ORIGINAL REPORTING: SOLAR POWER INTERNATIONAL 2014: 'THE BEST ENERGY WE HAVE HAD FOR YEARS'

Solar Power International 2014: 'The best energy we have had for years' ; Three solar-utility initiatives and a maturing solar industry promise a big future

Herman K. Trabish, October 23, 2014 (Utility Dive)

The air was electric on the floor of Solar Power International (SPI) 2014 this week. More than 12,000 attendees shuffled between sleek displays and eager salespeople, chattering excitedly that this year will be the one that sees solar power truly come of age.

One key phrase in particular ran from one end of the event to the other.

“I have heard more people use the phrase grid integration than ever before. It is bubbling up in every conversation,” said Solar Electric Power Association (SEPA) President Julia Hamm in reviewing SPI 2014. “They are talking about solar being part of a healthy grid and asking how to turn rooftop solar into a grid asset.”

Co-produced by SEPA and the Solar Energy Industries Association (SEIA), SPI is the U.S. industry’s most important annual conference.

In a keynote address, SEIA President Rhone Resch warned anti-solar forces in Congress not to discontinue solar’s vital federal investment tax credit (ITC). Declaring the start of a campaign to extend the ITC, he promised that “as sure as World War I started in 1914, if the Koch Brothers and their allies come after solar, 2014 will be the beginning of World War III.”

Hamm announced two major initiatives aimed at developing utility-solar industry communication. A third, perhaps the most important, started up without notice.

The new, crowd-sourced 51st State initiative invites the utility and solar industries to re-imagine electricity market structures, regulatory frameworks, and rate designs.

“SEPA’s obligation is to drive this conversation,” Hamm said. The initiative will be formally launched at the quarterly National Association of Regulatory Utility Commissioners meeting in November with a fully developed website. A two-stage submission process will offer utilities, NGOs, think tanks, universities, and independent thought leaders the opportunity to contribute.

“We hope the initiative spurs new ideas," Hamm said, "but it will be a success if we just spotlight ideas already out there worth getting attention.”

Utility-solar initiatives

SEPA’s Utility Solar Database will help SEPA utility members learn from each other and build bridges between the utility and solar industries, Hamm said. The database contains about 500 utilities representing 95% of all solar on the U.S. grid.

“Suppose a utility is thinking about community solar,” Hamm said. “They can see every utility that has a community solar program and dig into them. They can see how other utilities have designed their programs and evaluate the design options.”

Or suppose a solar developer wants to build in South Carolina, she said. “They can select South Carolina and immediately find everything they need in the database about each utility in the state. They can learn about things like rate structures, program options, policy, business issues, and what utilities have done with solar. Those developers can then respond to RFPs with informed proposals.”

The unheralded Utility Executive Solar Leadership Roundtable may prove just as important in the long run. “There are hard conversations for utilities to have publicly, Hamm said, “but they are having significant conversations behind closed doors.”

The roundtable had its first two meetings in 2014. “Our goal is to have a core group of 12 to 15 utility executives committed to attending twice a year.” Others, including solar executives, may eventually join irregularly.

“They are having those significant conversations,” Hamm said. “I preface each meeting by reminding them the point is to help each other find solutions.”

In this week’s meeting, Hamm said, “we talked for three hours about how utilities can directly engage with what customers want in distributed solar and what utilities can offer to meet those wants.”

The execs were from geographically varied regions and from IOUs, munis and co-ops. “That diversity in one room made for a dynamic conversation,” Hamm said. “I have seen a light bulb go off when an IOU exec saw that a small unregulated co-op is doing innovative things he hasn’t even thought of yet, things he can do.”

Hot topics

During the SPI 2014 keynote panel, SolarCity CEO Lyndon Rive drew a burst of applause by saying the federal policy should be to tax pollution but, since that is unlikely, it should be to “Incentivize those who don’t.”

Rive also said that while bringing the price of solar down is at the top of solar’s agenda for the next two years, the longer-term goal must be to use storage for more effective grid integration. Executives from sPower, NV Energy, Greenskies, and Enphase Energy agreed.

Sessions covered all the hot topics in solar, from net metering and value of solar tariffs to import tariffs and utility rate designs.

A big debate weighed competing vertically-integrated and networked solar business models but wasn’t conclusive. There were sessions on innovative technologies, the nuts and bolts of installation, and the challenges of financing utility scale solar.

U.S. Energy Secretary Ernest Moniz alleviated some ITC concerns when he announced $53 million in new federal funding for 40 research and development programs through DOE’s SunShot Initiative.

“It is the best energy we have had for years,” Hamm said. “There are questions, like what will happen with the ITC and with net metering, and with tariffs. But people are really excited about where this industry is going. The conversations have evolved and matured.”

The show is bigger in than the past two years, spanning more than 200,000 square feet for exhibitions by more than 600 exhibitors. “There were well over 12,000 attendees,” Hamm said, stressing “well over.”

One of her show favorites was Start-up Alley, where ambitious ideas get pitched to would-be investors looking for the next SolarCity. “I love that as solar matures we are not leaving behind the entrepreneurs,” she said.

Utility awards

Hamm highlighted the Sacramento Municipal Utility District (SMUD) work with Clean Power Research on software that will make them more accessible solar advisors to their customers. “This is the first tangible thing I’ve seen a utility do to about that,” she said. She also called out Georgia Power for going “from zero to 60 in solar in two years.” For its performance, Georgia Power won SEPA’s IOU-of-the-year award.

“The 2011 SPI general session was a utility executive panel,” Hamm said. “We asked them what PPA price would make them buy solar. They all agreed on $0.07 per kilowatt-hour and $0.08 per kilowatt-hour. And now prices are well below that. This is real. Utilities are finally starting to treat solar as generation in their resource plans instead of as load reduction, even if it is customer-sited and owned.”

The City of Palo Alto muni was the public-utility-of-the-year for both a long term plan to cut greenhouse gas emissions and their success with solar in the last year. Southern Maryland Electric Cooperative was coop-of-the-year for meeting its renewables mandate by building solar locally so its members could benefit from the jobs and revenues.

CEO-of-the-year was Warren McKenna. He was a founding member of Iowa’s chapter of the SEIA and led his 650-member Farmers’ Electric Cooperative in building a 51 kilowatt community solar project.

On the show floor

People on the floor invariably said this was the most optimistic and positive SPI they had attended. One suggested people are being lifted up by the maturing industry’s success. Another said people are excited about solar’s future.

“It seems like the industry is coming together,” said Clean Power Finance Communications and Public Relations Director Alison Mickey. “The threat of losing the ITC at the end of 2016 seems to give us a common cause. And ‘tax fairness’ seems like a new rallying cry. There is also plenty of talk about tax equity and life after the ITC.”

Like Hamm, Mickey also heard “grid integration” everywhere. Utility participation seems bigger than last year, she said. “And people are talking more about the-grid-of-the-future and the-utility-of-the-future.”

The industry is maturing, she said and it shows in the attendees’ sophistication, the innovative technologies and business models, and in the industry’s work with utilities. “Southern Company sponsored the gift bags,” she said. “It was the first thing I noticed when I registered. What many might have thought of as not the most progressive of utilities was a conference sponsor.”

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ORIGINAL REPORTING: ONE GRID TO RULE THEM ALL: IS A NATIONAL TRANSMISSION SYSTEM COMING TO AMERICA?

One grid to rule them all: Is a national transmission system coming to America?; A bold idea to interconnect the nation’s three grids is just a financing agreement away Herman K. Trabish, October 31, 2014 (Utility Dive)

A project that would transform the U.S. grid’s three isolated segments into a national transmission system could be financed and working on construction by the end of 2014. Two major concerns regarding the much-hyped Tres Amigas interconnection have been answered. Utilities and other potential investors are gathering, and power producers throughout the Southwest are checking in regularly.

“It’s a really bold idea,” said former FERC Chair James Hoecker. “Butinterconnecting the country’s three major grids seems like the logical step toward a national bulk power network.”

Tres Amigas will be the first interconnection of the Eastern, Western, and Texas grids. Sited on 14,400 acres in Clovis, New Mexico, at the edge of the three systems, it will modernize the carrying capacity of the world’s biggest machine, the 120-year-old U.S. transmission system.

Tres Amigas will also establish a power exchange, much like the markets now operated regionally. And through the exchange, new energy resources will become available nationwide.

Using state-of-the-art power electronics, the interconnection will allow power trading with price differentials that justify Tres Amigas’ $1.8 billion cost, explained Tres Amigas Chief Operating Officer David Stidham.

Creating 'a massive power exchange'

When Tres Amigas CEO Phil Harris was the CEO of PJM Interconnection, he led the creation of the first regional transmission organization (RTO) power exchange in the Northeast, said Stidham. Under Harris, PJM became the world’s biggest competitive wholesale electricity market. It now serves parts of 14 states, over 830 companies, 60 million customers, and has a 167 gigawatt carrying capacity.

After Harris retired, he consulted for the China National Grid Project, designed to interconnect China’s less-than-robust State Grid and Southern Power Grid systems through “a high voltage direct current system that dwarfs anything in the U.S.” explained Stidham.

With ERCOT’s Competitive Renewable Energy Zones (CREZ), which bulked up Texas panhandle transmission for carrying wind, “all of a sudden the three U.S. grids were close together,” Stidham said. Harris “started putting the two ideas of a high voltage national interconnection with modern power electronics and a massive power exchange together.”

Amarillo and Clovis were the cities nearest the grids’ proximity. Under New Mexico Governor Bill Richardson, the state leased 15,000 acres for the 30 gigawatt project, Stidham said. The control and dispatch center will be inAlbuquerque because of Governor Susanna Martinez and state legislators’ strong pro-business negotiations.

“Tres Amigas will allow power transactions that are not now available,” Stidham said. “A wind project typically requires a power purchase agreement [PPA] to obtain bank financing. But if the developer could sell into any of the three markets, and sell at the highest price available, the concept of a merchant project becomes financially attractive.”

A national marketplace opens the opportunity to sell midday Southwestern solar into the East Coast’s late afternoon peak demand period and to sell pre-dawn Western wind into the East Coast’s midmorning peak. Merchant projects become potentially more profitable than projects with PPAs when those higher per-kilowatt-hour peak demand opportunities are available.

Tres Amigas will provide the same open access same time information system(OASIS) available through RTOs like PJM. “Power producers will make known what power is available at what price and buyers will engage in transactions for five and fifteen minutes ahead, hour ahead, or long term power,” Stidham said. “That is where the cash register is.”

The big questions

There are two big questions facing Tres Amigas, Hoecker said. The first is whether the takeaway capacity is substantial enough to justify the expense. The other is whether jurisdictional questions with the notoriously independent Electric Reliability Council of Texas (ERCOT) system can be resolved.

Both of those questions have answers, according to Stidham who—as former Xcel Energy Director of Power Engineering—knows transmission takeaway capacity. And as the developer of 782 megawatts of Texas wind for EON Climate and Renewables, he also knows ERCOT.

From the 1970s, FERC agreed that ERCOT does not conduct interstate commerce and therefore is excluded from jurisdiction under the Federal Power Act, former FERC Chair Hoecker said. ERCOT was granted further exclusions in the Energy Policy Act of 2005. But that Act made ERCOT subject to federal reliability provisions and made its jurisdictional independence questionable, Hoecker said. As part of a nationally interconnected system, those questions could be more potent.

FERC’s ruling on the Pattern Energy Southern Cross HVDC transmission project, which will deliver Texas wind to the Southeast, makes ERCOT’s jurisdictional independence secure, Stidham explained.

Under provisions of sections 210 and 211 of the Federal Power Act, FERC:

-directed the City of Garland, Texas, to interconnect with Southern Cross

-directed Oncor and CenterPoint to provide transmission into and out of ERCOT, and

-affirmed that none of the stakeholders, including ERCOT, was subject to FERC jurisdiction.

As for takeaway capacity, Stidham said, the voltage source converters (VSCs) that Tres Amigas will employ at the core of its system will both increase carrying capacity and help protect reliability by keeping voltage at safe levels.

“It can direct up to 40% of its capacity in reactive power, in directions independent of real power, so that it can act as a static VAR compensator instantly supporting or reducing voltage as needed,” Stidham explained. “It also allows generation to be injected into the line so that wind generated electricity, for example, could be kept flowing at 100% capacity even if the line’s owner is only using 45% of its capacity.”

“The power electronics are pretty well understood technology,” Hoecker acknowledged. “It simply converts DC power to AC and vice versa.”

If they build it, who will come?

Hoecker raised questions about financing and participants.” If the bankers are serious about this, it means they have identified commercial opportunities.”

“UBS and Goldman Sachs are arranging the financing,” Stidham said. Harris is talking to undisclosed potential utility purchasers, backers of Real Estate Investment Trusts, and equity investors.

“The financing must be completed by the end of 2014,” Stidam explained. If it is not, Tres Amigas will lose its place in FERC’s interconnect queue and FERC-approved interconnect agreements with PNM, Xcel, and the Southwest Power Pool—key elements in investor presentations—will have to be done over.

“There is nothing firm with power producers or investors but this is one of those if-you-build-it-they-will-come situations,” Stidham said. “There are a lot of renewable and hybrid generation facilities waiting for us to get financing and break ground. That will allow them to get financing because they will be able to show a path to multiple markets.”

Construction is expected to take 33 months, Stidham said. The project is almost completely permitted. What is left will be in New Mexico, where Tres Amigas has access to County rights-of-way, and in Texas, where the CREZ process established streamlined procedures. With no federal land involved, there should be none of the complexities and delays in NEPA permitting.

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ORIGINAL REPORTING: SOLAR'S TAX CREDIT FIGHT COULD LEAD TO 'TOMORROW POWER & LIGHT' OR 'WORLD WAR III'

Solar's tax credit fight could lead to 'Tomorrow Power & Light' or 'World War III'; Solar industry leaders promise to fight for solar’s tax credit and a renewed grid

Herman K. Trabish, October 21, 2014 (Utility Dive)

A political fight is coming for solar’s crucial federal tax incentive, a fight one key industry leader warned could be “World War III.”

But beyond the foreboding politics, another industry leader said, is the possibility of "Tomorrow Power & Light," the utility of the future operating a safe and reliable system of affordable integrated central and distributed choices for electricity customers.

In 2016, solar’s federal investment tax credit (ITC) will drop from 30% to 10%. Backed by the current 30% benefit, this year’s solar installations will be 70 times higher than they were in 2006, when the Energy Policy Act of 2005 put the ITC in place. By the end of 2014, there will be nearly 30 times more total solar capacity online than in 2006.

“We’ve gone from being an $800-million industry in 2006 to a $15-billion industry today,” Solar Energy Industries Association (SEIA) President Rhone Resch said to kick off the industry’s annual national conference. “The price to install a solar rooftop system has been cut in half, while utility systems have dropped by 70 percent.”

Solar is the fastest growing of the renewables industries. “During every single week of this year we’re going to install more capacity than what we did during the entire year in 2006.”

A shot across the bow

But “make no mistake about it, there are people and groups that will do anything - and say anything - to try and stop solar dead in its tracks,” Resch said. With “duplicity, subterfuge and deep pockets” filled with Koch Brothers money, they are “emboldened” by state-level actions and “will be turning their sights on the ITC.”

Resch declared the start of a campaign to extend the ITC and promised that “as sure as World War I started in 1914, if the Koch Brothers and their allies come after solar, 2014 will be the beginning of World War III.”

Solar will “be fighting an uphill battle every step of the way,” Resch said. But because polls show “more than 90% of Americans support greater development of solar energy,” he explained, “we’re going to have a bigger, more determined army, motivated by a nobler, more righteous cause.”

The new campaign will “pound away at the fairness argument,” Resch said. Since the 1914 enactment of the oil and gas industry’s Intangible Drilling and Development Costs tax code benefit, he explained, the average annual subsidy has been $4.8 billion while renewables have received only $370 million per year for the far fewer years they have had tax incentives.

“How is that fair? 100 years for big oil but just 10 years for the 30% solar ITC,” Resch asked. Yet many in Congress who are “allies of the Koch Brothers and other anti-solar groups” want to eliminate the ITC. “Forget about it,” Resch warned them. “Walk away.”

The broad based campaign to keep the ITC in place will also, Resch said, educate Congress and urge a “commence construction” provision for the ITC, defend expanded net energy metering and renewables mandates, and push for the industry to use the “tremendous, new” opportunities in the EPA Clean Power Plan.

Utilities react

“He’s trying to rally his troops around an important issue,” Public Service Electric and Gas VP Joseph Forline said. “But solar costs have come down quite a bit and solar is getting closer and closer to being competitive. The tax credit is something that will be hotly debated in 2016 and I don’t think it is a slam dunk.”

“Solar is too important for us to get wrong,” said Pacific Gas and Electric VP Steve Malnight, whose utility has 4,500 megawatts of solar under contract and “more solar rooftops in our service territory than anywhere else in the world.” In California, he said, “we have had a lot of success working with policymakers, utilities, and solar companies. That is a track record that demonstrates how it should be done and how it can be done.”

Resch “was intentionally provocative,” said former President/CEO of Jersey Central Power and Light and American Clean Energy CEO Stephen Morgan, who became a distributed energy developer the day after he retired from the utility industry. “The argument has been about the subsidies that this industry and wind get," he said. "There has been no commensurate conversation about the subsidies all the other energy industries, oil, coal, natural gas, get. Get rid of them all or give everybody commensurate treatment.”

Instead of talking war, Morgan said, “you need a fact-based discussion about the costs and the benefits of the subsidies. Presumably there is a benefit that outweighs the cost of the fossil industry subsidies. We think we could say the same thing about our industry. So let’s put the facts on the table.”

Beyond tax credits: Solar and the grid

“Solar needs a strong grid infrastructure,” Solar Electric Power Association (SEPA) President Julia Hamm said. That means all the stakeholders, grid operators, utilities, regulators, and solar providers face change.

“Change is the law of life,” Hamm said, quoting John F. Kennedy. “Those who look only to the past or present are certain to miss the future.”

This is the beginning of “an evolutionary shift from a grid that is almost entirely built and run on central station power and one-way power flow, to a grid that is increasingly decentralized and diverse,” she went on.

German utilities admit they missed a big opportunity when they declined German government offers to the lead the energy transition in the early 2000s, she said. “They had focused only on immediate financial impacts and underestimated the long-term strategic and economic value.”

Similar mistakes are now playing out in Hawaii and Japan, she said. But “we have the opportunity to learn from the experiences across the ocean and to do things differently.” Sterling, Mass., Municipal Light Department, PSEG-LI,Georgia Power, and NV Energy are leading the way, she said.

'Tomorrow Power & Light'

SEPA is assimilating their many other similar utility experiences into its Utility Solar Database. And building on that, SEPA is introducing a new crowd-sourced initiative to re-imagine 20th century market structures, regulatory frameworks, and rate designs. “What if it were different? What if we could start all over again with a clean slate?” Hamm asked.

“Imagine 'Tomorrow Power & Light', a fictional utility in the year 2030 that gets 30% of its electricity from solar,” she said. In its service territory, the 51st state, there is no pre-defined electricity or solar market, no subsidies, only “a suite of electricity resources available, including solar. There is a grid to deliver power and balance the system. And there are the customers.”

SEPA’s just-launched 51st State initiative invites stakeholders to “start all over,” Hamm said. “How would you design the electricity market? How would you make sure that rapid distributed solar growth occurs, while ensuring continued delivery of affordable, reliable and safe electricity service to all customers?”

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ORIGINAL REPORTING: HOW UTILITIES CAN STREAMLINE ROOFTOP SOLAR INTERCONNECTION AND CUT COSTS

How utilities can streamline rooftop solar interconnection and cut costs; Online interconnection turns NV Energy customer complaints into customer service

Herman K. Trabish, October 16, 2014 (Utility Dive)

No long ago, the interconnection of rooftop solar was mostly handled at utilities by distribution system engineers and staff.

Not anymore. By the end of 2013, over 475,000 U.S. solar installations were interconnected. And a million are expected by the end of 2017.

To drive growth, the U.S. Department of Energy wants to bring the installed cost of solar down to $1 per watt. That initiative is expected to drive permitting, inspection and interconnection (PII) soft costs from 2013’s $0.17 per watt to $0.14 per watt by 2020, according to Distributed Solar Interconnection Challenges and Best Practices, a recent report from the Solar Electric Power Association (SEPA).

SEPA’s survey “uncovered utility initiatives to lower the administrative costs of distributed generation interconnection, making the process of connecting to the grid simpler and more transparent for customers.” But it also revealed that “only 17 percent of utilities are able to process applications online.”

“What was five or ten interconnections a month is now 50, 60, 100, or—for some utilities—1,000 per month,” explained SEPA Research Director Mike Taylor. “Utilities are starting to grapple with the fact that this may take dedicated resources.”

“What struck me the most was that 63 percent of utilities are already planning improvements and pro-actively streamlining their processes,” noted survey co-author and SEPA Sr. Researcher Becky Campbell.

Some 86 percent of utilities are only seeing two interconnection applications per day and often not seeing business activity impacts, she said. “But big utilities in states with active solar markets may be seeing 1,000 applications per year, which is 40 per day,” she said. “They are realizing it makes sense from a business perspective to streamline these processes, not just to accommodate the customer, but also to manage their time and costs more effectively.”

Time is money: Interconnection's high cost

Even where smart meters contribute to streamlined processing, the survey found, customers often still require direct one-on-one communications, adding significant time and cost on both sides of the interconnection process.

From application submittal to utility approval now takes an average of four weeks, just as it did in 2008, SEPA found. But utilities with online processes only require an average of two weeks

Of the two-applications-per-day utilities, 41 percent process them in an average of two weeks. Only 15 percent of utilities with larger volumes manage that two week turnaround.

Three-quarters of the interconnection applications are being handled by less than 5 percent of utilities. That is likely why only 15 percent have “optimized processing high numbers of interconnections in short periods of time,” SEPA found.

Others are still trying to figure out how to respond and there is a range of attitudes, Taylor said. “Utilities are like people. You get all kinds.”

Many are only now seeing a post-recession return of sales and revenues, Taylor added. “They were in cost-cutting and outsourcing mode just as solar was growing really fast.

They were cutting resources just as they were seeing this new customer service need. Maybe now they’re coming out of that, taking a second look, and seeing how they can save their customers and themselves money and time.”

An online solution

The SEPA survey was performed as part of a U.S. Department of Energy SunShot Initiative award that also funded the development of a new online platform for interconnection application processing by Clean Power Research (CPR) PowerClerk Interconnection (PC-Interconnect) was developed by CPR out of its widely used PowerClerk Incentives (PC-Incent) online tool. PC-Incent was developed eight years ago for the New York State Energy Research and Development Authority (NYSERDA). It automated the processing of applications for state incentives. It has been used by 22 utilities and agencies to process over 280,000 applications representing more than 6 gigawatts of renewables capacity.

Now, utility incentive funds are being expended, but customers continue to apply for interconnection. For most solar owners, grid interconnection is crucial to the solar value proposition.

Slow interconnection application processing provokes complaints from utility customers and the installers and contractors representing them. The biggest complaint is a lack of application status transparency. Online platforms address this with a real time status check capability.

As a result, NV Energy—which was the SunShot award designated utility partner and the first to test PC-Interconnect—went from taking 2.7 days from application receipt to a sent reservation notice to taking 1.8 days, said Renewable Generation Operations Manager Jeff Healon.

Other common pain points in solar interconnection application processing solved with PC-Interconnect, according to Healon, include:

-Incomplete or inaccurate applications, outdated forms, incorrectly filled out forms, and missing forms

-An increasing volume of phone assistance inquiries

-Waiting for signed forms to be delivered by snail mail

Addressing the pain points

Online platforms like PC-Interconnect and those being developed by utilities in-house reduce snail mail and address pain points promptly. Advantages include:

-Forms are standardized and utility administrators can keep them updated. Automated algorithms minimize incomplete and inaccurate information.

-Inaccuracies can be eliminated by comparing submitted information with smart meter data or information from other databases. Corrections can be made instantly via email.

-Accurate online data makes answering phone inquiries quicker and more precise.

-E-signature technology allows documents to be signed securely in real time.

As utility and state incentive programs draw to a close, public agencies no longer process applications. Detailed information about the incentivized distributed generation important to utilities and the solar market is being lost.

CPR’s PC-Interconnect allows utilities to ask for that PV system information on interconnection applications. In utilities’ databases, that information can be market or operations intelligence or be used in ways that make utilities’ distributions systems safer and customer services better.

“Customer service has been a boon for us,” Healon said. “We can deal with large installers and with growing numbers of customers across the state and do it faster and give them better information.”

The July/August 2014 SEPA survey of 400 utilities asked about annual interconnection application volume, processing times, submission methods, and strengths and challenges in the process. Some 16 percent of utilities, across 25 states and a range of ownership types, responded.

The findings establish that taking interconnection online cuts time and solar soft costs while improving the experience for utility customers, solar customers, and the solar industry. It also establishes that most utilities have a long way to go to get there.

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ORIGINAL REPORTING: GRID OF THE FUTURE: HOW TRANSMISSION AND NEW TECHNOLOGIES CAN WORK TOGETHER

Grid of the future: How transmission and new technologies can work together; Ex-FERC Chairman: "We may get to the point where we don't need a network of wires. But I can't foresee that."

Herman K. Trabish, October 15, 2014 (Utility Dive)

Far from threatening the grid, non-transmission alternatives can enhance reliability and complement existing and new transmission infrastructure, according to a new study.

Implementing these resources begins with understanding each option, and it ends with filling the system’s needs with the most economical set of options.

“The first question planners need to ask is ‘What do I need for the system?’” Julia Frayer, managing director of London Economics International and lead author of Market Resource Alternatives: An Examination of New Technologies in the Electric Transmission Planning Process, told Utility Dive. “Then it is important to study transmission and all the Market Resource Alternatives (MRAs) that can help meet that need.”

MRAs—London Economics's term for non-transmission alternatives—include energy efficiency, demand response, utility-scale generation, distributed generation, energy storage, and smart grid.

To keep distortion and prejudice out of the study of MRAs, it is important “to make sure the cost-benefit analysis is comprehensive,” Frayer said.

Complementarity, not substitution

"We are talking about what the Federal Energy Regulatory Commission (FERC) meant in Order 1000 when it told transmission system planners they had to consider ‘non-transmission alternatives,’” former FERC Chair Jim Hoecker told Utility Dive, explaining why the transmission trade groupWIRES, which he advises, commissioned the study.

“MRAs are important but they aren’t all deployed the same way and they have different characteristics,” Hoecker said. “Sometimes they help rationalize the transmission planning process and sometimes they have nothing to do with it.”

The term NTA [non-transmission alternatives] contains the implication that alternatives will substitute for transmission, Frayer said, hence the change in terminology to Market Resource Alternatives. But they are all part of an integrated electric system: Transmission needs generation and generation needs transmission.

“And that applies to all the MRAs,” Frayer added. “The system does its job, to deliver electricity, only because all the components are there. Substitution is the worst word to describe that. We need to talk about complementarity.”

“Each of the technologies has enormous benefits and will be absolutely critical to the future of the electric system,” Hoecker said. “But it is a dangerous misunderstanding to think these technologies simply obviate the need for a robust transmission system. We may get to the point where we don’t need a network of wires. But I can’t foresee that.”

Moon charts

The WIRES report uses what Frayer called “moon charts” to show complementarities between transmission and MRAs in providing energy, capacity, ancillary services, system loss reductions, system lifespan, continuous service, and locational services for wholesale and retail customers. The objective, she said, was to understand how MRAs fit into the transmission planning process.

Transmission combined with the technologies provides the full range of services, the study found,. The MRA technologies, even with transmission, do not. To select between the options, a cost-benefit analysis is vital for planners. But a “least cost analysis” is insufficient. It must be comprehensive.

“One must consider the ability of a solution, be that MRAs or transmission, to provide benefits and services to various customer classes and over varying geographies and time dimensions," Frayer said.

“All technologies meet local needs,” she added. “If you are pairing local needs with the need for capacity, utility scale generation and transmission are similar. But for transmission to provide capacity, it needs to be paired with generation.”

All of the options also have a degree of “operational uncertainty” and “negative and positive externalities” that must be weighed in any cost-benefit analysis.

Energy efficiency and demand response are similar in providing capacity, Frayer explained, but each is limited in a different way. “Efficiency is expected to provide capacity for many hours whereas DR provides it only for a subset of hours—at peaks or when the system is under stress," she said.

Not choosing between A and B

The study concludes with a set of case studies that identify where planning methodologies and modeling techniques succeeded or failed. “Sometimes we predispose our modeling analysis so we only think of substitutes,” Frayer said. “Instead of choosing between A and B, we should be asking what amount of A and what amount of B will provide the best solution.”

When the Bonneville Power Administration (BPA) was planning for its I-5 Corridor Reinforcement Transmission Project, new lines—as well as energy efficiency, demand response, distributed generation, and re-dispatch of existing generation—were considered to meet a “reliability need.”

BPA concluded the MRAs alone were “potentially insufficient and too risky to meet the identified reliability needs over the long term.”

Despite operational uncertainties, BPA invested in energy efficiency and demand response as a complementary and interim measure “along with transmission to increase the net benefit to the system and customers.”

In another case study, the California Public Utilities Commission approved theTehachapi Renewable Transmission Project (TRTP) to meet public policy goals, the paper reports, but “no economic analysis was performed.”

If a full cost-benefit analysis that included RPS goals or carbon reductions had been done by the commission or by the California Independent System Operator, it adds, “more transmission investments may have been appropriate… [and] the complementarity between transmission and generation would have spurred additional wind developments in the wind abundant regions, which may have created further benefits to customers.”

And in Texas, where there is nearly 13,000 MW of installed wind capacity, “transmission was used to promote the development of renewable resources,” the study notes. Putting together the tools and techniques

“None of this is rocket science and we are not asking planners to change everything they do,” Frayer said. “These tools and techniques are not novel, untested, or experimental. They are all in use by planning departments. We just suggest they put them together in a different order so they are not looking at substitution only.”

“This is a new vision of how the electric system will work,” Hoecker said. “It says that MRAs, collectively and individually, as important as they are, are rarely a substitute for the investment in transmission we really need right now. If people defer that investment long enough, they are going to have reliability problems and life is going to get a little more expensive.”

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ORIGINAL REPORTING: THE FUTURE OF U.S. OFFSHORE WIND: 2015 'IS THE YEAR IT HAPPENS'

The future of U.S. offshore wind: 2015 'is the year it happens' ; Two projects will finally get steel in the water and prices will start coming down

Herman K. Trabish, October 16, 2014 (Utility Dive)

Aerican offshore wind is on the verge of making history.

Before the end of next year, construction will start on the first two ocean wind projects in the United States.

There are about 7 GW of offshore wind installed globally, most in Europe, and 6.6 GW more are in construction, according to the Offshore Wind Market and Economic Analysis report from the Department of Energy and Navigant Consulting.

But none of the 14 U.S. projects in advanced stages of development, representing 4.9 GW of wind power, have started construction to date.

“This is the year it happens,” Deepwater Wind CEO Jeff Grybowski said at the recent American Wind Energy Association (AWEA) offshore wind conference. “We are nine months away from the installation of our first foundations,” Grybowski said of Deepwater’s fully permitted and approved five turbine, 30 MW Block Island Wind Farm off Rhode Island.

Cape Wind

Cape Wind is also scheduled to sink steel into Nantucket Sound waters late next year. At 468 MW, it will be the first U.S. utility-scale offshore project, but it will build on the experience of 64 such projects already in service in Europe, including the 630 MW London Array.

“We are on track and expect to close financing by the end of this calendar year,” Cape Wind Communications Director Mark Rodgers said. Led by the Bank of Tokyo Mitsubishi, along with Rabobank of Holland and French investment bank Natixis, Cape Wind is looking to add debt and equity funding to the $1.5 billion it has already secured. Siemens will supply the turbines. The build out of the Massachusetts port of New Bedford will also be done by the end of this year. It is, Rodgers said, “the first port facility in North America specifically designed for staging and assembly of offshore wind turbines.”

Rodgers’ confidence about financing comes from the project’s power purchase agreements with National Grid and NSTAR, Massachusetts’ dominant utilities. “That is the driver for our financing,” he said.

The PPAs cover 77.5% of the project’s output and make it almost certain that at least 101 of the planned 130 turbines will go into construction next year.

Though the project’s opponents, funded by billionaire William Koch, may create new legal hurdles, “weak appeals of 26 solid legal decisions on the side of the project and the agencies that reviewed it are no longer going to impact our ability to finance or build,” Rodgers said.

“When physical construction begins, it will be a game changer for this industry,” Rodgers added. “The benefits will be self-evident.”

Utilities in offshore wind

Dominion Virginia Power, the first U.S utility to get into offshore wind, is moving ahead with its Department of Energy-backed Virginia Offshore Wind Technology Advancement Project (VOWTAP). Slated for construction 24 miles off Virginia Beach, the two 6-MW Alstom turbine installation is being carefully planned.

“We need to complete our engineering design and procurement process, receive regulatory approvals and complete construction to achieve the 2017 commercial operation date,” said Dominion Virginia spokesperson David Botkins.

The U.S. utility industry should be paying attention. Utilities were among European offshore wind’s early equity investors, reported Jerome Guillet, Managing Director of Parisian investment bank Green Giraffe Energy, during one of the AWEA conference sessions. Like Dominion, European utilities typically were engaged from early development.

European utilities like RWE, Dong, and SSE kept the first projects on their balance sheets. Now utility consortia are signing on for the build out of large North Sea and Atlantic Ocean development zones.

Many U.S. utilities and other investors have been skeptical of offshore projects because of high costs. Block Island’s first year output will sell at $0.244 per kilowatt-hour, according to Deepwater spokesperson Meaghan Wims. Cape Wind’s 2014 price is $0.199 per kilowatt-hour. Both projects’ contracts have annual escalators.

Offshore wind economics

Commercial success depends on more than just a low levelized cost of energy, according to DOE Wind & Water Technologies Sr. Advisor Gary Norton.

Offshore wind provides other benefits:

-It suppresses electricity market prices because its marginal generating cost is effectively zero

-It eases transmission congestion because it can be near major load centers

-It’s coincidence with load peaks gives it a high capacity value

-It offers fuel diversity

-It makes compliance with renewables mandates possible for densely populated states with few other renewable resources

-Jobs and economic growth come with local development

-It provides energy security where high electricity prices and high demand threaten the availability of conventional sources

“A robust offshore wind supply might have prevented the sharp power price spikes during last winter’s polar vortex by using the frigid winds to shave peak period demand for natural gas,” AWEA offshore wind policy manager Chris Long pointed out.

Such economic benefits could be considerable. There are 54 GW of U.S. offshore wind potential available for development even after ocean areas where there could be environmental concerns or interferences to military, shipping, or commercial activities are excluded, according to the DOE/ABBNational Offshore Wind Energy Grid Interconnection Study (NOWEGIS). Integrating that potential into the U.S. grid could save the economy $7.68 billion per year, or $0.041 per kilowatt-hour, in electricity costs.

Coming innovations

DOE will continue to lead cost-cutting with efforts like its new atmosphere to electrons (A2E) initiative focusing on whole plant costs, Norton reported. But “there is no silver bullet. Cost reduction will come from an industry-wide effort on all fronts.”

Economies of scale will come from learning curve effects, volume production,supply chain maturity, operational experience, and increasing turbine and project size.

Reduced risk that will lead to a lower cost for capital will come from regulatory support, proven structural integrity, reliable construction and installation practices, and the development of a track record with the marketplace.

Costs can be cut through turbine optimization, advanced substructures, floating platforms, array optimization and grid integration innovations.

But no innovation in U.S. offshore wind is more highly anticipated than the DOE-backed Principle Power Inc-Deepwater Wind WindFloat Pacific project. It will literally float up to five 6-MW turbines in 350 meter-deep water 18 miles off Oregon’s coast.

As unlikely as a giant floating wind turbine might seem, PPI’s technology is proven. A prototype 2-MW floating turbine has operated off Portugal’s coastsince 2011 and generated over 11 gigawatt-hours of electricity. The company is backed by multinational utility EDP and oil and gas major Repsol.

At scale, floating deep water technology is expected to dramatically reduce costs of construction and maintenance. It is considered the only practical solution for developing wind off the U.S. Pacific coast. Unlike the long broad Atlantic continental shelf, the Pacific shoreline drops away too steeply for ocean floor-mounted turbines.

Execution of the project will begin sometime after the middle of 2015, according to PPI CEO Alla Weinstein.

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Huge News From Tesla

Tesla Founder Elon Musk just announced a new battery for his EV Roadster 3.0 will demonstrate a single-charge 400 mile range in January. Could put a lot gas-powered vehicles out of business. Explains why Ford, GM, and most carmakers are going to the plug. From Ford via YouTube

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Things Are Happening

Why not now? From ClimateReality via YouTube

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Climate Change In Miami Beach

South Florida is quickly becoming a sea level rise case study. From the YaleClimateForum via YouTube.

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ORIGINAL REPORTING: HOW UTILITIES CAN MITIGATE GRID IMPACTS OF HIGH SOLAR PENETRATIONS

How utilities can mitigate grid impacts of high solar penetrations; New strategies for utilities and installers to put solar in better places to protect the grid

Herman K. Trabish, October 16, 2014 (Utility Dive)

Nothing is likely to hold back the rise of solar, so utilities and grid operators across the country are looking for ways to protect the grid from new threats that come with high solar penetration.

Solar photovoltaic capacity roughly tripled between 2011 and 2013. About 140,000 grid-connected distributed PV systems were added in the U.S. in 2013, bringing the cumulative total to 475,000. Forecasts project another doubling of the growth rate by the end of 2016, according to the report Utility Strategies for Influencing Locational Deployment of Distributed Solar from the Solar Electric Power Association (SEPA) and the Electric Power Research Institute (EPRI).

With high penetrations of solar on some distribution circuits and rising levels on many others, “electric utilities are increasingly being asked to develop grid planning and management strategies that uphold system reliability and safety standards without limiting the pace of solar resource expansion,” the report said.

The three broad pathways for utility-solar interactions are in rates that value (1) its energy, capacity, and ancillary services, (2) its peak and off-peak generation, and/or (3) its locational flexibility, according to a paper from the Rocky Mountain Institute eLab.

Today, there is only significant concern in Hawaii and parts of California IOU territories.

But grid planners in Massachusetts and New Jersey are formulating strategies to deal with exponential growth, according to another paper from the Interstate Renewable Energy Council (IREC). And planners at New York’s ConEd are looking at distribution level impacts, the SEPA paper reports.

“We started from the premise that distributed solar installations are built where the consumers are or where the solar industry markets,” said SEPAResearch Director and report co-author Mike Taylor. “Consumers and the solar industry are going to put solar where they want to, but there is an influencing opportunity for utilities.”

6 routes to better solar siting

The SEPA/EPRI paper describes six ways for utilities to “get ahead of the curve” and “send a market signal that some areas are easier for interconnection,” Taylor said.

The most common is an information exchange. High solar penetration areas tend to have the best demographics and the least obstructions. They also tend to be where the interconnection costs are highest and the waits for approvals are longest. Maps showing these areas, as well as low solar penetration but high electricity demand areas, are already pointing installers in California,Hawaii, and the Northeast to new markets. But, they are still not “optimized” or “widely in use,” Taylor said.

Penetration screens can protect systems’ power quality and minimize the risks of unintentional islanding, voltage deviations, and protection miscoordination on overloaded distribution circuits, according to IREC. But “they do not provide much guidance regarding the ability of the local distribution system to accommodate a specific proposed generator at a specific point of interconnection.”

Targeted interconnection processes might do that, the SEPA paper proposes. “The signal now is, if you are in a high penetration area, it is going to take longer or cost more, or both, to interconnect,” Taylor said. “Utilities could flip that by guaranteeing a lower cost or shorter time-line. It would be promoting the ease of low penetration.”

Utilities could also offer incentives “for locating in low penetration areas or in high demand areas where solar could help relieve congestion,” Taylor said. An in-house cost-benefit analysis might reveal opportunity. Or a utility might conclude that if processing a rooftop solar interconnection is significantly faster and cheaper in low penetration areas, “why not offer half or more of the difference as an incentive?”

That is especially true where interconnect applications in high penetrationareas trigger costly grid studies or expensive infrastructure upgrades.

Utilities also can exert price leverage on interconnection costs. This could be a useful tool where “incentive” is synonymous with “subsidy” and “tax” as “politically untenable or dirty words,” Taylor said.

The solar industry would fight an increased interconnection cost, Taylor said. But it might trade that for new incentives, which ratepayer advocates or utilities would likely oppose. “In one place, the best approach might be an incentive. In another, it might be better to raise the cost,” Taylor said. “It’s a political calculus.”

Where it is politically or economically viable, a dedicated tariff could be offered for solar-generated power from low penetration locations. “It is similar to a value of solar tariff or a feed-in tariff or a reverse auction mechanism-determined rate—a sweetener for sending solar onto the grid." Taylor said.

Out-of-the-box thinking

Finally, Taylor said, there could be “targeted distribution infrastructureupgrades and cost allocations.”

Where there is high solar penetration, utilities often must do costly and time-consuming feeder system evaluations before greenlighting new installations. Evaluations often call for upgraded distribution system infrastructure equipment like transformers, advanced inverters, capacitor banks, static VAR compensators, line regulators, and/or load tap changers to manage two-direction power flows and system-threatening frequency and voltage fluctuations.

To avoid such costs, “they just shut down solar,” Taylor said. “Or they may shut down everything above a certain system size. Or they may allow the interconnection but whoever triggers the evaluation has to pay for the study and the upgrade.”

The complete distribution system renovation needed for the new emerging smart grid and distributed energy reality will be costly and most utilities remain reluctant to undertake it, Taylor added.

But the costs for solar could be allocated at the distribution system level across all the beneficiaries, Taylor said. “This idea is very theoretical and out of the box and we are interested to see how utilities and the solar industry react to it.”

A utility could distribute the costs for the study and upgrade among all applicants for new solar builds. Or the solar industry could fund them and own franchise rights on that feeder system. Either way, utility ratepayers don’t bear the cost.

“Since solar customers are causing the need for the upgrade, maybe the solar industry would want to pay for it,” Taylor said. “They would have to run the numbers to see if it is worth the cost of upgrading for the additional business it would get in that already highly penetrated area, relative to going to a low penetration area.”

Such a cost allocation scheme might require an update of the current regulatory rules on distribution system management, Taylor added, but it could also make things like crowdfunding and community solar more workable.

What about a distribution system operator?

The SEPA proposals are conceptually sound, James Tong, vice president of strategy and government affairs at solar third-party finance company Clean Power Finance, told Utility Dive. But, a revised regulatory construct should also create an independent third-party to guarantee that decisions about the distribution system are transparent and balanced.

Tong is the co-author, with former FERC Chair Jon Wellinghoff, of a call for an independent distribution system operator (IDSO). “The whole idea of an IDSO comes from the need for a neutral arbiter,” he said.

From the solar industry’s point of view, utilities have significant leeway to influence outcomes, Tong explained. "Utilities could identify low penetration by grid needs," he said. "But if you’re a utility, would you rather meet those needs with customer owned assets or monopoly owned assets? You’re incentivized to do the latter."

A neutral IDSO may not be the perfect solution, Tong said, “but it reduces tension.” With SEPA’s tariff proposal, customers might object to rates that differ by location, and the cost allocation idea raises “broader philosophical issues” between utilities and the renewables industries, Tong said.

“If clean energy is just an individual choice, it makes sense to charge individuals,” Tong said. “But if we as a society agree that cleaner energy is a public goal, then to say the solar customer is the one creating the cost for the grid and should pick up the tab is unfair.”

In the many states with policies dedicated to new renewables, private capital is supporting societal goals. “Where everybody benefits, everyone should pay,” Tong said. “It’s also unfair to force rooftop solar customers to pay for grid upgrades when many of them are likely needed regardless of distributed solar,” he added. “Studies show outages are extremely expensive in the U.S., costing an estimated $18 billion to $33 billion per year. A more resilient and robust grid benefits everybody.” click here for more

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ORIGINAL REPORTING: IDAHO POWER'S VITAL BOARDMAN-TO-HEMINGWAY TRANSMISSION LINE WRESTLES WITH PERMITTING

Idaho Power's vital Boardman-to-Hemingway transmission line wrestles with permitting; Instead of delivering renewables, it’s struggling over sage grouses and ground squirrels.

Herman K. Trabish, October 14, 2014 (Utility Dive)

There are two reasons the 300-mile Boardman-to-Hemingway transmission project is crucial to the energy future of the High Plains and the Pacific Northwest.

First, by connecting to Pacificorp’s massive, still unfinished Energy Gateway transmission system, the 500 kilovolt, alternating current line will deliver energy generated on the High Plains to load centers and lucrative electricity markets in the Pacific Northwest.

Second, it offers greater potential for the connected eastern and western grids to deliver abundant renewables generation to California’s insatiable energy appetite.

“We are trying to interconnect to the Mid-Columbia grid, the Mid-C market,” Idaho Power 500 Kilovolt Projects Manager Doug Dockter told Utility Dive. “The Pacificorp balancing authority is farther south and the transmission is critical for them because they are trying to use it to work their [Energy Imbalance Market] with the California Independent System Operator.”

The regional loads are complimentary, Dockter said. Idaho Power’s demand from air conditioning and agricultural irrigation causes a summer peak. But for much of the rest of the Northwest, demand peaks in the winter due to the need for space heating.

“There is usually extra energy in the Northwest for us in the summer and when they are peaking in the winter, we sell to them,” Dockter said. “With access to the Mid-C market, we could satisfy regional generation needs without building new generation.” In conjunction with the Energy Gateway and the Energy Imbalance Market, Dockter said, intermittent wind and solar resources can be more reliably interconnected across a greater region.

But, he added, “we first have to get the permits.”

The first complications

Idaho Power began permitting Boardman-to-Hemingway in 2008. Then it ran into complications and stopped. The utility spent a year working with stakeholders along the route, and resumed trying to coordinate state and federal permitting processes in 2010. “We have been going through those ever since,” Dockter said.

Idaho Power is the project lead. The Bonneville Power Administration and Pacificorp, both would-be beneficiaries of the line, are helping fund permitting.

The federal National Environmental Policy Act (NEPA) process is led by the Bureau of Land Management (BLM). The BLM must provide a draft environmental impact study (EIS), then a final EIS, and finally a Record of Decision (ROD). Oregon’s Energy Facility Siting Council (EFSC) is the state-level jurisdiction. The two processes, Dockter said, were not designed to be run together and do not complement each other.

Boardman-to-Hemingway was one of seven projects designated for special attention by the Obama Administration’s Rapid Response Transmission Team (RRTT) in 2009. It was supposed to streamline the process by driving cooperation between the federal permitting agencies.

“The RRTT has given us access to people in Washington, D.C., but it has not been effective for getting permits,” Dockter said. “The RRTT’s purpose was to make sure those nine agencies involved in permitting are working well together. What we are noticing is that the BLM has been ineffective in managing its own process. That is what is hampering [Boardman-to-Hemingway].”

The Bureau of Land Management

The BLM’s organizational structure is ineffective for permitting multi-state transmission, Dockter believes.

“The field offices in each area are responsible for their little chunk of ground. When you pass through multiple field offices, you have to make sure they are willing to coordinate and cooperate," he said. "That is extremely challenging."

Dockter, who has been involved in Boardman-to-Hemingway since 2008, said inconsistent management “has created many issues.” The utility has “gone through five different BLM project managers” since the project started, he added.

While NEPA permitting requires the weighing of multiple alternative routes, Oregon's EFSC is standards-based. “We have to submit the route and prove we can meet 28 different standards to get their site certificate,” Dockter said.

Until the BLM issues its ROD “sometime in 2016,” Dockter explained, the final route is uncertain. BLM’s preliminary analysis provides a “likely” route.

But to advance the process by taking on the rigorous and costly EFSC certification procedures, Idaho Power must guess which proposed segments of the line might endure final BLM scrutiny.

The BLM, for its part, noted that multi-state projects like Boardman-to-Hemingway are naturally complicated.

"The Boardman-to-Hemingway Transmission Line proposal involves working with numerous federal, state, and local agencies across multiple jurisdictions in six counties and two states," BLM National Project Manager Tamara Gertsch told Utility Dive. Nonetheless, the agency remains "on track to release the draft Environmental Impact Statement this fall."

Sage grouses, ground squirrels, and bombs

Two of the project’s biggest impediments are the greater sage grouse and the Washington ground squirrels that live on Boardman’s U.S. Naval weapons systems training facility. “The big challenge with the sage grouse is the unknown,” Dockter said. His efforts await the results of a BLM study of Oregon and Idaho sage grouse areas. “We don’t know how it might impact what we are trying to do.”

Oregon’s Sage Grouse Conservation Partnership, or SageCon, is also assessing sage grouse concerns. The unknowns there are even more problematic for Dockter because directives will likely not come until after Boardman-to-Hemingway is permitted.

Observers say Idaho Power and the Department of Defense are moving toward a route for the line along a road to the east of the Navy’s only Pacific Northwest live bombing range, but Dockter said there is no agreement.

Three factors need to be reconciled, he explained. The first is Navy weapons training, the second is the endangered Washington ground squirrel habitat at the edge of the bombing range, and the third is high-value agricultural land across the road from the Navy facility.

Stakeholders seem to have identified a viable corridor that follows a road on the east side of the bombing range. But they have not been able to agree on whether the line should be on the east or west side of the road.

Once again, a final route may not come until after the BLM completes its NEPA analyses. “All the routes in that area are still in play,” Dockter said, “and we are working diligently to decide.”

'Left holding the bag'

In Idaho Power’s most recent Integrated Resource Plan, Dockter said, the two key strategies for advancing load service over the next ten years are the Boardman-to-Hemingway line and demand side management.

“Both of those options are no-carbon resources and, especially with the EPA’s newly proposed 111 (d) requirements, it would be a huge advantage to build [Boardman-to-Hemingway]. But we can’t get this thing permitted,” Dockter said. “We are trying to do what is right. It is almost like there is in-fighting between branches of the government and we are left holding the bag.” click here for more

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Christmas In The Trenches, The 100th Anniversary

Long-time NewEnergyNews readers will recognize John McCutcheon’s song as a Christmas tradition here. It is getting more attention than usual this year because it is the 100th anniversary of the events on which the song is based. From FolkFaves via YouTube

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Al Gore -- Must We Change? Can We Change?

In asking and answering these questions, this guy is pointing – as he always has – in the only real direction to go. Give him 10 minutes. From Julio Ruiz via YouTube

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The Miracle In The Miracle On 34th Street

You gotta believe!!! From the 1955 TV version/airdropper1987 via YouTube

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ORIGINAL REPORTING: HOW CALIFORNIA IS INCENTIVIZING SOLAR TO SOLVE THE DUCK CURVE

How California is incentivizing solar to solve the Duck Curve; South-facing systems produce more solar, but west-facing panels may produce more valuable solar to the grid.

Herman K. Trabish | October 13, 2014 (Utility Dive)

UD-West-Facing2-10-5-2014 (1)

The California Energy Commission wants to turn rooftop solar in a whole new direction. Discovering where and when west-facing rooftop solar has a value proposition as good or better than traditional south-facing rooftop systems could alter who wants to be in the business.

A predictive analysis of 1,000 typical homes with 4 kilowatt west-facing rooftop solar systems over the course of a typical year in Fresno, California, found that facing panels towards the West could be appealing to both customers and electricity providers. Houses with west-facing panels saw a 20% total energy reduction (about 1,100 megawatt-hours) in comparison to the same homes with south-facing systems, according to CEC Commissioner David Hochschild. But the analysis also showed a 56% total energy increase (about 700 megawatt-hours) in the critical 2:00 pm to 8:00 pm peak demand period.

This projection is confirmed by new real-world research.

“We have now looked at a full year. West-facing panels are out-producing south-facing panels between 3:00 pm and 7:00 pm," CEO Brewster McCracken said of a Pecan Street Research Institute study of 50 Austin, Texas, homes with rooftop solar. "In the winter, it was 25% more generation during those hours. In the summer, it was almost 70% more.”

“South-facing panels are out-producing west-facing panels in all but two months when you look at the total daylight hours,” he added, confirming the thrust of the CEC analysis. “In the peak hours, west out-produces south all year long. In total production, south produces more.”

Important news for utilities, grid operators, and home builders

With utilities and grid operators increasingly concerned about meeting big peak demand ramps in metropolitan load centers, rooftop solar’s potential coincident electricity supply has become more valuable.

“When you have production in the late afternoon hours, it helps keep peaker plants offline and those are the most polluting, most expensive, and least efficient natural gas generation,” Hochschild explained. “Even if those systems produce fewer kilowatt-hours per year, their output is at a very valuable time so they are worth providing an incentive for.”

Hochschild took over the commission’s New Solar Homes Partnership (NSHP)last fall when its administration was transferred from the state’s IOUs—Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric. With administrative consolidation, program costs came down, Hochschild said. “Those savings are going into solar incentives.”

The other commissioners, aware of California’s demand shift toward a later afternoon peak and of the economic and environmental disadvantages of gas peakers, approved Hochschild’s proposal for a new solar incentive.

For installing west-facing solar on new homes, developers can now get a 15% premium—up to $500—over the NSHP incentive that has supported 12,500-plus new home solar installs since it was added to the California Solar Initiative (CSI) in 2008.

“We want more west-facing PV but this is not a mandate, it’s an option,” Hochschild explained. “It doesn’t take away anything. It just provides an incremental incentive for builders.”

Real estate market surveys have shown solar adds property value, but it is not yet clear that developers will respond.

“Anything, including efficiency or solar, that adds cost, raises the price,” Hochschild acknowledged. “You have to really sharpen your pencil to make it work for these guys. Every builder I have talked to has said they would not be doing solar at all were it not for the NSHP program.”

Support from the California Building Industry Association (CBIA) and individual home developers may be because the incentive goes to the builder and not the homeowner impacted by the orientation change, Hochschild acknowledged. But building cycles are long term and the incentive has only been in place five weeks, he added. The CEC will publish the first data at the end of this year.

Rate design

Both Hochschild and McCracken noted that regulatory debates over rate design around the country could also drive the market toward west-facing solar.

“If you have peak demand pricing, west might be more valuable than south,” McCracken said.

Time-of-use (TOU) rates, even without net energy metering, could change the value proposition in places like California and Texas because solar output is “so in line with peak pricing, especially during those late afternoon summer hours,” he said.

In the absence of a new rate design, with solar growth driven exclusively by total output, “south is the way to go,” McCracken said. “But west-facing panels will be grid-friendlier and provide more utility system benefit.”

TOU rates could be a way for utilities to provide a bigger incentive than the CEC NSHP premium for the west-facing solar they need, he added.

“It is a complex question but it is possible with time of use pricing and certain rate designs," McCracken said. "West facing would be more valuable just because the difference in the summer months is nearly 70% during peak hours. It is possible that would narrow, if not overcome, the gap for west-facing systems.”

And, he added, “research shows the differences are not that big. If prices come down a little more, west-facing roofs, even without rate design changes, are suddenly going to become viable.”

“$500 isnt a decision maker but there are other considerations,” said K Kaufmann, communications manager for the Solar Electric Power Association (SEPA), the solar industry-utility alliance.

Two trends SEPA has noted echo Hochschild and McCracken:

People who might not have considered putting solar on a west-facing roof might decide to do it

Rate structures that link compensation for solar to the time of day it is generated could be an incremental incentive

“It's impossible to say without more data if utilities would like this,” Kaufmann noted, “but as you get more solar on the grid, anything that provides more control for utilities could be attractive.”

Arizona Public Service jumps in

Value to the grid was a factor when Arizona Public Service asked regulators in August to approve a plan for the utility 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 rate based program would be very similar to the third party ownership (TPO) lease contracts offered by private sector companies like SolarCity, Clean Power Finance, and SunPower, because the APS hosts will pay no upfront fees and have no ownership responsibilities.

Rate-basing will allow APS to “maximize the potential system benefits,” according to APS Renewables Manager Marc Romito. “Every opportunity we can, we will be facing these systems west or southwest.”

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.

In dealing with California’s growing peak demand challenge, “solar is a big part of the solution," Hochshild said, "but it can be a bigger part still if production matches the peak.”

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