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

  • Weekend Video: Bll Maher And EPA Head Gina McCarthy Dish About The Pope
  • Weekend Video: The Grim Facts
  • Weekend Video: Climate Change And Human Health
  • THE DAY BEFORE

  • ORIGINAL REPORTING, JUNE 26: HOW BASIN ELECTRIC IS HANDLING EXPLOSIVE NEW LOAD GROWTH IN NORTH DAKOTA
  • ORIGINAL REPORTING, JUNE 26: HOW THE WEST'S NEW ENERGY IMBALANCE MARKET IS BUILDING A SMARTER ENERGY SYSTEM
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    GET THE DAILY HEADLINES EMAIL: CLICK HERE TO SUBMIT YOUR EMAIL ADDRESS OR SEND YOUR EMAIL ADDRESS TO: herman@NewEnergyNews.net

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    THE DAY BEFORE THE DAY BEFORE

  • ORIGINAL REPORTING, JUNE 25: WHY DEPT OF ENERGY IS GOING BIG ON COMMUNITY SHARED SOLAR
  • ORIGINAL REPORTING, JUNE 25: INSIDE THE PG&E PROPOSAL TO BUILD 25,000 EV CHARGING STATIONS
  • THE DAY BEFORE THAT

  • ORIGINAL REPORTING, JUNE 24: WHY COMMUNITY SOLAR IS EXPLODING IN MINNESOTA
  • ORIGINAL REPORTING, JUNE 24: INSIDE THE DEAL: WHY DUKE ENERGY IS BUYING ONE OF THE LARGEST U.S. COMMERCIAL SOLAR DEVELOPERS
  • AND THE DAY BEFORE THAT

  • TODAY’S STUDY: ALL ABOUT SOLAR LOANS, SOLAR LEASING, AND SOLAR PURCHASE CONTRACTS
  • QUICK NEWS, June 23: GOOD BETS TO MAKE ON WIND; OKLAHOMA WIND COULD BOOM – THEN BUST; WIND FOR COAL IN COLORADO
  • THE LAST DAY UP HERE

  • TODAY’S STUDY: HOW GRID OPERATORS ARE HANDLING NEW ENERGY
  • QUICK NEWS, June 22: SOLARCITY MOVES INTO COMMUNITY SHARED SOLAR IN MINNESOTA; NO. CAROLINA SOLAR ADVOCATE NC WARN FILES SOLAR TPO FINANCING TEST CASE; SOLAR STILL FIGHTING IOWA UTILITIES
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    Anne B. Butterfield of Daily Camera and Huffington Post, 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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    Your intrepid reporter

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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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  • Monday, June 29, 2015

    TODAY’S STUDY: SMART MONEY GOES TO NEW ENERGY – BUT WILL IT BE ENOUGH?

    New Energy Outlook 2015

    June 2015 (Bloomberg New Energy Finance)

    Executive Summary

    By 2040, the world’s power-generating capacity mix will have transformed: from today’s system composed of two-thirds fossil fuels to one with 56% from zeroemission energy sources. Renewables will command just under 60% of the 9,786GW of new generating capacity installed over the next 25 years, and twothirds of the $12.2 trillion of investment.

    • Economics – rather than policy – will increasingly drive the uptake of renewable technologies. All-in project costs for wind will come down by an average of 32% and solar 48% by 2040 due to steep experience curves and improved financing. Wind is already the cheapest form of new power generation capacity in Europe, Australia and Brazil and by 2026 it will be the least-cost option almost universally, with utility-scale PV likely to take that mantle by 2030.

    • Over 54% of power capacity in OECD countries will be renewable energy capacity in 2040 – from a third in 2014. Developed countries are rapidly shifting from traditional centralised systems to more flexible and decentralised ones that are significantly less carbon-intensive. With about 882GW added over the next 25 years, small-scale PV will dominate both additions and installed capacity in the OECD, shifting the focus of the value chain to consumers and offering new opportunities for market share.

    • In contrast, developing non-OECD countries will build 287GW a year to satisfy demand spurred by economic growth and rising electrification. This will require around $370bn of investment a year, or 80% of investment in power capacity worldwide. In total, developing countries will build nearly three times as much new capacity as developed nations, at 7,460GW – of which around half will be renewables. Coal and utility-scale PV will be neck and neck for additions as power-hungry countries use their low-cost domestic fossil-fuel reserves in the absence of strict pollution regulations.

    • Solar will boom worldwide, accounting for 35% (3,429GW) of capacity additions and nearly a third ($3.7 trillion) of global investment, split evenly between small- and utility-scale installations: large-scale plants will increasingly out-compete wind, gas and coal in sunny locations, with a sustained boom post 2020 in developing countries, making it the number one sector in terms of capacity additions over the next 25 years.

    • The real solar revolution will be on rooftops, driven by high residential and commercial power prices, and the availability of residential storage in some countries. Small-scale rooftop installations will reach socket parity in all major economies and provide a cheap substitute for diesel generation for those living outside the existing grid network in developing countries. By 2040, just under 13% of global generating capacity will be small-scale PV, though in some countries this share will be significantly higher.

    • In industrialised economies, the link between economic growth and electricity consumption appears to be weakening. Power use fell with the financial crisis but has not bounced back strongly in the OECD as a whole, even as economic growth returned. This trend reflects an ongoing shift to services, consumers responding to high energy prices and improvements in energy efficiency. In OECD countries, power demand will be lower in 2040 than in 2014.

    • The penetration of renewables will double to 46% of world electricity output by 2040 with variable renewable technologies such as wind and solar accounting for 30% of generation – up from 5% in 2014. As this penetration rises, countries will need to add flexible capacity that can help meet peak demand, as well as ramp up when solar comes off-line in the evening.

    • Daily load profiles are also getting ‘peakier’, reflecting more household and commercial consumption and less steady industrial baseload. As this trend increases over time, power systems will need to increasingly reward system services such as demand response, battery storage, interconnectors and control systems that work along with traditional firm capacity to help match supply with demand.

    • Despite significant growth in renewables, fossil fuels will maintain a 44% share of generation in 2040 – albeit down from two-thirds in 2014. Some 1,291GW of new coal-fired capacity will be added to 2040, and 99% of this will be in developing countries where supply is relatively cheap and climate change policies weak or yet to be implemented. Only 1,359GW of gas will be added globally – 86% in developing countries – as its role as a 'transitional fuel' looks more and more doubtful outside the US where the shale gas revolution and environmental regulations seem set to push coal out of the market.

    • CO2 emissions from the power sector will rise by 13% over 2014-40. The utilisation of lowcost domestic fossil-fuel reserves from developing countries, the long life of coal plants and the absence of a strict regulatory framework will mean power sector carbon emissions are likely to peak around 2029 at 15.3Gt, then ease only slowly to reach 14.8Gt in 2040.

    • More than half of the new generating capacity to 2040 will be built in Asia Pacific so that for every 1GW of new build in the Americas, 3.4GW will be installed in APAC. China alone will attract $3.3 trillion of new investment – nearly double the total for the Americas – and build 2,601GW more capacity by 2040.

    • In Europe, small-scale solar will increase its share of the capacity mix to 22% from 6% in 2014 as households and businesses try to offset high retail power tariffs. Meanwhile environmental legislation, the age of the coal fleet, the EU carbon price and the technology’s relative inflexibility will nearly halve coal capacity. By 2040, just under 50% of generation will come from variable sources like wind and solar.

    • In the Americas, the US story to 2020 will be all about gas, which will see 90% of new build, thanks to low wholesale prices and coal retirements. From 2020 however it is small-scale solar that dominates, with 21GW added per year. At the same time, Latin America will invest just under $500bn in wind and solar as it tries to diversify away from an over-reliance on drought-prone hydro over the next 25 years.

    • In the Middle East & Africa, some 38% of new capacity will be fossil-fuelled as countries seek to exploit their substantial reserves. But we also expect 160GW of solar PV as many of these nations exploit their world-class solar potential. Despite the prevalence of subsidised retail power tariffs, as much as 40% of the new solar could be small-scale systems, used for example to build mini-grids to electrify communities sited away from the main grid.

    QUICK NEWS, June 29: SCOTUS SLOWS EPA CLEAN AIR EFFORTS; SOLAR HIGHWAYS; JAPAN TURNS FROM NUKES TO WIND POWER

    SCOTUS SLOWS EPA CLEAN AIR EFFORTS High court strikes down power plant regulations

    Richard Wolff, June 29, 2015 (USA Today)

    “A narrowly divided Supreme Court struck down federal clean air regulations…on coal- and oil-fired power plants…The 5-4 ruling blocks the Environmental Protection Agency from jump-starting new rules designed to reduce the amount of dangerous mercury and other toxins that pollute the nation's air, at an unknown net cost to power plants and consumers…It was a major defeat for the Obama administration, which had been on a roll at the high court on environmental matters…[and] a victory for a coalition of 20 states, along with major electric utilities and coal producers…[The court agreed EPA must take the estimated annual cost of $9.6 billion into account, but the agency did not do so…The government said the regulations would prevent premature deaths and illnesses from asthma, cancer and heart disease, and protect pregnant women and unborn children...[from] overexposure to mercury…Among the industries most threatened were coal plants…” click here for more

    SOLAR HIGHWAYS Start of test with solar energy generating noise barriers alongside highway

    June 29, 2015 (PhysOrg)

    “Alongside the A2 highway near Den Bosch, The Netherlands, two test noise barriers are installed that generate solar energy. The aim of this practical test, that was officially launched 18 June is to assess the economic and technical feasibility of this form of energy generating noise barriers…These 'luminescent solar concentrators' (LSCs) receive sun light and guide it to the side of the panels. There, it lands in concentrated form on traditional solar cells…The researchers intend to assess the feasibility of generating electricity using solar cells integrated in noise barriers or SONOBs (Solar Noise Barriers)…The aim is to provide better understanding of how much electricity these semi-transparent acoustic screens can generate under different conditions.,,” click here for more

    JAPAN TURNS FROM NUKES TO WIND POWER This Huge Wind Turbine Floating on Water Is Fukushima's Energy Solution

    Bryan Lufkin, June 23, 2015 (GizModo)

    “A mere 12 miles from the wrecked Fukushima Daiichi nuclear plant will soon sit a 620-foot, 1,500-ton [7 MW] windmill atop a 5,000-ton podium. It’ll be the biggest [most powerful] floating wind turbine on Earth, and it could usher in a new age of green energy for a region largely fed up with nuclear energy…The beast of a turbine sports three 270-foot-long blades and is built to stand against winds nearly 200 mph…The $401 million Fukushima wind farm project is a government-sponsored collaboration among 11 companies and research orgs, like Mitsubishi, Hitachi, and the University of Tokyo…” click here for more

    Saturday, June 27, 2015

    Bll Maher And EPA Head Gina McCarthy Dish About The Pope

    They agree: He can't be ignored. From Real Time With Bill Maher via You Tube

    The Grim Facts

    This is the human impact of Pakistan’s heat wave. Is it related to climate change? Is the Pope Catholic? From CNN via YouTube

    Climate Change And Human Health

    There is a threat – and an opportunity. It’s “no longer a question of science or technology. it’s a matter of political will…” From LancetTV via YouTube

    Friday, June 26, 2015

    ORIGINAL REPORTING, JUNE 26: HOW BASIN ELECTRIC IS HANDLING EXPLOSIVE NEW LOAD GROWTH IN NORTH DAKOTA

    [NEWENERGYNEWS is on the road today. Regular features will return next week.] How Basin Electric is handling explosive new load growth in North Dakota; The co-op is planning new transmission and generation as a result of the oil and gas boom

    Herman K. Trabish, February 13, 2015 (Utility Dive)

    In a time when most utilities across the nation are struggling with stagnant or declining load growth, those in North Dakota have a different problem. Explosive growth in the state's Bakken shale region has brought on a 12% jump in the state's population in just the last five years.

    Keeping the lights on is a challenge, but Basin Electric Power Cooperative is combining the latest natural gas peaker turbine technology, some of the best wind resources in the world, and persistent transmission expansion to do it.

    “Our 2014 load forecast showed we need to add 1,883 MW by the year 2035 and of that the Bakken requirement is 1,616 MW,” Basin Electric’s Media Manager Curt Pearson told utility dive.

    Basin Electric is one of the biggest U.S. generation and transmission (G&T) electric cooperatives and, driven by the Bakken boom, its $2 billion-plus 2013 revenues topped all U.S. electric cooperatives.

    Basin is owned by 138 member cooperatives across 540,000 square miles in nine states from the Canadian to the Mexican borders. It serves 2.8 million electric customers and operates 4,913 MW of generation that includes coal, gas, oil, nuclear, and renewables. A total of 483 MW is renewable energy, with 438 MW of wind. Basin also owns 2,168 miles of high voltage transmission and maintains 2,253 miles of it.

    The need for new G&T

    Basin started seeing load growth in 2008 in the Bakken shale region around Williston, North Dakota.

    “In 1997, there were 3 oil drilling rigs in North Dakota. In 2014, before the oil price collapse, there 187 rigs operating,” Pearson said. “But the load growth is not just from oil production. It is the workers coming in, the schools hiring new teachers, sheriff departments hiring new deputies, new apartments, new homes, new schools, hospitals expanding, new stores, gas stations doubling in size.”

    The cooperative’s planners quickly realized the rural area would need a strengthened transmission system. They started with 2010’s Rhame-Belfield and 2011’s Williston-Tioga 230 kilovolt (kV) expansions, but Bakken demand only continued to rise.

    Basin engineers realized they would need more.

    “We build only to meet the needs of our member electric cooperatives and we do that based on their load forecasts," Pearson said. "But our members in the Bakken area kept coming back, year after year, with increased load forecasts.”

    The engineers concluded they needed two things: A high capacity line to deliver the G&T’s existing power capacity to the region and new generation.

    The answer to the generation need was a series of phased expansions of peaking natural gas capacity at its Pioneer and Lonesome Creek stations in the heart of the Bakken. Basin incorporated state-of-the-art natural gas turbine technologies.

    The new peakers, which have been coming online over the last year, will work in coordination with Basin’s existing generation.

    They will also work in conjunction with newly developed North Dakota winds, some of the most powerful winds in the world, with capacity factors of 45% to 50% or higher.

    With over 400 MW now in service, NextEra Energy and other developers are working to build more to meet Bakken oil patch needs.

    “There is a very good school of thought that says if you have wind and you can back it up with natural gas peaking stations, you in fact have base-load power,” Pearson said.

    The new line

    Basin’s answer to the need for a new line is the 200-mile, $350 million, 345 kVAntelope Valley Station to Neset Transmission Project. Begun in September 2014 and scheduled for completion in 2017, its loop around Lake Sakakawea starts just north of Beulah in the center-west of North Dakota. It goes west to near Grassy Butte, then north to near Williston, then north beyond Williston to near Tioga.

    They had to obtain approvals from the Western Area Power Administration, the Rural Utilities Service, the U.S. Army Corps of Engineers, the U.S. Forest Service, and the North Dakota Public Service Commission, Pearson said. “It was a very complex project,” Pearson said.

    Because Basin went through the Rural Utilities Service to obtain funding and because the line would interconnect with the Western Area Power Administration transmission system, a National Environmental Policy Act-based Environmental Impact Study (EIS) was required. It was published last May.

    “We are only waiting for an approval from the Corps of Engineers for a river crossing south of Williston but it is in process now that we have agreed to special provisions for a floodplain with wildlife habitat,” Pearson said.

    Compared to the permitting processes for other lines, Basin’s approval process of only three years was practically turbocharged. Pearson expressed amazement after reading in Utility Dive of the seven year struggle for permits by developers of the Transwest Express. He suggested Basin may have met fewer problems with federal agency staff.

    That may be because the Basin line covers a smaller and single state footprint. The biggest challenge was obtaining rights-of-way from some 300 landowners. The response was good because the cooperative’s developers knew they were dealing with rancher-members and farmer-members of Basin-associated cooperatives.

    “We truly wanted to work with them, to listen to their concerns, and to locate the line suitably,” Pearson said.

    They also knew landowner talk. “We know that if we make an offer at 9:00 in the morning, the next neighbor down the line knows about it by 2:00 in the afternoon,” Pearson said. “If we make an offer for land but later settle with another member-landowner at a higher price, we will go back and make it right with the first landowner.”

    Landowner fatigue

    Something Basin calls “landowner fatigue” or “pipeline fatigue” was the biggest challenge in obtaining rights-of-way.

    “If a utility goes to a rancher and makes an offer for land to site a transmission line or a pipeline, that rancher probably says ‘OK, it serves the greater good, I can live with it,’” Pearson explained. But with developers frantically building infrastructure like pipelines, water systems, and telecommunications lines in the region, Basin was sometimes making the fourth or fifth request.

    “That rancher may say ‘enough is enough,’” Pearson said. “It leads to much tougher negotiations, higher prices for access, and more effort.”

    Basin now has its rights-of-way and permits and EIS and construction has begun. But the price of oil has collapsed and things are changing in the Bakken. Kicker: The oil price collapse

    “Our planning staff is studying the changes with a great degree of diligence,” Pearson said. “The crews are being sent home. But the drilling rigs are being parked, not shipped out of state. For anyone to assume the Bakken is done is simply wrong.”

    “In the heart of the Bakken, they will retrench their efforts because the resource is phenomenal," Pearson said. “Drillers there have a 99.99% chance of hitting a productive well.”

    There will be a year or two of redirected focus and consolidation, he believes. “People up there are using this slowdown to take a breather and get caught up,” he said.

    During that pause, the Antelope Valley Station to Neset line will be nearly completed. Wind builders will expand the state’s installed capacity and spread it out geographically.

    In combination with the new transmission, the impact of wind’s variability will be diminished. That will make both Basin’s new gas peakers and its wind even more cost-effective.

    By then, Pearson said, the drillers will be back.

    ORIGINAL REPORTING, JUNE 26: HOW THE WEST'S NEW ENERGY IMBALANCE MARKET IS BUILDING A SMARTER ENERGY SYSTEM

    [NEWENERGYNEWS is on the road today. Regular features will return next week.] How the West's new Energy Imbalance Market is building a smarter energy system; The market saved millions in its first two months and helped prevent curtailment of renewable resources

    Herman K. Trabish, February 19, 2015 (Utility Dive)

    One of the great speculations about the Western grid has been tested and proved true.

    A new report shows the just-initiated energy imbalance market (EIM) linking the California grid and the seven state Pacificorp system saved almost $6 million in its first two months. The market allows utilities to trade energy from a significantly larger area to balance out supply and demand fluctuations.

    “It is very encouraging that some of the predictions and expectations of what this was supposed to do are materializing,” said California Independent System Operator (CAISO) Vice President Mark Rothleder.

    The new EIM demonstrates the West’s fiercely independent balancing areas will profit through an automated but unobligated sharing of resources to meet momentary supply-demand fluctuations.

    CAISO’s recently released analysis, "Benefits for Participating in EIM; 2014 Q4 Report," finds that the estimated gross benefits from the first two months of EIM's existence are $5.97 million and “reflects EIM’s ability to select the lowest cost resource across the PacifiCorp and ISO [balancing authority areas] to serve demand.”

    Pacificorp is owned by Warren Buffett’s Berkshire Hathaway Energy. Pacific Power (PACW), its western arm, serves electricity customers in Oregon, Washington, Idaho, Wyoming, Montana, and California. Rocky Mountain Power (PACE), its eastern arm, serves Utah, Idaho, and Wyoming.

    “An EIM allows grid operators to net out their differences,” explained American Wind Energy Association Research Director Michael Goggin. “A utility in one state has an increase in demand and a utility in a neighboring state has an increase in wind output. It would increase efficiency if they could exchange and net out the differences. That reduces the need for flexibility and reserves on the system.”

    Reducing any one balancing authority’s use of flexibility and reserves sharply cuts costs for the grid operator because those are a power system’s highest-priced needs.

    “We are seeing transfers of economic energy,” Rothleder said. “The EIM is making use of the transfers to optimize the resource mix to meet the combined area’s imbalance needs.”

    Results of the first two months

    Preliminary estimates for November and December 2014 show Pacificorp sent 180,786 megawatt-hours (MWh) to CAISO and received 27,361 MWh. In the transfers, CAISO saved $1.24 million, PACE saved $2.31 million, and PACW saved $2.42 million.

    The savings demonstrate the EIM’s 15-minute marketplace automated optimization system can accurately “select the lowest cost resource across the PacifiCorp and ISO balancing authority areas to serve demand,” the report concludes.

    The study that drove the creation of the two-system EIM assumed benefits would be shared equally, Rothleder said. “But it was recognized the ultimate accrual of benefits could change by season and flow direction.” With only two months of data, it is premature to conclude this will be the regular ratio of savings between the systems, he added.

    More importantly, the direction of the transfers is consistent with the economics, Rothleder said. ”We are actually decreasing the overall dispatch cost by accessing more economic transfers in real time.”

    Transfers are taking place at up to 421 megawatts (MW) per 15-minute interval between the PACW and the CAISO, at up to 220 MW per interval from the CAISO to PACW, and at up to 200 MW per interval from PACE to PACW. “We probably saw levels that approached that maximum transfer limit at times,” Rothleder said.

    Renewables: Oversupply and curtailment

    Another predicted benefit realized in the EIM’s first two months was the reduced curtailment of renewables. Data is incomplete because it is impossible to know what would have happened if there was no EIM, but the evidence is telling.

    “We know there were times in November and December when there were negative prices in California, most often around midday on the weekends,” Rothleder explained.

    That meant an oversupply. But instead of a renewables generator being “economically dispatched down” (i.e., voluntarily cutting output to avoid being sold at the lower prices), the resources were transferred to Pacificorp markets.

    “There was not necessarily an avoided manual curtailment although we may have prevented the need to do that or to economically dispatch down,” Rothleder said.

    An important takeaway from observing EIM operations and other supply-demand factors is that oversupply conditions in California are likely to appear first “in the springtime, on weekends, at midday rather than off-peak hours, and then spread to other seasons,” Rothleder said.

    While California’s renewables mandate remains at 33%, there will likely not be oversupply in the summer. “If you look forward to a 40% and 50% [mandate]," he said, "depending on the mix of resources and what other mechanisms are in place, like regional coordination or storage playing a role, this pattern could spread to other parts of the year.”

    Much was learned in the EIM’s first two months that will make it easier tobring in NV Energy late this year, Rothleder said. Lessons included the operation of an automated 5-minute marketplace, how to do transfers and manage flow-gate-flows across a neighboring non-participating system like the Bonneville Power Authority (BPA), and how to train new operators.

    A West-wide EIM?

    “Big picture, this is transformational, not just for Paciificorp and the ISO but it has generated a lot of discussion in the rest of the West and opened up new lines of communication,” Rothleder said.

    The success is unlikely to impede opposition from the American Public Power Association (APPA) to a West-wide EIM among the region’s 38 balancing area authorities.

    APPA is concerned about the “strong potential for an EIM to lead to a Western Regional Transmission Organization (RTO),” according to Electric Market Reform Initiative Manager Elise Caplan. RTOs, under federal jurisdiction, “have been highly problematic in the eastern part of the country.”

    APPA resistance is likely to continue despite the CAISO report’s direct refutation of the claim in APPA’s resolution on the EIM that “cost/benefit studies done to date have not clearly demonstrated the value of an EIM to consumers.”

    Advocates insist a West-wide energy imbalance market would be a balancing mechanism and would not lead to RTO obligation.

    “It is inaccurate to say that NV Energy is joining the ISO’s EIM,” CAISO Senior Public Information Officer Steven Greenlee stressed. “It is voluntary participation. NV Energy can use the EIM as it needs it. It is not obligated.”

    NEWENERGYNEWS IS ON THE ROAD TODAY SO NO QUICK NEWS, June 26

    Thursday, June 25, 2015

    ORIGINAL REPORTING, JUNE 25: WHY DEPT OF ENERGY IS GOING BIG ON COMMUNITY SHARED SOLAR

    [NEWENERGYNEWS is on the road today. Regular features will return next week.] Why Dept of Energy is going big on community shared solar; DOE's SunShot initiative awarded $14 million to develop business models for shared solar

    Herman K. Trabish, February 12, 2015 (Utility Dive)

    A new solar sector is emerging, a sector so new that its name — community shared solar — has not yet been precisely defined.

    That is why the Department of Energy (DOE) SunShot Initiative just gave $14 million to 15 awardees to define what community shared solar is, identify what business models will work, and explain how it will make solar more accessible and affordable. Only one thing is now clear.

    “There is no dispute that installing solar on a roof is far less economically efficient than putting 5,000 panels in an open field in 60 days and selling it to 1,000 customers,” said Paul Spencer, founder and president of Clean Energy Collective, the biggest U.S. community solar developer. “There is no comparison as to the capital efficiency of those two solutions.”

    In terms of accessibility, explained SunShot Director Minh Le, a new analysis from the National Renewable Energy Laboratory now in peer-review suggests that “between 50% and 75% of households and just over 50% of businesses are unsuitable to host PV systems on their roofs because of shade, orientation, structural factors, or ownership issues.” The new sector will bring solar to them.

    As for affordability, community shared solar can reduce solar costs in two ways and both are attracting significant utility interest.

    “Utility participation is going to be transformational,” Le said. “The perceived resistance to solar from utilities is really not there when you talk about aggregating consumers on larger projects to get economies of scale and siting near substations or distribution feeders to reduce interconnection issues.”

    DOE gets into community shared solar

    DOE’s role in the current expansion began in 2012 with its report, "Guide to Community Shared Solar: Utility, Private, and Nonpro¬t Project Development," Le said. The Guide outlined business models, challenges, and opportunities. It led to 2013’s “Community Shared Solar: Getting to Scale" workshop.

    The workshop developed DOE’s expansive definition that includes a range of ownership concepts and benefit allocations. Interest from utilities, the solar industry, and other stakeholders in breaking down barriers to community shared solar led to SunShot’s Solar Market Pathways program.

    The current round of Market Pathways funding awarded the Solar Electric Power Association $705,830 to study “the intersection of community solar business models and consumer demographics” and produce “more standardized, streamlined and cost-effective business models.”

    “One of our first tasks,” explained SEPA Senior Research Manager Becky Campbell, “will be to find some level of consensus about how these programs are defined.”

    Campbell hopes SEPA’s survey and research will develop individual business models with unique names so “we can not only be on the same page when discussing community solar, but we can take it one step further and start to use common terminology to describe the traits of each program model.”

    The commercial business models

    CEC is the only private sector community solar developer offering both established business models, according to Spencer.

    In one, customers own panels. “The customer makes a down payment on the panel at the front end of the transaction, with cash or financing, and owns the asset,” Spencer explained. “The customer gets 100% of the power being sold to the utility in the form of a dollar amount credited to their utility bill for the production of the solar-generated electricity produced by the customer’s panels in the array.”

    The dollar amount credited is slightly less than the amount earned by the total output of the panels owned because a small percentage goes into a CEC-administered escrow account to cover operations and maintenance and other expenses.

    CEC’s Remote Meter proprietary billing software is merged into the local utility’s billing system. It automatically integrates the credits earned by the solar with the customer’s utility bill so that the customer gets one utility bill.

    The panel investment can eventually pay for itself, creating ownership equity. CEC earns its money by selling the array’s panels at a slight mark-up from cost.

    “The second model, a rental model, is more complicated to understand but less complicated for us to do, which is why other companies are doing it,” Spencer said. CEC calls its rental model SolarPerks. Other players like SunShare and SunEdison also use it. It provides a net utility bill savings proportional to the amount of kilowatt-hours the subscriber commits to paying for but the subscriber has no upfront cost and earns no ownership equity. A residential customer gets a guaranteed 5% savings while commercial customers can save up to 10% or more.

    The subscriber deals with two bills. The utility bill shows the dollar amount of the credit for 100% of the solar kilowatt-hours to which a residential subscriber commits. CEC debits that subscriber’s bank account for 95% of the credit.

    “Though there is a monthly savings, the subscriber has no ownership,” Spencer stressed. “It appeals to a different public and works differently, but still saves money.”

    Utilities have been less successful with the ownership model than with the rental model unless, like CEC, they offer some form of loan or on-bill financing to help customers with upfront costs.

    “If you finance and blur the lines, the first model ends up looking a lot like the second model until the panels are paid off,” Spencer said. “But the market definitely likes the zero-down option and since it supports more solar, it produces more environmental benefits.”

    DOE awards

    CEC won a $700,000 SunShot Initiative award last fall to develop and implement the National Community Solar Platform (NCSP). It is intended to help developers, EPCs, utilities, and community solar organizers avoid the complexities that CEC had to resolve with securities law, tax law, electronic on-bill crediting solutions, state and federal law, and land use issues to become the leading U.S. community solar developer.

    Expected to launch by spring 2016, the platform will provide web-based access to information and market-proven tools that will make community solar development “easier, cheaper, faster, and widely scalable.”

    A Market Pathways award of $2,430,682 went to Dominion Virginia/Virginia Electric and Power to lead a team of representatives from state government, research institutions, environmental organizations, local communities, and solar businesses in developing business models for utility-administered solar.

    Given the lethargy of Virginia’s solar market, Dominion Virginia’s interest is groundbreaking. And given that a similar coalition of stakeholders teamedwith Duke Energy in nearby South Carolina to prepare the ground for what may be a coming solar market explosion there, the progress of Dominion Virginia’s team will be worth watching.

    Market Pathways awarded $1,238,308 to the Cook County Department of Environmental Control’s Chicago project to identify business models that most benefit seniors, multi-unit housing tenants, and low-income customers. “By having the solar project in the community instead of buying solar generated electricity from a distant utility-scale project, it also offers the opportunity for local economic development,” Minh said.

    How big can community shared solar get?

    When world-leading solar developer First Solar became “a minority yet significant owner in CEC” late last year, Spencer said, the companies calculated that if only about a quarter of all roofs are suitable for solar and 40% of those are occupied by renters, the market for community solar is about seven times as big as that for rooftop solar.

    “We share First Solar’s enthusiasm about the opportunity,” Minh said. “Our projection is that between 20015 and 2020 there will be a cumulative $6 billion to $12 billion invested in the community shared solar space – but that is an estimate made in the very early days of what could be a very exciting market.”

    ORIGINAL REPORTING, JUNE 25: INSIDE THE PG&E PROPOSAL TO BUILD 25,000 EV CHARGING STATIONS

    [NEWENERGYNEWS is on the road today. Regular features will return next week.] Inside the PG&E proposal to build 25,000 EV charging stations; California’s IOUs await regulators’ approval to get into the EV charging business

    Herman K. Trabish, February 12, 2015 (Utility Dive)

    California utilities are going to attack the range anxiety impeding electric vehicle growth. Following the December California Public Utilities Commissiondecision to allow utilities to invest in EV charging infrastructure, Pacific Gas and Electric Company (PG&E) trumped the state’s two other investor owned utilities by asking for regulatory approval of the biggest charging station build-out ever.

    “California has the most electric vehicles in the U.S. and PG&E has over 60,000 electric vehicles in our service territory, the most in California and 20% of all U.S. EVs,” explained PG&E Director of Electrification/Electric Vehicles James Ellis. “But with 40% of California greenhouse gas emissions (GHGs) coming from the transportation sector, growth in EV infrastructure is not fast enough to drive adoption of the electric transportation needed to meet the state’s 80% GHG reduction by 2050 goal.”

    PG&E wants CPUC approval to partner with the private sector to build 25,000 level two charging stations and 100 DC fast charging stations, which is about 25% of the infrastructure needed by 2020 in its Northern and Central California service territory.

    The 25,000 level two chargers, to be located at commercial and public sites like multi-family dwellings, retail centers, and workplaces, will provide up to 25 miles for every hour of charging. The 100 DC fast chargers, which fully recharge an EV’s battery in only 30 minutes, would be more dispersed.

    Other IOU initiatives and costs to ratepayers

    The program’s total cost of $653.8 million would be applied across the PG&E ratepayer base because the program supports state GHG and pollution reduction goals. Ratepayers would see no bill impact in 2016 and 2017, according to PG&E, and costs would reach only $0.001 per KWH over the next five years, adding an estimated $0.70 per month to the typical residential customer’s bill from 2018 to 2022.

    The San Diego Gas & Electric (SDG&E) $103 million electric vehicle-grid integration (VGI) plan was designed to test customer response to variable rates for vehicle charging.

    It would build 5,500 charging stations, primarily at multi-family housing and workplaces, between 2015 and 2025. The capital cost would be approximately $59 million and operations and maintenance over the ten years would add $44 million.

    The Southern California Edison (SCE) $355 million Charge Ready Programswould run five years, from 2015 through 2019, and result in a rate increase of $0.001 per KWH, or 0.1% to 0.3% of the average bill. Phase 1, a one-year pilot, would cost $22 million and deploy up to 1,500 charging stations. Phase 2 would cost an additional $333 million and deploy up to 30,000 charging stations by 2020. SCE would locate, design, build, own, and maintain the electrical infrastructure. Customers would choose, own, operate, and maintain the charging stations.

    Both an Administrative Law Judge and The Utility Reform Network (TURN) customer advocate expressed concern about rate impacts from SDG&E’s VGI. This suggests the utility proposals may face serious scrutiny before winning regulatory approvals.

    Why utilities should be involved

    “Plug-in America very much supports the utilities becoming involved,” said Plug-in America Director Jay Friedland. “But the devil is in the details. We will be watching to make sure they are installing the right infrastructure in the right places and serving the needs of electric vehicle drivers.”

    The CPUC seems aware, in reversing its 2011 decision prohibiting utilities from building EV charging infrastructure, that it must “make sure the infrastructure is going into the ground and into the ground in the right places,” Friedland added.

    Government subsidies for charging infrastructure are typically workable only at the local level because municipalities know their transportation systems, Friedland explained. The private sector has been significantly more successful.

    “An owner who goes to a Tesla super charging station knows there will be 4 or 8 or even 12 chargers,” he said. Other automakers are moving in that direction, as exemplified by a new BMW-Volkswagen plan. Private charger manufacturers like ChargePoint have also built infrastructure.

    “The third model is utilities,” Friedland said. “So far, only NRG Energy has jumped in but that is the beginning of the utility model.”

    The infrastructure

    If California is to meet Gov. Brown’s 2013 goal of having 1.5 million zero emissions vehicles (ZEVs) by 2025, Ellis said, it will have about 1 million in 2020 and PG&E’s 40% will be 400,000 of those, Ellis said. Based on research from the National Renewable Energy Laboratory and the Electric Power Research Institute, PG&E calculates the need is a level two charging station for every four vehicles.

    That comes out to 100,000 charging stations for its territory, resulting in PG&E’s proposed 25,000 stations to meet 25% of that need.

    “A 25% market share will not be overbearing to the market because it leaves 75% to the other players,“ Ellis said. “But it will reduce barriers to EV ownership, drive adoption, and raise awareness.”

    The 100 DC fast chargers will likely make up no more than 20% of the PG&E territory’s 2020 need, Ellis acknowledged.

    “The studies show we will require 500-plus DC fast-chargers," he said. "Some automotive companies are suggesting 1,200-plus fast chargers to make charging more analogous to today’s fueling paradigm,” he said. “We may need more than 100 in the future.”

    Deployment of DC fast chargers is more logistically challenging, both Ellis and Friedland said, because of their high impact on the grid.

    PG&E will build the level two chargers as quickly as possible to create more convenience and reduce range anxiety for both plug-in hybrid electric vehicle (PHEV) and battery electric vehicle (BEV) drivers, Ellis said. “But where we might have a bank of 10 level two chargers, we might only have one or two DC fast chargers.”

    PHEV drivers do not need fast chargers, he added, and “BEV drivers will be able to charge for up to 30 minutes and get enough range to get to the next level two charger.”

    The PG&E proposal does not include level one chargers, Ellis said, because they are not likely to cost-effectively support the bigger and more demanding batteries coming from EV makers.

    How and why PG&E will build

    PG&E will contract with site hosts and provide the EV service connection at no cost through a separate service drop, instead of through existing infrastructure. Its EV service provider partners will deploy and operate the chargers through a competitive bidding procurement but PG&E will own them.

    “We will sell electricity to the service provider at an applicable time-of-use commercial rate,“ Ellis said. “They will sell it to customers. But the two rates will be nearly the same, and approved by the CPUC. The billing partner will make money through a services contract with us, not through a significant markup on the price of electricity.”

    Putting a price on emissions would be good for utilities because it would drive the uptake of electric vehicles which would in turn boost demand for the electricity that utilities sell, PG&E CEO Tony Earley Jr. told a conference recently.

    “If we can get more EV charging and more electricity use through EVs at opportune times, that helps us maintain rates and potentially even puts downward pressure on rates over the long term,” Ellis explained.

    Kicker: Renewables integration

    A happy side effect of the chargers is that they can also help PG&E integrate more renewables onto the grid.

    “We would like to do smart charging and turn those chargers on when we have high renewables, especially solar, on the system,” Ellis said. The TOU rates are intended to drive consumers in that direction and the level two chargers are intended to get the electricity to the vehicles in the targeted time frame.

    “It used to be that we wanted to push charging to the night because that was when the power was cheaper and in excess,” Freidland said. “Now, there is a demand for smart charging and demand response. A charger owner might allow the utility to use it during the midday supply peak when renewables are in excess but not during the early evening demand peak. A modification of what Tony Early said is that EV charging will help utilities sell electricity in a smarter way.”

    NEWENERGYNEWS IS ON THE ROAD TODAY SO NO QUICK NEWS, June 25

    Wednesday, June 24, 2015

    ORIGINAL REPORTING, JUNE 24: WHY COMMUNITY SOLAR IS EXPLODING IN MINNESOTA

    [NEWENERGYNEWS is on the road today. Regular features will return next week.] Why community solar is exploding in Minnesota; Mortenson-SunShare partnership leads the charge with 100-plus MW solar pipeline

    Herman K. Trabish, February 5, 2015 (Utility Dive)

    Minnesota had 14 MW of solar installed at the end of 2014.

    Remarkably, it now has over 400 MW in its community solar queue today.

    In December, Xcel Energy launched its Solar*Rewards Community for Minnesota. Based on a successful program in Colorado, Xcel Minnesota customers will be able to pay for solar energy-generated electricity from third-party developed central station arrays that is sent to the grid and get credit on their electricity bills for it.

    “I am blown away by the response to the community solar program,” said John Farrell who, as one of the architects of Minnesota’s solar law, helped put the policy framework for this boom in place. “It is going to explode in 2015, driven by the many, many people getting into the game who previously would not have thought about solar, businesses, individuals, cities.”

    Community solar is “a program through which individual members of a community have the opportunity to ‘buy in’ to a nearby solar installation…[and] receive a proportional share of the financial or energy output of the system,” according to Expanding Solar Access Through Utility-led Community Solar from the Solar Electric Power Association (SEPA). “Community solar programs may be offered by electric utilities or through third-parties or community groups.”

    “Only 22% to 27% of residential rooftop area is suitable for hosting an on-site photovoltaic (PV) system,” according to the 2010 Guide to Community Shared Solar from the National Renewable Energy Laboratory. “Community solar options expand access to solar power for renters, those with shaded roofs, and those who choose not to install a residential system on their home for financial or other reasons.”

    But, Farrell pointed out, “some utilities are looking at community solar as a way to poach people away from net metering and change the economics in their favor.”

    “Larger solar developments – as compared to putting solar panels on individual roof-tops – usually cost less to install, which can make solar power more affordable and convenient,” said Xcel Energy VP Chris Clark in announcing the program.

    Minnesota’s Community solar gardens bill, passed in 2013, was intentionally designed with no cap on capacity to prevent utilities from limiting distributed solar.

    “We made sure community solar is value added in Minnesota,” Farrell explained. “It expands the opportunity for people to participate in solar but also allows traditional net metered distributed solar to continue to grow.”

    Community solar business models

    SunShare, the second biggest U.S. community solar developer, is moving aggressively to take advantage of the Minnesota opportunity.

    “In 2014, our total capital activities exceeded $50 million, including investments from NRG Renew and others, and we expect to grow substantially in 2015 and 2016,” explained CEO David Amster-Olzewski.

    Clean Energy Collective (CEC) is the leading private sector community solar developer, with 37 megawatts of built capacity in 51 projects involving 19 separate utilities across 8 states. It just won what appears to be major backing from First Solar, one of the world’s biggest solar developers. CEC is currently focusing the bulk of its activity in Massachusetts.

    CEC has succeeded using an up-front payment for panels business model. It always works with an active utility partner, which handles the billing.

    SunShare’s automated system informs the utility of its array’s output and the percent of that output contracted for by each subscriber, Amster-Olszewski explained. Each subscriber gets a bill from the utility detailing usage, credits earned for the solar array’s output, and the various other utility charges.

    Under Minnesota’s law, subscribers earn an applicable retail rate (residential: $0.12 per kWh, small commercial: $0.11 per kWh, large commercial: $0.09-plus per kWh) plus the $0.02 per kWh renewable energy credit fee from Xcel. That will make the remuneration for community solar comparable to the remuneration earned by net metered customers, Amster-Olszewski said.

    Each subscriber also gets a bill from SunShare, based on a fixed 20-year per-kilowatt-hour contract rate and the month’s electricity usage, he explained. The rate is at or under the utility rate, with a 2% to 3% inflation escalator. It protects subscribers from the EIA-estimated 4% to 5% national average annual power price increase.

    With its new SolarPerks model in Massachusetts, CEC is introducing a plan in which subscribers pay nothing upfront, contract with CEC for kilowatt-hours, are credited by the utility for their share of the array’s output, and pay 95% of that credit to CEC for owning and maintaining the array.

    “The subscriber automatically gets a 5% reduction with no upfront cost,” a CEC spokesperson explained. “But as electricity goes up, the subscriber will never be victim to an increasing electricity bill.”

    The SunShare-Mortenson deal

    To anchor its Minnesota growth, SunShare formed a strategic partnership with Minnesota-based Mortenson Construction, one of the biggest U.S. energy project and renewables builders.

    “We are always looking for the next market, the new market, and particularly we are looking for markets that will be strong in 2017 and beyond,” explained Mortenson Vice President and General Manager Trent Mostaert. “We saw community solar get started in Colorado and saw SunShare play a leading role. When they came to Minnesota, we decided to jump on board.”

    In 2017, Mostaert noted, the federal investment tax credit (ITC) drops from 30% to zero for residential solar but will be 10% for commercial arrays. “Yet it is selling power to subscribers at close to the retail rate instead of trying to sell into the wholesale market,” he explained.

    Mortenson will serve as Engineering, Procurement, and Construction (EPC) contractor on SunShare’s projects, Mostaert said. Both companies’ representatives acknowledged the builder is also acting as an informal bridge for SunShare to the Minnesota market.

    Over 100 MWs of SunShare’s Minnesota pipeline has already won preliminary approval from Xcel, according to Amster-Olszewski. “That represents $250 million in projects to be developed mostly in 2015 but also in 2016, he said. “We are working with capital partners and expect to have announcements in the next 3 months.”

    Interconnection issues on the horizon?

    Interconnections could be a concern amid the boom, Mostaert said. “If we had more visibility into Xcel’s transmission capacity, it would make it a lot easier to plan our projects.”

    With more data and information about the capacity of feeder lines earlier in the process, he explained, Mortenson and SunShare could identify land to target for development. Instead, they are “now locating at substations and major transmission lines and hoping there is capacity on those lines.”

    Where poor planning allows feeder lines to become overloaded, as in Hawaii,development has become impeded and more costly. That could be happening now in Minnesota. Once the interconnection application is filed and the $1 million per 10 MW fee is paid, Xcel provides feeder capacity information, Mostaert said. But that could mean a developer discovers the feeder is overloaded after committing land and significant money.

    Both Xcel and the Minnesota Public Utilities Commission are reportedly working on resolving the interconnection issues, Mostaert said.

    "Even if only half the solar in the queue is built, that is still ten times more solar that was installed in this state before this year and it will only grow from there because electricity prices keep going up,” Farrell said. “The exploding growth will bring Xcel back to the commission with some reason it has to be slowed, capped, changed, or something, to keep their control of the grid. Community solar is going to call attention to that.”

    ORIGINAL REPORTING, JUNE 24: INSIDE THE DEAL: WHY DUKE ENERGY IS BUYING ONE OF THE LARGEST U.S. COMMERCIAL SOLAR DEVELOPERS

    [NEWENERGYNEWS is on the road today.Regular features will return next week.] Inside the deal: Why Duke Energy is buying one of the largest U.S. commercial solar developers ; Duke’s $225 million fund will ready commercial solar for a post-ITC market

    Herman K. Trabish, February 10, 2015 (Utility Dive)

    One of the largest U.S. power companies has created a new $225 million fund for commercial scale solar and bought a controlling interest in one of the biggest commercial solar developers.

    “We are going to acquire controlling interest in REC Solar and we are going to rely on their business plans,” explained Duke Energy VP/Commercial Portfolio President Marc Manly. “They know what they are doing. And they have targeted markets where the retail rates make it economic for customers, where customers want it, and where the regulatory rules are appropriate.”

    This follows other recent acquisitions of solar and energy service providers by utilities. REC Solar CEO Al Bucknam believes it to be part of an emerging trend driven by the coming change in solar’s 30% federal investment tax credit (ITC). He pointed to NextEra’s purchase of Smart Energy Capital and NRG Energy’s buys of Verengo Solar NE, Pure Energies, and Roof Diagnostics as examples.

    “The ITC is dropping from 30% to 10% at the end of 2016,” Bucknam said. “While that will tighten economics, the lower rate is likely to make more capital available, at lower cost, because there are more investors that could absorb 10% than could absorb 30%.” Solar companies will need “scale and reach” to succeed. The partnership with Duke will give REC Solar the scale it needs to cover the entire U.S. market, to procure effectively, and to develop more standardized, lower cost construction processes. “A low cost position is going to be a critical advantage,” Bucknam explained. “We have a stronger balance sheet and support from Duke. This is a strategic partnership and not just a financial transaction.”

    REC Solar's business

    REC Solar has over 440 commercial scale projects built or in development representing over 140 MW of installed capacity. It also offers both financing for customers who don’t want to want to pay cash up-front and maintenance services for customers who don’t want ownership responsibilities.

    “We don’t have our own captive funds. Prior to this, if a customer required financing we would find an investor with a tax appetite that would own the project and we would sell the energy or lease the project to the end-user,”Bucknam said.

    With Duke’s dedicated $225 million fund comes established “project approval criteria” that provide REC Solar with a clear understanding of what projects will fit into the utility’s portfolio and what the necessary documents, pricing, and return requirements are.

    “The traditionally difficult front end process of getting a project financed is now going to be much smoother and cleaner,” Bucknam said. “We can tell the customer, ‘we will deliver your project on this date with these terms and it won’t change.’”

    And, he added, “it will be so closely integrated with REC Solar that from the customer’s perspective, they are dealing with REC Solar and we are making it all happen.”

    More projects, smaller projects

    Neither Bucknam nor Manly would specify the project approval criteria but Bucknam said REC Solar will use them to target markets. “We are looking at doing smaller projects. Our average project has been in the 800 KW range and that is likely to drop. We will likely be doing more projects under 500 kW than in the past.”

    Smaller projects are not a requirement but the financing is set up to make them work.

    “There has been a lot of whale hunting in commercial solar,” Bucknam said. “We are not giving up the larger stuff. But the smaller end of the market has been underserved so there is a lot more potential there.”

    At that targeted size, it is mostly roofs, Bucknam said, but REC Solar is open toparking structures and fields, too.

    “With this acquisition,” Manly said, “it will give us a full suite of services and products to offer, from utility scale to community solar, where we build with the economics of utility scale in one farm but through PPAs parse it out, and I think that is exciting, all the way down to, with REC Solar, if a customer wants it on their big box rooftop, on their garage top, in their back 40, we can offer that.”

    Duke’s new solar reach

    Indicative of this new reach are Duke’s just-proposed 110 MW of new solar by 2021 to the Public Service Commission of South Carolina (PSCSC). The utility now has less than 2 MW of grid connected solar in South Carolina. But it helped craft the state’s 2014 Distributed Energy Resource Program Act, which is expected to soon open the door to a solar boom in South Carolina.

    Duke wants to offer: 1) rebates that could be up to $5,000 for retail rate, net metered rooftop and small-scale solar; 2) community shared solar for nonprofit organizations, churches, community centers, renters, and schools; and 3) over 50 MW of utility-scale solar installations.

    In negotiating the REC Solar acquisition, it became clear Duke and REC Solar's interests were clearly aligned, Manly and Bucknam agreed. From a strategic review of the solar market, Duke concluded it did not want to be in the residential sector like utilities such as Arizona Public Service and NV Energy. REC Solar had come to the same conclusion and last year sold what remained of its residential business to Sunrun.

    “It was a natural fit,” Manly said. “We wanted to augment what we were doing by getting into commercial and they got rid of stuff we didn’t want.”

    Historically, REC Solar has sold turn-key systems in the commercial solar market and will continue to do development, sales, installation, and maintenance in that space, Manly said. The $225 million Duke funding is aimed at REC Solar customers who want financing. “If the customer meets credit and other criteria, we will finance the installation and give the customer a PPA,” Manly said. “Our existing utility-scale solar group will manage it.”

    The kicker: Community solar

    Both Manly and Bucknam were also enthusiastic about using the partnership and funding to move into community solar.

    “It is something that has excited me for a long time,” Manly said. “What makes sense economically is for us to find a place to build a big solar farm and, as long as the transmission is not too expensive, sell that on a community basis. And that market is developing.”

    “Duke won’t have to push us in that direction,” Bucknam joked. “The parameters might be a little different from the standard commercial deal because instead of selling power to the host of the system, you are now looking for subscribers for the power. The marketing and sales is new but it doesn’t mean we can’t address it.”

    NEWENERGYNEWS IS ON THE ROAD TODAY SO NO QUICK NEWS, June 24.

    Tuesday, June 23, 2015

    TODAY’S STUDY: ALL ABOUT SOLAR LOANS, SOLAR LEASING, AND SOLAR PURCHASE CONTRACTS

    Banking on Solar: An Analysis of Banking Opportunities in the U.S. Distributed Photovoltaic

    David Feldman and Travis Lowder, November 2014 (National Renewable Energy Laboratory)

    Executive Summary

    This report provides a high-level overview of the developing U.S. solar loan product landscape, from both a market and economic perspective. It covers current and potential U.S. solar lending institutions; currently available loan products; loan program structures and post-loan origination options; risks and uncertainties of the solar asset class as it pertains to lenders; and an economic analysis comparing loan products to third party-financed systems in California.

    Solar-specific loan financing is growing in the United States—2014 in particular saw several new loan product announcements and program launches (See Footnote 2 in the Introduction). A solar loan financing arrangement differs from third-party ownership (TPO) in several key aspects, including: the retention of ownership rights by the system host and its associated tax benefits and other incentives; the fixed nature of its monthly payment (similar to a lease but not a power purchase agreement [PPA]); and the variability in the size of payments based on the interest rate and tenor of the loan (i.e., individual payments spread over a longer period will be smaller in size).

    Several analysts and industry stakeholders have indicated that solar loans will increasingly capture market share relative to the TPO model in the coming years. While the actual competitiveness of the loan option in solar finance will be determined by the offerings in the market, this report attempts to provide a framework for understanding how loan structures could affect the ultimate cost to distributed PV consumers. Solar loans have the potential to provide an economical option (from an LCOE perspective) for homeowners and businesses to finance the purchase of a solar system, retaining the benefits of ownership that TPO systems cannot provide while avoiding the large upfront cost of a PV system.

    Section 4 of this report presents the results of an economic analysis comparing the economics of residential and commercial customers using solar loans to those using TPO to finance on-site PV generation. As demonstrated in Figure ES-1 below, the levelized cost of energy (LCOE) for residential systems with solar loans was lower than the LCOE for residential systems with PPAs by 19% to 29% (varying by the term of the loan), due to the higher cost of capital necessary for the sponsor and tax equity in a PPA transaction.

    There are, however, several economic factors which influence the value of loans to consumers that go beyond the pro forma financial models. These include the higher annual payments to service these shorter-term loans during the beginning of the lifetime of the solar asset – as demonstrated in Figure ES-2 below. In fact, in the first year of a five-year loan, the debt service payments were calculated to be almost double what a customer would pay to a utility, and over twice as much as a PPA or 20-year loan. At the end of the loan term, a customer’s annual payments would drop to the cost of operations and maintenance (O&M), including an inverter replacement in year 10, and, if desired, monitoring by a third party; however, some customers may not want to pay more for their electricity for the first five or ten years of the PV system’s operation.

    Other factors that may impact the economics of a solar loan or TPO include whether or not the host has sufficient tax liability to take advantage of the federal and/or state tax incentives; the additional liability and maintenance costs associated with ownership; the complications of adding assets and liabilities onto one’s balance sheet (as opposed to a TPO transaction, which is off-balance sheet); and the economic time horizon of individual decision makers. Moreover, any specific market offerings in either solar loans or TPO products will differ from the assumptions in this report, which provides only a general framework for interpreting the comparison and relative competitiveness of both forms of finance. System costs, monthly payments, amortization schedules, the ultimate cost of energy, and other factors will differ by each product and each individual deal with the consumer.

    Introduction

    The growth in distributed (and particularly residential) solar photovoltaics (PV) deployment in the U.S. has been facilitated in large part through the third-party ownership (TPO) model. In 2013, TPO represented some 66% of the U.S. residential solar market, and a considerable portion of the commercial market (Litvak 2014). The success of the TPO model is attributable in part to its economic proposition: TPO can provide consumers access to PV-generated electricity at a price that is competitive with those consumers’ utility (i.e., retail) rates. However, in the last two years, another solar financing option is becoming commensurately competitive and has begun to capture market share: loans.

    Until recently, loan financing for distributed solar installations was largely done through home equity loans or home equity lines of credit (HELOCs), commercial loans, and other standardized loan products available to homeowners and businesses for general expenditures. Historically, solar-specific loans—i.e., products for which the underwriting, loan terms, lender security interest, and other programmatic aspects are all designed for financing solar installations exclusively1 —have not had much market presence. Prior to the fall of 2013, there were few widely available (i.e., not jurisdictionally limited, such as property assessed clean energy programs or on-bill financing in a utility’s service territory) solar loan options in the United States. However, from the period between approximately October 2013 and October 2014, at least nine new solar-specific loan programs were announced, and several more have begun operations without a formal announcement.2

    A solar loan financing arrangement differs from TPO in several key aspects, including:

    • Ownership: When financing through a loan, the system host retains ownership of the PV assets. Third-party ownership, as the name implies, entails ownership and maintenance by the solar company and its investor partners.

    • Tax benefits and other incentives: Owners of loan-financed systems receive all applicable tax benefits and incentives available to the solar assets (this follows from ownership). As of October 2014, these benefits and incentives could include: the 30% federal investment tax credit (ITC) for individuals (see Section 3), production-based incentives (PBIs), renewable energy credits (RECs), and others. When leasing a system through a TPO arrangement, these benefits typically go to the third party. Additionally, third-party owners can make use of the accelerated depreciation schedule to increase the system cost savings—homeowners cannot.

    • Monthly payments: A solar loan is typically amortized through monthly payments of both principal and interest (P&I). In contrast, TPO systems are paid for via either a monthly fixed rate in a lease arrangement, or a charge per unit of electricity produced by the system (on a $/kWh basis) in a PPA arrangement. It is common for both leases and PPAs to contain annual escalators that step up the charges by a specified percentage (typically around 3%) each year.

    • Effect on home valuation: Some studies suggest that homeowners could increase the value of their home when they install and own a solar system on their rooftop (Hoen et al. 2013; Desmarais 2013). While no comparable study has yet been performed on TPO systems, the National Renewable Energy Laboratory’s (NREL’s) communications with appraisers and homeowners in California, as well as speculations made in recent news articles (Wade 2014) suggest that systems financed through a PPA or a lease may not be rolled toward the value of the home (appraisers may, in fact, count them a deduction against the home value), and could complicate the sales process. It is important to note, however, that the effect that each financing option has on home value is still not well understood. Additional data, regulatory decision making, and the development of industry best practices will be necessary before the market arrives at a standard method for appraising solar assets.

    • Cost: The cost to finance a system through a loan is largely determined by the interaction between the loan amount, the applicable interest rate, and the tenor or term of the loan. For example, a $20,000 loan with a 6% annual percentage rate (APR) of interest and a 15-year maturity will add an extra $18,000 in costs to the principal amount, or about an extra $100 a month in interest payments. TPO systems are typically financed on a portfolio basis through complex financial structures that bring in tax equity investors to monetize the 30% ITC and depreciation expense. The weighted average cost of capital (WACC) of these structures reflects, principally, the tax equity’s yield on their investment, the cost of any associated debt, and the sponsor’s (i.e., the solar company’s) cost of equity. The resulting cost of the system will be influenced by this WACC, which is typically higher than the cost of capital on the loan.

    This report provides a high-level overview of the developing U.S. solar loan product landscape, from both a market and economic perspective. It covers current and potential U.S. solar lending institutions; currently available loan products; loan program structures and post-loan origination options; risks and uncertainties of the solar asset class as it pertains to lenders; and an economic analysis comparing loan products to third party-financed systems in California. The report begins (Section 2) with an overview of the U.S. distributed solar market to contextualize the discussions to follow. For readers already familiar with this information, the authors recommend beginning at Section 3 on page 18.

    The penultimate section of the report (Section 4) provides an economic analysis of solar loans versus TPO. The authors built three pro forma financial models to calculate the levelized cost of energy (LCOE) for a residential loan, a commercial loan, and a TPO PPA in the state of California. These LCOE figures are used to compare the system costs associated with each financing arrangement, and—for the residential loan and TPO PPA—to compare with the retail rates of one of California’s three investor-owned utilities. This report finds that the single largest differentiating factor influencing LCOE in the models was the cost to finance the solar assets— namely the interest rate on the loan, and the WACC in the TPO PPA. Accordingly, the modeled LCOE for solar loans was lower than the TPO LCOE in this analysis. The U.S. Solar Market…Solar Loans: Lenders, Processes, Products, and Risks…The Solar Loan Product Landscape…

    Conclusion

    In June of 2014, GTM Research released its second update on the residential solar financing landscape. The report predicted that the TPO market, which has been a large driver of residential PV deployment for the last several years, would peak in 2014 and gradually cede share to loans and alternative forms of financing (such as PACE) thereafter (Litvak 2014).

    While the actual competitiveness of the loan option in solar finance will be determined by the offerings in the market, this report attempts to provide a framework for understanding how loan structures could affect the ultimate cost to distributed PV consumers. Solar loans have the potential to provide an economical option (from an LCOE perspective) for homeowners and businesses to finance the purchase of a solar system, retaining the benefits of ownership that TPO systems cannot provide while avoiding the large upfront cost of a PV system. According to the analysis, solar loans at 5-, 10-, and 20-year maturities delivered a lower LCOE than a 20-year TPO PPA, representing a reduction of 19% to 47%. Both loans and TPO were found to generate electricity at a rate lower than the blended rate for SDG&E’s second and third tiers of residential rates.

    It is important to emphasize that while solar loans may result in a lower cost of generation to the consumer, thus reducing the lifetime costs associated with the system, the monthly payments on a loan may not necessarily reflect these favorable economics. Depending on the interest rate, the principal and the tenor of the loan, monthly P&I could be higher than the system owner would pay under both a TPO arrangement and the utility rate. However, the faster the loan is paid down, the more “free” electricity the host will enjoy post-financing, offsetting utility bills at no additional cost for the remaining useful life of the system. This becomes something of an optimization exercise for consumers deciding on a financing option, who may weigh their ability to make possibly higher monthly payments against the ultimate savings a loan could provide over the system lifetime. From a qualitative survey of the solar-specific loan options available in the market or in the planning phase as of this writing, NREL has determined that most products fall into the range of 5 to 20 year maturities. Of note, SolarCity has recently announced that it intends to roll out a 30-year product (Wesoff 2014), which would match typical mortgage maturities and could reduce monthly payments to a level highly competitive with or lower than utility rates in markets with lower power prices.

    There are other factors, beyond loan tenor, that may impact the economics of a solar loan and TPO: the hosts’ requirement for a tax liability to take advantage of the federal tax incentives; the additional liability and maintenance costs associated with ownership; the complications of adding assets and liabilities onto one’s balance sheet (as opposed to a TPO transaction which is an off-balance sheet); and the economic time horizon of individual decision makers. Individual decision makers will have to determine how these risks and benefits compare with their own economic profile.

    A broader range of loan financing options with flexible interest rates and maturities, coupled with deeper market penetration, could help reduce the financing costs associated with installing solar, and thus provide another trajectory for the achievement of the U.S. Department of Energy’s SunShot goals. Distributed solar continues to perform robustly in terms of both growth and its ability to attract investment; the wider availability of financing, the diversity of financing options, and the competitive rates at which to finance in this space, will all prove influential to the ultimate success of this market, both in the near term and post-ITC.

    QUICK NEWS, June 23: GOODS BETS TO MAKE ON WIND; OKLAHOMA WIND COULD BOOM – THEN BUST; WIND FOR COAL IN COLORADO

    GOODS BETS TO MAKE ON WIND The Best Play In Wind Energy Right Now

    Martin Tiller, 21 June 2015 (OilPrice)

    “…Everything points to serious growth in the [wind] industry over the next few years…[but figuring how to invest] is when the going gets tough…The problem is that there are seemingly two types of companies in the space, small ventures…or multinational, giant conglomerates…The German company Siemens (ADR: SIEGY) and GE (GE) were one and two in a recent global market share analysis,.. While GE doesn’t disclose separate revenue or profit numbers for wind energy, Siemens does, and the importance of the business within the company is actually quite surprising. In 2013, wind power accounted for 5.2 Billion Euros in revenue at Siemens, or around 25 percent of the total…[or] you might consider Vestas (VWSYF), the Danish company that finished third in those rankings…Siemens looks like the best investment…” click here for more

    OKLAHOMA WIND COULD BOOM – THEN BUST Oklahoma wind industry looks to finish projects before tax incentives end

    Michael Overall, June 16, 2015 Tulsa World

    Oklahoma wind developers foresee a hectic 18 months as they race to complete project before their state tax incentives expire December 31, 2016. They also foresee uncertainty and a potential crash following the incentives’ expiration. The recently enacted SB 498 terminated wind developers’ 5-year property tax exemption and SB 502 ended wind developers’ investment/new jobs tax credit. Wind projects currently in production or put into production by December 31, 2016, will retain the full 5-year property tax exemption. Fiscal conservatives backed the laws to limit the impact of the incentives on a budget deficit expected to be $611 million for fiscal year 2016. Legislative consent to the laws was produced through a compromise brokered by stakeholders. The zero emissions production tax credit is expected to allow Oklahoma wind to remain cost-competitive but it is expected to be a target for budget hawks. click here for more

    WIND FOR COAL IN COLORADO Amid coal fight, power company seals wind deal

    Dennis Webb, June 11, 2015 The Daily Sentinel

    Tri-State Generation and Transmission Association, a Colorado generation and transmission cooperative that supplies 44 electric cooperatives and public power districts in Colorado, Nebraska, New Mexico and Wyoming, contracted for the 76 MW output of Iberdrola Renewables’ Twin Buttes II Wind Project. The wind will provide backup if the utility cannot get the Colowyo mine’s half of its Craig coal facility’s supply. A federal judge ruled in May the Colorado Office of Surface Mining Reclamation and Enforcement’s 2007 approval for the mine’s expansion was flawed. Mining will be shut down within 60 days if Tri-State’s appeal fails and errors are not corrected. Tri-State’s delivered electricity in 2014 was 24% renewables-sourced. Baseload coal provides 59% of the utility’s mix while 2% of its electricity comes from natural gas and the balance is merchant-supplied. The Twin Buttes wind project is expected to annually provide $270,000 in local tax benefits and $250,000 in landowner lease payments. click here for more