NewEnergyNews

NewEnergyNews

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.

YESTERDAY

  • ORIGINAL REPORTING: President Obama’s clean energy revolution
  • ORIGINAL REPORTING: Demand flexibility and the power delivery transformation
  • THE DAY BEFORE

  • ORIGINAL REPORTING: Why can't utilities innovate like startups?
  • ORIGINAL REPORTING: How Warren Buffett's bet on an Energy Imbalance Market in the West is paying off
  • THE DAY BEFORE THE DAY BEFORE

  • TODAY’S STUDY: On The Path To SunShot – Utilities And Distributed Solar
  • QUICK NEWS, May 24: Portland, Ore, Bans Climate Change Denial From Science Classes; Wind Hits 100%-Plus Of Aussie State’s Power For 10 Hours
  • THE DAY BEFORE THAT

  • TODAY’S STUDY: A Review Of Alternative Rate Designs
  • QUICK NEWS, May 23: Human-Caused Changes Threaten A Third Of Bird Species With Extinction; Attack On Wind Linked to Oil Industry Money; Solar Plus Storage Multi-tasking To Cut Costs
  • AND THE DAY BEFORE THAT

  • Weekend Video: New Energy FulFills Its Potential
  • Weekend Video: The Nuclear Fantasy
  • Weekend Video: Building Wind Was Never Better
  • THE LAST DAY UP HERE

  • FRIDAY WORLD HEADLINE-Unlike U.S. Republicans, Islam Calls For Climate Change Action
  • FRIDAY WORLD HEADLINE-New Energy Powers A Nation For Four Days!
  • FRIDAY WORLD HEADLINE-Solar Rising On The Wide World
  • FRIDAY WORLD HEADLINE-The Power Of The Oceans
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    Anne B. Butterfield of Daily Camera and Huffington Post, f is an occasional contributor to NewEnergyNews

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    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

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    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

    email: herman@NewEnergyNews.net

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

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

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  • Friday, May 27, 2016

    ORIGINAL REPORTING: SolarCity wants to help utilities plan for distributed resources

    SolarCity wants to help utilities plan better for distributed resources; A new white paper from the leading solar installer aims to modernize utility DER practices

    Herman K. Trabish, August 27, 2015 (Utility Dive)

    For utilities and system operators who find that coping with all the new distributed resources on the grid is like holding an armful of marbles, you may have a new — and rather unexpected — best friend: SolarCity.

    The leading U.S. solar installer’s new white paper, "Integrated Distribution Planning," aims to get all the new grid resources and their uses organized so they can be put to the best use by power companies and system operators.

    “It starts with the assets themselves,” explained SolarCity Senior Director of Grid Engineering Solutions and white paper author Ryan Hanley.

    The assets are distributed energy resources (DERs), which include distributed renewables like rooftop solar as well as advanced inverters, stationary energy storage, electric vehicles, and technologies that allow for demand flexibility — the ability of utility customers to control their electricity use and participate in energy efficiency and demand response programs.

    Programs for individual DERs at utilities “have been successful and pushed engagement,” Hanley said. “But that approach limits the true capability of these assets. As an aggregate portfolio of multiple assets, these diverse assets accommodate for their individual weaknesses and become more powerful.”

    By modernizing utility interconnection, planning, procurement, and data sharing processes, utilities and distribution system operators can capture the benefits of DERs in bundles to both meet distribution needs and expand customer choice, the white paper explains.

    The idea to aggregate was put forward some months ago by former Texas utility executive and utility commissioner Karl Rabago.

    “The time has come to complete the transformation of the electric utility sector,” he wrote in a blog post in February. “A deliberate and sustained effort to establish robust markets for distributed energy services is the major remaining step in that process.”

    “It is imperative to transition to a grid that actively leverages the wave ofrenewable distributed energy resources,” Hanley’s paper explains, because it is a way of “engaging customers in energy management, increasing the use of clean renewable energy, improving grid resiliency, and making the grid more affordable by reducing system costs.”

    How the new responsive grid would work

    Under the paradigm of distribution system planning that Hanley and his colleagues are pushing, utilities could meet system needs with aggregations of distributed resources, put together by companies like SolarCity.

    “Today, a utility thinks of control as a fiber line going directly to a generator,” Hanley said. “In the future, a utility controls our assets through an interface at a substation.”

    Under that system, the utility communicates its need through the interface in grid terms, asking for capacity or reactive power or another ancillary service. SolarCity or another supplier commits to meet the need and then uses aggregated DERs in the region served by the substation to meet the utility's demands.

    “We don’t tell the utility how we will do it because every day it will probably be a little different,” Hanley said.

    SolarCity would look for the most economic portfolio of assets to meet any given utility need. One day it might be part pre-contracted reduced customer consumption, part reimbursed customer consumption cuts, and part purchased energy from batteries. Another day it might include solar from roofs where customers are not home, or power from parked electric vehicles as well as reduced consumption.

    “The utility gets what it needs every single time because we have a firm contract to deliver,” Hanley said. “The way we make money is getting good at optimization, at making sure our assets are available.”

    Utilities would need to be no more concerned about SolarCity fulfilling its “contract to deliver” than they now are about central station power plants meeting their obligations, Hanley said. “The key is to make the financial disincentive so punitive that people show up. We are ready for that.”

    DERs can support the grid, and in many ways do it better than the assets now available, he added.

    “The premature retirement of the San Onofre Nuclear Generating Station cost Southern California ratepayers over $3 billion," Hanley said. "With distributed resources, there is never one big asset that fails. There will be small ones that fail, but having a stranded cost of over $3 billion would not happen.”

    Rabago applauded SolarCity’s attention to DERs and the distribution systembecause it meets the “glaring absence of adequate, comprehensive, integrated distribution planning.” But, he reminded, “you still have to plan for the rest of the system.”

    The Distribution Loading Order

    To modernize procurement for the distribution system, the white paper offers its biggest innovation.

    System needs are today met through procurement of “utility-owned distribution equipment such as transformers, capacitor banks, reconductored wires, and other capital equipment,” it says.

    “To fill the need they don’t procure, they install equipment,” Hanley explained.

    In a high DER penetration future, “distribution planners must be willing and able to consider the full range of solutions,” the paper says. To lead planners there, the paper proposes a new distribution-level policy concept to encourage utilities to use DERs instead of traditional energy solutions when they are cost effective. It's called the Distribution Loading Order.

    Some states have a system level loading order. California, Hanley noted, requires its regulated utilities to consider energy efficiency first, followed by demand response, and then renewables and distributed generation, before the grid operator can look to traditional generation.

    “This procurement loading order puts the traditional ‘least cost, best fit’ solution in the ground,” Hanley said. Efficiency, demand response, and renewables are bypassed if they are not price competitive. “If fossil fuels are the cheapest, they get picked.”

    Similarly, SolarCity’s loading order “prioritizes the utilization of individual DERs or portfolios of DERs over traditional utility infrastructure, when such portfolios are cost-effective and able to meet grid needs,” the paper reports.

    The idea is to “use DERs before traditional capital grid investment if DERs are cheaper than or the same price as doing a substation upgrade,” Hanley said. “If DERs are not cheaper, pick the upgrade.”

    Utilities and distribution system operators should consider two DER opportunities before turning to hardware, according to the paper. First, are “DER portfolios that voluntarily respond to price signals sent from the utility that incent the desired behavior to meet grid needs.”

    SolarCity customers with solar-plus-storage, smart thermostats and meters could readily respond to price signals to alter their usage when system demand peaks, Hanley said. “If utilities do substation upgrades, they won’t use these low marginal cost resources.”

    If those DERs do not meet the “least cost, best fit” standard, procurers should turn to “DER portfolios that are contractually obligated to deliver grid services based on contracted prices.”

    Only if planners conclude these options cannot meet system needs should they turn to hardware upgrades, Hanley said. “This extends the tool kit utilities have to meet their distribution system needs, and if they follow the economic principle of ‘least cost, best fit’ it also guarantees that ratepayers are getting the best solutions available.”

    The distribution loading order concept impressed Rabago.

    "We have long claimed to use 'economic dispatch' as the protocol,” he observed. “But best buys don’t actually go first. Rather, the system loads baseload to recover capacity costs, then continues to dispatch from least to most dispatchable.”

    SolarCity’s loading order could be the needed protocol, he thought. But also needed at the system level is a “‘load management utility’ with performance standards rewarding maximum reliance on DER first, and then using large-scale resources only as necessary.”

    Other modernizations

    The paper’s discussion on interconnection modernization comes down to a relatively simple idea that covers a lot of ground: “Streamline the DER interconnection process, eliminate unwarranted costs, and expand allowable interconnection approvals.”

    The paper offers an array of granular improvements on ideas presented elsewhere, Hanley said, because, as the paper notes, “the pace of change is measured…[and] a more comprehensive set of enhancements is needed.”

    A key improvement, it says, would be utilities incorporating “automated DER Hosting Capacity analyses into the interconnection review process to increase allowable interconnections while decreasing the application review timeline.”

    “The extensive detail on interconnection will benefit all DER, and is long overdue,” Rabago said. “SolarCity has the national reach and visibility to add value to this discussion.”

    The planning modernization section covers much of the same ground as the California Public Utilities Commission (CPUC) Distribution Resource Planning (DRP) proceeding but “we try to push that ahead,” Hanley said.

    “The goal is to identify locational needs across the [distribution] grid, just like they do on the transmission grid," he said.

    As the presence of DERs increases, customer choice must also be accommodated into grid needs, the paper reads.

    “Utilities will need to become much more proficient at forecasting customer DER growth than they are today.” With a more detailed understanding of what is coming, it adds, planners will be able to find DER alternatives to procured investments “at low or no cost.”

    The analysis should not be limited to technical capacity but should “be informed by economics,” Rabago said. “We need value-based analysis of DER so that best buys can go first…[and not] resources that offer suboptimal value.”

    Data sharing

    DER providers need operational and planning data to achieve optimization and drive innovation, but utilities make little of it available, the paper asserts. “Solely publishing outcomes of utility analyses rather than sharing the underlying data does not enable sufficient industry stakeholder engagement,” it reports.

    There are five categories of data that utilities must commit to sharing, SolarCity believes:

    -Locations where DERs would be of most value to the system

    -The circuit by circuit capacity of the system

    -Locations of planned investments in the system for which DERs may reduce the need

    -Real-time and historical operational data that points to how DER portfolios can meet grid needs

    -Pricing data and event statistics that would support transactive markets

    To allow DER providers to serve the system, the paper says, utilities must make the data accessible online and downloadable. System maps made available by Southern California Edison and Pacific Gas & Electric in the CPUC’s Renewable Auction Mechanism program and the DRP proceeding are examples of data sharing that, while not perfect, are innovative, Hanley said.

    The practice of utilities holding data unavailable to the market is part of an outdated business model, Hanley said.

    “Companies that can crunch more data than the utilities have ever seen are on the sideline because they can’t get access,” he explained. “But it has been shown time after time that if you share data, innovation will accelerate and it is good for consumers.”

    In the role of system support, SolarCity could send sales teams to circuits where there will be upgrades and avoid circuits without capacity.

    “Utilities will say they can tell us where to install or the hosting capacity on a circuit and you don’t need the underlying data,” Hanley said. “But there will be new questions tomorrow that can only be answered by having the data.”

    Rabago applauded the paper’s data and transparency discussion.

    “This adds important detail to a discussion that is too often very generalized," he said. "It will also be a huge battleground.”

    What the paper proposes “is a new paradigm and it will take time,” Hanley said. But utility engineers think about DERs like any technology and are becoming more comfortable with them every month.

    "As DERs become cheaper, [utilities] will use more of the products," he said. "It is already reaching a tipping point.”

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    SPECIAL QUICK NEWS, May 27: Trump Twaddle On Wind Set Straight

    Trump Twaddle On Wind Set Straight Trump allows for renewable energy, but cites bad information

    Peter Kelley, May 26, 2016 (American Wind Energy Association)

    AWEA is always glad to hear about support for renewable energy, like this statement today from candidate Donald Trump, in a press conference and a speech on energy policy to an oil industry group in Bismarck, North Dakota:

    “So we can pursue all forms of energy. This includes renewable energies and the technologies of the future.”

    Trump said that includes wind. However he then cited bad information that’s out-of-date, discredited, misleading, and just plain wrong, about the cost of wind, incentives to build turbines, and effects on eagles and birds.

    Trump on the cost of wind energy: “Wind is very expensive, I mean wind is, without subsidy, wind doesn’t work.”

    Actually: Wind is already cheaper than fossil fuels in wind-rich areas like Iowa and Texas, a statement Politifact checked and rated “True.” It’s increasingly cost-competitive not counting any incentives. The overall cost of wind-generated electricity has fallen 66 percent since 2009.

    Trump on incentives: “You need massive subsidies for wind…The government should not pick winners and losers.”

    Actually: All forms of energy have incentives, most of them permanent in the tax code. The only ones preparing to phase out their incentives are wind and the other renewable industries. The wind Production Tax Credit is set to phase out starting next year.

    Trump on eagles: “…there are places maybe for wind. But if you go to various places in California, wind is killing all of the eagles.”

    Actually: Publicly available data of all known eagle fatalities shows collisions with wind turbines at modern wind farms are responsible for less than five percent of all documented human-caused golden eagle deaths. Cases are even rarer of bald eagles striking turbines. The numbers of both kinds of eagle are increasing in the Western U.S.

    Trump on birds: “Wind turbines kill far more than a million birds a year, far more…so wind is, you know, it’s a problem.”

    Actually: Mr. Trump’s numbers are off by orders of magnitude. Wind power has among the lowest impacts on wildlife of any way to make electricity. Leading wildlife groups like the Audubon Society, the National Wildlife Federation, and the World Wildlife Fund support responsibility sited wind turbines. Wind energy is the low-cost solution to carbon pollution in particular which threatens all wildlife. Unlike all other human sources, the wind industry works to minimize and offset the limited impacts it has on individual birds, building on a legacy of care for birds and environment.

    Trump ended by saying “Despite that, I am into all types of energy. And by the way, while we’re in North Dakota, I have to say that: I love the farmers.” We encourage Mr. Trump to love the wind farmers, too. In most cases they’re the same people: 98 percent of wind turbines are erected on private land, leased from farmers and ranchers.

    So the good news about wind energy is not just it’s good for consumers and the environment, it has also given the farmers in 40 states a valuable new cash crop, as it has in North Dakota.

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    Thursday, May 26, 2016

    ORIGINAL REPORTING: President Obama’s clean energy revolution

    President Obama calls for clean energy revolution: 'There is something big happening in America' ; Obama spoke about renewables investments, utility business models, and the dawn of a new clean energy age.

    Herman K. Trabish, August 25, 2015 (Utility Dive)

    Fresh from establishing the first national regulatory standards for carbon emissions earlier this month, President Obama has now joined the debate over the utility business model and called for a distributed, clean energy revolution.

    The president took his commitment to the fight against climate change to new ground in a keynote address at the eighth annual Clean Energy Summit in Las Vegas, Nevada. His bold words reinforced the message delivered earlier in the day by Senator Harry Reid (D-NV), who also showed an unflagging commitment to renewables and a reformation of the utility business model.

    “Earlier this month I unveiled our Clean Power Plan,” the president told a packed house at the Mandalay Bay Convention Center. “It is the first set of nationwide standards to end the limitless dumping of carbon pollution from our power plants and it is the single most important step America has ever taken to combat climate change.”

    He repeated his now-familiar belief that “no challenge poses a greater threat to our future than climate change.”

    But his administration holds another belief as well, he added.

    “We are deeply optimistic about American ingenuity. We think we can do good and do well. We believe we have the power, the dynamism, and the creativity to solve a big problem while keeping the engines of the American economy moving.”

    The president talked about his administration’s crucial investments, beginning with the 2009 Recovery Act — which he called the biggest commitment to renewables ever made — and carrying through to a just-announced $1 billion Department of Energy (DOE) commitment to new loan guarantees for distributed generation technologies.

    That loan program was just one of multiple executive orders the White House released Monday ahead of Obama's speech, all looking to stimulate the growth and technological progression of distributed resources.

    In line with his executive orders, the president aggressively advocated for higher penetrations of renewables like solar and wind, and reiterated that government investments that are needed to help make it happen.

    “If we keep investing in wind rather than making mindless cuts chasing shortsighted austerity, wind could provide as much as 35% of America’s electricity and supply renewable power in all 50 states by 2050,” Obama said, taking a swipe at fiscal conservatives on behalf of wind energy’s production tax credit.

    “America generates 20 times as much solar as we did in 2008,” President Obama said. And with a new solar array connected every three minutes, the solar industry last year added jobs 10 times faster than the rest of the economy, he said.

    “Now is not the time to insist on massive cuts to investments that have helped drive our economy, including the hundreds of millions of dollars in cuts that many Republicans want to take from successful job-creating clean energy programs,” Obama said, “investments that have finally, in some places, made clean power from the sun cheaper than conventional power from utilities.”

    It had to be a hard-to-hear message for NV Energy CEO Paul Caudill, who spoke just ahead of the president. His utility is in a tense face-off with Nevada solar advocates over its proposal to reduce the nationally embattled net energy metering policy crucial to the rooftop solar value proposition.

    “NV Energy needs to get real,” Senator Reid, whose age and health make a 2016 Senate run unlikely, warned in a private session earlier in the day. “It is not 1888. Customers want choice. If NV Energy continues on this path, they will lose on the battlefield of public opinion and the courts will also ultimately decide they are wrong.”

    President Obama on the economics of renewables

    It is impossible to overstate the significance of solar becoming price competitive with utility-provided electricity, the president said. “For decades we have been told it doesn’t make economic sense to switch to renewable energy. Today that is no longer true.”

    He described big renewables buy-ins from major corporation such as Google, Apple, and Costco. “Walmart has the most installed onsite solar capacity of any company in America," he said. "They are not in the business of giving away money.”

    The commitment of these companies should be cause for hope in the climate fight, he added, but to get to the renewables goals his administration has set, “we have to triple where we are today — so I am here to give you hope, but not complacency.”

    He described a new initiative from DOE to fund the Property Assessed Clean Energy (PACE) program that will allow homeowners to obtain solar financing secured by their mortgages and repay the loan through their energy bill savings.

    “It will allow more Americans to join this revolution with no money down,” Obama said. “You don’t have to share my passion for fighting climate change. Americans are going solar not because they are treehuggers, though trees are important, but because they are cost-cutters. Solar isn’t just for the green crowd anymore — it’s for the green eyeshade crowd, too.”

    Resistance and change

    Solar is less than 1% of the U.S. energy mix and wind is only about 5%, but together they were over half of the new generation capacity built in 2014, the president said. “We see the trend lines. We see where technology is taking us, we see where consumers want to go.”

    But fossil fuel interests, formerly unrestrained advocates of a free market, are suddenly opposed to choice in the marketplace because “solar is what people want to buy,” he smiled. “That’s a problem.”

    The president acknowledged Tea Party members who, in joining a Green Tea Alliance with environmentalists, stayed true to their free market ideology. “This is not and should not be a Republican versus Democratic issue,” he said. “If you care about the future of our children and grandchildren, you should care about it.”

    For decades, he explained, “utilities generated power, usually by burning fossil fuels, they ran lines to homes and businesses, and we paid for it. It wasn’t exciting. There wasn’t a lot of innovation. And we didn’t think about much about it until the bill came. And the economy grew under that model."

    But that has all changed, the president said. With smart technologies, customers can understand their energy use, change their habits, use energy more efficiently, and save without great sacrifice.

    “That empowers us to generate our own energy or store it in battery packs or sell it to the grid," he said. "That is power. That is the future. It is happening now. It is like evolving from the telegraph to the smart phone in less than a decade.”

    The president commended the utilities that are adapting their business models “to seize the opportunities of this emerging reality.” He called outCPS Energy of San Antonio for its rooftop solar program, Southern Company for its partnership with Nest and Tesla on energy storage, and Oklahoma Gas & Electric for its smart meter rollout.

    The rapid change is also drawing protective resistance from “some fossil fuel interests” dedicated to an “outdated status quo,” he said. But utility CEOs may have found solace in the president’s call for addressing “legitimate issuesaround how a new distributed system can work and how to deal with the costs.”

    There is no legitimacy, however, in “massive lobbying efforts backed by fossil fuel interests or conservative think tanks or the Koch brothers” against consumers’ rights to choose renewables, the president said. “That is not the American way. That is not progress. That is not innovation.”

    Obama echoed Senator Reid’s earlier attack on NV Energy. “The utility business model made sense a long time ago,” Reid said. “But today consumers would rather pay to make their homes more efficient than for utility electricity.”

    Utilities thinking of clean energy as a burden,” Reid said, makes as much sense as the Washington Nationals benching star player Bryce Harper. “Utilities must not have a stodgy commitment to the status quo. They must seize the clean energy opportunity or consumers will suffer.”

    There is something big happening

    President Obama framed the fight over energy as a question of whether the “big polluters” control the system or consumers have the “freedom to choose,” pitting “old ways” against new business models.

    “This is about the past versus the future and America believes in the future," Obama said. "But to make that future real, we have to have everyone: Utilities, entrepreneurs, workers, businesses, consumers, energy regulators, treehuggers, Tea Partiers. Everybody has to seize the opportunities before us.”

    Some utilties that have chose to disrupt themselves have already moved in the direction the president and Senator Reid described. In particular their comments fall in line with NRG Home’s organizing principle, as described recently to Utility Dive by CEO Steve McBee.

    “The company’s strategy, value proposition, and value creation are aimed at figuring out what the customer wants,” McBee explained. Companies that don’t understand what is happening are struggling, while companies that are empowering consumers are seeing success.

    “There is something big happening in America,” President Obama said. “For the first time we can actually see what our clean energy future looks like.” If the opposition claims it is a bad thing, “we have to be able to politely but firmly say ‘Sorry, we are moving forward.’”

    It is “an age old debate in America between the folks who say ‘No we can’t’ and the folks who say ‘Yes we can,’” Obama said. “America always comes down on the side of the future. We have always been a people who reach, proudly and boldly and unafraid, to that more promising future. We refuse to surrender the hope of a clean energy future to those who fear it and fight it. And sometimes provide misinformation about it.”

    They underestimate what the American people are capable of, the president said.

    “This generation of Americans is hammering into place the high-tech foundations of a clean energy age. Like the Americans who harvested the power of the atom, they are harvesting the power of the sun. That is what Americans do. You,” he said to the clean energy advocates in the summit’s audience, “are doing it every day, and I am going to be right there beside you.”

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    ORIGINAL REPORTING: Demand flexibility and the power delivery transformation

    How demand flexibility is about to transform electricity delivery; Automated energy efficiency, dubbed 'flexiwatts,' could change how we consume energy for good

    Herman K. Trabish, August 26, 2015 (Utility Dive)

    Solar and battery storage are commonly noted as the biggest threats — and opportunities — for the utility business model, but a new report shows that when consumers use their electricity may matter just as much to utilities as if they produce it themselves.

    The potential for utility customers to dramatically reduce their energy consumption with less than a $1,000 dollar investment in home energy management devices could put a big dent in utilities’ bottom lines unless they figure out how to leverage the new technologies in a way that benefits both consumers and themselves

    “The key to changing the balance of power between utilities and their customers is the customers' ability to control when and how they use electricity and for that demand flexibility is very important,” explained Rocky Mountain Institute (RMI) Principal James Mandel, co-author of the newreport "The Economics of Demand Flexibility; How “Flexiwatts” Create Quantifiable Value for Customers and the Grid."

    Flexiwatts come from demand flexibility (DF), which is using “communication and control technology to shift electricity use across hours of the day.”

    The premise is to use smart technology to move things like air conditioning, water heating, and electric vehicle charging to times when load is lower and electricity is cheaper. Devices now have the capability to control those functions and can be programmed to know when the lower price periods are.

    “Demand flexibility need not complicate or compromise customer experience," RMI reports. “Technologies and business models exist today to shift load seamlessly while maintaining or even improving the quality, simplicity, choice, and value of energy services to customers.”

    This is the third paper in RMI’s series on how solar PV and batteries are can lead to load defection by electricity users and, ultimately, grid defection by customers if utilities do not adjust.

    The first analysis predicted increasing load defection, which is the growing use by customers of electricity they generate with their onsite distributed generation and save in their onsite storage.

    The group also forecasted the possibility by the 2020s and 2030s of increasinggrid defection, which is customers moving to 100% self-supply. That could happen, the papers suggested, if utilities’ only response to falling costs for distributed energy resources [DERs] like solar PV plus batteries is increased electricity rates.

    A utility business model that accurately values DERs "can potentially lower system wide costs while contributing to the foundation of a reliable, resilient, affordable, low-carbon grid of the future,” the load defection study explained. But if utilities’ plan for the future is just to build more infrastructure on both sides of the meter, their costs could be significant.

    Customers are going to invest in DERs, Mandel said. If utilities don’t send the right price signals, customers will invest “in a way that serves their own best interests instead of a way that serves system-level best interests.”

    The money in demand flexibility

    To make demand flexibility work, customers must have some form of time varying pricing, Mandel said. It could be time-of-use pricing, which increases the price of electricity during the highest priced daily periods. Or it could be real-time pricing, which sets hourly electricity prices, or critical peak pricing, in which the grid operator reserves the right to increase the price sharply at certain peak hours.

    “The best pricing is pricing that reflects utility costs,” Mandel said. “Real time pricing is an example of that. Demand charges sometimes are and sometimes aren’t.”

    Technology specific pricing is shortsighted, he added. “Pricing consumers can use to their advantage should be an option for all customers.”

    Customers can have demand flexibility with minimal investment, Mandel said in talking about the new analysis. With 65 million electricity customers already on some kind of time varying rates, the savings could be substantial.

    The paper assumes only four shifts, all relatively uncontroversial, in electricity use: The use of smart thermostats and programmable timers on clothes dryers, EV chargers, and water heaters.

    The total cost of such a system would likely be less than $1,000. With it, the analysis estimates, “demand flexibility could offer customers net bill savings of 10% to 40%.”

    RMI modeled net bill savings in a variety of real-world utility scenarios. For the Commonwealth Edison real-time pricing scenario, consumers were predicted to save $250 million per year, a 12% savings. For the Salt River Project residential demand charge scenario, it was $240 million per year, a 41% savings. For a proposed Hawaii Electric Companies no-export-compensation for solar rate, it was $110 million per year, a 33% savings. And for Alabama Power’s avoided cost compensation for exported PV rate, $210 million per year, an 11% savings.

    These bill reductions could put a dent in bottom lines across the electricity delivery system. But by adapting to what customers are likely to do anyway, utilities and system operators could save much more. They can “avoid $9 billion per year in traditional investments, including generation, transmission, and distribution,” the analysis shows.

    Another $4 billion in savings is available from optimizing for hourly energy prices and from using demand flexibility for ancillary grid services. In all, the RMI researchers concluded that about $13.3 billion per year could be saved across the nation if demand flexibility practices took hold.

    “The $13 billion per year saved from the projected $80-plus billion in annual grid investment is a conservative estimate," the paper reports, "because we analyze a narrow subset of flexible loads only in the residential sector, and we do not count several other benefit categories."

    While U.S. electricity demand is flat to fading, the country is expected to spend an estimated $1.5 trillion over the next 15 years on grid infrastructure because of an increasingly “peaky” demand profile, explained RMI Transportation and Electricity Manager Jesse Morris. In the past, the solution has been fast-ramping fossil fuel “peaker” plants. More recently, there is some use of grid-scale storage.

    “That is supply flexibility,” Morris said. “This paper says forget about supply flexibility and turn demand down with these kinds of smart devices. It is much cheaper. Our calculations show that with just the four devices, we can save 13% of that $1.5 trillion.”

    Whether it is peaker plants or grid-scale storage, this is a cheaper asset than supply flexibility, Mandel added. “Grid investments are likely to raise prices and increase sunk costs, whether they are for traditional or renewable central station generation. Cutting investments with demand flexibility saves consumers money. Using both supply and demand flexibility is a smarter way to run a grid.”

    Flexible demand and customer-sited solar

    What utilities must recognize, the analysts said, is that while widespread solar-plus-storage is likely years off for many of them, demand flexibility is available to customers now and makes load defection an increased reality.

    Demand flexibility is a critical third technology along with solar and battery storage, Mandell said. “For many of the things batteries can do for a customer, it can do them much cheaper.”

    Demand charges are already common for commercial-industrial customers and are increasingly being imposed on residential customers, Mandell said. A residential demand charge imposes a bulk fee, often between $10 and $50, for every kilowatt the customer consumes during the highest 15 minute or 30 minute period of usage during the month.

    Demand charges make battery storage an economic option even at today’s high prices and limited capacities. But demand flexibility can provide more of that same service today at a much lower cost.

    “In our load defection analysis, there were timelines for customers to self-generate a portion of their electricity,” Mandel said. “Those timelines are accelerated by five to ten years if you include demand flexibility as a third resource for those customers.”

    Where utilities are fighting solar PV with cuts to net energy metering or demand charges, demand flexibility makes it a more economic option because it allows the use of more of the solar kilowatts on site.

    In the grid defection context — completely cutting the cord from the utility — demand flexibility dramatically lowers the cost in combination with PV and batteries.

    In the load defection scenario, demand flexibility helps customers use as much as 90% of the solar energy-generated electricity on site.

    “It is a way for a customer to manage their solar generation on site as opposed to relying on things like net metering to make their economics work out,” Mandell said.

    “Instead of buying a battery, it is possible to make sure appliances turn on when the sun is shining and not when it is not,” Morris added. “That can be done with automation and no sacrifice of comfort. It provides the same service as the battery without the battery.”

    How utilities and regulators can respond

    The opportunity is available equally to vertically integrated investor owned utilities, deregulated transmission and distribution providers, and retail electricity providers in deregulated markets. The keys are offering rates that encourage changes in customer behaviors and to take advantage of the changes they make, the paper reports.

    Utilities need to understand flexiwatts as a way to get to grid cost reductions, not just a threat to revenues. They can then construct rates reflecting utility marginal costs to “ensure that customer bill reduction (and thus, utility revenue reduction) can also lead to meaningful grid cost decreases.”

    Having taken these steps, utilities should be able to see where demand flexibility will take them and “harness enabling technology and third-party innovation” to build customer-facing business models that target both lower bills for their customers and reduced sunk costs.

    State regulators can support utilities in making a transition by pushing them to see demand flexibility as an opportunity instead of a threat, the paper explains. They can frame demand flexibility as “a potentially lower-cost alternative to a subset of traditional grid infrastructure investment.”

    They can also support the introduction of new rate structures that balance “the potential complexity of highly granular rates against the large value proposition for customers and the grid” and facilitate utility-private sector partnerships likely to lead to innovation.

    “Given the benefits,” the paper says, this “should be a near term priority.”

    It is, Mandel added, “economic today with technology priced very conservatively. And the rate structures exist today. It is a big opportunity and a cost-effective opportunity.”

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    Wednesday, May 25, 2016

    ORIGINAL REPORTING: Why can't utilities innovate like startups?

    Why can't utilities innovate like startups?; They could if regulators let them.

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

    It seems obvious to say that utilities are not known for their innovation. But a new white paper produced by investor-owned utilities and private sector stakeholders suggests that may be because regulators are holding the industry back.

    The working group that produced the paper could easily have been adversarial but there was a surprising amount of accord, the executive who helped lead the process told Utility Dive.

    With end-to-end committed participation by Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and a range of grid-associated businesses, the working group developed a collective vision for the California grid in 2030, said Advanced Energy Economy (AEE) Sr. VP Steve Chadima.

    "A transformation of the grid is underway,” reports AEE’s Toward A 21st Century Electricity System In California. Its roles and functions have already changed. And to accommodate the change, utilities are moving to provide new services and “enable a more integrated, ‘plug-and-play’ electricity system.”

    To sustain the transition and achieve that 2030 vision, the state’s policymakers and regulators must lead utilities and stakeholders in parallel pursuit of innovation in product and service delivery; system design and technology; and regulatory frameworks, incentives and revenue mechanisms.

    “There is a natural tendency for regulators to be cautious because they don’t want utilities experimenting with ratepayer dollars,” Chadima said. “But that is a foreign idea to anybody in the private sector. They take risks every day.”

    The regulatory process is not conducive to innovation but utilities have recently begun to think not about ratepayers, but about customers. “Customers want to have and make choices,” Chadima said.

    Utilities have had, and many still do have, a lock on the relationship betweenthe customer and the electricity, Chadima said. But the working group found that is changing in California and will soon be changing elsewhere.

    The challenge is getting regulators to stop thinking about ratepayers and instead think in terms of customers, Chadima said. “Then they will start to think about customer choice.”

    “There is very strong agreement that utilities need to be able to experiment more,” Chadima said. “And there should be incentives for utilities to embracenew technologies and new services.” But they need regulatory approval to do so.

    “Utilities and regulators are not known to be nimble and they may not know what their customers want,” said former Xcel Energy executive and currentCenter for Energy and Environment Policy and Communications Director Mike Bull. “The way to find out is to be able to offer services on a pilot basis.”

    To free up utilities to innovate, Bull wants regulators to establish official pilot program guidelines. It can take 18 months to get a program through the regulatory process and almost as long to discontinue an unsuccessful one, he explained. Guidelines like those he proposed for Minnesota’s cutting edge e21 Initiative could change that.

    An experimental utility project would not be likely to “put ratepayer dollars at risk for fly-by-night things” if it met commission-approved standards that were pre-vetted by all stakeholders, Bull said. A pilot might then be put in place without a lengthy and costly regulatory review.

    The framework

    The AEE working group called for California regulators to explore two different operational models for utilities, either of which would sustain the utility’s role as the distribution system operator. One transforms it into a distribution system platform. The other makes the utility an Independent Distribution System Operator (IDSO).

    The group also proposed two different, rather technical market operation and pricing models, as well as three different and equally wonky utility revenue models.

    To define and prioritize the viability of these competing ideas, the working group recommended regulators identify issues that impede but could enablenew business models, consider the impact of the changes on regulated markets and competitive markets, and streamline and integrate the regulatory process.

    “The paper offers recommendations but some, like pricing models and revenue models, are not singular answers,” Chadima acknowledged. “There was no ‘best pricing model’ and ‘best financing model.’ Instead we offered a range of models.”

    The working group brought together people who have long debated these issues in regulatory proceedings, Chadima said. Developing concrete proposals that describe points of agreement could streamline future proceedings.

    “Things happen very rapidly in the marketplace but regulatory proceedings may take 18 months. By then, technology has changed and we are on to something else,” Chadima said. “At some point down the road, there will be disagreement before regulators on these things. But because of this work, the disagreement will be more on timing and intensity than on direction.”

    Of the working group’s ten recommendations (see the end of the article for all ten takeaways), many participants focused on two concepts as the most important, Chadima said.

    The first was creating a comprehensive framework to get a fully integrated solution. The way it is currently done, with work on separate issues in separate dockets, is like asking different people to design different parts of a car but preventing them from collaborating, explained Chadima.

    “The parts might be great but they might not fit together,” he said. “The point is to find ways to encourage systemic thinking and get above the individualdockets and figure out how they fit together.”

    The second key recommendation was creating new incentives to achieve the things stakeholders and policymakers decide they want. An example, Chadima said, is time-differentiated rates “to encourage people to use electricity when there is more on the grid and conserve when there is less.”

    Utilities as innovators

    Utilities have developed a “culture of caution” in response to limits imposed by regulators, policymakers, laws, and consumer advocates, Chadima said.

    But they also see “the entire way they do business and relate to their customers and to the grid is changing and the choice is theirs to either fight it and eventually find themselves taken over or to embrace change and figure out how to be relevant in this new world.”

    The working group agreed there is a role for utilities, Chadima said. “This is not about destroying the utility and getting everyone off the grid.”

    The vision is for utilities to keep their role as distribution system operators. “They will be an intermediary, getting content and services from the grid and providing services to their customers, uploading as much as they are downloading, in a much more dynamic world.”

    That is why there was so much agreement on recommendation 8: “Accelerate the pace of regulatory review and allow utilities to take reasonable risks toencourage innovation and entrepreneurship and accelerate commercialization of new products and services.”

    “Utilities see they need to change,” Chadima explained. “That is why they need the freedom to experiment.”

    When invited to innovate in the recent California Public Utilities Commissiondistributed resource plan (DRP) docket, all three of the state’s IOUs demonstrated aggressive entrepreneurial impulses.

    The commission asked that the DRPs include demonstration projects that dovetailed with smart grid deployment plans and met minimum cost and cost-effectiveness criteria.

    They also had to meet very strict technical requirements and be ready for implementation, in conjunction with identified Load Serving Entities, third-party DER providers, and DER technology vendors, within a year of regulatory approval.

    SCE proposed two field pilots. One would demonstrate how an optimal location could be selected to allow the use of multiple distributed energy resources (DERs) that would meet area needs at a minimum cost. The second would demonstrate how a dedicated control system could manage five circuits at the distribution system level to optimize DER dispatch at a high penetration.

    PG&E proposed a micro-grid pilot project for San Francisco’s Angel Island State Park as an alternative to the costly replacement of an undersea cable. It would include an optimal DER portfolio "running 24 × 7 and 365 days," PG&E said, and test whether the micro-grid could be more cost-effective and reliablethan the cable.

    “It is not about 3-year plans and giant flow charts anymore. Utilities want to take some risks and try new things,” Chadima said. “They need a regulatory framework that allows them to try things, see if customers respond, and, if they don’t, get feedback and figure out what a new approach might be.”

    The regulatory debates will not end, Chadima said. As the working group participants discovered in discussing pricing and revenue models, there are decisions the commission will have to make. “There are some very strongly held beliefs about what utilities should be able to spend ratepayer money on.”

    From the working group's paper:

    To summarize, the Working Group offers these 10 key recommendations to help the State of California achieve a 21st Century Electricity System:

    1. Develop a comprehensive framework that integrates/coordinates the existing regulatory proceedings

    2. Restructure/align/create new incentives to achieve the desired outcomes while maintaining the long-term viability of the utility and recognizing the value of the grid

    3. Develop new market structures that enable two-way market signals to allow customer participation

    4. Encourage data exchange and circuit-level coordination of available grid and customer resources

    5. Utilize standards and protocols, ideally drawing from National standards, to ensure interoperability of devices located on the utility side of the meter and on customer premises

    6. Assess what is appropriate for the regulated vs. competitive market and how the two would interact as the market evolves

    7. Encourage training of the workforce that will develop the skills needed for the 21st Century Electricity System

    8. Accelerate the pace of regulatory review and allow utilities to take reasonable risks to encourage innovation and entrepreneurship and accelerate commercialization of new products and services

    9. Examine the role of rate design in helping to achieve the long-run financial integrity of the grid as a platform

    10. Examine the functionality and enabling technologies that will be integral to the distribution grid of the 21st century

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    ORIGINAL REPORTING: How Warren Buffett's bet on an Energy Imbalance Market in the West is paying off

    How Warren Buffett's bet on an Energy Imbalance Market in the West is paying off; The market is proving that regionalism has its benefits.

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

    UD-ISO-EIM-1-Q2-2015-08-13-2015

    Led by a partnership between California’s grid operator and Warren Buffett-owned utilities, a few Western balancing authorities are daring to break out of their usual lonesome cowboy role and ride with a posse of electricity providers. They are making millions for themselves and their customers by doing so.

    For decades, individual balancing authority areas (BAAs) in the Western U.S. operated independently to keep load and generation balanced. In the East, regional transmission operators and independent system operators developed interlocking systems with shared resources that make reliability a much easier lift.

    In the fall of 2014, the California Independent System Operator (ISO) and the utilities of PacifiCorp, a subsidiary of Warren Buffett's Berkshire Hathaway Energy (BHE), launched an Energy Imbalance Market (EIM) to better manage system imbalances across regions.

    “This EIM asks whether a system operator can manage imbalances in load and generation regionally so if one balancing area is up and one is down, the operator can net them against each other and not move generation to balance each individually,” explained BHE U.S. Transmission President and CEO John Cupparo.

    The answer to Cupparo’s question is a resounding “yes,” according to the just-released Benefits for Participating in EIM report from the ISO.

    It shows EIM benefits for Pacificorps East (PACE) and West (PACW) and the ISO reached $10.18 million in Q2 2015, while total gross benefits for the eight months of the EIM operation have been $21.41 million.

    These numbers validate estimates made before the launch. They provide confidence that benefits predicted when NV Energy, another BHE subsidiary, joins this fall will be realized. They also boost expectations that returns will be even higher when Arizona Public Service and Puget Sound Energy join the market in 2016.

    “This is clearly a ‘the bigger, the better’ situation in terms of optimizing the system,” Cupparo explained.

    Looking back

    For decades, each balancing area equilibrated load and generation going into each hour and adjusted its generation stack as circumstances imposed in order to stay in balance, Cupparo said.

    The Western Electricity Coordination Council (WECC) was tasked with keeping critical transmission paths and intersections between balancing areas maintained so the overall system stayed in balance.

    “But as renewable resources have penetrated the system, causing deviations in any given hour, with wind moving up and down and solar coming in and out, it has changed the dynamic and challenged utility system operators’ ability to manage inside their balancing areas,” Cupparo said.

    California’s grid operator has long recognized the value in a wider and more diverse system. “If we have regional collaboration and we are able to move energy to our neighbors and accept energy from our neighbors to balance the system, it helps us a great deal,” agreed Angelina Galiteva, one of five Governors on the California ISO Board.

    The latest data

    “One of the important contributors to the EIM benefit are transfers, which allows lower cost supply from one BAA to meet demand in another. As such, the transfer volume is a good indicator of a portion of the EIM benefit,” the ISO quarterly report explains.

    Utilizing the ISO’s state-of-the-art market software system, the EIM has been making such transfers in five minute (real time dispatch, or RTD) and fifteen minute (fifteen minute market, or FMM) increments. This report is the first to capture the granularity of RTD transfers.

    Total transfers for April through June 2015 were approximately 260,452 MWh from PacifiCorp to the ISO and 35,368 MWh from the ISO to PacifiCorp. Transfers can be negative if RTD transfers flow in one direction and FMM transfers flow in the other.

    Because only FMM transfers were used to calculate the Q1 2015 benefit of $5.26 million, the ISO did an FMM-only calculation for the Q2 2015 benefit which came to a comparable $6.12 million.

    The 66% higher benefits through the inclusion of the RTD market in the calculation, the ISO reports, is due to “the added transfer volume and the larger price difference between PacifiCorp and the ISO in the five-minute intervals.”

    The new report refines the allocation of greenhouse gas emissions adder payments from the ISO to Pacificorps but does not alter the total numbers.That information was referenced but not detailed in the report. It is likely to become more vital once the Clean Power Plan is in place and transfers of GHGs go to state emissions calculations.

    The calculation of the EIM benefit also includes the ISO’s avoided renewables curtailment, a crucial feature of an EIM.

    “Having a bigger footprint means being able to balance renewables with our neighboring states and helps us avoid over-generation,” Galiteva explained.

    This will become even more crucial as California rapidly adds renewables to its generation mix to meet the 50% renewables by 2030 mandate now working its way through the state legislature. “Hitting 40% and moving toward 50%, we are looking at 800 to 1300 MW of curtailed renewables, which we don’t want to do,” Galiteva said.

    An avoided renewables curtailment benefit is earned if renewables generation in the ISO is transferred to Pacificorps but would have been curtailed in the absence of that transfer. It is a cost savings benefit and can count as a GHG reduction and earn a renewable energy credit.

    The total avoided renewable curtailment volume for Q2 2015 was 3,629 MWh, which included 1,474 MWh in April, 1,253 MWh in May, and 902 MWh in June.

    “Assuming the avoided renewable curtailment displaces production from other resources at a default emission rate of 0.428 metric-tons CO2 per MWh,” the ISO reports, “the avoided curtailment displaced an estimated 1553 metric tons of CO2.”

    Looking ahead

    The EIM's regional approach means “avoiding the risk of stranded assets, being able to incorporate more renewables, being able to utilize assets in a much more optimized way, and being able to bring on facilities and bring on projects because we know we can use the energy or export it,” Galiteva said.

    It offers both increased reliability and increased flexibility for the system, she added. It also offers the opportunity to create a special tariff for flexible resources.

    Such a tariff would drive the growth of energy storage and dispatchable renewables, Galiteva said, “so that the resources that come online are good grid citizens and are able to respond to ISO controls and ramp up and ramp down.”

    Though a regional construct, an EIM would also favorably impact local economics. “Local transmission capacity additions that allow new renewable generation to come online become more valuable with an EIM in place because it allows the local generation to not only be a player locally but to be a player regionally,” she said.

    By quantifying the benefits of regional participation, the ISO EIM’s $21 billion in benefits during its first eight months sets the stage for much more, Galiteva believes.

    It limits the amount of needed transmission in the short term but in the long term it helps identify where asset and transmission additions are needed and quantifies their value, Cupparo said. “Down the road, the EIM benefits can grow if we can bring incremental resources on without having to think about how the system will be managed.”

    “Pacificorps has joined, NV Energy is joining, Puget Energy and APS are coming on, and others are calling to learn more every day,” Galiteva said. “And with more regionalism, we have more ability to reliably absorb higher penetrations of renewables.”

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    Tuesday, May 24, 2016

    TODAY’S STUDY: On The Path To SunShot – Utilities And Distributed Solar

    On The Path To SunShot – Utility Regulatory and Business Model Reforms for Addressing the Financial Impacts of Distributed Solar on Utilities

    Galen Barbose, et. al., May 2016 (National Renewable Energy Laboratory)

    Executive Summary

    Net-energy metering (NEM) with volumetric retail electricity pricing has enabled rapid proliferation of distributed photovoltaics (DPV) in the United States. However, this transformation is raising concerns about the potential for higher electricity rates and cost-shifting to non-solar customers, reduced utility shareholder profitability, reduced utility earnings opportunities, and inefficient resource allocation. Although DPV deployment in most utility territories remains too low to produce significant impacts, these concerns have motivated real and proposed reforms to utility regulatory and business models, with profound implications for future DPV deployment.

    This report explores the challenges and opportunities associated with such reforms in the context of the U.S. Department of Energy’s SunShot Initiative. As such, the report focuses on a subset of a broader range of reforms underway in the electric utility sector. Drawing on original analysis and existing literature, we analyze the significance of DPV’s financial impacts on utilities and non-solar ratepayers under current NEM rules and rate designs, the projected effects of proposed NEM and rate reforms on DPV deployment, and alternative reforms that could address utility and ratepayer concerns while supporting continued DPV growth. We categorize reforms into one or more of four conceptual strategies (Table ES-1). Understanding how specific reforms map onto these general strategies can help decision makers identify and prioritize options for addressing specific DPV concerns that balance stakeholder interests.

    Reducing compensation to DPV customers.

    Recent efforts to address stakeholder concerns about the impacts of DPV have revolved largely around reforms to NEM rules and retail rate structures. These include, for example: new or increased charges for DPV customers, minimum bills, demand charge rates for DPV customers, reduced compensation for electricity exported to the grid, reduced compensation for all DPV generation under two-way rates, and transfer of renewable energy certificate ownership to the utility. Although such reforms can address the concerns of both utility shareholders and non-solar customers and are often relatively straightforward to implement compared to more fundamental reforms to utility business models or markets, they accomplish their objectives only by constricting DPV customer-economics and deployment. They are thus largely a zero-sum game. Community solar is one possible exception because its economies of scale may allow for compensation at prices below retail rates, while maintaining customer-economics comparable to rooftop DPV with full NEM.

    To demonstrate the deterioration in DPV customer-economics that could occur if, in particular, NEM were eliminated, we compare the payback period of DPV systems with and without NEM, based on original analysis described further within the main body of the report. In the latter case, we assume that DPV generation exported to the grid in each hour is compensated at wholesale electricity prices, rather than at retail rates. As shown in Figure ES-1, elimination of NEM would increase the payback period for residential DPV systems by 1.4–8.9 years across the six illustrative states shown, depending on the state and the size of the system. Elimination of NEM would erode the customer-economics of commercial DPV as well, though only in cases where significant grid exports occur and where volumetric rates under the prevailing retail electricity tariff are substantially above wholesale electricity prices. As other studies have shown, customersited storage and demand flexibility can help DPV customers insulate themselves from such changes, though in doing so would also thwart the effort to stem utility revenue erosion.

    Given the implications for DPV customer-economics, reforms to NEM rules could also significantly impact long-term DPV deployment levels. Under an extreme bookend scenario in which NEM is immediately eliminated across all states and replaced with the alternative compensation scheme described above, cumulative U.S. DPV deployment in 2050 would be roughly 20% lower than under a continuation of current NEM policies (Figure ES-2, left), based on original analysis described further within the main body of the report. Conversely, indefinitely extending and expanding NEM to all customers and states would lead to DPV deployment levels in 2050 that are 30% higher than under current policies (Figure ES-2, right). In both cases, the impacts are notably more pronounced for residential than for non-residential markets. Many other recent studies have also shown potentially significant impacts on DPV customer-economics and deployment from other kinds of retail rate reforms, such as timevarying pricing, demand charges, two-way rates, fixed customer charges, and minimum bills.

    Within the context of the SunShot Initiative, NEM and retail rate reforms represent significant risks to achievement of near-term cost and deployment goals as well as the longer-term legacy and impact of the initiative. Within the immediate timeframe of the SunShot 2020 cost-reduction targets, constraints on market growth could dampen the pace of soft-cost reductions driven by increasing industry scale and learning. Uncertainty in the outcome of NEM and retail rate reforms also exacerbates business risks for the solar industry and potential solar customers, inflating soft costs associated with customer acquisition and financing. Longer term, NEM and retail rate reforms could produce an outcome in which achievement of the aggressive SunShot 2020 cost targets could still fail to spur the initiative’s vision of dramatic, sustained DPV growth.

    Fortunately, several other strategies—as discussed below—offer the potential to address utility and non-solar customer concerns about DPV, without unduly constraining DPV customereconomics and market growth.

    Facilitating higher-value DPV deployment.

    Many reforms seek to address stakeholder concerns about DPV by facilitating higher-value DPV deployment. Certain retail rate reforms—such as time-varying, locational, and unbundled attribute pricing—could incentivize optimally sited and grid-friendly DPV, though these innovations generally increase costs to DPV customers and could require significant efforts from utilities to establish the value of DPV production and handle customer differentiation. Enhanced utility system planning can provide an analytical foundation for these pricing designs and for other mechanisms to preferentially direct DPV deployment toward locations or design characteristics that increase its value to the utility system. In addition, utility ownership of DPV assets may enable higher-value forms of deployment through optimized siting and operation. Community solar might also facilitate optimized siting and design and more readily enable deferral of distribution system upgrades. Over the longer term, major reforms to utility business models and retail markets (e.g., transforming electric utilities into energy services utilities and forming distribution network operators or transactive retail electricity markets) could facilitate higher-value DPV deployment through enhanced price signals or procurement processes.

    Broadening customer access to solar.

    Bringing solar to traditionally underserved customer classes can diffuse concerns about cost-shifting and potentially regressive effects of NEM; indeed, one reason why energy efficiency programs are less susceptible to such concerns is that opportunities for participation are broad and often include programs targeted to low-income or other hard-to-reach customer segments. Among the reforms highlighted in this report, community shared solar offers perhaps the most explicit path toward expanding customer access, if opportunities for participation are broadly available. Utility DPV ownership that is restricted to underserved customer segments may provide another pathway to expanding access to those customers, and it may minimize some objections over utility entry into a competitive market.

    Aligning utility earnings and profits with DPV.

    Under traditional cost-of-service regulation, DPV tends to erode utility financial performance via reductions in sales growth and deferral of traditional utility capital investments. Reforms can seek to realign utility financial incentives so they are neutral toward, or even produce utility shareholder benefits from, DPV growth. Such reforms are thus targeted at addressing utility shareholder concerns, in particular, but can exacerbate ratepayer concerns surrounding possible cost-shifting to non-solar customers. Some suggested reforms entail relatively “incremental” changes to utility regulatory and business models. These include decoupling and other ratemaking reforms to reduce regulatory lag, which already have widespread adoption and hold utility profits immune to DPV growth. Performance based incentives and utility ownership or financing of DPV assets could create positive utility earnings opportunities associated with DPV growth, and they have precedents, but they represent a greater departure from the traditional cost-of-service model. Finally, many novel conceptual utility business model and market reforms are intended to realign utility financial incentives vis-à-vis DPV, such as by reorienting utility profits around the provision of services rather than commodity sales of electricity.

    In summary, efforts to address concerns by utilities and non-solar customers about the financial impacts of DPV growth are unfolding across the country in a variety of forms. To date, much of this activity has centered on reforms to NEM rules and retail rate designs. This pathway has certain practical advantages because these kinds of reforms address concerns of both utility ratepayers and shareholders and can often be implemented in a relatively immediate fashion. However, these reforms are generally premised on reducing compensation to DPV customers and, as such, achieve their objectives only insofar as they constrict DPV customer-economics. Other reforms discussed in this report instead provide opportunities to address utility and/or ratepayer concerns about DPV without necessarily constraining growth of those resources—by focusing on facilitating higher-value DPV deployment, expanding customer access, and aligning utility earnings and profits with DPV growth. Some of these alternatives have already been adopted in some locations and are options for wider implementation by 2020, while others will unfold over a longer horizon. In either case, opportunities exist to preserve the long-term legacy of the SunShot Initiative by promoting a stable regulatory environment and utility business models that align DPV adoption with the continued provision of safe, reliable, and affordable electricity service.

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    QUICK NEWS, May 24: Portland, Ore, Bans Climate Change Denial From Science Classes; Wind Hits 100%-Plus Of Aussie State’s Power For 10 Hours

    Portland, Ore, Bans Climate Change Denial From Science Classes Portland School System Bans Teaching Materials That Cast Doubt on Climate Change

    Eric Chaney, May 23, 2016 (The Weather Channel)

    …Last week, the Portland Public School board unanimously passed a resolution which directs schools to ‘abandon the use of any adopted text material that is found to express doubt about the severity of the climate crisis or its root in human activities.’ …The resolution broadly calls for all Portland schools to ‘develop an implementation plan for climate literacy.’…Climate literacy is essential for the success of Portland Public Schools students, the resolution says, both as members of their communities and citizens of the world…Teaching climate change isn't always easy. A survey conducted by Science Magazine in 2014 found that although more than 95 percent of active climate scientists attribute recent global warming to human causes, only about half of U.S. adults believe the same thing…” click here for more

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    Wind Hits 100%-Plus Of Aussie State’s Power For 10 Hours Wind energy hits 100% of South Australia demand on Sunday

    Giles Parkinson, 24 May 2016 (RE New Economy)

    “…[On May 22, the wind energy-generated electricity supply met South Australia’s electricity] demand for more than 10 hours, from 1.40am to just before midday (11.55am), with a peak of 120 per cent of demand at 4.30am…[It is 40 per cent of the state’s installed capacity, but] with more wind energy projects in the pipeline that could more than double the current capacity, [there is a growing] need for more inter-connectors to other states…[W]hat’s interesting to watch is the comparison between South Australia and Queensland, the other state most reliant on gas as the marginal cost of generation…While gas is used to fill in the gaps between wind and solar in South Australia, it is used in Queensland to fill the gaps between the output of coal and system demand, minus the input of 1.5GW of rooftop solar. Queensland, apart from a few biomass power plants, has no large-scale renewable energy generation…In the past two weeks, South Australia’s average daily price has been cheaper than Queensland’s on eight days out of 14…” click here for more

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    Monday, May 23, 2016

    TODAY’S STUDY: A Review Of Alternative Rate Designs

    A Review Of Alternative Rate Designs; Industry Experience With Time-Based And Demand Charge Rates For Mass-Market Customers

    Aman Chitkara, Dan Cross-Call, Becky Li, and James Sherwood, May 2016 (Rocky Mountain Institute)

    EXECUTIVE SUMMARY

    There is a serious conversation unfolding around electricity rate design for mass-market (residential and small commercial) customers—both in the U.S. and internationally. New proposals are appearing for how to improve rates to meet emerging challenges (and opportunities) around environmental impact, customer engagement, bill management, reliability, and cost recovery. These proposals frequently generate debate and conflicting opinions between stakeholders.

    RATE DESIGN CHALLENGES

    Recent trends are forcing stakeholders across the industry to take stock of how customer needs are evolving and how that affects the electricity system. Customer load profiles are becoming more diverse while new technology is increasing potential customer capabilities. Existing default rates in the U.S. are simple—typically pairing a flat, volumetric energy rate with a customer charge. These rates have worked well enough but are proving inadequate in the face of recent trends, as they fail to provide price signals that reflect system costs and enable customer response. An expanded rate design toolkit is needed, but it is critical that solutions do not reduce signals for energy efficiency or be difficult for customers to understand and respond to.

    POTENTIAL SOLUTIONS

    Two types of alternative mass-market rate designs are often proposed to meet rapidly evolving customer needs in the near-term:

    • Time-based rates can provide more accurate price signals to customers, better reflecting the marginal cost of supplying and delivering electricity. These price signals may lead customers to change their consumption patterns to reduce both peak and total consumption.

    • Demand charge rates can provide a price signal to reduce peak demand and can potentially allocate peak driven costs more fairly. Customers may respond by changing their consumption patterns to reduce peak demand, flattening their load profile. These solutions can be important near-term steps in the ongoing evolution of rate design.

    Objectives of This Report

    To support informed decision making, this report provides a meta-analysis of numerous existing studies, reports, and analyses to support an objective assessment of the efficacy of time-based rates and demand charge rates for mass-market customers. The report:

    • Provides a structure for utilities, regulators, and stakeholders to design and evaluate time-based and demand charge rates.

    • Identifies major design choices required for each rate, and reviews options for those dimensions.

    • Identifies whether empirical data confirms (or refutes) the potential benefits of each rate, and notes where clear evidence is not available.

    • Determines best practices that can help achieve and maximize desired outcomes.

    • Highlights areas where further study is needed.

    RESEARCH INSIGHTS ON TIME-BASED RATES; RANGE OF FINDINGS

    Our review of industry experience with time-based rates finds that they can reduce customers’ peak consumption and total energy consumption without compromising customer acceptance (in terms of enrollment and retention). Empirical evidence shows that time-based rates have the potential to result in:

    • Peak load reduction of 0–50%

    • Reduction in total energy consumption of 0–10%

    • Customer enrollment rates of 6–98% and retention rates of 63–98% These impacts depend on key choices made in designing the rate.

    KEY DESIGN CHOICES THAT INFLUENCE IMPACTS

    The impact of time-based rates can vary widely, as evidenced by the wide ranges at left.

    This variation is influenced by key choices made along nine important design dimensions. Several of these dimensions have a particularly noteworthy effect on the efficacy of the rate:

    • Peak/Off-Peak Price Ratio is one of the strongest predictors of customer peak load reduction, as higher ratios send a stronger price signal to shift consumption away from peak hours—for instance, time-of-use rates with a 5:1 ratio tend to double the peak reduction compared to a 2:1 ratio.

    • Peak Period Duration and Peak Period Frequency have a significant impact on customer acceptance. Customers are less willing to enroll in a rate, and less able to respond once enrolled, where the peak periods are too long or when critical peak pricing events occur too often.

    • The Financial Mechanism is a strong driver of peak load reduction. Price-based rates can double the reduction achieved with rebate-based rates, which reward conservation but do not penalize consumption.

    • The Enrollment Method affects customer acceptance, where opt-in rates attract more-engaged participants, but opt-out (default) rates have enrollment rates 3–5 times higher than opt-in rates, as well as increased peak reduction.

    • Enabling Technology can substantially increase the peak load reduction by customers. Rates coupled with “active” technologies (which automate customer response) reduce peak load by an additional 10–20 percentage points compared to the same rate without technology.

    RESEARCH INSIGHTS ON DEMAND CHARGE RATES; RANGE OF FINDINGS

    Our review finds that there is comparatively little industry experience with mass-market demand charges relative to time-based rates. Limited empirical evidence is available to provide insight on the efficacy or impact of demand charges on any desired outcome beyond cost recovery. However, there is a serious debate and much theory about how they may affect customers’ peak consumption, total energy consumption, and acceptance.

    Claims regarding the impact of demand charge rates on these outcomes (positive or negative) are largely speculative. The industry needs to better align on what is currently known and unknown, and where further research will be most useful.

    KEY DESIGN CHOICES THAT INFLUENCE IMPACTS

    While there is a clear gap in the empirical evidence, our research suggests that there are key design choices that will determine the efficacy of the rate. Of the eight important design dimensions for demand charges (some of which differ from time-based rates), four are likely to be particularly influential:

    • The Cost Components & Allocation directly determine the magnitude of the demand charge price. Approaches range from including only customer-specific costs (e.g., service transformer) to including all costs associated with system infrastructure built to meet peak demand (e.g., including marginal generation and transmission capacity). The magnitude of the price will impact both peak consumption and customer acceptance, depending on whether customers are able to change behavior in response to the rate.

    • Peak Coincidence can provide a more-targeted price signal, where charges coincident with system peak may help customers understand when to reduce their demand. In contrast, non-coincident charges are assessed against customer demand at any time, regardless of whether non-coincident demand affects system costs.

    • A Ratchet Mechanism can help stabilize utility revenue by locking in a floor at a certain level for the customer’s demand bill, but the mechanism may remove customers’ incentive to reduce peak load, depending on how the ratchet is designed. • Enabling Technology may be the most important determinant of whether customers actually respond to a demand charge price signal. It is possible that sufficiently educated customers will respond by reducing peak demand, but technology that automates their response will reduce the possibility of customers not changing their behavior due to confusion about the rate.

    CONCLUSIONS

    RESEARCH TAKEAWAYS

    • Specific design choices are key to the efficacy of any time-based or demand charge rate. In particular, the accuracy of the price signal (e.g., cost components and allocation) and the ability for customers to respond (e.g., peak period duration or a ratchet mechanism) are critical design choices.

    • In theory, it may be possible to achieve similar objectives using either time-based rates or demand charges, but this remains unproven. Proposals often state similar objectives, including recovering costs while sending price signals that better reflect the drivers of those costs. However, it is unclear whether the two rate designs send equally effective price signals—more evidence on the impacts of demand charges is needed.

    • Regulators and utilities considering these alternative rates should incorporate identified best-practice design principles. Evidence shows effective time-based rates—particularly time-of-use rates—can be developed and widely deployed using design choices described in this report. While there is insufficient evidence on the impacts of demand charges, demonstration and evaluation projects can be implemented to gain experience.

    • Improved mass-market rates for consumption are necessary but not sufficient. Ongoing attention is also needed to develop improved pricing structures and compensation mechanisms that fairly represent the benefits and costs of distributed generation and other distributed energy resources. Although this report focuses exclusively on rates for consumption, a more complete transformation of electricity pricing will also include accurate and fair value pricing for on-site generation and similar customer-provided grid services.

    FUTURE RESEARCH NEEDS

    There are significant knowledge gaps related to both time-based and demand charge rates that the industry and researchers should address. Specific topics that emerged through this work include:

    • Evaluating rate impacts on total energy consumption

    • Identifying the impact of demand charges on key outcomes

    • Improving understanding of the relationship of rates and technology

    • Clarifying methods for including and allocating cost components

    Looking Ahead

    Moving toward time-based or demand charge rates is an important step in the evolution of more-sophisticated rates. While near-term improvements are critical, it is also important that the industry stay focused on longer-term goals for rate design. This can include:

    • Transitioning more-sophisticated rates from opt-in to default, as California is doing with time-of-use rates, and exploring opportunities to further evolve rate sophistication, such as by combining time-based and demand charge rates.

    • Developing new rates that provide greater pricing granularity to better signal value and enable response, both through behavior and with technology.

    • Developing new ways to manage the tension between maintaining a minimally complex customer experience and continuing to increase rate sophistication.

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