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.


  • ORIGINAL REPORTING -- A good rate design is hard to find
  • ORIGINAL REPORTING -- Growing Pains For Community Solar

  • ORIGINAL REPORTING – VP Joe Biden Talks Solar
  • ORIGINAL REPORTING -- Solar as utility partner and good citizen of the grid

  • ORIGINAL REPORTING: Energy Storage In California Debated
  • ORIGINAL REPORTING: A Public Utility For Hawaii?

  • ORIGINAL REPORTING -- Beyond batteries; The Many Ways To Store Energy
  • ORIGINAL REPORTING -- Solar Vows Fight For A Level Playing Field

  • TODAY’S STUDY: What EVs Can Do For The Grid
  • QUICK NEWS, June 20: Welcome To The Heat Dome; The Crucial Concept Of Storing Solar; Pacific Ocean Windpower Coming On

  • Weekend Video: World New Energy Booms
  • Weekend Video: The Great Deal That Is Wind Power
  • Weekend Video: Climate Denial – Sign Of Civilization’s Decline?
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    Anne B. Butterfield of Daily Camera and Huffington Post, f is an occasional contributor to NewEnergyNews


    Some of Anne's contributions:

  • Another Tipping Point: US Coal Supply Decline So Real Even West Virginia Concurs (REPORT), November 26, 2013
  • SOLAR FOR ME BUT NOT FOR THEE ~ Xcel's Push to Undermine Rooftop Solar, September 20, 2013
  • NEW BILLS AND NEW BIRDS in Colorado's recent session, May 20, 2013
  • Lies, damned lies and politicians (October 8, 2012)
  • Colorado's Elegant Solution to Fracking (April 23, 2012)
  • Shale Gas: From Geologic Bubble to Economic Bubble (March 15, 2012)
  • Taken for granted no more (February 5, 2012)
  • The Republican clown car circus (January 6, 2012)
  • Twenty-Somethings of Colorado With Skin in the Game (November 22, 2011)
  • Occupy, Xcel, and the Mother of All Cliffs (October 31, 2011)
  • Boulder Can Own Its Power With Distributed Generation (June 7, 2011)
  • The Plunging Cost of Renewables and Boulder's Energy Future (April 19, 2011)
  • Paddling Down the River Denial (January 12, 2011)
  • The Fox (News) That Jumped the Shark (December 16, 2010)
  • Click here for an archive of Butterfield columns


    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.

  • ---------------
  • 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 along the San Andreas fault. 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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    ORIGINAL REPORTING -- Growing Pains For Community Solar

    Negative RECs for community solar: Market failure or utility opportunity?; Xcel and Colorado installers are at odds over how much utilities should pay for RECs

    Herman K. Trabish, September 23, 2015 (Utility Dive)

    Editor's note: Community solar developers continue to struggle to get regulators to understand their unique concerns.

    Solar advocates say the Colorado Public Utilities Commission opened the door to a significant market failure when it declined to reconsider a decision allowing Xcel Energy to accept negative Renewable Energy Credits (REC) bids for community solar projects.

    In states like Colorado with a renewable energy mandate, utilities are required to accumulate a certain number of RECs each year from developers when they contract for mandated renewables generation. The credits normally add a small premium to the price paid by utilities, creating an added incentive for developers.

    For the first time this summer, Xcel began accepting bids for negative REC prices for community solar arrays in a recent Request for Proposals (RFP). Installers, who say the negative RECs are illegal and are driving a “race to the bottom” in shared solar, filed a complaint with regulators.

    But the Colorado Public Utilities Commission (CPUC) saw nothing wrong with negative RECs on their face. In response to the complaint from the Colorado Solar Energy Industries Association (CoSEIA), the CPUC agreed with Xcel that its RFP that included the negative RECS “does not violate any statute or Commission rule.”

    The commission, however, did not comment on whether negative RECs fit into the intent of the state’s community solar law, opening up further debate between Xcel and the installers.

    The ruling allowed the utility to use its market leverage to drive bids down in pursuit of the best deal for its entire customer base, but developers say the negative RECs limit their ability to serve the full range of potential community solar customers.

    How negative RECs came about

    In 2013, bidding on community solar projects took REC prices to $0.00. That pushed SunShare SunShare CEO David Amster-Olszewski to first raise the question in 2014 of whether regulators should exercise authority over the competitive bidding process and establish a REC floor price. That, he and other solar advocates argued, could help prevent a utility from taking advantage of its natural monopoly to drive down prices.

    The commission declined to act on the question, based on proceeding technicalities. It has subsequently stood by its decision in response to more recent filings from CoSEIA and Western Resource Advocates requesting reconsideration.

    Xcel is compelled by a 2014 Colorado PUC order to construct between 6.5 MW and 30 MW of community solar. When the commission declined to clarify whether it was in keeping with the mandate’s intent for Xcel to let REC prices go negative, the utility naturally seized that opportunity to take the lowest possible bids.

    In response to its most recent RFP, Xcel accepted bids for 29.5 MW in Colorado projects from SunShare, CEC, and Community Energy Solar, thereby meeting almost the maximum amount of mandated community solar.

    The REC policy debate

    Bound by non-disclosure agreements, the utility and the developers cannot specify what REC prices were accepted. Xcel confirmed to Utility Dive that it did, in fact, accept negative REC offers in the bidding.

    Solar installers say the negative RECs do more than cut into their revenues — they make customers pay more.

    “The bids are not for the power price. That is set by pre-established tariffs,” explained SunShare CEO David Amster-Olszewski. “When the REC price is positive, the utility pays the customer, but when the REC price becomes negative, the customer pays the utility for the utility to meet its mandate.”

    Xcel says that lower REC costs mean just the opposite — that they save customers money and allow the utility to invest elsewhere.

    “The acquisition of the REC, for the purposes of meeting the Colorado Renewable Energy Standard, is recovered from all customers through the Renewable Energy Standard Adjustment,” Xcel Rates and Regulatory Affairs VP Alice Jackson said. “The lower cost of the REC from developers benefits our customers directly and allows for those dollars to potentially be spent on other renewable projects.”

    In a reply to the Colorado SEIA filing, Xcel argued that “bidders are free to bid whatever prices they wish.”

    “[I]f your members believe that a negative bid price is too low,” it wrote in its filing, taking aim at the solar industry group, “they do not need to offer such a price.”

    “We will continue to offer a market for vendors to bid to build projects to provide our customers with an additional solar choice,” Jackson said. “The price at which those vendors elect to bid is entirely at their discretion.”

    Solar installers say they will push forward with new bids and attempt to continue the debate over RECs.

    “While this makes the 2015 RFP process more difficult, we expect there will be the opportunity to discuss this further with Xcel and the other stakeholders.” said Tom Hunt, VP of corporate development for Clean Energy Collective, a community solar developer.

    Implications of negative RECs

    The hopes of those who see community arrays increasing solar access for low and middle income residential utility customers without solar-suitable roofs could be stymied if negative REC bidding continues and/or spreads to other states.

    Negative REC pricing, SunShare’s Karen Gados told Utility Dive, would likely drive her company and other community solar developers to focus their customer acquisition on the commercial and industrial rate class and bypass lower and middle income residential customers.

    Clean Energy Collective's Hunt agreed.

    “We share the concern that negative RECs are not good for the market because they distort mechanisms put in place to get low and middle income residential customers involved."

    While Colorado wrestles with its negative REC issues, community solar is taking off across the nation.

    A recently released National Renewable Energy Labs study reported that at least 49% of U.S. households and 48% of businesses do not have solar-suitable rooftops.

    “By opening the market to these customers, shared solar could represent 32%–49% of the distributed PV market in 2020,” NREL wrote, “thereby leading to growing cumulative PV deployment growth in 2015–2020 of 5.5–11.0 GW, and representing $8.2–$16.3 billion of cumulative investment.”

    The U.S. community shared solar market will add 115 MW in 2015, a roughly 500% year-on-year increase in growth over the 21 MW added in 2014, and almost twice the 66 MW cumulative installed capacity at the end of last year, according GTM Research’s "Community Solar Outlook 2015-2020."

    GTM Research forecasts 59% annual growth for community solar over the next five years to reach an annual capacity addition of 500 MW and a cumulative installed capacity of 1,800 MW in 2020. Some 29 developers are now working in community shared solar development, with sector leaders Clean Energy Collective (CEC) and SunShare accounting for 32% of the capacity now online.

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    Thursday, June 23, 2016

    ORIGINAL REPORTING – VP Joe Biden Talks Solar

    Joe Biden at SPI: 'We are on the cusp of something huge'; Biden's keynote speech extols the renewables sector and gears for the upcoming fight for the ITC

    Herman K. Trabish, September 17, 2015 (Utility Dive)

    Vice President Joe Biden extolled the future of renewable energy and took aim at intransigent utilities and climate change deniers yesterday when he addressed the Solar Power International (SPI) conference in Anaheim, California.

    “We are on the cusp of something huge,” Biden told an audience of 4,000 at the conference considered the solar industry’s most important deal-making and innovation-unveiling conclave.

    The most recent U.S. Solar Market Insight Report forecasts a boom through the end of 2016, a slowdown from 2017 to 2019, and then further expansion afterwards. The Department of Energy’s Wind Vision broadly envisions a similar pattern for wind power.

    “If we stay at it, we can make it faster and more affordable for Americans to choose cleaner and more affordable energy,” Biden said.

    Before addressing those who oppose the extension of solar’s vital 30% federal investment tax credit (ITC), Biden ticked off some of the more impressive numbers the renewables industries have posted under the current administration.

    "Since President Obama and I took office — and put wind’s production tax credit in place from 2009 through 2012 and solar’s ITC in place from 2008 through 2016 — solar power has increased 20-fold, grown jobs 86% to 174,000, and is expected to get to 210,000 jobs by the end of 2015," Biden said.

    The solar industry also now employs more veterans than any other part of the economy and plans to employ 50,000 vets by 2020, the Vice President added.

    “That is helping us meet the sacred obligation of caring for those who have fought for us.”

    With $90 billion invested into renewable energy since 2008, solar installationshave increased almost 50% per year, from 20,000 in 2009 to a forecast 1 million in 2016. And there will be solar to power 4.6 million homes by the end of 2015.

    Wind power has tripled its installed capacity and now can power 16 million homes, Biden said. Wind now provides over 73,000 jobs — more than the coal industry — and could provide over 600,000 “good, decent-paying jobs that a person can raise a family on” by mid-century.

    The almost $20 billion U.S. renewables market is making renewable energy cost competitive with conventional generation, he added. The cost of solar fell by roughly 50% since 2010 from $0.151 per kWh in 2009 to an all-time low of approximately $0.037 per kWh this year.

    “It was incredibly impressive to me that a senior official could speak about solar in such detail,” said Raymond Hudson, director of the highly-respected energy consultancy DNV GL.

    “He was right about the price of solar and that it is on the verge of parity with coal and other traditional forms of electricity generation,” Hudson said.

    The grid: Two-way flow

    Hudson was also impressed by Biden’s ability to talk about the nationwide benefit that could come from enhancing the transmission and distribution system in support of renewables.

    “Earlier this year, the Department of Energy (DOE) and the White House released a roadmap to make our entire energy infrastructure more reliable, resilient, safer, and more secure,” Biden said.“Our recommendation is to ensure the system can carry solar and wind energy from where they are produced to where they are used. The demand is there."

    Solar has provided 40% of all the new U.S. electricity generation capacity in 2015, Biden added.

    “One million workers now take care of our transmission and distribution infrastructure. If we make the right investments, we can support another 1.5 million jobs. The technology is there.”

    Biden's presence at the conference highlighted the increasing importance of solar to the nation's fuel mix and economy, officials told Utility Dive.

    “This is the first sitting executive to ever speak at a solar conference," said DOE Solar Energy Technologies Office Director Minh Le. "It shows that solar is here now and having an important positive impact, not just on pollution but also on economic growth and job creation across the economy."

    What Biden was describing is the democratization of electricity, Le said. It's the first significant change in electricity delivery since Thomas Edison created the one-way flow of centralized power generation at his Pearl Street Station in 1882.

    “With the two-way flow now possible, consumers have choice and they are forcing change on the utility sector,” Le said.

    Challenges: 'The Koch brothers — fine guys as I understand it'

    An energy transition “is within our reach – but there are challenges,” Biden said. “The private sector can only thrive with certainty in the investor environment and with free and fair competition.”

    But utilities and utility associates are on the defensive. Biden used the net metering arguments taking place nationwide as an example.

    “If I told you ten years ago there would be a debate about whether consumers have too much freedom to choose how much and what type of energy they generate, I doubt you would think that would happen," he said. "It is happening. Deep-pocketed special interests that have lobbied for years for fossil fuels are now saying ‘Let’s take away consumer choice. Let’s stifle the market.’”

    He named the special interests blocking extension of the ITC and fighting solar on other policy issues.

    “The Koch brothers — fine guys as I understand it — and groups like theAmerican Legislative Exchange Council, have successfully argued for limits on the amount of net metered systems, like in Wisconsin. They are pushing back against change at every level, trying to alter how the market functions.”

    While these fossil fuel-funded special interests contest allocating critical incentives like the ITC to renewables, they defend over $5 billion in tax credits to the oil industry, Biden asserted.

    “At one point, that arguably made sense ... but is anybody having a problem getting oil out of the ground today?”

    Just half that unnecessary tax benefit would cover what renewables need, Biden said, and "there would be $2.5 billion left to reduce the deficit and invest in things people need.”

    Even so, Biden acknowledged twice throughout his speech those hardest-hit by the coal industry's demise, and described a "moral obligation" to take care of the coal miners. There will be winners and losers in the energy transition, the Vice President said in his short speech.

    "We have to take care of the hardworking losers in industries like coal miningthat aren’t going to thrive," he said. “That is a moral obligation. But that is not a reason to continue a policy so damaging to our environment.”

    Yet climate change deniers continue to throw up roadblocks to constrain the administration’s ability to act. “If you push them, they would probably deny gravity,” Biden joked.

    One such limitation, Biden said, is the budget that the Republicans recently passed, which slashed funding for the renewable energy and energy efficiency office of the Energy Department by 40%.

    “They also doubled down on policies that devastate scientific research and development budgets. What are we doing?” he asked. “We are getting in our own way. Get out of the way.”

    Let the will of the people and of the market prevail, Biden added.

    “The idea that we won’t do everything to grow the renewables so critical to the future of this country is absolutely absurd," he said. "Our grandchildren will look back and ask what we were debating about. The stakes are too high for shortsighted politics and short term decisions.”

    The Clean Power Plan's moral obligation

    Biden described the intent of the administration’s Clean Power Plan. Beyond limiting pollution from power plants, Biden said the plan “builds our communities’ resilience to climate change by investing in more resilient roads, bridges, water systems, and buildings that can withstand future wildfires, floods, and superstorms.”

    The administration also targeted another doubling of renewable energy capacity by 2020, underscored that commitment with the announcement of a new $102 million grant fund for renewables coinciding with Biden’s speech.

    “That is how we have always grown the economy,” Biden said. “If we step up and capture this energy transformation, we will create a virtuous cycle of good paying jobs and attract companies to our shores.”

    Even those who resist investing in renewables will benefit from a cleaner environment and a stronger economy. It is no longer wise to think in any other way, Biden warned. Major companies have begun pricing the cost of carbon into their business decisions. Google prices it at $30 per metric ton and Disney puts it at $10 to $20 per metric ton.

    “I wouldn’t go long on investments that lead to carbon pollution," Biden said, "and I would bet on clean energy.”

    When he introduced Congress’s first climate change legislation in 1986, Biden promised that reality has “a way of intruding” and that is what today’s extreme heat waves, superstorms and droughts are.

    “If we are lucky and work hard, we might freeze things as they are now, but we have a long way to go," the Vice President said. "If we move now, we can cauterize this wound, but we have to move fast.”

    America’s biggest assets

    The U.S. has assets that will support its race toward confronting climate change with renewable energy, Biden said.

    The first is the consensus among the American people to invest in renewables, “notwithstanding the minority that has been able to stop action so far.”

    The second is the most advanced scientific and technological skill set in the world.

    “We know how to ‘think different,’” he said, quoting Steve Jobs’ advice for success. “American children don’t get criticized for challenging orthodoxy. It is stamped into our DNA.”

    The third is an economic system that accommodates change quickly and “the most agile venture capitalists in the world,” Mr. Biden said.

    Finally, there is the ability to solve consequential problems.

    "I recently gave Chinese leaders a one word definition of this country, he said. “Possibilities.”

    Biden believes that word underscores the American people's philosophy.

    “We explore, we invent, we build, we break down barriers. We never stop. If there is any group of Americans that I don’t have to explain this to, it is you in the solar industry. So thank you. And keep it going.”

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    ORIGINAL REPORTING -- Solar as utility partner and good citizen of the grid

    SunPower: Keys to solar success are utility partners, being a 'good citizen of the grid'; One of solar’s key companies touts company growth, partnerships with utilities

    Herman K. Trabish, September 17, 2015 (Utility Dive)

    Editor’s note: Solar’s role as a grid partner has emerged as key to the industry’s future.

    The president of one the solar industry’s most important companies believes partnering with utilities is critical to solar success.

    SunPower is one of a handful of vertically integrated U.S. solar industry giants, alongside SolarCity, Sunrun, and SunEdison.

    “I am really excited about the positive things that are happening with utilities,” SunPower's Business Units President Howard Wenger told Utility Dive in an exclusive interview during the Solar Power International (SPI) 2015.

    “We have always regarded utilities as our partners and the grid as important."Wenger said. "Utilities are entitled to fair compensation for delivering a reliable network. That is in everyone’s best interest.”

    The question of solar energy’s impacts on the grid was a common theme throughout the industry's most important annual conference.

    Solar now supplies about 1% of U.S. electricity, but as growth eventually takes it to 20% grid penetration, solar power producers must learn to be good citizens of the grid, Clean Power Finance President and CEO Nat Kreamer said during the SPI opening session.

    “We cannot grow solar without maintaining reliability and safety.”

    Because utilities are starting to partner with distributed energy resources providers, solar companies are beginning to understand “what it means to be good citizens of the grid,” said Solar Electric Power Association (SEPA) President and CEO Julia Hamm said later in that session.

    Wenger said his company's already got that covered.

    “Being a good citizen of the grid is part of SunPower’s DNA,” he said.

    Wenger has worked in solar since 1984. In 1989, convinced that “the only way PV could happen in a big way was through utilities because they have all the customers," he went to work for PG&E, one of the largest power companies in the country. When deregulation ended the California utilities’ engagement with generation, Wenger returned to the private sector.

    Now, many of the top utilities across the country have re-engaged “and want to figure out how to make this work,” he said.

    “Even the Edison Electric Institute seems to be embracing solar in models like community solar that can work for utilities,” he said.

    SunPower’s big solar

    Sunpower just brought the last sections of the 747 MW Solar Star photovoltaic projects online for Berkshire Hathaway Energy (BHE) Renewables. Covering seven square miles of two Southern California counties, the project came in four months ahead of schedule with SunPower as lead engineering, procurement, and construction contractor.

    Despite the project's apparent successes, Wenger was reluctant to elaborate on details.

    “I spoke earlier today with new BHE Renewables CEO Rick Weech and we remain engaged with them, but we have no announcement to make at this time,” Wenger said.

    Utilities are generally interested in owning assets, and it is logical for them to start with large-scale, central station renewables because that is what they are familiar with, he said. Companies like BHE Renewables are growing comfortable with solar as an investment, building confidence over obtaining promised returns.

    SunPower’s lack of community solar plans

    SunPower lacks specific new plans in community shared solar, Wenger said.

    “There are many community solar market models being developed and understanding how they work is important,” he said.

    So far, the amount of talk circling around community solar is inversely proportional to its share of the actual installed U.S. capacity, which remains quite small. Though it will grow rapidly over the next five years, it will likely remain a tiny part of the total U.S. installed solar capacity in 2020, according to Wenger.

    Even so, community solar remains significant for two reasons. First, it hasgrabbed the attention of utilities and the solar industry.

    The SEPA membership is half solar industry and half utilities, according to Hamm, and community solar "is the number one thing both sides are asking us about."

    Second, Wenger said, “more than half of the people in the U.S. can’t get solar any other way. That is exciting. But it is early days.”

    A key tenet of SunPower’s marketing strategy is to simplify solar for consumers, Wenger said.

    “Community solar can be simple, but underneath there is a complex arrangement between the utility and the developer and the customers.”

    Community solar appears complex and seemingly touches every functional area of a utility’s business, Hamm said. But when they see there are tools and existing models, they realize they can implement it.

    While they don't have community solar in their pipeline yet, Wenger says they aren't counting it out.

    “SunPower is spending considerable time and effort on it,” Wenger said, “but the here and now is that it is a business development activity for us.”

    SunPower’s midsize solar business flourishing

    Recent numbers in the Q2 2015 U.S. Solar Market Insight Report from GTM Research and the Solar Energy Industries Association show the mid-size commercial and industrial (C&I) segment of the solar industry underperforming.

    “There are still a lot more questions than answers in non-residential solar,” Senior Solar Markets Analyst and report lead author Cory Honeyman recently told Utility Dive. In Q2 2015, non-residential PV was down 20% from Q1 and down 33% from 2014’s Q2. Installation dropped below 200 MW, the least activity in since 2011.

    Wenger said forecasts he has seen suggest C&I, including the public sector that counts schools and government buildings, might become the fastest growing segment of solar. He cited a 50 MW contract that SunPower recently gained from Southern California Edison, and an almost 70 MW contract it obtained with Stanford University as examples of the segment’s potential.

    “For SunPower, institutions want solar and we expect that market segment to keep growing,” he said.

    Distributed solar

    SunPower, like others in the residential rooftop business, is seeing a burst of distributed solar activity. Installation of residential photovoltaic (PV) solar in Q2 2015 was up 6% over the previous quarter and up 70% over the 2014’s Q2, according the Solar Market Insight report.

    “Uilities are deciding what to do about it,” Wenger said. “They can fight it, or they can make a business out of it. Those trying to make a business out of it, and enablers of solar far outweigh the number of resistors.”

    SunPower can work those utilities at being a good citizen of the grid in several ways, Wenger said. The collaboration with SCE demonstrated its ability to partner on identifying and delivering location optimal solar to help the utility cut distribution costs and increase reliability when an adequatelydetailed feeder system analysis is available.

    “The next step is creating a market signal,” he said. Utilities and regulators could develop a market-based program with incentives — perhaps a rebate or a bill credit — that would reward solar developers for taking solar to system locations that maximize distribution system infrastructure investment deferral.

    “The incentive wouldn’t exceed the benefit to the utility,” Wenger said, “but the benefit could exceed any lost revenue from the addition of distributed generation enough to justify the incentive expenditure. And the customers would benefit by getting a preferential return for their solar.”

    SunPower has teamed up with SunVerge and Stem on solar plus storage systems to provide the same kind of infrastructure investment deferrals for distribution system operators. It is also adding smart inverters and micro-inverters to its residential installations to enable remotely provided distribution system voltage support tailored to the utility specifications.

    “SunPower is looking to enhance the grid, not bypass it,” Wenger said. “The grid of the future will have a high degree of hardware and software connectivity and SunPower is well on our way to being the provider of a complete, integrated solution that has very sophisticated hardware and best-in-class software.”

    SunPower also believes policy should value “a healthy, reliable, stable grid and insure fair treatment for utilities and solar providers,” he added.

    Both sides in the net metering debate need a “durable solution” that doesn’t have to be renegotiated every year, he explained.

    Retail rate remuneration for solar generated electricity sent to the grid “is a policy that has worked beautifully since it was put in place in California in 1994,” Wenger said. “It has created thousands of jobs and put thousands of megawatts of clean reliable electricity on the grid.”

    He likes net metering because it is a simple construct and easy for the consumer to understand but acknowledged that it was only an approximation of the real value of solar in 1994.

    Wenger also acknowledged the unresolved debate between utilities that say the wholesale rate for electricity is closer to the real value of solar and advocates who argue distributed solar’s value to the grid far exceeds the retail rate. He referenced extensive research that concluded the value is 2 to 3 times the wholesale rate.

    “Solar is at a very low penetration on most grids,” Wenger asserted. “As penetrations increase, these questions become more relevant. But for now a minimum monthly bill will keep it simple while making sure we cover the utility’s costs. That is common ground.”

    Where solar is under-penetrated, net metering is the right vehicle because it is an effective policy, it is easy to understand, and easy to administer.

    “It has created a new technology market in California and in markets that are under-penetrated, it can still do that,” he said.“In places where penetration is high, like California and Hawaii, it is time to go to the next step, from rough justice to justice.”

    What to tell a utility executive

    “You can do it all — big power and distributed power,” Wenger said when asked what advice he'd give a utility executive.

    “I would begin by saying this technology is undeniable," he said. "I would show him a solar cell and how light goes in and electricity goes out. There are no moving parts and it requires no water and creates no pollution.”

    Costs have come down by a factor of 10 over 15 years, Wenger added, with the industry now shipping 50-plus GW per year. The next step is listening to consumers.

    “Figure out how to deliver this value to them because they want it.," Wenger said. "You want to serve your customers. Let us help you do that.”

    SunPower can help develop either of the types of rooftop programs it is presently working on with Dominion Virginia and ConEd Solutions.

    “There are ways on the regulated and unregulated sides to play in DG and in solar power plants. There are new business models. Solar can be done in a way that is thoughtful and benefits the utility and protects it and its assets.”

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    Wednesday, June 22, 2016

    ORIGINAL REPORTING: Energy Storage In California Debated

    CPUC pushed to study solar-storage further after filing pegs value at $0.25/kWh; California is at risk of improperly valuing storage unless it opens a separate regulatory track on its value, an industry group says

    Herman K. Trabish, September 15, 2015 (Utility Dive)

    The California Energy Storage Alliance (CESA) wants state regulators to do something that apparently has never been done before in the state: A cost-benefit analysis of solar paired with energy storage. A CESA filing asks California's commissioners to open a new track in their landmark proceedings on how to define, value, and incorporate distributed energy resources. The track would be aimed at expanding on a first draft calculation done by CESA on the value of solar-plus-storage systems to the grid.

    The VOS+S estimate finds storage adds significantly to the value of solar.

    Using the Public Tool provided to help stakeholders in the state's grid modernization docket establish a new rate and remuneration mechanism for solar, CESA “generated a sizable benefit stack of $0.25 per kWh in levelized value when PV solar is combined with three hours of energy storage,” it reports in its filing with the California Public Utilities Commission (CPUC).

    That calculation likely underestimates the actual value of solar and storage systems, CESA explained in the filing, because the tool “undervalues energy storage in a variety of ways."

    To include storage in the calculation, CESA changed only two assumptions made by the Public Tool. It upped the state’s assumed renewables mandate to 50% by 2030 — which state regulators passed into law last week — and gave increased value to distributed solar-plus-storage because it can be located in utilities’ distribution systems where it is of most value.

    The significance in such a storage valuation scheme is that it helps utilities and regulators determine how much owners of such facilities should be paid for energy and services they offer the grid.

    “The calculation of $0.25 as the value of solar-plus-storage means something like that could be justified as the amount customers who install solar-plus-storage should be reimbursed at,” explained Strategen Consulting Manager Edward Burgess.

    Strategen is consultant to CESA in the CPUC Net Energy Metering (NEM) 2.0 proceedings organized to develop standard tariffs and fees for customers with distributed generation by the end of the year. The proceeding was mandated by AB 327, which became law in 2013 and mandated rate and solar remuneration reform.

    This replacement for retail rate net metering “could be any type of redefinition or redesign of the compensation mechanism that enables DER technology growth,” Burgess said.

    The outcome of CESA's limited assessment of solar-plus-storage made with the CPUC-approved Public Tool “is so compelling, the commission should consider a separate track on how to capture those benefits for ratepayers,” Burgess added.

    “These calculations show the value to the system in general is at least $0.25 per kWh and this is just a rough first effort to quantify the value of solar-plus-storage,” he said.

    “This first attempt at a value of solar-plus-storage is not comprehensive, partially because the CPUC’s tool is limited, but it suggests what would happen if storage is added to the mix,” said Ted Ko, policy director for storage provider Stem. “This new policy world must develop policies and tariffs that recognize the full value not just of individual silo’d resources but of integrated combinations of technologies.”

    A solar-plus-storage track?

    From the implementation of the very first net metering programs to drive solar growth, retail rate remuneration to system owners was only a rough approximation of the value of the electricity they send to the grid, many grid experts say. Only in the last few years have efforts begun to more precisely quantify the complete costs and benefits.

    The NEM 2.0 proceeding in California, and others like it across the country, were initiated to arrive at a more comprehensive and specific remuneration. Now, CESA’s filing says, it is time to do the same for solar-plus-storage.

    Karl Rabago, director of the Pace Energy and Climate Center and a former Texas utility regulator, agrees.

    “Capturing and fairly compensating the value of storage adds a new level of complexity and opportunity to valuing the increased deployment of distributed energy resources,” Rabago, who helped devise the nation's first value of solar tariff as an Austin Energy executive, said. “But rough justice is not enough anymore.”

    CESA’s filing recognizes the engagement of the Investor-Owned Utilities (IOUs) in the multiple AB 327 proceedings but it is concerned the power companies didn't give enough thought to the value of storage.

    “There is little mention in the [utility] Proposals regarding cost-effective energy storage paired with PV solar, even though AB 327 requires it," CESA wrote.

    The IOUs’ distributed resource plans, filed in a parallel CPUC proceeding also aimed at meeting AB 327 mandates, include significant uses of DERs with storage, Burgess said.

    “There are a lot of things in the utilities’ proposals that are moving away from silo’d thinking and toward the true value of DERs,” agreed Stem's Ko. “There are some good elements, some of the same ideas being supported by environmental and DG advocates.”

    But, the CESA filing points out, the IOUs and others in the NEM 2.0 proceeding seem to “underestimate the benefit potential and growth trajectory of energy storage,” and therefore fail to think about enabling rate structures. CESA wants the new proceeding to study the significant opportunities that solar-plus-storage offers utilities — opportunities it says have been so far ignored.

    The storage association “recommends the Commission establish a forum to understand the hurdles and opportunities presented by PV solar-plus-energy storage, including potential tariffs to unlock their combined value.”

    The group's calculation, Burgess said, finds “a value proposition so compelling [that] we should be spending time trying to find ways to drive its growth.”

    Going forward, CESA will do a more detailed cost-benefit analysis of combined storage and solar systems, and will likely propose a pricing structure and/or a reimbursement mechanism to help capture this additional value. Other stakeholders such as the IOUs and the solar companies would likely also weigh in. Then it would be up to the commission to choose the appropriate regulatory mechanisms.

    S+S as a 'sharpshooter' of value

    The CESA calculation is for “a new hybrid resource” that uses three hours of storage to serve peak load, but also optimizes solar output, Burgess said. The storage component allows the solar to be tailored to meet other grid needs.

    “It is a sharpshooter of value,” he said.

    Daniel Vickery, market development manager at Green Charge Networks, pointed out that the solar-plus-storage value number CESA found is quite similar to the difference between peak and off-peak electricity rates for commercial-industrial customers.

    What the calculation essentially describes, he explained, is that with solar-plus-storage you can move electricity generated during off-peak hours to peak period use. With that technique, you can avoid demand charges and higher variable rates during times of high electric demand.

    Though comparing solar and storage to traditional generation resources is difficult, the $0.25 per kWh levelized avoided cost roughly matches thelevelized cost of energy of a natural gas peaker turbine, Burgess said.

    The difference, he explained, is that peaker turbines are typically used less than 10% of the 8,760 hours in a year, while storage gives solar a capacity factor much closer to baseload generation.

    Acquiring a natural gas peaker turbine is a cost-driver for utilities, but it only takes a few hours of storage capacity to eliminate that expenditure for a rarely used generator, he continued. Plus, storage facilities offer additional benefits to the grid.

    “Solar-plus-storage can do things traditional assets can’t, like absorbing daytime assets," Burgess said. "A peaker can only generate.”

    With storage, Vickery said, “you no longer need to build the power plant, you no longer need the new power lines, you no longer need the new substation. The utility could be investing the money elsewhere.”

    The new track CESA is calling for, whether in the NEM docket or the Commission’s DRP or IDSM proceedings, could result in a tariff that is an effective price signal to customers to invest not only in solar, but in storage as well, Ko said. It might be a premium above the reimbursement for solar alone, but it would move more customers toward building resources that meet not only their own needs, but the grid’s needs as well.

    Getting the timing right

    “The lack of consideration of energy storage in the [utility rate] Proposals could lead to flawed proposals and designs,” the CESA filing explains, which could in turn stunt the deployment of storage in the state. Examples of such flaws are the IOUs’ proposals for “some combination of fixed charges, demand charges, and time-of-use rate plans," all of which fail to consider the value of solar-plus-storage.

    “Fixed charges are a blunt instrument,” CESA explains, because they do not move customers toward technologies that shift electricity usage to meet grid needs. And demand charges now proposed, CESA adds, “are not well designed to address system cost drivers or to direct customer responsiveness.”

    The preliminary calculation shows energy storage can reduce costs for ratepayers. “More nuanced charging regimes can provide additional system value and cost-savings,” the filing argues, and "can move customers to more charging during low-cost, off-peak periods and discharging during high-price, peak periods.”

    If utilities use demand charges, they must align them to system cost drivers and especially to peak demand, which is the one big cost driver, Burgess said.

    But the bigger point is that “if you want to design something that encourages storage, it needs to be designed more precisely," he said. "Demand charges need to vary with time of day and time of year. More technical rate designswill advance technology instead of curtailing it."

    The filing does not propose any specific rate design, Burgess emphasized. Butsmart time of use rates should be part of a new rate design that unlocks the deployment of solar plus storage.

    “We are reaching the recognition,” Ko said, “that when you generate energy, when you put energy onto the grid, and when you consume it is a lot more important to value than just taking energy whenever it comes, as we have in the past.”

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    ORIGINAL REPORTING: A Public Utility For Hawaii?

    IOU, co-op or muni? Experts debate the creation of public utilities; A merger debate in Hawaii has sparked a campaign for a public utility, but is that model best for ratepayers?

    Herman K. Trabish, September 16, 2015 (Utility Dive)

    Editor’s Note: A decision from Hawaii regulators on the merger is expected any day.

    It seems that not a month goes by without another installment in "Utility 2.0" news. Most recently, it was New Hampshire, which announced last month that it would join growing group of states in opening a regulatory docket to collect comments on grid modernization and changing utility business models.

    How utilities can make money in the 21st century is among the most pressing questions for utility officials across the country, with most executives telling Utility Dive in a survey that they don't expect their business models to be the same in 5 years as they are today.

    For the most part, conversations about changing business models have centered on market structures, deregulation schemes, and the amount of vertical integration appropriate in the power system. But in Hawaii, a different question on utility business models is getting a lot of attention as part of a larger debate over a controversial merger — whether the power company serving the state should be an investor-owned utility, a cooperative, or a municipal power company.

    It is a debate that could have ramifications for utilities of all types nationwide.

    The Hawaii Issue

    In response to the proposed acquisition of Hawaiian Electric Industries (HEI) by Florida-based NextEra Energy, a group of residents in Hawaii took their activism beyond opposition to the deal. They formed the KULOLO (Keep Utilities Locally Owned, Locally Operated) movement, aimed at convincing regulators to explore alternate utility ownership models as they evaluate the merger proposal.

    “We believe the Utility 2.0 model might be a publicly owned one," KULOLO Spokesperson Rob Harris told Utility Dive.

    But not all stakeholders agree. Concentric Energy Advisors CEO John Reed argued in testimony to the Hawaii's regulators that commissioners must evaluate the proposed $4.3 billion purchase of HEI on its own, but must not concern themselves with the growing clamor in the state for a different kind of utility.

    “Several parties have filed comments that question whether alternatives should be considered to establish whether the Proposed Transaction is in the public interest,” Reed testified to the Hawaii Public Utilities Commission (PUC).

    Reed said the purchase of HEI's subsidiary electric utilities, and not the consideration of alternative, publicly owned electric utility business models is the decision before the commission. But he also questioned the alternative utility models that started the KULOLO movement.

    KULOLO would have the commission reject the NextEra/HEI investor-owned utility (IOU) business model in favor of a municipal or a cooperative utility.

    Reed argued that the electric sector nationwide is moving further away from co-op and muni models. Eight of ten privitization efforts since 2000 have been approved, he said, while “municipalization has generally been unsuccessful since 2000."

    "It is reasonable to conclude that the more recent trend has been privatization," he said.

    Of the more than 900 cooperatives and 2,200 municipal electric systems in the U.S., few have been formed in recent decades and “rarely through an acquisition approach,” Reed argued. “The economics of forming a new utility are very challenging.”

    Time also works against municipalization or establishing a cooperative that would acquire IOU assets, according to Reed (in docket 2015-0022).

    “The timeline to achieve municipalization of IOU assets could be as long as 5 years to 10 years, and often is not successful," he said. "Furthermore, when the financial analysis has been conducted, and all the costs have been identified, municipalization efforts are most often abandoned.”

    Struggles to create a public option

    Not surprisingly, electric co-op veterans take exception to Reed's perspective.

    “The reality is the U.S. is 99.9% electrified and divided into monopoly-defined service territories,” countered Solar Electric Power Association (SEPA) VP Bob Gibson, a former National Rural Electric Cooperative Association executive. “The idea that cooperatives are unworkable because there haven’t been new ones formed is misleading. It is usually just as hard for an IOU to buy a co-op or a muni. There have been relatively few new utilities.”

    Only two of 22 municipalization attempts since 2000 were completed, Reed testified. He described 6 attempts in Iowa over a 6 year period that all failed. He described three recent efforts in more detail.

    Jefferson County Public Utility District

    After a 2008 vote to proceed, it took five years for the Jefferson County Public Utility District (PUD) in Washington State to form an 18,000-customer electric utility in 2013. The $110 million cost was double the original estimate and almost 2.5 times the book value of the Puget Sound Energy assets.

    “Despite getting access to hydro power they continue to struggle to match the prior IOU’s rates,” according to Reed.

    “Jefferson County is probably the worst example of a takeover to pick,” said Regulatory Assistance Project (RAP) Senior Advisor Jim Lazar. The PUD paid a high price because they were able to take advantage of very low interest rates available through the Rural Utilities Service (RUS).

    “It is true they are having trouble maintaining the same rates as Puget but Puget was losing money there,” Lazar said. “Puget was willing to sell because it was a sparsely populated area that created relatively higher operating costs than the rest of their system.”

    One of the reasons rates haven’t gone down is that the Jefferson County PUDhas made substantial investments in system reliability that Puget wasn’t making, he added.

    Winter Park, Florida

    Reed also described the four to six year process through which the City of Winter Park, Florida, municipalized with assets acquired from Progress Energy. A bond issuance that promised an $8 million per year profit lost an estimated $11 million over the first four years of operation, the debt service ratio dropped off, and the muni’s credit rating went negative. Only a subsequent rate increase has alleviated the emergency.

    “The cost to acquire a utility often overshadows the new utility for decades,” Reed testified. "In addition to the high acquisition costs involved that are often multiples of book value, there is no inherent advantage of a coop or muni on the largest component of a customer’s bill – fuel mix.”

    “Most public power takeovers are in the vicinity of 140% of book value and they usually take time to produce significant net benefits,” Lazar said. But non-profits with access to tax exempt bonds and a responsibility to consumer-owners rather than shareholders tend to keep costs low.

    “And there is more,” Lazar added. “Satisfaction is much higher both for consumers and for employees whose only jobs are to minimize costs and maximize the quality of service.”

    In the case of Winter Park, a long-postponed undergrounding of infrastructure obtained from Progress in the system separation has kept costs high, explained EnergyShouldBe.Org Founder Ken Regelson, a municipalization advocate in the struggle between Xcel Energy and the City of Boulder, Colorado. But, he said, residents have supported the effort with voluntary rate increases.

    Reliability has improved dramatically with the number of yearly outages in 2014 falling from 22 to 0.5 and the average outage time cut by 67.5%, Winter Park recently reported. Rates are between 2% and 12% below surround IOU rates. And the utility has paid off all debt incurred in the takeover.

    Boulder, Colorado

    The contentious Boulder municipalization that began in 2011 remains incomplete, and multiple federal and state legal proceedings are ahead, Reed said.

    “It has cost millions of dollars,” he reported to Hawaii’s PUC, and “it is reasonable to expect that this case will take years more to resolve at a significant cost to the city.”

    “For a co-op or a muni to do a hostile takeover means undoing an incumbent utility. That is extremely difficult and extremely expensive if the incumbent utility is in opposition,” Gibson acknowledged, pointing to Boulder as an example of an IOU unwilling to let go of an affluent service territory.

    “But 12 co-ops just bought out the southern Minnesota service territory of Alliant Energy,” Gibson added. “Alliant no longer wanted to operate in those rural and semi-rural areas and they worked out a deal. That has happened often in recent years.”

    Where a public option has worked

    A takeover is very expensive if it is hostile, Gibson said. “But if there is an opening, there is no reason it can’t work.”

    Both Reed and Lazar said the system separation, in which the new utility takes over the involved part of the incumbent’s distribution system, is usually the most expensive and difficult part of the process.

    “Most communities already are built out, and large distribution systems are in place,” Reed testified. To purchase or build a distribution system at today’s market prices, “large amounts of capital would have to be raised and spent all at once, and other local government priorities for capital investment likely would be threatened by such a massive outlay.”

    As a result, he argued, customers of recently-formed public power companies have not had the low average retail electric rates once obtainable from a takeover.”

    “Lots of efforts did not come to fruition,” Lazar said, “but the takeovers that have happened have worked fine.” He highlighted four thriving Pacific Northwest public power providers:

    1-The City of Hermiston, Oregon, successfully municipalized, despite resistance from Pacific Power and Light (PP&L) in the early 2000s that forced it through the lengthy legal efforts Boulder now faces. An independent 2014 study found its customers to have the region’s lowest utility cost burden.

    2-The $45.5 million, 1988 buyout of CP National assets by the Oregon Trail Electric Cooperative was, like the recent Alliant deal in Minnesota, relatively pain-free because the IOU wanted out of the utility business and was looking for a buyer.

    3-The Columbia River PUD takeover of Portland General Electric assets in the mid-1980s began as a hostile proceeding, but a public vote led to a system separation appraisal by regulators that satisfied both sides.

    4-After the $23.5 million Emerald PUD takeover from PP&L in the early 1980s, the power provider struggled to keep its rates competitive. A $36 million bond offering retired the initial debt but took time to work through needed system upgrades.

    “I remember being at a public meeting as a consultant some years after Emerald was formed,” Lazar recalled. “A woman brought a box of candles to the board, saying that reliability had improved so much she didn’t need them anymore.”

    Back to Hawaii

    Many observers in Hawaii say the sentiment for a public option is so strong that the only thing keeping NextEra from pulling its offer for Hawaii’s electric utilities is a $90 million penalty for withdrawal before next spring. If it backs out at that time or if regulators reject the deal, “Hawaii will go after public options aggressively,” Lazar said.

    The most important testimony so far filed is from the State Office of Planning because it represents the Governor’s position, he explained.

    “That is the inside game testimony," Lazar said, "and it is visceral about what a bad move it was to bring in an outside corporation.”

    But the KULOLO sentiment is no guarantee of success, Reed argued. The 2002 takeover of Citizens Electric by the Kauai Island Utility Cooperative (KIUC) led to rapidly rising rates, despite the unequivocal cooperation of the seller.

    “When KIUC started operations in 2002, it had the highest rates of any island," Reed said. "The difference between Kauai and O‘ahu was 69%, and the difference between Kauai and Maui was 35%."

    KIUC communications manager Jim Kelly said that's not the whole story.

    “There were early issues with the generation mix that caused bills to go up, but the Board started turning things around in 2009 when it set a 50% by 2023 renewables goal,” he said. “Some of the first PPAs for renewables fell through during the financial crisis, but Recovery Act money and the investment tax credit helped propel the utility forward."

    We should be at 38% renewables by the end of 2015, and we should get to the 50% goal within about three years," Kelly said.

    And, as Reed’s testimony noted, “After 13 years, KIUC’s rates are now in line with other Hawaii islands.”

    The cooperative model’s greatest strength, Kelly said, is that “the owner-members democratically determine the direction of the business.” But that means a “huge component” of the utility leadership’s obligation is educating members about issues and costs, because the weakness of the cooperative model is how challenging it is to manage the owner-members’ expectations about rates.

    “Being a co-op does not mean your rates are automatically lower any more than being an IOU means rates are automatically higher,” Kelly said.

    Decisions about buying and being bought are made by the member-owners of municipal utilities and cooperatives, but both are rare, Gibson said. “Utilities are stable businesses. Unless it is a deal in the interest of both parties, it is going to be hard to make because IOUs, co-ops, and munis will fight to keep their territories.”

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    Tuesday, June 21, 2016

    ORIGINAL REPORTING -- Beyond batteries; The Many Ways To Store Energy

    Beyond batteries: The diverse technologies vying for the bulk storage market; Batteries are hot, but utilities looking to store a lot of power may find cheaper options elsewhere

    Herman K. Trabish, September 14, 2015 (Utility Dive)

    All the talk in the electric utility industry these days seems to be about battery storage, but there are other ways to save generated electricity for later.

    With more demanding state renewable portfolio standards, the finalization of the EPA's Clean Power Plan and utilities increasingly turning to renewables as a least-cost option, grid operators are likely to need more and bigger storage options by the mid-2020s, if not before.

    “The excitement in the market now is around the policies we have in place, which very specifically exclude big pumped hydro applications,” explainedCalifornia Energy Storage Alliance (CESA) Sr. Advisor Mark Higgins, the VP/COO at Strategen Consulting. “Those policies were designed to create a diversity of technologies. Bulk storage would work against that.”

    But, Higgins said, by around 2024, when California gets to about 40% renewables, there will be a real need to shift excess renewable energy supplies from the middle of the day to the late afternoon and evening. “That will require storage resources that can handle big amounts of energy over long periods of time.”

    Higgins expects California regulators to again take the lead, as they did withthe AB 2514 policy now driving battery technology growth, and put in place incentives for long duration storage technologies.

    Pumped hydro promises big capacity

    Pumped hydro storage (PSH) uses energy to move water from a lower reservoir to a higher reservoir where it can, at need, be released. The energy is recaptured as hydroelectric power as the water flows back to the lower reservoir.

    “Pumped hydro's sweet spot is bulk energy shifting,” Higgins said. “But there are not many good sites left, upfront capital costs are high and policy support is limited." Such obstacles have limited excitement about pumped hydro's growth.

    Duke Energy, however, says it is excited about pumped hydro, according to Spokesperson Lisa Parrish, because its quick start up time provides flexibility the utility needs. “Pumped storage functions like a giant water battery…At a moment’s notice, the stored water can be used to meet peak demand.”

    The potential of Califonia’s Bison Peak 1 and 2 PSH Projects excites Alton Energy President Ed Duggan. Eagle Crest’s Eagle Mountain PSH Project was green-lighted first by the Federal Energy Regulatory Commission (FERC), in hopes of helping fill the gap left by the shuttering of the San Onofre Nuclear Generating Station. But Duggan believes the combined 2,000 MW capacity of the Bison projects will have more benefits if he can get a green light from FERC.

    “Bison 1 and 2 meet three crucial criteria,” he explained. “First, they are strategically located at an intersection point of the California grid and some of the biggest utility-scale wind and solar installations already online.”

    He was describing the nearly 1,200 MW of photovoltaic solar in the Antelope Valley and the over 5,000 MW of wind capacity in the Tehachapi Mountainsthat form the Valley’s north boundary.

    “Second, the Bison projects have a larger elevation differential than other proposed pumped storage projects,” Duggan said. Competitors include the privately funded Lake Elsinore project, the Sacramento Municipal Utility District’s Iowa Hills project, EDF’s Swan Lake project, and smaller ones proposed by the San Diego Water Authority.

    “The greater elevation differential would allow Bison Peak to supply more power faster with less water,” Duggan explained.

    Finally, he said, Bison Peak’s bulk storage would be geographically available through the Southern California Edison and Pacific Gas and Electric transmission systems to the Los Angeles and San Francisco region load centers.

    Duggan believes the state will need at least 10 GW and possibly as much as 50 GW of bulk storage like PSH to meet the state’s targeted 80% reduction in greenhouse gases by 2050.

    Take the ARES train

    But the bulk storage may not all come from PSH, according to Advanced Rail Energy Storage (ARES) North America VP Francesca Cava.

    “We are like pumped hydro but without the constraints of water,” Cava said. “And we estimate ARES requires about half the capital expenditure.”

    ARES would use energy to do with box cars on a rail line what PSH does with water – push them up an incline so they can be released to generate electricity with their downhill momentum. The concept has been proven with a “peer-reviewed, patented” demonstration project in which ARES has moved a 6.5 ton rail car up a 15-inch gauge track with Tehachapi Mountain wind energy,according to the company.

    It is a gravitational technology but an intriguing if fairly simple concept, Higgins said. “The questions are: What are the applications? And how cost effective is it versus something else?”

    ARES will soon begin providing more answers, Cava said. They expect to be granted a Bureau of Land Management permit by the end of this year for a selected Nevada site and they expect to have an operational 50 MW project selling into the California grid’s ancillary services market via the Valley Electric Association cooperative utility by the end of 2017.

    It will have a 78.3% round trip efficiency, a 34 second full charge to full discharge response, and a 40-year system life. Ultimately, the ARES team believes, projects with multiple, side-by-side lines can provide up to 3 GW of storage over a 24 hour duration.

    “Pumped hydro can be very large but so can ARES,” Cava said. “And twice the capacity is not twice the cost so it scales relatively economically.”

    The case for CAES

    There are only two operating utility-scale Compressed Air Energy Storage (CAES) facilities in the world, though others in the U.S., the UK, and Europe are in various stages of development. The 290 MW, four hour full-output Huntorf facility in Germany went into service in 1978. The 110 MW, 26-hour full-output McIntosh facility in Alabama went into service in 1991.

    At both sites, energy is used to compress air into underground salt caverns. When that air is released, on demand, it turns generators that send electricity back to the grid.

    CAES makes sense when there is a need for a long duration response of between 8 hours and 26 hours, Higgins said, because the cost is largely upfront. Compared to the linear cost of increasing batteries’ storage volume, it is not very expensive to expand a CAES facility's capacity.

    “But,” he added, “it is not often you find a good storage site with all the advantages of the one in Utah being proposed for development by Burbank Water and Power (BWP) and its partners in the Pathfinder group. There is an underground salt cavern that happens to be next to a major transmission line and near sites of thermal plants scheduled to be shuttered.”

    “Geology is the biggest hurdle for CAES,” acknowledged BWP Power Resources Manager Lincoln Bleveans. “But another company has already proven the viability of this geology by storing natural gas liquids there.”

    BWP estimates it could build “about 90 caverns, each about the size and shape of the Empire State Building” in the underground salt deposits at Delta, Utah, Bleveans said.

    Around 2010, BWP began to realize California’s renewables mandate was eventually going to increase. Talk was emerging about over-generation and the increasing need for stored energy to meet an increasing late-afternoon, post-solar-availability peak.

    Bleveans and his team began more seriously considering the storage site nearthe Intermountain Power Project (IPP), from which the municipal utility already bought a small share of the facility’s 1,900 MW of coal-generated electricity. Adding to the site's appeal was that most of the IPP’s generation was already being sent along existing transmission to Southern California region munis.

    BWP also discovered Pathfinder Wind Energy was beginning the process of developing up to 3 GW of Wyoming wind and investigating ways to deliver the electricity it could generate to West Coast load centers.

    Soon BWP also discovered the Transwest Express, Gateway, and Zephyr high capacity transmission systems to be in development. All could potentially pickup Wyoming and other High Plains wind-generated electricity and deliver it to the storage site for later deliervy, on demand, to Western and Southwestern loads.

    BWP, Pathfinder, equipment provider Dresser-Rand, transmission builder Duke-ATC, and technology supplier ABB recently won preliminary approval for a $628 Department of Energy loan guarantee that would allow them to develop a 300 MW pilot project at the Delta site, Bleveans said.

    “CAES is very geology specific. It lives and dies on geology,” Bleveans repeated. “We are in due diligence mode. We are peeling the onion. And we haven’t cried yet. But we are still peeling the onion and trying to figure out if it is the right thing for our utility.”

    Bleveans declined to provide cost information but the current facilities are averaging $1,600 per kW to $2,200 per kW, according to Energy Storage Update. The report puts PHS at $1,200 per kW to $2,100 per kW, lithium-ion batteries at $1,000 per kW to $2,000 per kW, and flywheel storage at $2,100 per kW to $2,600 per kW.

    Flywheels struggle on cost

    Though cost would appear an obstacle for flywheels, they can be cost effective when they are cycled frequently, Higgins said. “It is like a giant spring. Energy is used to wind it up and energy is released when it unwinds.”

    But charge-discharge cycling doesn’t cause the same wear-and-tear in flywheels as it does in the chemistry of batteries, so performance degrades less.

    “Flywheels are a short-duration, high-power resource,” Higgins said. “They are most cost-effective for fast response ancillary grid services.”

    The PJM Interconnection and New York’s grid operator are both using 20 MWBeacon Power flywheels for frequency regulation, Higgins added.

    But lithium ion battery storage seems to be most grid operators' preference in recent ancillary services contract bidding, verifying flywheel technology's lack of cost competitiveness as reflected in the Energy Storage Update cost information cited above.

    Flywheels have, however, found some success in support of electric trains. “Flywheels can quickly deliver a lot of load as a fast train draws power to leave the station,” Higgins explained. “That avoids any strain on the grid from a sudden increased power demand.”

    Storing the sun

    Molten salt storage from the sun’s heat is just beginning to demonstrate its viability at U.S. solar power plants. Abengoa Solar’s 280 MW Solana parabolic trough solar power plant in the Arizona desert has proven it can provide Arizona Public Service with up to six hours of full capacity generation after dark or at other times when there is inadequate sun.

    SolarReserve’s Crescent Dunes solar power tower, due online in October, will raise the bar by providing NV Energy with ten hours of stored 110 MW generation. Its system drives molten salts up to the top of a 540 foot tower and into a 100 foot tall receiver, where they are heated by the sun to 1050 degrees Fahrenheit. They then flow into a 3.6 million gallon hot tank.

    At the utility’s need, the hot salts are released to flow past a closed water system in a heat exchanger where they transfer half their heat to boil the water. The steam drives a 110 MW turbine to generate electricity and is largely recaptured. The molten salts flow, at 550 degrees Fahrenheit, to the “cold” tank to await another cycle.

    The price of these “solar thermal” technologies includes the cost of both generation and storage. SolarReserve’s power purchase agreement with NV Energy set the price of its output at $0.132 per kWh.

    Recently, photovoltaic (PV) solar projects that generate power from the sun’s light have been bidding for utility contracts at and below $0.05 per kWh, pushing concentrating solar power projects like Solana and Crescent Dunes out of the market.

    But PV solar can only be stored in batteries or other technologies that hold electricity. They are more expensive, less efficient, and less scalable than molten salts, according to SolarReserve CEO Kevin Smith. With renewables mandates rising, utilities will soon see the value of stored solar heat to meet an increasing late afternoon-early evening peak in demand, he said. As Utility Dive has reported, storage capabilities could prove to be the savior for large CSP projects in the coming years.

    The coolest tech: Ice storage

    Ice Energy and CALMAC provide thermal storage at the opposite end of the temperature spectrum from solar power plant developers.

    Both companies are leaders in shifting the energy used to cool buildings from when the day is hottest, demand on the grid is highest, and electricity is most expensive, to the cooler night when demand is low and abundant, wind-generated electricity can be bought from most grid systems at very low prices.

    Both companies’ devices attach to building air conditioning (A/C) units. They freeze water at night so when cooling is needed the next day, the draw from the A/C is sharply reduced.

    CALMAC’s business model focuses on building owners, winning customers by simply cutting their electricity bills. The technology can have a huge impact, especially where high demand charges from peaking A/C use can be controlled.

    Ice Energy partners with utilities. Though already widely used across the U.S., its Ice Bear product got its biggest recognition yet by winning 16 contracts for 26 MW of distributed and behind-the-meter storage in the Southern California Edison (SCE) 2014 local capacity requirement (LCR) bidding.

    By allowing the utility to control if and when the Ice Bear is used, the technology acts as a demand response resource, Higgins said. SCE expects to eventually be able to cut its peak load, when necessary, by 95% of the contracted 26 MW with the flip of a control switch, according to Ice Energy.

    Building cooling is unaffected, but if SCE throws the switch, the cooling would be coming from wind energy-generated power, which helps the utility meet its renewables mandate. That electricity would also be lower priced.

    BWP, Glendale Water & Power, Redding Electric Utility, and Riverside Public Utilities also employ the Ice Energy technology, according to Energy Storage Update.

    Ice Energy’s business is expanding quickly, reported Chief Information Officer Chris B. Tillotson. It already has 12MW installed and 30MW contracted for and it is working on a development pipeline of over 100 MW. It is also readying an Ice Cub residential product, which should hit the market in time to be an early player in the aggregated distributed energy resources markets being developed in California and New York.

    The best tech depends on location

    “We believe this is the only non-battery distributed storage technology,” Tillotson said, taking the cooling technology out of competition with the bulk providers.

    For all the gravity-driven bulk storage technologies, Higgins said, “the question is whether the final engineering costs make it cost-effective.”

    “We are comparable to pumped hydro but it is easier to locate and build an ARES project, way easier because pumped hydro depends on water,” Cava said. “We need land and a mild grade but we have found at least 27 sites just in the state of California.”

    I don’t want to say PHS, ARES, or CAES is better, Bleveans said. CAES seems to have great potential if you have the right geology. LA DWP’s Castaic PHS facility proves the right geology and topography can make that a terrific solution. And with the right conditions, an ARES project might be good, too.

    "At the scale of bulk storage," Bleveans explained, “you have to be agnostic about technology because the technology has to be driven by site conditions.”

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    ORIGINAL REPORTING -- Solar Vows Fight For A Level Playing Field

    SPI 2015: Tax credit sunset preoccupies a fast-maturing industry; The tax credit fight reveals a rift within the solar industry as strong growth continues

    Editor’s Note: Solar prevailed in this effort at the tail end of 2015 when Congress finally enacted a five year extension that set the industry off on its current boom.

    Herman K. Trabish | September 15, 2015 (Utility Dive)

    Skyrocketing growth is no longer the big story in the solar power industry, although growth continues to skyrocket.

    The big story is how the increasingly vital segment of the energy industry will mature.

    Solar provided nearly a third of the nation’s recent new generation capacity, continues to set quarterly growth records, and is on track to double its mid-2014 cumulative installed capacity by the end of next year.

    Solar photovoltaic (PV) installed capacity is expected to reach 7.7 GW in 2015, up 24% from 2014, according to the Solar Energy Industries Association (SEIA) and GTM Research.

    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 there are some headwinds for the sector. In a sign it has reached a level of maturity achieved recently by the wind industry, solar advocates now face an uphill political battle for the industry's most vital federal incentive

    The mandated term of solar's vital 30% federal investment tax credit (ITC), in place continuously since 2008, will end on December 31, 2016. Beyond that deadline, the tax credit provided at the end of a project’s first year of operation will fall to 10% for commercial investments in solar and to zero for residential solar investments.

    SEIA is mounting a multi-million dollar lobbying campaign to secure a five-year extension that will get the industry to 2020, when it hopes the Clean Power Plan can take over to help boost growth.

    Failing that, insiders say solar advocates will attempt to convince lawmakers to include a two-year extension in next year's omnibus spending bill with a special in-construction provision for projects that break ground by the deadline.

    The ITC and SEPA v. SEIA

    Another sign of maturity is the internal rift SEIA’s plans have spawned. Its leaders wrote to the Solar Electric Power Association (SEPA), asking it to chip in on the costs of the lobbying campaign. SEPA and SEIA have long partnered in fostering solar growth through production of Solar Power International(SPI), the industry’s most important annual deal-making and innovation-unveiling conclave.

    But SEPA says it cannot provide the funds.

    “Our value is in bringing together parties in the solar industry and the utility industry with very diverse perspectives and to do that everyone has to trust us. Our credibility is the thing most important to us,” SEPA President and CEO Julia Hamm told Utility Dive in an exclusive interview. “We don’t do lobbying or advocacy. The minute we start putting money into a policy campaign, it can damage our credibility.”

    SEPA is just as committed to solar as SEIA but in a different way, Hamm said. “We are different by design. We complement one another.”

    SEPA is an educational organization whose mission is to engage with utilities on questions like interconnection and procurement. And it has invested in longer term programs like its 51st State Initiative, aimed at advancing the debate on regulatory and business model consequences of solar proliferation.

    “This is not about whether or not we support the extension of the ITC,” Hamm said. “We don’t take policy positions.”

    Much of the separation between the groups comes from their institutional structure and membership, Greentech Media pointed out. SEIA is a trade group that advocates for specific solar policies whose board is made up almost entirely of solar companies. SEPA, by contrast, has a board that includes several prominent utilities, some of which support altering net metering policies. Typically, it stays silent on controversial regulatory issues, preferring to bring the two sectors together through joint projects, surveys and other educational initiatives.

    “We stand by our letter calling on SEPA to step up,” SEIA President and CEO Rhone Resch told Utility Dive.

    Tax credits, solar finance headline opening session

    A number of speakers at the opening session of SPI addressed the ITC issue.

    Pacific Gas and Electric Regulatory Affairs VP Steve Malnight avoided a confrontation, but spoke up for SEPA.

    “SEPA is focused on bringing utilities and solar companies together,” he said. “As solar grows and utilities see higher penetrations on their systems, SEPA is helping utilities understand how distributed resources make solar even more cost effective and better for the system.”

    SEIA's Resch urged the session’s audience to understand how important the fight for the tax credit is.

    “Since the ITC was put in place, solar has added over 150,000 jobs and seen over $100 billion in capital investment in the industry,” he said. “A new Bloomberg New Energy Finance study shows the downstream segment of the U.S. solar industry will lose 80,000 jobs if the ITC is not extended.

    Implementation of the final Clean Power Plan (CPP) begins sometime after 2020, when SEIA wants the ITC to expire, Resch reminded them.

    “It is a long term driver, but not a panacea," he said. "And we need the ITC to get to 2020.”

    “The ITC represents between $0.30 per watt and $0.80 per watt of the installed cost of solar,” explained Clean Power Finance President and CEO Nat Kreamer. “There is no room for that to come out of the cost of hardware. The one place it can come from is soft costs. That’s jobs.”

    Kreamer provided a brief run-down of current solar finance opportunities, including securitizations, yieldcos, and solar stocks. The recent drop in solar stock prices, he said, is due to fund managers' profit-taking on solar investments to recoup losses from the falling oil price of oil.

    “The best way to invest is through a portfolio approach that takes advantage of the range of opportunities,” Kreamer said. “A trillion dollars is likely to go into solar to meet the demand created by the Clean Power Plan and other policy drivers.”

    Community solar consensus

    A near term opportunity is in community solar, the panel agreed.

    “There is always going to be a segment of the population that can’t be served by putting solar on their roof,” Malnight said. “Community solar allows for a large project’s economies of scale and gives customers the solar opportunity even if their roof are not solar suitable. It is going to open a lot of new approaches to solar.”

    The SEPA membership is half solar industry and half utilities, Hamm said. “Community solar is the number one thing both sides are asking us about.”

    “More and more utilities are developing programs,” she said after the panel discussion. “But it is not just for utilities. We are working with the Department of Energy to help define the different kinds of community solar business models and help the marketplace understand the differences between those models and come up with templates that will expedite the rollout of community solar nationally.”

    In places like Minnesota, solar advocates have blamed state and utility policies for preventing community solar subscribers from getting the cost savings available to rooftop solar owners.

    “Even with solar costs dropping, it is hard in many places to make community solar pencil with an initial price lower than the retail price of electricity but we are getting closer every day,” Hamm said. “And many lock in a rate over the long term so as retail rates go up, it will be a great hedge.”

    Community solar often seems complex from a utility’s perspective, Hamm said.

    “It seems to touch every functional area of the business, something utilities have not had to deal with," she said. "When you are building a power plant, it doesn’t impact everybody in the organization ... but community solar does.”

    When they see there are tools and existing models, she added, they realize they can implement it.

    'Good citizens of the grid'

    Solar now supplies about 1% of U.S. electricity, but growth will eventually take it to a 20% grid penetration, Kreamer said. That means solar developers will need to begin worrying more about using the grid responsibly, a third sign of sector maturity.

    “We cannot grow solar without maintaining reliability and safety,” Kreamer said.

    As industry leaders confront higher penetrations, they are learning to be good citizens of the grid, Kreamer said. “We are beginning to see redesigns of power markets away from a one-direction flow of power to a market that allows for many kinds of distributed energy resources.”

    A portion of the ConEd system in New York, he added, “is now viewed as a network and not a one way flow. That creates economic incentives that will bring in new technologies that provide low cost and reliability and safety.”

    The 51st State Initiative is intended for solar stakeholders to resist incremental thinking and imagine a new system that incorporates distributed energy resources while ensuring affordability and reliability, Hamm said.

    “Last year we asked for a variety of future visions. Now we are trying to identify the roadmap to get from where we are today to the many different futures,” Hamm said. “It will be different in different states. We will be asking people in the energy industry for those roadmaps.”

    “We are asking them to think about distributed energy technologies from the customer’s point of view and offer solutions that include combinations of different technologies,” she said. “As a result, we are seeing solar companies partnering with smart thermostat companies and with storage providers. This is the beginning of what it means to be a good citizen of the grid.”

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