.S. utility-scale electric capacity additions in both 2015 and 2016,according to EIA—yet another indication that utility clean energy deployment will continue to grow.

    ! Even among utilities in similar market and regulatory environments, however, there is a range of performance, suggesting that strong state-level policies are not the only factor in utility deployment of clean energy.

    ▪ State RPS policies, which have accounted for about 60 percent of the growth in U.S. non-hydro renewables, will likely be less of a driver going forward as costs for renewables continue to fall.18

    ▪ Retrenchment can occur in states despite demonstrated beneficial impacts of clean energy policy. While many states continue to encourage investment in energy efficiency, two states, Indiana and Ohio, froze their respective energy efficiency goals, likely leading to reduced energy savings by affected utilities and reduced bill savings for customers.

    ! Performance in this Benchmarking report is not the only measure of clean energy leadership, which also includes such factors as a utility’s level of support for clean energy policies. For example, National Grid and PG&E have been vocal supporters of energy efficiency, while FirstEnergy has actively criticized and opposed Ohio’s clean energy policies.

    ! Better, more up-to-date data is paramount. Data on utility clean energy deployment remains far too scattered among too many disparate sources. Forming a complete and uniform picture of how utilities compare on energy efficiency and renewable energy is critical, given the importance of carbon-free resources to the industry’s future and to U.S. and global climate change mitigation efforts…

    Data Recommendations

    Energy efficiency and renewable energy, which have grown dramatically in the U.S., will become increasingly important resources for U.S. electric utilities going forward. Forming a complete and uniform picture of how utilities deploy these resources is critical. Following are specific recommendations on how federal and state agencies, utilities, regulators and other stakeholders can improve the quality and availability of utility clean energy data.

    # Better, more up-to-date data is paramount. Data from important sources such as EIA and state RPS reports are not only incomplete but are often dated.

    # EIA, in its annual information request from electric utilities, should create a new Form 861 file focused entirely on renewable energy that is populated, at a minimum, by renewable energy sales and capacity data broken out by holding company and all subsidiaries; by renewable energy type (including distributed assets); and by ownership type (utility-owned, contracted, or customer-owned).

    # As part of this new form, EIA should clarify the definition of renewable energy to include only sources such as wind, solar PV, solar thermal, geothermal, biomass, and small hydro (up to 10 MW), and explicitly exclude problematic energy sources that are considered renewable in some states, such as waste coal, “black liquor,” large hydro (greater than 10 MW) and fuel cells (unless powered by renewable fuels). These two improvements alone would greatly aid data collection and transparency.

    # Additionally, EIA, FERC, or another federal agency should begin tracking distributed and centralized grid intelligence infrastructure such as energy storage and demand response, in addition to tracking smart meter deployment.

    # Federal guidance on state RPS and EERS reporting requirements could ensure comparable, verifiable and timely data about utility clean energy deployment throughout the U.S.

    # The financial community, including investors in the electric utility industry, should use this data to better evaluate the financial, environmental and social performance of electric utility companies. The data in this report should help investors identify how IOUs are adapting to disruptive challenges facing the sector and the extent to which utilities earn revenues from deploying clean energy.

    # Electric utility companies should use this report to compare themselves to their peers, especially companies in similar market and regulatory environments, and to evaluate their positioning and strategies.

    # Policymakers would benefit from determining which clean energy policies have been most effective in driving investment and creating value for customers, utilities, and the wider economy.

    # Consumers can assess how much clean energy their utility has deployed, how the utility is progressing toward state renewable energy and energy efficiency requirements (if applicable), and how well positioned the utility is for a lower-carbon future.

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    QUICK NEWS, June 28: Voters, Including Republicans, Move On Climate; World’s Biggest Wind Turbine; The Landmark New York Solar Price Deal

    Voters, Including Republicans, Move On Climate Republican Voters Evenly Split on Climate Change, Poll Finds

    Jack Fitzpatrick, June 28, 2016 (Morning Consult)

    “Most voters, including about half of Republicans, believe the climate is changing and the federal government should step in to cut greenhouse gases…[In the conservatively oriented poll by Just Win Strategies and TargetPoint Consulting ] 68 percent of all respondents said they want federal government action [on emissions]…Among Republicans, 48 percent supported that statement, and 46 percent opposed it…[T]he vast majority of Democrats (86 percent) and about two-thirds of independents (67 percent) [want action. The poll] also found that only 12 percent of respondents said they were more concerned about environment and climate] than any other issue…[It also] found that despite many Republican officials’ reluctance to directly address climate change, GOP voters don’t uniformly deny that the Earth’s temperature is increasing. Republicans were split evenly at 45 percent…[compared to] 89 percent of Democrats and 72 percent of independents…[A slight majority of Republicans (53 percent) said] they believe they will feel the effects of climate change in their lifetime or already are…90 percent of Democrats and 73 percent of independents [agreed]...” click here for more

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    World’s Biggest Wind Turbine World's biggest wind-power turbine unveiled for giant offshore renewable-energy project; The future for alternative energy takes huge leap forwards with structure capable of powering 10,000 homes.

    James Billington, June 27, 2016 (International Business Times)

    “The world's biggest wind-power turbine…would be one of Earth's biggest man-made structures when fully assembled…[with a 180 meter swept area and capable of powering] 10,000 homes…[Denmark’s LM Wind Power] is readying these giant blades for Adwen's offshore eight-megawatt turbine in France, part of three wind farms that can produce 500-megawatts of energy…[The blades, which increase energy yield 1% per year, are] made from a newly developed material that can withstand harsh off-shore weather…[and conduct lightning strikes safely to ground. The huge] wind-power blades represent a big leap towards lowering the cost of energy offshore, and are also a major move towards [the new energy] future…” click here for more

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    The Landmark New York Solar Price Deal New York utilities and solar companies compromise on price of solar energy sold to utilities

    June 27, 2016 (The Buffalo News)

    “New York’s biggest utilities and some of the nation’s largest solar energy developers, including SolarCity…have formed an unlikely alliance to try to hammer out a mutually acceptable proposal on how much solar power system owners will be paid for the electricity they sell back to the utility…[Utilities now complain] they effectively pay solar customers higher retail prices for power they could purchase from conventional sources at a much lower wholesale price. But solar advocates say the retail price is warranted…The compromise plan would reduce the payments but also place a value on the environmental benefits of solar power and its role in helping utilities avoid having to make costly upgrades to the power grid…If it works, New York would stand out as the rare exception among states that have tackled the highly contentious issue [of net metering…A group of big industrial customers opposes the compromise, arguing it would continue, or possibly expand, subsidies for solar power at the expense of other customers…[An alternative proposal is for a ‘full value tariff’ that] would be structured much like a cellphone bill…” click here for more

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    Monday, June 27, 2016

    TODAY’S STUDY: The Numbers Behind The Diablo Canyon Shutdown

    A Cost Effective and Reliable Zero Carbon Replacement Strategy for Diablo Canyon Power Plant

    James H. Caldwell, V. John White, Liz Anthony, PhD, William Perea Marcus, JBS Energy, Inc, June 2016 (Center for Energy Efficiency and Renewable Technologies)


    With the recent passage of SB 350, California has initiated the next phase in the deep decarbonization of its electric system. The result will be an increase in the renewable content of California’s electricity generation portfolio from 33+% in 2020 to 50+% in 2030 and a concomitant reduction in carbon emissions by some 40-45 MMTCO2 per year -- roughly half of current electric sector emissions. We now face another resource decision with large carbon emission implications – whether to extend the operating licenses for the Diablo Canyon nuclear power plant for twenty years. These licenses expire in 2024 (Unit 1) and 2025 (Unit 2).

    The California Independent System Operator has stated: “The absence of the DCPP (Diablo Canyon) appears not to have negative impact on the reliability of the ISO transmission system with the assumption that there is sufficient deliverable generation within the ISO controlled grid.”1 That is, unlike Southern California Edison’s San Onofre Nuclear Generating Station (“SONGS”) retirement in 2012, DCPP’s location and continued operation is not critical to grid reliability as long as its energy and capacity is replaced. The location and composition of this replacement portfolio is not critical for grid reliability. Given that the process to plan, procure, and construct new generation to replace a retiring DCPP or to complete the license extension process at both the State and Federal level2 takes approximately seven years, the time to formally start the process for dealing with a potential DCPP retirement is at hand.

    This study is intended to inform that process by comparing the cost to complete the license extension process plus the going forward operating, maintenance and incremental capital costs for DCPP operations from 2024 through 2045 (license extension period) to the cost of acquiring and operating a zero carbon replacement generation portfolio. The analysis will rely heavily on data submitted by Pacific Gas & Electric Company for its 2017 General Rate Case,3 and modeling work done for the Low Carbon Grid Study.4 The Low Carbon Grid Study is a peer reviewed comprehensive analysis of the California electric grid in 2030 where DCPP has been retired and replaced with a range of new renewable portfolios that both replace DCPP and meet California policy objectives of a grid that supports long term decarbonization with an interim 2030 target of 50+% RPS and 40+% reduction in carbon emissions below 1990 levels.

    The Grid and Diablo Canyon

    DCPP is easily the largest single generation asset on the California grid and the second largest in the entire West after the Palo Verde nuclear plant in Arizona. Over the past six years, it has provided 2240 MW of net capacity at a 90.0% capacity factor for an annual average energy production of 17,662 GWh/yr.

    A major pillar of reliability requires that the electric grid be capable of withstanding the sudden loss of its largest single producing element without loss of load. This event is called an “N-1 contingency” and Federal, regional and State rules all require that this event be mitigated by holding so called “spinning reserve5” equal to or greater than its 2240 MW capacity any time that DCPP is operating. This quantity of spinning reserve is called the “MSSC” (Maximum System Single Contingency) in the CAISO tariff. Thus DCPP must have “one for one backup” for its energy and capacity at all times and this backup must be dedicated to reserve duty in case of an outage. Thus facilities supplying these spinning reserves are unavailable to perform other useful functions on the grid – such as flexibility to help shape net system load with deep penetrations of wind and solar generation.

    When DCPP was constructed some 30 years ago, PG&E also built the Helms Pumped Storage Plant6 about 50 miles east of Fresno to be the cornerstone of the spinning reserve package for DCPP. Rated at 1212 MW of capacity, Helms is normally “self-scheduled” by PG&E to provide the bulk of the DCPP spin requirement.

    The consequence of not being fully prepared for a trip of large nuclear facilities was graphically demonstrated in what is called the “Great Blackout of 2011”7 -- the largest power failure in California history. When Units 2 and 3 of the San Onofre Nuclear Generating Stations (“SONGS”) tripped off line during a grid disturbance that began in Arizona on the afternoon of September 8, 2011, almost seven million people were left without power for as much as twelve hours. Ensuring grid reliability in the event of loss of so much power in a single location is indeed serious business -- even if DCPP is not the original source of the problem.

    The alternative to using Helms for spinning reserve is to start up and synchronize to the grid, but then leave “idling” some of the otherwise surplus natural gas plants in the state8. However, this alternative has several negative consequences that make using Helms to provide spin for DCPP the better solution. First, similar to an automobile in heavy city traffic vs. highway driving, the efficiency of most natural gas plants at idle or near idle is significantly less than when operated at full load.9 Thus natural gas is wasted and greenhouse gas (GHGs) emissions to maintain grid reliability are increased. Second, during light load hours in the fall, winter and spring, the energy produced at idle by the gas plants supplying spinning reserves for DCPP is not needed to serve load, and their presence crowds out other energy that is cheaper to produce and that emits less GHG – such as wind and/or solar. These zero carbon resources must then be “curtailed” to maintain the system load/resource balance10. Helms, whose replacement cost today is over $2B, was constructed specifically 30 years ago to save these costs.

    Should DCPP retire, the next largest generation asset on the CAISO system is the Delta Energy Center in Pittsburg at 880 MW and the system spinning reserve requirement would then become the larger of 880 MW or 3% of the load on the system at that point in time. Thus, when DCPP retires, the system requirement for spinning reserve will be cut significantly, and at least a portion of Helms would then be available to supply system flexibility without restriction.

    If the DCPP outage is unexpected, or planned for only a short duration, then PG&E would replace the lost energy with so called “system power” from other units somewhere in the West that have spare capacity. This system power, generally speaking, comes from otherwise surplus gas-fired generation with an average carbon emission rate of about 950 lb/MWh. So, if DCPP were to shut down for one year and the energy replaced with system power, CA electric sector carbon emissions would increase by roughly 7.6 million metric tons or about 8% of emissions today and about 38% of projected 2045 electric sector emissions if California meets its longterm carbon reduction goals. When DCPP finally retires, unless and until new carbon-free resources whose energy output equals the energy produced by DCPP are constructed, and those new resources are in addition to whatever resources are constructed for other reasons11 an increase in this system power output will be the result. This was the result when SONGS (which was only slightly smaller than DCPP) unexpectedly but permanently shut down in early 2012. CA electric sector carbon emissions increased by roughly 7 MMTCO2e in 2012 due to the SONGS shutdown.12

    Replacing DCPP energy with only the very best, most efficient natural gas generation is little better. The most efficient natural gas plant operated in the most efficient manner (full load in cool weather at sea level) has a carbon emission rate of, at best, 800 lb/MWh, so the increased carbon emissions are “only” 6.4 million metric tons or 32% of the total long term emissions target.

    Given the high cost of extending the NRC licenses, the high cost of continued operations at DCPP, and the risk of catastrophic failure of an aging plant on a seismically active site, the state of California needs to have a plan for retirement of DCPP. The plan must be to replace DCPP with zero GHG renewable energy and Energy Efficiency, both of which are incremental to existing policy initiatives and programs. As stated above, the time for that plan is now.

    The alternate portfolios

    The purpose of this study is to evaluate the feasibility of a cost-effective, reliable, zero GHG alternative to a license extension at DCPP. This requires a calculation of the cost of continuing to operate DCPP past its current license term vs. the cost of a replacement portfolio of capacity and energy to serve California electric load if and when DCPP retires. In order to do so, it is critical to understand the overall context of utility procurement over the next 10-30 years. There is no question that the dominant policy driver in this timeframe is the need to decarbonize the production of electricity to achieve critical climate policy goals. The decision to retire the plant or extend the DCPP license is an important decision but hardly constitutes the major procurement decision facing California. With the passage of SB 350, California utilities will be procuring 36-40 TWh of new bulk renewables (roughly 2 and one half times DCPP output) between now and 2030 to comply with the 50% Renewable Portfolio Standard (“RPS”). Plus, they will be acquiring all cost effective energy efficiency and accommodating a projected very significant expansion in customer sited and financed “rooftop solar” which does not count towards RPS compliance but clearly is a significant GHG reduction measure…


    At the solar PV penetration levels envisioned in all scenarios of 50% or greater RPS, whether DCPP is operating or not, most studies, including the Low Carbon Grid Study, have found some new bulk storage facilities to be cost effective “mitigation measures.” These facilities operate on a daily cycle of charging during the middle of the day when the sun is shining and discharging in the early evening as the sun sets, shifting the “net load” curve to reduce over-generation and contribute to serving the evening load ramp without combusting natural gas.

    For the purpose of this study, we assumed that this additional bulk storage would come from some fraction of the 5000 MW (six projects total) of new hydro pumped storage facilities under development in California that could be owned by PG&E. No attempt was made to specify which of these projects would/should be constructed. This decision, including provisions for an alternate advanced battery storage option, is best left to a robust competitive procurement process…

    Capacity Value

    Somewhat by chance, all three alternate renewable portfolios have essentially the same capacity value at roughly 1750 MW of system Resource Adequacy (“RA”) value once the portfolios are adjusted for the capacity value of the added bulk storage. This compares favorably with the actual 1250 MW of capacity made available if the 2240 MW of RA capacity value of DCPP reduced by the 990 MW of additional spinning reserve required to operate DCPP. At today’s RA prices of roughly $40/kW-yr,19 this additional capacity is worth some $40M/yr if DCPP is retired. This capacity value was calculated by the existing CPUC protocols for calculating “System RA” adjusted for the likely revisions to wind and solar “Net Qualifying Capacity” based on new modeling that is ongoing in the CPUC Resource Adequacy proceeding.

    Much like the discussion on storage above, this assumption should be revisited once the procurement process has refined the portfolio options more definitively.


    To assess the transmission requirements of the alternate portfolios, we used the results of the Low Carbon Grid Study for the Diverse and High Solar portfolios. These portfolios were deliberately picked to utilize as much existing and previously planned transmission expansion as practical. Only the load ratio share20 of the major new tie line for Wyoming wind needs to be assessed against these portfolios for cost comparison purposes. All other planned transmission expansions, such as the West of Devers and Gates/Gregg projects in California, are designed to reach a 50% RPS whether DCPP continues to operate or not.

    The Valley Solar portfolio is a different story. Constructing 6,500 MW of new solar generation in the Central Valley will clearly require significant new transmission investment even after allocating the transmission now used by DCPP to the new portfolio…


    The strong conclusion from the foregoing analysis is that it is clearly in the interest of California ratepayers to replace DCPP with a renewable portfolio in an orderly transition on a timetable that will enable ratepayers to benefit from the renewable tax credits that may expire in 2020. These renewable resources will be additive to the recently adopted policy of a 50% RPS by 2030. It is also in ratepayer interests to overhaul and expand current energy efficiency programs to bear part of the load caused by retirement of DCPP.

    We can confidently state that on a life cycle basis the investment in renewables and efficiency will, over time, provide consumers with lower cost electricity than DCPP, will be more reliable, and will eliminate the real financial and safety risks inherent in operating nuclear reactors that are 40 to 60 years old.

    Our conclusion is based on our analysis that: (a) the base, conventional wisdom estimate of DCPP license extension period costs at more than $14B is roughly the same as the base, conventional wisdom procurement and operating costs of a robust range of renewable resources and incremental energy efficiency that embody the true meaning of “least cost/best fit.”; (b) there is a near certainty that the base costs for DCPP life extension are low by at least 10% and probably more to cover either unforeseen issues during the license extension period, or conditions attached to the license extension to deal with issues such as seismic retrofits and/or once through cooling mitigation measures; the need to close unit 1 by 2023 due to embrittlement; the need for new steam generators, etc., (c) there is strong evidence to believe that the renewable replacement portfolio can be procured for at least 10% less than the base estimate; (d) that the retirement of DCPP will reduce required spinning reserves and relieve the Helms pumped storage plant, which is worth in excess of $2B, for a higher duty of providing flexibility to the grid to accommodate ever increasing penetrations of zero variable cost, zero carbon emitting renewable resources onto California’s electric grid.

    In addition, the DCPP costs are uncertain and subject to inflation. The renewable alternative costs are largely fixed. They have no fuel costs and little maintenance exposure. They are low risk inflation hedges and they eliminate the awesome enterprise level risks inherent in running nuclear reactors in a seimically active region.

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    QUICK NEWS, June 27: Dems Platform Calls For More Climate Change Science; SolarCity Could Become Tesla; What The Wind Industry Has Built

    Dems Platform Calls For More Climate Change Science Democrats adopt climate change science investigation in platform

    Devin Henry, June 27, 2016 (The Hill)

    “Members of the Democratic National Committee’s platform panel have formally endorsed federal investigations into climate research at fossil fuel companies, including a high-profile probe into Exxon Mobil Corp…The platform didn’t name Exxon, but the company has become the highest-profile target for Democratic attorneys general, who are looking into claims it misled the public about the extent of its knowledge about climate change…Exxon has denied the allegations and fought back against the investigations, calling them an infringement on the company’s First Amendment rights and, as the video below demonstrates, congressional Republicans have so far protected the company]…Despite the climate science amendment — and a call to use 100 percent renewable energy by 2050 — the committee rejected a host of other environmental issues, including a call to ban fracking, end fossil fuel production on federal lands and put a price on carbon pollution…” click here for more

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    SolarCity Could Become Tesla Tesla applies for 6 new trademarks to sell solar energy under the ‘Tesla’ brand

    Fred Lambert, June 26, 2016 (ElekTrek)

    “…[Though the Tesla plan to acquire SolarCity and fold the solar installer’s operations into Tesla’s own business] is still contingent on board approval and shareholder votes at both companies…the automaker is going ahead with trademark applications to sell solar products under its ‘Tesla’ brand…[Tesla] filed 6 new trademark applications [that] range from solar cells and solar modules…[to] the installation and repair of solar panels…[They also cover] the monitoring of solar energy generation and the financing of solar installations…If the Tesla – SolarCity merger goes through, Elon Musk said that he plans to sell both Tesla’s current products and SolarCity’s offering under the same roof and to use the same sales force. Based on these trademark applications, it looks like it could be a possibility that the whole product line could become ‘Tesla’ badged and the ‘SolarCity’ brand would be phased out…” click here for more

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    What The Wind Industry Has Built Wind energy is already an American industry

    Paul Vigeant, June 26, 2016 (South Coast Today)

    “…[The United States] leads the world in land-based wind energy…More than 50,000 turbines stand along ridge lines, prairies and hilltops across the United States. Installed capacity recently surpassed 70 gigawatts — enough to power more than 19 million typical American homes — and is expected to double in the next five years…[Wind] installed more electric generating capacity last year than any other energy source in America…[and] is on track to supply 10 percent of the country’s electricity by 2020, 20 percent by 2030 and 35 percent by 2050…[E]nergy supplied by the wind is as cheap or cheaper per megawatt hour than natural gas. And the cost of wind has shown a steady decline — 66 percent from 2009 to 2014, while volatile natural gas prices have brought consumers painful price spikes…A typical wind turbine has more than 8,000 components, and those pieces are manufactured in 500 plants in 43 U.S. states…The U.S. Department of Labor projects that the fastest growing occupation in the next 20 years will be wind turbine technician, a job that requires training, but no college degree, and paid a median annual salary of $51,050 in May 2015…” click here for more

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    Saturday, June 25, 2016

    Landmark Deal Will Close Last California Nuke Plant

    Based on multiple interviews with key environmentalists, this looks like a solid deal that opens the way for more New Energy and a nuclear-free future. Kudos to Friends of the Earth and David Freeman for this triumph. From Wochit News via YouTube.

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    Say Goodbye To Diablo Canyon

    A short, tuneful Diablo Canyon retrospective. Putting a nuclear plant on an earthquake fault was never a good idea and now it’s simply too expensive. Here’s hoping California stays lucky and avoids the big one for another 9 years. From A4NR via YouTube

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    Say Hello To Solar

    This video is a little long but it effectively shows how viable solar has become in almost every way. From ColdFusion via YouTube

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    Friday, June 24, 2016

    ORIGINAL REPORTING -- A good rate design is hard to find

    A good rate design is hard to find: Experts push utility-solar compromise; Getting rates right will be essential for both utility revenues and the growth of DERs

    Herman K. Trabish, September 21, 2015 (Utility Dive)

    Conventional knowledge is that the utility industry is slow-moving and resistant to change. But when it comes to reforming their rate designs, power companies have been quick to propose changes to make up for revenue lost to rooftop solar and other distributed resources.

    Last November, Brad Klein of the Environmental Law and Policy Center told Utility Dive that utilities across the nation had opened up 23 rate design proceedings across the nation to raise fixed charges or other fees on customers with rooftop solar or other forms of distributed generation (DG). The trend, he said, emerged after the Edison Electric Institute released a widely-circulated white paper in 2013 that recommended “a monthly customer service charge…to recover fixed costs.”

    Now, not even a year on, panelists at the solar industry's biggest annual conference have said that the number of such rate cases has about doubled.

    There are currently 48 to 50 rate cases that propose some kind of new increased residential fixed charge designed to make up for infrastructure costs not being met by existing rates, said Rusty Haynes, a Policy Manager at EQ Research.

    The cases span from Maine to Hawaii, and the proposed fee hikes range from almost nothing to 300%, Haynes told the audience at a rate design panel discussion last week at Solar Power International 2015 (SPI).

    About three-quarters of the proposals would increase fixed charges 25% or more, and seven — including proposals from KCP&L in Missouri, PNM in New Mexico, El Paso Electric in Texas, Westar in Kansas, and Xcel in Wisconsin — would double or more than double the existing residential fixed charge, Haynes said.

    Variations on the fixed charge proposals include efforts to “erode” the benefits of net energy metering (NEM) by imposing new demand charges usually reserved for commercial and industrial customers on residential consumers with rooftop solar or other DG.

    And in some of the rate cases, utilities are asking for both demand and fixed charges, he added.

    While it makes sense for states with high DG penetrations to be concerned about revenue losses compromising their ability to recover infrastructure costs, Haynes pointed out that several of the IOUs reside in places with low DG penetration, such as Westar, El Paso Electric, and Xcel Wisconsin.

    “In Iowa, utilities have signaled they might do the same, despite low DG penetration,” he said. “In Montana, Montana-Dakota Utilities has proposed a higher fixed charge and a demand charge for net metered systems.”

    In states with high DG penetration like California, Nevada, and Arizona, the rate changes are sometimes proposed in separate filings outside rate cases, Haynes added. And several states, notably New York, California, Massachusetts, Rhode Island, Hawaii, and Minnesota, have ongoing “sweeping grid modernization efforts” that include such rate changes.

    Good rate design

    Many of the proceedings in which rate changes are proposed have devolved into divisive and almost mean spirited debates, but a better understanding of rate design might prevent that, said Sustainable Energy Advantage Principal Analyst Jim Kennerly.

    Good rate design does two things, he explained.

    First, it represents the utility service’s value, keeping it affordable for the customer and profitable for the utility. Second, it is equitable so that “reasonable alternatives to service” can enter the marketplace.

    The key to good design is balancing these objectives, Kennerly said. If rates go too far in the direction of volumetric energy charges — charging customers based on energy usage — utilities might not recover enough of their costs when distributed energy resources (DERs) reach high penetrations on their systems.

    But if rates go too far in the direction of fixed charges — not dependent on usage — it could minimize diminish the impact of volumetric charges that give customers the incentive to conserve and to consider alternatives to service like solar and other DERs.

    If that happens, “the system might end up with less DERs than is optimal for society and for the grid,” Kennerly said.

    Arizona Public Service Regulation and Compliance Director Greg Bernosky agreed.

    “A fixed charge is a blunt instrument,” Bernosky said. "Rate design done well sends a price signal and can achieve the same outcome as a fixed charge, which is the recovery of fixed costs. If you can transition to something that has the price signal embedded in the rate, you don’t need to have a fixed charge.”

    The debate has become polarized because of sharply opposing beliefs held by utilities and by the solar industry and their advocates, Kennerly said.

    “Utilities believe solar creates costs and shifts those costs to customers who do not have solar,” he explained. Solar advocates believe retail rate remuneration through NEM is a fair way to convey value and “may even undercompensate solar owners for the benefits the electricity their systems sends to the grid.”

    Much of the contention could be attributed to the fact that this type of rate design discussion is new for many utilities, said Solar Electric Power Association (SEPA) Senior Director John Sterling

    Utilities have been filing rate cases since the 1960s and 1970s, Sterling said, “but this is the first time the conversation is changing because of what the load is doing."

    "Before, the grid operator would ask large loads to drop off when a peak threatened," he said, "But now, we have the load dropping and sending something else onto the grid. It is a very different discussion for a very old industry to try and understand.”

    Why good rate design is needed

    There are four reasons this standoff between stakeholders must be resolved before it worsens, Kennerly asserted.

    First, utility systems will be adding significantly more renewables and DERs in response to the Clean Power Plan’s Clean Energy Incentive Program, which allows the banking of renewable energy credits toward CPP compliance.

    Second, the decline of current renewables incentives, including wind’s federal production tax credit, solar’s federal investment tax credit, and many utility and state programs, means accurately valuing these alternatives to service will be “absolutely crucial” to getting financed and continuing to grow profitably.

    Third, new DERs such as storage and intelligent energy management systems are able to combine with DG to create "demand flexibility." As described in a recent Rocky Mountain Institute (RMI) paper, demand flexibility refers to the interconnection of emerging home energy technologies like rooftop solar, home energy storage and smart thermostats to allow customers to shape their energy use in response to variable rates and demand charges, Kennerly said.

    Customers’ use of demand flexibility has the potential to both significantly reduce utility load and drive down DER soft costs, Kennerly said, and “rate design needs to not get in the way of soft cost reduction."

    “Customers are smarter than we give them credit for,” Sterling said. “If we give them the information and education they need, people are ready and willing to figure out things like demand charges and time of use rates.”

    See Also: Rate design roundup: demand charges vs. time-based rates

    Finally, the standoff must be resolved because the value of solar and DERs change as penetrations increase, and the system gets less benefit from incremental additions.

    “There is less peak demand value in solar when there is more solar on the grid because each individual unit of solar has less impact,” Kennerly explained. “Rate design must take that into account.”

    Bernosky said that "getting myopic on one type of customer, like a solar customer, is not useful."

    “We think about lifestyle rates, not technology specific rates. A lower use customer rate, a seasonal customer rate, an active energy manager customer rate, those are reasonable bands within which to structure rates.”

    Getting to good rate design

    A resolution between stakeholders must begin with shifting the focus of rate design from the cost of service to the value of that service, Kennerly said.

    “The fully-loaded valuation of DER benefits and costs gets close to what should be the economically optimal penetration and what is likely the greatest amount of penetration,” he said.

    To get to this refocusing from cost of service to value of service, Kennerly recommended remembering two maxims.

    First, stakeholders should focus on interest and not position.

    “Utilities should not focus on opposition to NEM, but on their concern about fixed cost recovery," Kennerly said. "Solar advocates should express a concern for solar’s true value.”

    Second, he said, stakeholders should remember what Mick Jagger said.

    “You can’t always get what you want, but if you try, sometimes you just might find you get what you need.”

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