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

The new challenge: To make every day Earth Day.



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  • Weekend Video: Reindeer Stresses
  • Weekend Video: Pink Fracking
  • Weekend Video: Fighting Duke For Solar


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    Anne B. Butterfield of Daily Camera and Huffington Post, 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



    Your intrepid reporter


      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.

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  • Thursday, December 18, 2014


    A utility in the making: The municipalization of Boulder, Colorado; “The things that need to be done are not rocket science but you need to know how to do them.”

    Herman K. Trabish: August 27, 2014 (Utility Dive)

    The City of Boulder, Colorado, is fighting for its dream of a municipal electric utility.

    Xcel Energy, which now provides Boulder’s electricity, does not think city leaders are going about municipalization in a legal or practical way.

    “Xcel is waiting for us to stumble and we intend to show them we know what we are doing,” Heather Bailey, executive director of energy strategy and electric utility development for the City of Boulder, told Utility Dive. “The things that need to be done are not rocket science but you need to know how to do them.”

    Boulder's ambitious plan

    Bailey and Boulder’s transition team are getting input from investor-owned utilities, other municipal utilities, local experts, and the American Public Power Association. They have formulated a high-level, eighteen-month transition plan with seven major functional areas. And they have a 600-step to-do list.

    “To seamlessly integrate an electric utility,” explained the final report from PowerServices, Inc., Boulder’s municipalization consultant, the city must “manage multiple uncertainties and create a path forward” despite the fact that the Xcel-Boulder dispute remains a “complex process highly influenced by acquisition legal and regulatory proceedings.”

    The key objectives, PowerServices reported, are safe and reliable system operations, cost effective and reliable wholesale power, minimal transitional costs and customer impacts, and getting more renewables into the generation mix.

    These objectives will come through either of two scenarios. One foresees “coordination with Xcel Energy to provide wholesale power and services at acquisition (Day 1) until interconnection construction is completed (Day 2).” Power supply and operations would be stable over a gradual two-year transition period.

    Another foresees Boulder taking over “all aspects of utility operations immediately upon acquisition (Day 1) and prior to completion of interconnection construction.” In that scenario, Boulder would be on its own.

    “We are planning for the worst and hoping for the best,” Bailey said. “I suspect we will end up somewhere in the middle.” For now, her team is working to identify best practices and establish standards, procedures, and policies.

    The dispute with Xcel Energy

    The dispute over municipalization centers on Xcel-owned infrastructure within the Boulder city limits that the city believes should be turned over at a fair price through a district court condemnation proceeding.

    An October 2013 decision by the Colorado Public Utilities Commission (CPUC)ruled condemnation should be settled in a regulatory proceeding.

    “It is state law,” Xcel spokesperson Michelle Aguayo told Utility Dive. “The PUC made it very clear the Colorado Supreme Court has upheld that time and again.”

    It is not just what is best for Xcel Energy or Boulder, Aguayo said. “It is what is best for the grid and for all the customers of Colorado. They are looking at reliability, at safety, and at what state law has dictated.”

    The process seems to be “testing the relative importance of competing values,” explained Pace University Law School regulatory authority and former Texas regulator Karl Rabago. “The interests of a democratically convened local government in the health and welfare of its citizens” are set against “the property-and-investment-backed profit expectation interests of a corporation operating as a monopoly.”

    Sources who asked not to be named said Xcel’s dissatisfaction is with inadequate details provided by the city about the Xcel infrastructure it wants. The lawsuit prevented Aguayo from addressing that issue specifically but shetold the Boulder Daily Camera Xcel has “too many unanswered questions.”

    Xcel’s website echoes Aguayo, reporting that Boulder’s failure to settle forced it to take legal action.

    “The city has provided a detailed inventory to Xcel,” responded Boulder Senior Assistant City Attorney Kathy Haddock, though it cannot be publicly disclosed. “During negotiations, the city also provided Xcel a mapbook showing the locations of all Xcel facilities the city intended to acquire, and its negotiators had several meetings with Xcel."

    But first, jurisdiction must be established. “The PUC has ‘primary jurisdiction’ so even if the courts resolve the ultimate issues, there is an argument that the matter must be heard at the PUC,” Rabago explained. “The exception is that when there are clear issues of law and no real issues of fact, the courts are an acceptable place to start.”

    Boulder is ready for a five year battle that could go before the Federal Energy Regulatory Commission and Colorado’s Supreme Court, municipalization advocate Ken Regelson said.

    Xcel knows the utility must be operational by the end of 2016 or the city must ask voters for a third approval of the plan, so it is “throwing up as much legal dirt as it can to hold onto the $30 million per year in profits it earns in Boulder,” Regelson explained. “But they’re kidding themselves. We first got a 54% voter approval. And when Xcel spent millions trying to reverse that, we got a 62% approval. We know how to talk to Boulder voters and they want this.”

    The issue will also go back to Boulder voters if legal and regulatory proceedings set the value of Xcel's poles and wires higher than the initial ballot measure's $214 million limit. Boulder's path forward

    Heather Bailey is a veteran of regulatory complexities. She helped establish programs at the Public Utility Commission of Texas, was involved in creating a Lower Colorado River Authority transmission subsidiary, and consulted for NextEra Energy when it formed its transmission company. Her response to the dispute is to move ahead on plans for the municipal utility.

    Bailey’s Solar Working Group wants to expand the city’s privately-owned 14 megawatts of installed solar capacity and add community-owned solar gardens. They want to build a resilient distributed power supply through Boulder’s 26 energy-based local businesses. “A lot of them never got to do business locally because Xcel wouldn’t talk to them,” Bailey said. “We have begun creating partnerships.”

    Control of Xcel’s poles and wires is crucial, Bailey said. It is the only way Boulder can choose its own energy mix, structure its grid to incorporate micro-grids and energy storage, and make its own rules for where and how it can expand distributed solar and cogeneration. “We need that ownership,” she said.

    If they have to go back to voters, municipalization advocates can argue Xcel is using legal delays to hold on to profits the city could use to pay down debt, reinvest in infrastructure, inject into the local economy, or drive innovation, Bailey said. “Today we have no control over how to use it.”

    click here for more


    What happened to that national high voltage transmission system?; Clean Line, others still pioneering lines for remote renewables

    Herman K. Trabish | September 2, 2014 (Utility Dive)

    Once-bold calls for national high-capacity transmission to harvest abundant but remote U.S. wind, solar, and geothermal resources are now a distant whisper. But some developers are still pioneering upgrades for a fragile, somewhat balkanized electricity delivery system.

    “You can’t get enough clean energy from distributed resources,” said former Federal Energy Regulatory Commission (FERC) chairman and staunch distributed energy resources (DERs) advocate Jon Wellinghoff. “If you run the numbers, you find out we need these clean remote resources and transmission lines to get them to the load.”

    When DERs are interconnected to central transmission, the whole system becomes “more robust and more reliable,” Wellinghoff said recently in calling for an independent distribution system operator to streamline DER delivery. “Given the energy requirements of this country, we have to have both.”

    Calls for a national high voltage direct current (HVDC) transmission system began with the renewables expansion in 2006. But barriers were quickly identified.

    One of the first was that “nobody was in charge,” Wellinghoff said. FERC hasauthority to site interstate natural gas pipelines but very limited authority to site transmission lines. Local authorities at the state, county, municipal, and even tribal council level become involved. “No one is responsible for figuring out how to get the project done.”

    The 157 mile Roseland-Susquehanna line from Pennsylvania to New Jersey was stopped by one national park administrator’s objection to the replacement, on an existing two-mile right-of-way, of a 230 kV line with a 500 kV line, Wellinghoff recalled. Completion was delayed over six years, until $60 million in mitigation funds got the administrator to remit.

    In 2006, Wellinghoff proposed to Congress that if local jurisdiction failed,authority should fall to FERC after a year. “But it never went anywhere,” he said. Clean Line Energy in the heartland

    Clean Line Energy Partners (CLEP) is working on five lines “to connect the best resources in the country with load centers that don’t have access to them,” President Michael Skelly explained. “It is a very simple idea. The execution is quite complex. For five years, we have been going at it brick by brick, county by county, landowner by landowner, state by state.”

    Funded by National Grid and ZBI Investors, CLEP is developing four HVDC lines and one AC line. “With luck, we will break ground in the next couple of years. The Plains & Eastern (P&E) line to deliver Oklahoma wind to the Southeast is the best candidate.”

    Skelly’s team faces landowners, environmental groups, county officials, and state regulators as they work up a preliminary route. “By the time you are done studying possible routes, you have thousands of locations on a map that you want to stay away from.” After public feedback, a “refined route” must be permitted by state regulators.

    “A state commission can take over a year to decide if the benefits of the project outweigh the downside,” Skelly said. “Opponents file legal briefs, we respond, and there is a blizzard of paper. But you can’t rush public stakeholders. We are methodical. We work within the constraints of the process.”

    CLEP stresses the local benefits of its projects, such as suppliers with factories along their lines’ routes that create jobs. To satisfy landowners, CLEP pays 100% value up front as well as making annual per-power payments. And the team never stops communicating “what we are doing and why it is necessary,” Skelly said. “You can never communicate with enough people but we communicate with as many as we can.”

    The best response to local resistance is local support, Skelly said. Randolph County, Mo. Presiding Commissioner Susan Carter emphasized one CLEP project’s property taxes and jobs to state regulators and called for Randolph County “to be a part of America’s clean energy grid.” Cindy O’Laughlin and husband, owners of a Ready Mix concrete and trucking company, publicly championed the P&E line’s jobs. And Vicki McCune, director of a non-profit serving the Oklahoma Panhandle and bordering states, organized a “green letter writing campaign” to help the P&E line get public utility status.

    “Talk to people. Find champions. That is Chapter One of the playbook,” Skelly said. Tell your story. Answer all questions. Talk benefits. Correct misinformation.

    Are there fixes?

    The federal government could streamline the process, Skelly said. The DOE is considering the controversial use of its eminent domain power for both the P&E line and the Transwest Express line that would deliver Wyoming wind to Las Vegas and Southern California.

    “There is not clear consensus on infrastructure now and big changes in the relationship between the states and the federal government are unlikely,” Skelly said. “We are working with existing authority, whether it is federal, state, or local. We are not in the policy making business. We are just trying to get our projects done.”

    The energy content of Oklahoma wind is 3.4 times that of wind in the Southeast. That will make the harvest and delivery of it cost effective, Skelly believes. Power producers will pay for the line to carry their electricity at a return to CLEP investors, Skelly said, of “around $0.02 per kilowatt-hour.”

    “They will be competitive market disruptors,” said Exeter Associates Principal Kevin Porter, who does transmission research for Lawrence Berkeley National Labs. “The line will be the highway that delivers lower cost electricity and they will charge a toll to use it. But it is a very big capital expenditure with a fair amount of risk.”

    Several factors are imposing delays and “considerable uncertainty” in transmission right now, Porter explained. The biggest is depressed load growth, a hangover from the recession. “Most of these lines were based on electricity demand growth. The need now for new lines is almost non-existent.”

    The growth of distributed generation, low cost natural gas, state energy efficiency initiatives, and fulfilled state mandates are also dampening demand.

    The on-again, off-again federal production tax credit (PTC) adds to uncertainty. “The Bonneville Power Authority’s “open season” procedures put 4,200 megawatts of new transmission capacity into construction from 2009 to 2011, when the PTC was set, Porter said. “In the last two years, with PTC uncertainty, BPA hasn’t had an open season. There was no demand.”

    Despite the determination of CLEP and the TransWest builders, Porter doesn’t “see big multi-state projects happening in the near future.” Only if something big happens, like a commitment to fighting climate change, will transmission building stop “treading water,” Porter said.

    The increasing impacts of climate change and new EPA rules will put much more pressure on getting clean resources, Wellinghoff said. “People will have to understand transmission lines are necessary, in conjunction with distributed resources.”

    click here for more

    Wednesday, December 17, 2014


    The state of the U.S. wind industry (and what it means for utilities); Wind PPA prices now beat natural gas prices.

    Herman K. Trabish: August 25, 2014 (Utility Dive)

    The wind industry is facing strange times.

    A record amount of new capacity is in construction, much of it backed by utilities, but Congress may not renew the industry’s vital federal support.

    Without a production tax credit (PTC) and bigger state renewables mandates imposed on utilities, growth could stop cold—or record low prices might drive a utility-led renaissance.

    “Utilities are recognizing they can buy wind at $0.025 per kilowatt-hour or even $0.03 per kilowatt-hour and save on fuel expenses,” explained Research Scientist Mark Bolinger, co-lead author of Lawrence Berkeley National Labs’2013 Wind Technologies Market Report. “If they can do that without incurring capital expense or risk by offloading those to the developer using PPAs, there is little reason not to.”

    The state of the U.S. wind industry

    Growth faltered in 2013 because Congress was slow to renew the PTC. But it was finally renewed with an in-construction provision that will keep developers busy through 2015, according to the report. The unpredictability of Congress, natural gas prices, and innovation make growth beyond 2015 uncertain.

    Cumulative U.S. capacity grew only 2% in 2013, to 61,110 megawatts, on a $1.8 billion investment. China led the world in new capacity, with 16,088 megawatts, and cumulative capacity, with 91,460 megawatts, in 2013.

    Though wind has been a third of new U.S. electricity capacity since 2007, it was only 7% of new electricity capacity in 2013, as natural gas and utility-scale solar emerged. The U.S. got about 4.5% of its electricity from wind last year, while Iowa got 27%, South Dakota got 26% and seven states got over 12%.

    Data from grid operators’ 2013 interconnection queue foretells this year's construction boom. There were 114 gigawatts of wind being reviewed forinterconnections at the end of 2013. It was second only to natural gas and totaled 36% of all generating capacity being considered.

    Utilities own 13% of U.S. wind and independent power producers own 83%, with the remaining 2% owned by self-generators. Electric utilities were 2013’s dominant off-takers, owning 4% and buying 70% of the wind power produced. Merchant projects sold the rest into wholesale markets. That percentage could grow significantly with wind’s increasingly competitive price. Presently,utilities own 15% and buy 54% of all U.S. wind power capacity, with merchants accounting for 23%, and competitive market players taking the other 8%.

    The price of wind

    “Most of the PPAs signed in 2013 were, on a levelized basis, at $25 per megawatt-hour to $30 per megawatt-hour because of a combination of falling costs and higher capacity factors,” Bolinger said.

    The falling costs are attributable to technology advances and economies of scale. A turbine's cost in 2013 was between $900 per kilowatt and $1,300 per kilowatt. Wind’s 2014 installed cost is estimated at $1,750 per watt, down almost $500 from the 2012 installed cost.

    Whole-year average capacity factors now range to nearly 50% in some regions. That comes from technology advances allowing for taller towers, longer blades, more power production, and the harvest of lower speed winds. In 2012, turbines capable of utility-scale output from low to moderate winds made up half the new fleet; in 2013, they made up 90%.

    There was also downward market pressure on prices. “With the price of natural gas as low as it is, wind developers have to offer the low prices to compete," Bolinger said. "But they are not giving it away. They are earning a return and they are attracting investors.”

    The report compares near term wholesale electricity market prices, dominated by natural gas, to wind’s PPA prices. It is not an exact comparison because gas prices fluctuate while a PPA locks in wind’s price. “You have to consider the long term hedge value,” Bolinger said.

    That is why there were so many examples last year of utilities contracting for two and three times the amount of wind for which they issued RFPs, he explained. Examples reported by Utility Dive last year include:

    Austin Energy’s RFP for 200 megawatts ended with PPAs for 570 megawatts in the $23 per megawatt-hour to $33 per megawatt-hour range

    Westar Energy’s RFP for 80 megawatts ended with PPAs for 200 megawatts

    Public Service of Oklahoma’s RFP for 200 megawatts ended withPPAs for 600 megawatts at an estimated utility cost savings of $53 million in the contracts’ first year.

    The opportunity for utilities

    The expiration of the 2013 PTC leaves utilities with two ways to take advantage of wind’s present low prices, Bolinger said. The newest IRS guidance indicates PTC-qualified projects that are sold can retain the tax benefit, so utilities can still buy projects from independent developers. And PTC-qualified projects being built by developers on a merchant basis can be signed to PPAs at the current low prices.

    There are approximately 12,600 megawatts of PTC-qualified wind capacity under construction in 106 projects across 21 states, according to the American Wind Industry Association’s 1H 2014 market report.

    In Texas, only 18% of the 8,300 megawatts under construction have PPAs and the other 82% will be selling into the market. Of the 6,200 megawatts under construction outside Texas, 44% have PPAs, 26% are utility-owned and 30% will be selling into the markets. That is approximately 8,750 megawatts that could be available at $0.025 per kilowatt-hour to $0.03 per kilowatt-hour.

    “One way to think about wind right now is as a ‘no-regrets’ strategy,” Bolinger said. “If you can buy wind at a price that is cheaper than gas and lock it in for 20 years, chances are you will be in a good position, especially if gas prices rise.”

    click here for more


    How Sacramento's public utility is getting in the residential solar business; The new utility business model may simply be answering customers’ questions.

    Herman K. Trabish: August 25, 2014 (Utility Dive)

    In oday’s competitive marketplace of smart and distributed services, utilities do not have ratepayers — they have customers. Utilities can play a crucial role in those customers’ lives if they move beyond just generating, delivering, and billing electricity.

    “Utilities have to think hard about their customer engagement strategies,” explained Sacramento Municipal Utility District (SMUD) Solar Retail Strategy Planner Patrick McCoy.

    SMUD is a leader in a booming rooftop solar industry that provided U.S. utilities with 135,000 system interconnections in 2013, bringing the total of interconnected systems to 435,000, representing 10.7 gigawatts of capacity.

    Customers call SMUD daily about solar. They ask whether they should pay cash, take a loan, or lease solar. They ask about the size of the system, the role of battery storage and plug-in vehicles

    “The majority of callers want to know, ‘Is solar right for me?’” McCoy said. “We understand that to mean, ‘Will it provide the kind of savings I expect?’”

    SMUD began last year with about 1,000 interconnected systems but that had doubled to over 2,000 systems by the end of 2013. With falling system prices, that steep growth curve was even unaffected by the drop in California’s rebate to only $0.25 per watt.

    “The industry has provided a great service but it has raised questions for SMUD customers,” McCoy said. “Our local installers’ messages can be misleading and get our customers confused.”

    As a result, SMUD has discovered a new role as “a trusted advisor that helps customers manage costs, evaluate options, and focus on their goals.”

    Things are now “customer-centric,” McCoy said. “SMUD wants to be the preferred resource for all things energy-related. We want our customers to come to us for help in making informed decisions.”

    To do that, SMUD’s internal goals are:

    -getting solar basics right to win customers’ confidence

    -allowing customers’ to “experience excellence” from utility interactions, which means learning communication skills

    -making sure SMUD's solar information is accurate, current, and complete

    -giving up communication channels that are “so 20th century” in favor of community engagement, social media, and self-service online tools.

    Because SMUD program managers now spend half their time fielding basic questions on solar from customers, the utility is working with Clean Power Research (CPR), through a Department of Energy SunShot grant, to develop a software-as-a-service (SaaS) Solar Engagement Platform.

    The platform is being designed, McCoy said, to lead customers to the answer to that fundamental question: “Is solar right for me?”

    How SMUD is leveraging big data for its 'trusted advisor' role

    The scalable, hosted, and customizable CPR software integrates with the utility’s customer portal and can therefore draw on the utility’s database, explained CPR Product Manager Brian Boler.

    Similar independent SaaS advanced solar tools are being built by EnACT, ModSolar, and Genability. SunPower and Sunnova have proprietary in-house tools. All are intended to work with utilities through DOE’s Green Button Initiative.

    Using utilities' assimilated smart meter data and CPR's electric rate and solarirradiance data, the platform becomes “an objective solar decision-making tool,” according to Boler.

    “Utilities have terabytes of data,” McCoy added. “The key in this context is to know and understand customers more intimately.”

    Clicking the solar tab allows customers with smart meters to access the utility’s IT data and advance the process. If there is no smart meter data, the customer can input bill information.

    The software then builds a “solar savings estimate” to offset 80% of the customer’s annual energy use. The calculation comes from actual energy consumption data and, through a mapping tool, actual rooftop space, orientation information and regional solar irradiance data.

    It incorporates federal, state, and local incentives and rebates and allows customers to compare advantages from variables like system size and rates. A final report includes savings, a before-and-after energy use pattern, and a carbon footprint calculation.

    The platform provides a cash flow, bill savings, and payback period analysis with a one-view comparison of cash, loan, and lease options. The user can enter varying interest rates and compare leases with something or nothing down. Data can be viewed as a graph or chart.

    The analysis also includes data on the service territory’s solar users and contact information on local installers, allowing customers to more readily obtain competitive bids.

    Still in beta testing, the platform’s price has not been set but it will eventually be licensed to utilities by CPR on a standard SaaS model, Boler said.

    The value in reduced call volume is worth the price, McCoy said, and it expands the utility’s role as that “trusted advisor.” Customers now expect utilities to provide “comprehensive bundled solutions and service, and that includes integrating solar PV.” McCoy was asked if SMUD is planning to follow Arizona Public Service into the residential solar business. Unlike investor-owned utilities like APS, he replied, a public utility like SMUD would require a private sector partner to be competitive.

    “We are evaluating business opportunities for a direct to customer solar service," he said. "So the answer is yes.”

    click here for more

    Tuesday, December 16, 2014


    Has APS invented a rooftop solar business model for utilities?; The plan is to rate-base solar and get more peak production. But is it legal?

    Herman K. Trabish: August 11, 2014 (Utility Dive)

    Arizona Public Service’s ground breaking rooftop solar program could become the 21st century business model utilities have been looking for— if it gets past state regulators. APS, Arizona’s dominant electric utility, wants to fund, install, own, and maintain 3,000 rooftop solar systems. The utility proposes to reimburse each customer who hosts part of the cumulative 20 megawatts of solar with a monthly $30 bill credit for the entire 20 year program.

    The bill credit is a lease payment for rooftop real estate, explained APS Renewables Manager Marc Romito. The roofs will be pre-screened by APS but, as with the third party ownership (TPO) lease contracts offered by private sector companies like SolarCity, Clean Power Finance, and SunPower, the hosts will pay no upfront fees and have no ownership responsibilities.

    APS determined $30 to be the value of the roof space through a study of other U.S. utility programs and consultations with local solar installers. That is significantly higher than Arizona’s average $5 to $10 per month savings from a solar lease deal, according to TPO market leader SolarCity’s VP Jonathan Bass. Rate-basing rooftop solar

    “They don’t have to think about whether they can do something profitably. It will be profitable because they can rate-base it,” SolarCity's Bass argued. “If there were ever a reason for a regulatory body to exist it would be to stop a state-sponsored monopoly from unfairly competing against the free market in an entirely new industry.”

    APS is "not trying to compete with [the third-party ownership] model,” Romito countered. “Customers will still have lease and cash purchase options. This is for an entirely new class and category of customers that have no way to access a lease or cash purchase.”

    APS developed the solar business model by listening to its customers, Romito said. “They like the idea of their utility participating in rooftop solar.”

    APS began hearing that message in protests by pro-solar utility customers during last fall’s passionate fight over Arizona’s net metering policy. In that case, the TPO leasing companies and APS fought bitterly over the utility’s proposed $8 per kilowatt bill charge on net metered solar owners. The Arizona Corporation Commission (ACC) disappointed APS by reducing the bill charge to $7 per kilowatt.

    Net metering

    Through its AZ Sun Program, APS has built hundreds of megawatts of utility scale and commercial-industrial scale projects. It has almost fulfilled its commitment to the ACC to build more solar than is required by the state’s 15% by 2025 renewables mandate. This year, it will invest $50 million to $70 million more, either for the rooftop program or a less costly 20 megawatt community solar array.

    “Another 20 megawatts of solar is going on the system,” Romito said. “This creates an opportunity to expand rooftop solar in our service territory.”

    The program “avoids any tie in with a net metered rate or rate design,” Romito said. Though its renewable energy credits will help APS meet the renewables mandate, it also helps satisfy the mandate’s 30% distributed generation requirement. “We are interconnecting these systems on our side of the meter. There is no net metering involved. We are tying the production directly into the APS distribution system.”

    If it wins ACC approval in an open regulatory proceeding expected later this year, APS wants to complete development by the end of 2015. It would partner with qualified local solar installers selected through an open bidding process. And it would set installation standards and specify the most reliable solar modules and the most advanced inverters, Romito said.

    The legal question

    Solar leasing companies like SolarCity think the APS program may be illegal.

    But unlike solar leasing companies, Romito said, “we have been here for over 100 years. We are held accountable by a regulatory body and we are accountable to our customers. We are putting this project into our regulated portfolio.”

    That is why, Bass said, the ACC should not approve the proposal. “Rate-basing allows them to get paid for their cost and get a guaranteed return. That is a totally unlevel playing field. It takes away the incentive to keep costs down and would reverse a lot of the progress made by the free market in lowering solar costs.”

    “It is illegal,” added Rose Law Group Sr. Partner Court Rich, who specializes in energy policy law. “It saddles all ratepayers with the tab for APS’s investment and profit on each solar system for decades.” If the ACC approves the proposal, Rich added, regulators could find themselves “settling landlord tenant type disputes between thousands of customers and the utility.”

    The commission last year considered and rejected a proposal to deregulate APS but “I don’t think they contemplated the idea of expanding the monopoly,” Rich said.

    There is “absolutely” no legal issue, Romito said. Rate-basing assets “is routine business for us. The fixed rate of return is how we recover costs if we demonstrate we are serving our customers.” Rate-basing has been “legally vetted in the commission process,” he added. It exists because “the regulated utility gives you reliability and quality.”

    The program is not in direct competition with solar leasing companies, he added. “It is another option and creates more rooftop solar, in partnership with any solar company that bids to participate.”

    Total production versus peak production

    Rate-basing will allow APS to make one crucial change in rooftop solar.

    “We have a unique opportunity because we are participating in the system deployments, to maximize the potential system benefits,” Romito said. “Every opportunity we can, we will be facing these systems west or southwest.”

    That orientation would reduce the APS rooftop installations’ total output but push production from the early afternoon solar peak toward the utility’s peak demand later in the day, Romito explained. “We hope to see peak production around 3 PM.”

    Anything but total production compromises a leasing company’s business model, Romito said. “But if rooftop solar is going to be deployed, we want tomaximize overall system performance.”

    “It is not about peak production versus total production but what makes sense for a particular customer,” SolarCity's Bass countered. “APS wants to do solar on terms that are most favorable to them. But it is not necessarily in the best interests of ratepayers and certainly not in the best interests of the general public or solar customers.”

    Arizona’s solar industry employs approximately 8,500 people and has built more than 35,000 installations, Bass added. “This is a threat to the entire solar industry in Arizona. I think utilities should get involved in distributed generation but they should do it through an unregulated division that competes on the same terms as everybody else.”

    click here for more


    Jon Wellinghoff: Utilities should not operate the distribution grid; The grid needs Independent Distribution System Operators, the former FERC chair told Utility Dive

    Herman K. Trabish: August 15, 2014 (Utility Dive)

    As distributed energy resources come onto the grid in increasing numbers, the distribution system may need a new level of regulation to ensure new services get delivered efficiently, according to a proposal from Jon Wellinghoff, former FERC chair and current partner at Stoel Rives, and James Tong, vice president of strategy and government affairs at Clean Power Finance.

    Regional Transmission Operators (RTOs) and Independent System Operators (ISOs) have, in partnership with utilities, expanded and streamlined the grid’s electricity markets over the last decade.

    Now, utilities need a partner at the distribution system level to do the same for retail electricity, according to the proposal.

    Why the grids needs an Independent Distribution System Operator

    In order for solar and other distributed energy resources (DERs) to add more value to the bulk system and cause less stress, Wellinghoff and Tong are calling for the creation of an Independent Distribution System Operator (IDSO) to handle the planning and operations of the distribution network.

    Today, utilities own and rate base transmission system assets while answering to the Federal Energy Regulatory System (FERC) and leaving day-to-day operations to RTOs and ISOs. Under the proposal, they can own and rate base distribution system assets while answering to state regulators and leaving moment-to-moment operations to the Independent Distribution System Operator.

    The consolidation of balancing authorities and operational control of the wholesale market system through system operators has proved a much more efficient model, Wellinghoff, co-author of Rooftop Parity: Solar for Everyone, including Utilities, told Utility Dive in an interview.

    The proof is a 2009 study by FERC and four Southeastern state commissions that showed Entergy could save a minimum of $700 million over ten years by joining the Midcontinent Independent System Operator, he said.

    “Now we have the software tools and computing capability to bring those benefits down to the distribution level,” Wellinghoff said. That will grow the system and give DER entrepreneurs greater visibility into where the value is in technologies like solar PV and storage. “They will go get that value. And that will benefit customers who use and invest in DERs.”

    “And that also will create new incentives for innovation,” added co-author andClean Power Finance VP James Tong.

    What an Independent Distribution System Operator would do

    “State commissions will still have complete authority, just like FERC has complete authority over the RTOs,” Wellinghoff said.

    But their role changes slightly, he explained. The IDSO would manage planning and operations. The commission would have ultimate approval authority and be “a market overseer, enforcer of market rules, and creator of market structures, much as FERC does now at the wholesale level.”

    An IDSO would:

    maintain system safety and reliability

    provide open and transparent system access

    implement market mechanisms

    oversee optimal DER deployment and dispatch

    guard consumers’ access to all transactive energy services

    allow regulated utilities, unregulated energy sellers, independent energy and service providers, and electricity customers equal opportunity to meet new electricity consumer needs.

    Utilities now do the planning and set values at the distribution level, Tong said. “Because of that, the debates are about net energy metering. But the real threat to the existing utility model is that people are becoming more efficient.The EIA estimates load growth will only be 0.9% per year for the next 30 years.”

    The opportunity for utilities

    If utilities turn operation of the distribution system over to an IDSO, Tong said, they can focus on the opportunity to offset slowed load growth by investing in DER and DG on the regulated side and opening similar opportunities on the unregulated side.

    “In a world that is all monopoly-owned assets, utilities could be effective distribution system gatekeepers,” Tong explained. “But in a world with a lot of DER and customer-owned assets, there is an inherent conflict of interest. It would be, to borrow an analogy, like an air traffic controller that also owns an airline.”

    While FERC has begun turning the grid over to system operators, state commissions and utilities can similarly turn moment-to-moment distribution system operations over to IDSOs. That would free utilities, bolster unregulated energy suppliers and independent energy service providers, and empower electricity customers.

    An IDSO would eliminate distribution system encumbrances for regulated utilities, the proposal explained, and free them from some reliability burdens. Utilities could then form partnerships with independent generation and service providers. Those businesses could offer profit opportunities in return for utility capabilities like customer outreach, billing, project implementation, local regulatory expertise, and access to capital.

    California regulators have acknowledged the need for streamlining distribution system operations in a proceeding to oversee IOU’s implementation of mandated Distribution Resources Plans. California IOUs are mandated to integrate cost-effective DERs into their distribution systems “with the goal of yielding net benefits to ratepayers.”

    Where the systems meet

    There is an especially important opportunity at the intersection of wholesale transactions on the transmission system and retail transactions on the distribution system, Wellinghoff said.

    An example is the recent decision by a D.C. district court that FERC has no jurisdiction over demand response because it is a retail product. “There are 15,000 megawatts of demand response in PJM and that is of tremendous benefit. According to PJM, it drove down capacity prices $12 billion last year,” Wellinghoff said. "If that decision stands, it could exclude all types of retail activities, including distributed generation, storage, and efficiency.”

    The only way to prevent the loss of what are extremely valuable assets would be the creation of something like an IDSO, he said. It could aggregate those retail products and allow a market exchange through a wholesale-retail interface with the bulk system. “The states would have jurisdiction over what the court says are retail products and FERC would continue to have jurisdiction over the wholesale products.”

    Even utilities that are now opposing the entry of demand response in capacity markets could see benefits. Instead of “frantically doing whatever they can to prevent customers from reducing usage through things like demand response,” Wellinghoff said, “they could be the owners and maintainers of a distribution system platform, upgraded to include demand response on IDSO plans, that they could build and rate base.”

    An IDSO also would reduce a utility’s risk in the approval process, Wellinghoff added. The IDSO would do planning through a stakeholder process with the utilities at the table. It would then recommend the selected investments to the regulators. “That is in essence an independent third party recommending to the commission that upgrades be made that the utility could rate base,” Wellinghoff said.

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    Monday, December 15, 2014


    How should utilities value solar?; Utilities can go from Net Energy Metering to Transactive Energy Services with solar

    Herman K. Trabish: August 4, 2014 (Utility Dive)

    Solar is a revenue opportunity utilities can no longer ignore.

    In the next few years, electricity providers will have to face the question of how solar will fit into their businesses.

    The answer will likely come from among the five ways to value solar described in Utility Solar Trends from the Solar Electric Power Association (SEPA).

    “It is something of a menu,” explained co-author Mike Taylor. “The choice will depend on the politics, the balance of the utility interests and solar interests, the state of the solar market, and how advanced and organized the solar industry is.”

    The traditional ways to value solar

    The traditional way to value solar is through the retail electricity rate. It is the basis for rooftop solar’s vital net energy metering (NEM) policy. “NEM is a reasonable tool in nascent markets. Its simplicity and ease of understanding to customers and the solar industry work have spurred solar,” explained SEPA Strategy and Programs VP Eran Mahrer. “But once you have the first seeds of a market, you need to think about where you want to go over the long term.”

    The next two ways of valuing solar are variations on the retail electricity ratethat have evolved out of the many debates over NEM. One would retain NEM and add some kind of “demand” or “fixed” or “flat” charge for all customers to cover lost utility revenues.

    The other would retain NEM and add a “dollars-per kilowatt” or a “dollars-per-month” or a “dollars-per-kilowatt-per month” charge for solar owners.

    “These are different constructs of the same thing,” Mahrer said. “They use familiar tools that utilities and regulators have used for years to solve the new problem. But will they work in a universe of increased distributed generation resource types, electric vehicles, and more active home energy management systems?”

    New ways to value solar

    The last two ways of valuing solar, Mahrer said, are forward-looking. One separates the retail price of electricity. It pays solar owners for the value their site-generated electricity adds to the grid and charges them the same as all other utility customers for their use of grid electricity.

    This value of solar concept was first introduced by Austin Energy in 2012. This year, Minnesota made it a law which is now being studied by Xcel Energy and Minnesota Power.

    SEPA’s fifth option is Transactive Energy Services, as developed in research by San Diego Gas and Electric, the EPIC Center, Black & Veatch, and Clean Power Research.

    Though not yet implemented, It is “a broad sweeping reform of current rate design" that considers the full range of energy attributes and services provided by both utilities and customers. And it incorporates “detailed menus of electricity costs, benefits and services.”

    “Transactive Energy Services could have a whole series of numbers that could be generated on an annual basis or on a near real-time basis, depending on the market,” Mahrer said. “It is not available today but there will be a lot of enabling technologies, through the advanced metering infrastructure being put in place today, or other types of communication technologies, and it is where the industry has to go.”

    “Today you buy electricity as a bundled product but it is being unbundled,” Taylor added. “The interim step is probably time-of-use rates that Sacramento Municipal Utility District is working on, to send smarter market signals for consumption and generation.

    That is a transition toward a very sophisticated and wholly conceptual future that will require smart meters, a smart grid, sophisticated customers, and solar people who can explain it to customers.”

    Mass customization

    Transactive Energy Services is similar to the mass customization used by manufacturers to allow customers to place orders for standard products with customized attributes at little incremental cost, Mahrer said. “Today, customers want a customized product from utilities that may have a solar attribute, an efficiency attribute, a rate that conforms with their behavior, an energy management system, a demand response rate, electric vehicle charging, or storage.”

    Community solar is a first step toward mass customization, Mahrer added. Utilities are beginning to realize it is not a good idea to send customers who don’t have the means to build solar on their rooftops to other providers. Instead, they can build a solar project and market either panels or kilowattsfrom it to their customers.

    This will be an especially important approach after December 31, 2016, when the 30% investment tax credit (ITC) drops to 10%, according to the SEPA paper. The tax equity available to institutional investors has been vital to the accumulation of the capital needed to build utility-scale solar projects.

    Without the ITC, the utility-scale solar market could change drastically. This is part of why utilities’ have been reluctant about solar, according to Mahrer. “Utilities have been slower to react to solar because the rules of engagement are not clear,” he said. “A lot of questions remain unanswered and, unsurprisingly, utilities have resisted going first.”

    But “utilities can be expected to evolve and streamline offerings,” the SEPA paper concludes. “At a minimum these designs will have to respond to customers’ needs without adversely affecting retail rates, while offering new revenue and partnership opportunities for utilities and the solar industry.”

    The ultimate best practices have not yet emerged but SEPA proposes responding to the uncertainties not by ignoring solar but by planning for it, Mahrer said. “We underscore the need for a planned transition strategy.”

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    Is Puerto Rico the new poster child for the utility death spiral?; The island’s public utility got an extension on paying its debt but bankruptcy still looms.

    Herman K. Trabish: August 13, 2014 (Utility Dive)

    Puerto Rico never recovered from the 2008 recession.

    The Commonwealth of Puerto Rico’s unemployment rate was 13.8% for May, compared to 6.3% for the U.S. mainland, and the island’s 2013 per capita income was $17,636, 61% below the U.S.’s $44,712.

    The island's main utility, the Puerto Rico Electric Power Authority (PREPA), was also hit hard and has yet to recover. Although a vital $671 million credit line needed to buy fuel was just extended until March 2015, the utility is facing bankruptcy.

    The economy

    Efforts to stimulate the island's economy have floundered. In July, Moody’s,Standard and Poor’s, and Fitch’s downgraded $61 billion of the Commonwealth’s debt to junk bond status. That caused new interest rates that “hinder and depress economic activity,” Moody’s subsequently wrote.

    The island’s economy “continues to stagnate and provides little hope for revenue growth,” Moody’s reported, and it is “too weak to absorb further tax hikes or utility rate increases.”

    In June, the Commonwealth passed the Recovery Act, a new bankruptcy law allowing PREPA to restructure its debt. That means Puerto Rico’s longstanding “willingness to meet debt obligations” has been replaced by a “decreased willingness to pay bondholders,” Moody’s explained.

    PREPA’s challenges

    PREPA faces unique challenges. Like many resource-poor island nations, the Commonwealth’s electricity is largely generated with oil imported from Brazil. Its $0.24 per kilowatt-hour electricity rate is twice the average mainland electricity price of $0.12 per kilowatt-hour.

    Most analysts agree a shift to more affordable natural gas and domestically generated renewables is the way out for PREPA in the long term. One analysis found Puerto Rico could reduce its $2.6 billion in oil costs by $1 billion with a shift to natural gas. But political and regulatory obstacles have so far blockedGovernor Alejandro Garcia Padilla’s efforts to make that happen.

    Most utilities are barred by law from selling or mortgaging hard assets, so they raise debt financing by pledging future revenues, explained Chadbourne & Parke Partner Lawrence LaRose.

    To date, PREPA has accrued over $9 billion in debt. Though it is one of the biggest U.S. public utilities, that debt is still a proportionately huge burden compared to 2012 revenues of $4.94 billion. Because of the flailing economy’s falling electricity demand, revenues continue to decline and unpaid debt is mounting.

    In May, PREPA was able to buy fuel only by using reserve funds. If not for a temporary forbearance on $146 million granted by Citibank and the patience of the Scotiabank-led international lending consortium that is owed another $550 billion, PREPA might already be in bankruptcy.

    On August 14, Citigroup and the Scotiabank-led consortium extended their combined loans of $671 million to march 2015, allowing PREPA the funds needed to buy fuel for its power plants. In return, PREPA agreed to accept oversight and to establish a five-year business plan.


    Since ratepayers tend to pay their bills, utility bonds are usually considered secure, if low interest, investments. To protect them, municipalities facing bankruptcy typically do not “impair” utility bonds, said LaRose, who has taken part in major U.S. municipal bankruptcy proceedings like those in California and Detroit.

    Puerto Rico’s Recovery Act “allows PREPA to impair its revenue bond holders in any number of ways, some even more aggressive than Detroit’s under the bankruptcy code,” LaRose said. That is because, like most other municipal restructurings, Puerto Rico’s has a political as well as a financial dimension.

    PREPA will continue to deliver the service of providing electricity, LaRose predicted. “If the government of Puerto Rico took the extraordinary steps of passing this legislation and providing it for PREPA, they intend to keep the lights on. What they are saying is they will take the risk of upsetting the bond market in order to keep millions of voters happy.”

    Franklin Templeton Investments and Oppenheimer Funds Inc., which cumulatively hold $1.6 billion in downgraded PREPA bonds, have filed a strong argument in the U.S. District Court for Puerto Rico to have the Recovery Act ruled in violation of the U.S. bankruptcy code, according to Mintz, Levin Municipal Finance Attorney Leonard Weiser-Varon. “We continue to ascribe a high probability of success to this preemption argument if and when it is adjudicated,” he wrote.

    BlueMountain Capital Management LLC, which holds $400 million in PREPA bonds, has also filed against the utility.

    As part of the credit extension, the lawsuits were put on hold but justice was always unlikely to come quickly. Contract impairment claims are “highly fact-sensitive and unlikely candidates for summary judgment,” according to Weiser-Varon.

    The utility death spiral

    The bond funds’ legal filings argued PREPA has other alternatives, including:

    -raising rates

    -collecting on the $640 million it is owed by The Commonwealth

    -getting a 2014 through 2018 tax break from The Commonwealth that could save over $1 billion

    -cutting internal costs and inefficiencies

    -doing better at collecting delinquent bills

    Ultimately, though, a utility’s financial base must be sufficient to meet the cost of providing all its services, including debt service, LaRose said. PREPA has a declining financial base and rising debt. It also has little if any margin for a rate increase that would not create more delinquent accounts and lost customers. It is fast approaching a tipping point.

    “If they hit it, it becomes a death spiral because the more you raise rates, the more you lose revenue,” LaRose said. Though it is something that comes up in most municipal cases, he added, it is not yet clear whether it will happen to PREPA.

    Editor's Note: Efforts to contact PREPA by phone and email went unanswered and Scotiabank declined to comment.

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    Saturday, December 13, 2014

    Reindeer Stresses

    Tis the season. Have reindeer ever faced a dual combination of terrorism and climate change like this? But if anti-depressants fail, there may be another solution. From versusplus via YouTube

    Pink Fracking

    From Comedy Central

    Fighting Duke For Solar

    There was a time when utilities like Duke Energy were renewables champions. Now too many talk the talk but seem afraid to walk the walk. From NC WARN via YouTube

    Friday, December 12, 2014


    Why utilities can add 8.8% rooftop solar at little cost or reliability loss; “Nothing is very different than the way the system is operated today and the costs appear to be modest.”

    Herman K. Trabish: July 23, 2014 (Utility Dive)

    Utilities can get almost 9% of their electricity from solar without significant costs or compromises in reliability, according to new research.

    With most U.S. utilities now getting less than a percent of their power from solar, this important finding from national energy laboratory researchers should significantly postpone concerns about the impact of solar on the grid.

    “They can keep their balancing performance in the same range as it has been without PV for a cost of less than $2 per megawatt-hour,” explained Lawrence Berkeley National Labs Senior Researcher Andrew Mills, co-author ofIntegrating Solar PV in Utility System Operations from Argonne National Labs, the National Renewable Energy Labs, and LBNL.

    The study modeled day-ahead, hour-ahead, and real-time operations and resources at Arizona Public Service (APS) and added first 8.8% solar PV and then even higher levels of penetration. At the lower PV level, “nothing is very different than the way the system is operated today and the costs appear to be modest,” Mills said. “They could add almost 1,700 megawatts of PV with uncompromised reliability and only a small increase in the need for balancing reserves.”

    The tipping point: 17%

    With PV supplying 17% of the APS system’s electricity, there would be challenges if flexibility is not increased, Mills said. With the high PV and low load typical of spring and winter days, curtailment and the need for balancing reserves would increase. The result would be increased integration costs.

    That high PV-low flexibility scenario would also cause a decrease in the standard reliability metric, called the Control Performance Standard 2 (CPS2). The CPS2 measures the monthly percentage of ten minute periods during which supply and demand are balanced to within 50 megawatts.

    The North American Electric Reliability Corporation (NERC) requires the CPS2 score to be above 90% and the APS internal goal is 99%, Mills said. In a recent western region study, he added, two-thirds of the participating utilities kept their CPS2 scores between 96% and 98%.

    To keep their CPS2 scores up, utilities can meet higher PV penetrations with more system flexibility or with a way for the operator to sell the excess power at times of low load, the researchers concluded. When those options were modeled in the study’s sensitivity analyses, Mills said, “the cost of integration came down and curtailment went down to more reasonable levels.”

    The big picture

    The study is important in a broader context, Mills explained, because it compliments findings in papers like NREL’s landmark, interconnection-wideWestern Wind and Solar Integration Study (WWSIS).

    ”They both show a lot of renewables can be integrated reliably in the overall system,” Mills said. “We focus on a particular utility’s current operating practices and ask what it would look like to that utility to add a lot of PV. At the low PV penetration level, there aren’t things that stand out from this study that contradict or conflict with what NREL found.”

    Two things have changed since the researchers concluded their work that advance the study’s conclusions, Mills noted.

    The reliability standard

    First, NERC’s proposed change in the reliability metric seems to be nearing FERC approval and implementation. “The CPS2 makes the accounting of performance easier but only measures overall and average reliability for an individual utility,” Mills explained. “It doesn’t ask if the utility is responding when the system is stressed.”

    The new NERC metric will reflect how individual utilities perform when the overall system begins to deviate away from the 60 hertz frequency curve toward 59.9 Hz or 60.1 Hz. “That encourages helping keep the overall system in balance,” Mills said. Concern with overall system balance is also driving the second change.

    An energy imbalance market

    “An Energy Imbalance Market was talked about when we wrote the paper but with the new CAISO-PacifiCorp-NV Energy EIM being put in place, the concept has gained momentum,” Mills said.

    To demonstrate the key factors that minimize integration costs and sustain reliability, the researchers did “a worst-case scenario” with high PV penetration, dramatically limited system flexibility, and significantly increased balancing reserve requirements. The result was an integration cost of $9.60 per megawatt-hour and a 10% curtailment of renewables, despite penalty charges to the utility and reserve shortfalls.

    It is an “unrealistic” scenario designed to highlight, the researchers wrote, “the importance of finding buyers for excess power during times with high PV production or the need to increase flexibility from existing thermal power plants or other resources.”

    With an EIM now being implemented on the western grid, and other balancing authorities, including APS, actively studying how they can participate, Mills said, “it diminishes the need to study cases where there is no outside market. If you were doing the study now, you would want to include a scenario where the utility was part of an EIM.”

    The study shows the advantages of an EIM. “It raises the question of finding the opportunities that the studies with bigger scopes find,” Mills said. “APS is definitely following the development of EIMs and working to understand them.”

    The paper’s findings, Mills said, are “what utilities need to be thinking about now so when they get to higher PV penetrations they know what they need to do to meet the challenges.”

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    How 4 utilities are using big data; AEP, Vattenfall, Austin Energy and City of Palo Alto Utilities show that no-one-size-fits-all.

    Herman K. Trabish: August 5, 2014 (Utility Dive)

    Utilities and grid operators are turning to experts to handle the big data they are gathering.

    Use of data about their systems and their customers varies widely. While it can inform transactive energy services that will ultimately mimic an electricity market at the customer level, more often today it is about simply reporting peak load event information to customers via email.

    There are three areas where utilities are working to build big data operations, according to ABB Smart Grids VP Gary Rackliffe.

    ABB’s acquisition of Ventyx and its business intelligence software, which is used by over 50 utilities, solidified its standing among other smart technology leaders like GE, Siemens, and Alstom.

    Currently, Rackliffe said, ABB is working to:

    improve distribution grid management, particularly around storm restoration,

    improve system health management by precisely assessing risks of asset failure, and

    manage distributed energy resources integration into transmission and distribution systems.

    “There are five Vs in big data,” Rackliffe said. “Volume, how much data. Variety, the types of data. Velocity, the rate the data comes in. Veracity, the accuracy of the data. And value, the usefulness of the data.”

    Storm response and asset health

    In the first application, ABB is assimilating storm data. “We data mine information on past storms to predict how the system will be impacted and to estimate restoration times,” Rackliffe said. Based on that situational awareness, ABB can “predict the type of equipment inventory and crew resources that will be needed to handle grid restoration.”

    In the second application, American Electric Power (AEP) is now rolling out the ABB-Ventyx Asset Health Center. With over half its transformers more than 50 years old, AEP is integrating its system data with ABB’s operations technology/information technology (OT/IT) capabilities, Ventyx's business intelligence and layered-in analytic algorithms to manage its 40,000-mile, 11-state, 5-million-customer grid.

    “Our customers want to drive down the total risk of failure and get better performance with the same number of people or get the same performance with fewer people,” Rackliffe said. “And there is a big wave of concern now about being able to manage aging infrastructure.”

    Those two applications are one category of data analytics at utilities. Consumer analytics is the second and it includes demand response (DR).

    Transactive energy and demand response

    Meter data and other data on customer behavior is used “to tease out consumer preferences and understand how different DR programs like peak-pricing or time-of-use rates or [electric vehicle] charging will affect demand,” Rackliffe explained.

    ABB is working with European utility giant Vattenfall in Gotland, Germany, on a project targeting a 10% load shift at 2,000 homes and 30 commercial facilities. It will use Ventyx’s Demand Response Management System (DRMS) to manage a consumer marketplace with the full range of transactive energy services, including wind, solar PV, energy storage, EV charging, and tiered pricing, Rackliffe said. “Predicting customer responses is where data analytics is going.”

    Like the Opower-BGE pilot in Baltimore, Austin Energy and City of Palo Alto Utilities (CPAU) have also been using data analysis, though on a smaller scale, to study consumers’ reactions to DR.

    An Austin Energy demonstration program, funded by a Department of Energy ARPA-E grant, tested how AutoGrid’s Demand Response Optimization and Management System (DROMS) could be used to reduce peak load. The utility used the single platform to control 60 thermostats from two different manufacturers’ and 15 electric vehicle chargers from a third manufacturer, all at dispersed customer locations, explained Austin Energy Consulting Engineer Russell Shaver.

    Over about a dozen peak demand periods in June and September of 2013, the AutoGrid software was able to adjust the thermostats’ temperatures up four degrees and turn off the car chargers for about two hours. The platform also allowed EV owners to turn their chargers back on via email and allowed customers to push a button on the thermostat if they chose to opt out of the event.

    Austin Energy had no experience with other data analytics vendors but was impressed with what AutoGrid could do. “When we have a DR event, we have to go into each different online portal provided by each of our thermostat manufacturers to issue a DR signal,” Shaver said. “We want a centralized DR portal like the one built by AutoGrid so we only have to issue that signal once.”

    The City of Palo Alto Utilities (CPAU) has been running “a very small [demand response] pilot” with seven or eight large commercial customers for four years, said Senior Resource Planner Karla Dailey. “During a May 14 event, the only one this year, we were able to reduce the load 5,653 kilowatts.”

    CPAU used AutoGrid to communicate the event to its customers, to do the back end analytics and to report savings to its customers, Dailey said. It has not tested AutoGrid’s claims to be able to manage petabytes of data.

    Dailey sets up the parameters of the anticipated event and participants are emailed. “AutoGrid is a communication tool for us,” Dailey said. “We don’t make demand reduction happen. The capability is there but we are not there.”

    Demand response has a lot of potential but it is utility specific and depends on the customer profile, the local climate, and on costs. “There is no one-size-fits-all for DR programs,” Dailey said. “All we are trying to do is shave our summer peak. But there are lots of other things a utility can do with DR and we are going to be looking at all of them.”

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    No QUICK NEWS Today

    Thursday, December 11, 2014


    Are natural gas and renewables the future of Texas' power grid?; Demand response, energy efficiency, and combined heat and power are set to play a bigger role.

    Herman K. Trabish: July 2, 2014 (Utility Dive)

    Renewables and natural gas are Texas' energy future but demand response and energy efficiency will also be increasingly important, according to a new study refining the state grid operator’s forecasts.

    With demand response and combined heat and power that could be cost-effectively added to the Texas grid by 2032, the grid operator’s business as usual projection of 20,600 megawatts of new Texas generating capacity for 2032 could fall to 13,580 megawatts, according to the Brattle Group’s Exploring Natural Gas and Renewables in ERCOT, Part III: The Role of Demand Response (DR), Energy Efficiency (EE), and Combined Heat and Power (CHP). And if Texas seizes the potential of other equally cost-effective energy efficiency opportunities, needed new capacity could drop all the way down to 10,988 megawatts.

    The Electric Reliability Council of Texas (ERCOT), the state grid operator, provided data to support Brattle’s research and has found their work helpful in addressing future grid reliability, acknowledged spokesperson Robbie Searcy. “The scenarios in this report are not inconsistent with the possible scenarios we considered in our last 2012 long term system assessment.”

    Brattle and ERCOT concur the biggest sources of generation will be natural gas and renewables but, Brattle notes, increased DR, CHP, and EE divide growth “more evenly” between gas and renewables.

    The scenarios

    Both assessments offer several scenarios. ERCOT projects, for instance, that 13,765 megawatts of coal plant retirements forced by a carbon policy would drive new capacity additions of 39,800 megawatts. Higher natural gas prices would limit new natural gas capacity and increase renewables, according to ERCOT. Renewables’ lower capacity factors would increase new nameplate capacity to 94,954 megawatts.

    Scenarios proposed by Brattle reflect other possibilities. “Slower load growth encourages older base load resources to stick around, which is economical, but slows the turnover of the fleet,” Brattle notes. “This has a two-edged effect on fuel efficiency and emissions, slowing the growth of new [natural gas] but generally increasing the growth of wind power but not solar. Thus, demand response in the ERCOT system is more complementary to wind than to either solar or gas.”

    By 2017, Brattle forecasts, economic and achievable DR will grow by 20% to 30%, or between 450 megawatts and 760 megawatts. By 2032, DR will grow 90% to 150%, or between 2.3 gigawatts and 3.8 gigawatts, over ERCOT’s current portfolio. With dynamic pricing, DR can cost-effectively provide Texas with over a gigawatt of peak reduction.

    “The size of the total DR portfolio (existing and new) in 2032 is 6,350 megawatts, 7.8% of the projected system peak,” Brattle forecasts. “Combined with 3 gigawatts of peak reduction in the expanded EE portfolio, this represents a 40% to 50% reduction in projected peak demand growth.”

    DR, CHP, and EE will become more important because of natural gas price volatility, expected but indeterminate carbon and renewable policies, and the rapidly falling price of renewables.

    The Combined Heat and Power Opportunity

    The Texas industrial sector has a big untapped opportunity in CHP, according to Brattle report co-author Dr. Ira Shavel. “CHP in large scale is similar in cost to a combined cycle plant. A big petrochemical facility, for example, can support a combined cycle plant that has similar capital cost and similar operating cost to any other power plant but is more efficient,” Shavel said. And the excess electricity generated by the captured heat of that combined cycle turbine could pay off the investment.

    With more DR, CHP, and EE, projected energy prices would be similar toERCOT system prices between 2010 and 2012. “The highest annual average price for a converged year is about $67 per megawatt-hour,” Brattle concludes. And that “extreme scenario” requiring rigorous emissions reductions and causing high natural gas prices would still be $3 per megawatt-hour lower than a comparable scenario without demand management.

    Another reason for Brattle’s increased emphasis on demand side factors is that “ERCOT assumes a more aggressive cost decline for solar in the future,” Shavel said. “They get more solar in their analysis and we get more wind.”

    The Role of Demand Response

    Demand response may be the biggest reason. “Our finding was that DR impacts solar more than wind because DR shaves the peak,” Shavel explained. “DR beats solar in peak shaving. A peakier load shape and more high-priced hours occur primarily during the summer peak when solar has its highest output. DR takes some of that potential market away.” But DR has little effect in “the deep off-peaks when prices are lower and wind output is higher,” he added.

    Energy efficiency is also a factor in the differing Brattle and ERCOT conclusions. “DR is targeted at the peak, and therefore at things that are deployed when electricity prices get high and supply gets relatively short,” Shavel explained. “Efficiency reduces the overall intensity of electricity use. Efficiencies also affect peak demand, but they are basically targeted at kilowatt-hours. DR is targeted at kilowatts on peak.”

    While ERCOT’s forecast freezes efficiency, Shavel said, Brattle began withfederal efficiency standards already in place and assumed modest requirement increases. “We ended up with about 4% energy efficiency by 2032.”

    Ultimately, Brattle finds, “the most important feature of DR is that it saves customers’ money by deferring plant construction, while still reducing emissions.”

    Because a carbon policy is coming but not immediately, “the logical evolution of these resources might be to emphasize DR and energy efficiency now,” Brattle suggests.

    “Since DR does not have large long-term capital servicing requirements, few costs would be ‘stranded’ when a stronger climate policy triggered a larger fleet transition.”

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    Could FERC put a price on carbon?; EPA can require emissions cuts but FERC can make emissions unaffordable for utilities.

    Herman K. Trabish: July 28, 2014 (Utility Dive)

    The Federal Energy Regulatory Commission (FERC) could be more effective than the EPA in the Obama administration’s fight against greenhouse gas emissions, according to a new legal opinion. And such a move by FERC would not be without precedent, says one of the opinion’s authors.

    Through FERC’s authority over electricity rates, power contracts, and utility planning, as well as its responsibility for new transmission and natural gas pipelines, the agency can influence the cost-effectiveness of new generation and new infrastructure by putting a price on emissions, according toAddressing Climate Change Without Legislation from the University of California Center for Law, Energy, and the Environment.

    “It is not unusual for FERC to be aggressive in implementing what it sees as appropriate public policy,” explains co-author Steven Weissman.

    Congressman Henry Waxman (D-CA) urged such action on climate change to FERC commissioners at the July 29 House Energy and Commerce subcommittee hearing.

    "The statutory standards that FERC administers give the agency many tools to help combat climate change," Waxman told all four commissioners. The ideas proposed in the U.C. Berkeley legal opinion, which he entered into the Congressional Record, deserve "serious consideration" and show "we don’t have to choose between protecting the environment and reliable electricity."

    Wholesale electricity rates are in FERC's jurisdiction

    “FERC’s regulatory duties include overseeing wholesale electricity rates to ensure that they are just and reasonable and not unduly discriminatory or preferential,” the opinion reads.

    The Federal Power Act does not define “just and reasonable” but FERC and the Supreme Court have interpreted the phrase, the opinion goes on. They did not require a specific rate calculation methodology but said rates must be in “a zone of reasonableness” that balances the interests of electricity suppliers and customers while protecting “the general public interest.”

    For suppliers, “rates will be just and reasonable if they provide an opportunity to earn sufficient revenue to cover the operating expenses and capital costs of the business and provide a return on investment,” the opinion says. And for customers, “just and reasonable rates do not permit exploitation, abuse, or gouging, or unjust discrimination between customers.”

    Because fossil fuel generators do not pay for the environmental costs of emissions, the opinion argues, they have a potentially unreasonable competitive advantage over renewable energy developers. FERC could use its authority over rates to eliminate this advantage with a “carbon adder” on the wholesale electricity rate that reflects such costs.

    Through its authority over utility power purchase agreements, FERC could impose that carbon adder on contracts, the opinion notes. Through itsauthority over utility planning, it could require their Integrated Resource Plans to consider such an adder.

    “There has already been a significant amount attention to climate issues in FERC’s considerations,” says Weissman, a former California Public Utilities Commission (CPUC) Administrative Law Judge and policy advisor. CPUC decisions reflected an increasing awareness over time of the link between energy and climate change, Weissman says, and three particular recent decisions from FERC in support of renewables suggest it may also soon be ready to join the climate fight.

    Possible FERC action not without precedent

    Congress created a “chicken and egg” dilemma when it established the principle that access to transmission has to be non-discriminatory, he explains. Developers of utility-scale solar and wind need to know they will have transmission lines to their remote locations before they build but transmission builders need to know they will have users to pay for the new infrastructure before they will build.

    “FERC resolved the dilemma by deciding non-discrimination meant unfair discrimination,” Weissman says. In a decision supporting renewables, it pronounced renewables “locationally constrained” to where the sun shines and the wind blows and therefore in need of special consideration.

    In a similar decision, FERC interrupted delays in transmission build-outs to locationally constrained resources, Weissman goes on. It decided the cost of a new line would not fall only to the developer but to all those generators within that system who benefit from it.

    And finally there is the just-enacted Order 1000, Weissman argues. It required transmission planning to be coordinated and paid for regionally, making it “easier to move renewable energy while spreading the cost of new transmission across a broader base of customers,” he explains.

    “Those orders don’t necessarily mention climate change but they recognize the need for new transmission for public policy ends,” Weissman says. They showed that FERC can have its own sense of what public policy can be and proceed aggressively.

    A precedent in which FERC used rate adjustments for public policy ends, the opinion reports, was in its 2006 order, subsequently upheld by the court, forPJM Interconnection “to impose a charge equal to the marginal cost of transmission line losses on all wholesale customers.”

    The decision was made “on policy grounds” and to send “the strongest signal possible” to PJM generators to use transmission efficiently. PJM estimated the change has saved $100 million annually.

    FERC was aware the added charge would produce “a mismatch between costs and revenues and would most likely lead to a significant over-collection by PJM,” the opinion explains. That is why it also ordered that surplus funds be fairly returned to market participants.

    Climate action?

    “It is not a huge step for FERC to take more direct climate change action,” Weismann says. “It is likely in time there will be a price on carbon. Including a carbon adder in wholesale electricity rates now would help ensure that electricity demand is met using the generating resources with the lowest environmental cost and help guide utilities in directions that would not leave them vulnerable to sudden cost increases later.”

    The opinion also outlines ways FERC could similarly act through its authority over U.S. hydroelectric and hydrokinetic development and over natural gasinfrastructure and pipelines construction permitting.

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