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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ORIGINAL REPORTING: IS SUNZIA READY TO DELIVER NEW MEXICO WIND TO PHOENIX AND LOS ANGELES?

Is SunZia ready to deliver New Mexico wind to Phoenix and Los Angeles?; After years of fighting for permits, SunZia is about to get a green light—or a lawsuit.

Herman K. Trabish, October 9, 2014 (Utility Dive)

The SunZia Transmission Project just won a hard-fought peace with the U.S. military. But the project must now face a fight with environmentalists before it can deliver high value New Mexico wind and southwestern solar power to energy hungry cities in California and Arizona.

“SunZia is grounded in regional planning. It is not a developer’s wild idea,” SunZia Southwest Transmission Project Manager Tom Wray explained to Utility Dive.

Wray has been involved in transmission planning since 1995. Even then, the Southwest Area Transmission Subregional (SWAT) Planning Group was looking for a way to improve “the transfer capability between southern New Mexico and southern Arizona” and “the interface between Arizona and Southern California,” Wray said.

Proposed in 2006 and intended to meet that need, SunZia would be two 500 kilovolt, alternating current (AC) lines with a 3,000 megawatt capacity. Projected to cost $2 billion, SunZia would “enable the development of renewable energy resources, including wind, solar, and geothermal generation, by creating access to the interstate power grid in the Southwest,” according to the U.S. Bureau of Land Management website.

“SunZia is just a long extension cord to tap into 11,000-plus megawatts of class 4 winds with a capacity factor of 45% to 47% that are currently stranded in central New Mexico,” Wray said. And it could also transmit the enormous solar resource along the Interstate 10 corridor, he added.

SunZia is only now completing its National Environmental Policy Act (NEPA)permitting process, which began in 2009. “Big transmission projects are not for the faint of heart,” Wray acknowledged. “We are hoping to get an ROD [Record of Decision] by February 2015.”

The permitting maze

“SunZia was the first major long distance transmission line that started through the NEPA process,” explained Sonoran Institute Senior Adviser John Shepard. “These long distance transmission lines are the mother of all land use challenges. They cover a lot of ground, cross multiple landscapes, go by multiple communities, and, for the most part, the beneficiaries are the power generators at one end and the purchasers at the other end. In between, these lines have significant impacts on landscapes and communities that get limited benefits.”

The Wilderness Society (TWS) was among the southern Arizona environmental groups that worked with SunZia and the many federal agencies involved, under NEPA, in permitting for lands under the jurisdiction of the Department of Interior (DOI). “We think public lands have a role but we want development to be done in the right places and the right ways,” TWS Assistant Director Alex Daue told Utility Dive.

TWS accepts the need for new transmission but wants a route that strikes a balance between providing renewables and avoiding “unacceptable impacts,” Daue said. “Unfortunately, the route the developer and DOI’s Bureau of Land Management (BLM) have settled on in Arizona does not strike that balance.”

SunZia has, however, reached an agreement with the Department of Defense (DOD) to underground five miles of wires in three separate segments on lands near the White Sands Missile Range, Wray said.

The agreement came only after DOD rejected the route selected in the BLM’s final Environmental Impact Study (EIS). Reaching a compromise took “at least a couple of dozen meetings over a couple of years,” Wray said. “I understand and respect the DOD position. But providing electricity is also a matter of national security.”

In the end, driven by the White House Council on Environmental Quality (CEQ), SunZia found cooperation from the office of the Secretary of Defense, Secretaries of the Interior Salazar and Jewell, and DOI Counsel Steve Black.

Launched in 2009, the Obama administration’s Rapid Response Transmission Team (RRTT) initiative “worked very well” by showing the agencies how to improve interdepartmental cooperation, Wray said. “Getting that done was a big deal. Secretary Salazar and Steve Black deserve a lot of credit for changing that mindset. And Secretary Jewell has continued that effort.”

The RRTT was created to prevent “residual objections” to the BLM final EIS, Shepard said. By that standard, it “manifestly failed because DOD was against the BLM route in the final EIS.”

“Everyone involved with these projects is struggling with the legacy of the old way of doing them, without upfront planning and a landscape scale approach to finding lower impact routes and better engagement with stakeholders and the public,” Daue said. “RRTT is trying to leverage some of the evolving thinking but it is a real challenge.”

“They have a path forward,” said American Wind Energy Association Western Policy Director Tom Darin, who helped develop the RRTT while working at the White House. “Some think the solution is a bad precedent because burying high voltage lines costs a lot of money. But White Sands might say it should have been a longer segment. It is a path forward. The RRTT helped the project get there.”

Ready to finance?

With the last objection to the final EIS resolved, the BLM’s early 2015 ROD would allow Wray to proceed to financing. “It will be a project-financed project,” he explained. “There is a lot of money now chasing bankable projects with PPAs from investment grade utilities. We will take generators’ contracts to sell electricity to their customers and pledge those contracts as collateral to borrow money to build the project.”

When construction is completed, SunZia will refinance. “Banks love transmission lines because they are risk-less and they are forever,” Wray said.

He expects construction to take “about 36 months to 40 months” and be complete in time for “the next tranche of opportunity” to sell renewables in the California and Arizona markets. He predicts that will come between late 2018 and early 2020, driven by increased state mandates and the need for more renewables to meet federal emissions regulations.

But TWS and other Arizona environmentalists may disrupt Wray’s timetable. When the BLM’s designated western energy corridors threatened “unacceptable impacts,” the groups’ lawsuit stopped development in those corridors. It remains stopped while BLM rewrites rules for environmentally sensitive areas and access to renewable resources.

The environmental groups likewise object to the BLM’s final decision on the SunZia route. It could, they argue, harm the San Pedro River Valley, its wildlife refuge, and avian habitat. It would also fragment the still unspoiledAravaipa Canyon. “The environmental impacts far outweigh the benefits,” Daue said, though proposed routes through Tucson would be acceptable.

Because of the population and infrastructure there, that BLM alternative route through the Tucson basin was never really viable, Shepard said. “But the environmental community maintains the impacts of SunZia in the San Pedro River Valley are significant enough that the route should not happen.”

Daue would not predict whether or not there will be another lawsuit.

“If there is, and the court determines BLM did not do adequate study, it will require a re-evaluation of those aspects of the EIS,” Shepard said. BLM will probably not issue a Notice to Proceed if there is a legal challenge. “White Sands is handled," Shepard explained. "The San Pedro River Valley is the other deal-breaker.”

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ORIGINAL REPORTING: WHAT NET METERING WILL DO TO THE UTILITY BUSINESS

What net metering will do to the utility business; A close look at rooftop solar's impact on utility earnings and rates

Herman K. Trabish, October 3, 2014 (Utility Dive)

Customer-sited solar photovoltaic systems have very real impacts on utility rates and returns, according to a major new study from the Lawrence Berkeley National Laboratory. But those consequences are very different for ratepayers and utilities. But there are things utilities can do to balance the impacts of customer-sited PV and resolve some of the passionate regulatory debates over net metered solar across the country.

“Our hope was to dial back some of the heat and hysteria in these debates by showing two things,” explained Researcher Andrew Satchwell, one of the lead authors of Financial Impacts of Net-Metered PV on Utilities and Ratepayers, released earlier this month. “One, these are complex issues involving lots of trade-offs; and, two, in most jurisdictions there is time to figure this out in a thoughtful and deliberative way."

What you need to know

The most important specific conclusions of the research are: Customer-sited photovoltaic (CS-PV) solar use equal to 2.5% of a utility's retail sales would cause an estimated 3.9% reduction in earnings for a prototypical vertically-integrated southwestern utility and a 4.5% reduction for a prototypical wires-only northeastern utility.

That 2.5% solar use would cause an average retail electricity rate increase of 0.1% or less for the southwestern utility and 0.2% for the northeastern utility.

Shareholder impacts are significantly greater than ratepayer impacts for both types of utilities across all variables, including load growth, rate structure, ratemaking processes, and utility cost growth.

The southwestern utility’s return on equity (ROE) would decrease only 0.3% under 2.5% solar use. The northeastern utility’s ROE would decrease 4.7% due to higher assumed O&M costs and the fact that the northeastern utility in the study does not own generation units.

The report’s clear distinction between the integrated southwestern utility and the wires-and-poles northeastern utility makes an important point.

“First and foremost, the discussion needs to have nuance," Satchwell told Utility Dive, "because the impacts to the utility and to ratepayers really depend on the specific physical, financial, and operating characteristics of the utility.”

Solar PV currently accounts for only about 0.2% of total U.S. electricity generation and no more than 2% in most states. But there are states, like Hawaii, where the penetration of customer-sited solar is contributing toincreased pressure on regulators and utilities. At solar's current growth rate, other states could soon see similar impacts.

Beyond statistical estimates of the impacts of 2.5% customer-sited solar PV penetration, the paper offers a detailed cost-benefit analysis of ways to mitigate impacts as CS-PV reaches 10% of a utility’s retail sales.

“Even at penetration levels significantly higher than today, the impacts of customer-sited PV on average retail rates may be relatively modest," the paper concludes.

More importantly, “incremental” mitigations, such as decoupling revenue from electricity sales, providing an adjustment mechanism, creating shareholder incentives, or altering regulatory timetables and proceedings, offer ways to change the impacts of CS-PV on utilities’ rates, earnings and returns.

What’s not in the report

“We shied away from grand conclusions," Satchwell told Utility Dive. Instead of pronouncements about “the utility death spiral,” he explained, "the report shows there can be wide variations in the size of the impacts and interdependencies between impacts. What that means for the actions of the utility is beyond the scope of this report.”

The infamous cost shift, which some argue is caused by net metered solar, is also beyond the report’s scope, Satchwell said, though it is an important area for further study. “You have to be able to model both participating and non-participating customers and you have to make assumptions about the level of costs for the utility and how to fairly and equitably allocate those costs," he said. "You can’t just make one assumption.”

The impacts of customer-sited PV are greater for shareholders than for ratepayers—but that does not pit utilities against their customers, Satchwell said. Instead, utilities, regulators and customers need to understand the tradeoffs between incentives and mitigations.

Adding variables and mitigating impacts

The contentious issue of solar’s total value highlights the way a variable can have “divergent implications for ratepayers and shareholders,” Satchwell said. “The higher the value of PV, the higher its ability to defer capital investments, which leads to potentially higher negative financial impacts for utility shareholders, due to lost earnings opportunities.”

As customer-sited PV reaches higher penetrations, its shareholder impacts can be mitigated with some of the same measures used by utilities to offer energy efficiency to customers. Though both reduce a utility’s electricity sales, both can still benefit utilities.

Things like decoupling mechanisms and lost revenue adjustment mechanisms (LRAM) address revenue erosions that can lead to deferred investment and lost earnings. Decoupling allows utilities to add a customer charge or credit, usually less than 2% of total sales, to balance total lost or gained revenues. The LRAM provides a similar adjustment for revenue changes specifically resulting from energy efficiency or from customer-sited PV.

Shareholder incentives can even encourage utilities to invest in CS-PV, despite reduced earnings opportunities, by making it more like any other capital investment. An example might be Arizona Public Service's proposed move into rooftop solar ownership, Satchwell acknowledged.

Under the mooted scheme, APS would provide 3,000 customers with a monthly bill credit. That would diminish earnings, but APS has asked regulators for the opportunity to rate base program costs. That would mitigate lost future earnings opportunities created by CS-PV.

“Our mitigation analysis shows you can mitigate impacts, but something that didn’t necessarily come through in the report is that several of these mitigations can be combined to find more a comprehensive approach,” Satchwell said.

A mitigation of shareholder impacts through decoupling might result in the exacerbation of ratepayer impacts, he explained. That could be combined with allowing CS-PV to count toward a utility’s renewables portfolio standard (RPS) obligation. “In the way we modeled RPS compliance, counting CS-PV toward the RPS has no impact, positive or negative, on shareholders," Satchwell said. "But it reduces the average rate.”

Several approaches can be combined to develop a more comprehensive way to address trade-offs between shareholders and ratepayers, Satchwell said.

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ORIGINAL REPORTING: HOW TO BUILD HIGH VOLTAGE TRANSMISSION IN AMERICA

How to build high voltage transmission in America; Projects are struggling with permitting across the country, but PSE&G and PPL got it done.

Herman K. Trabish | October 6, 2014 (Utility Dive)

As Public Service Electric & Gas (PSE&G) and PPL have proved, all it takes to get a high voltage transmission line built in the U.S. today is the patience of Job, a little help from the Obama administration, and the ability to fly.

The 150 mile, $1.4 billion, 500 kilovolt alternating current (AC) Roseland-Susquehanna line will be completed by PSE&G and PPL by spring 2015. Of the seven high voltage projects named for special attention by the Obama Administration’s Rapid Response Transmission Team (RRTT) in 2009, it is the only one nearing completion.

The credit for that goes to the utilities’ teams. But Roseland-Susquehanna was born with some advantages.

The need for the line

Regional Transmission Operator PJM gave the Susquehanna project an imperative and a timeline when it initiated the undertaking in 2007 “to resolve numerous overloads on critical 230 kV circuits across Eastern Pennsylvania and Northern New Jersey” forecast for 2012.

PJM’s 2010 Regional Transmission Expansion Plan (RTEP) “identified five NERC reliability criteria violations, confirming the need [for a new high voltage line]” and noted that “incremental upgrades are not a practical solution.”

PJM conducted a market efficiency analysis that predicted the upgrade would save congestion costs of $160 million by 2012 and $280 million by 2014.

Besides christening the project with an imperative and a reward, PJM set out the division of labor. “The advantage of each utility working its own state was that each of us could go to our own commission during the siting process and get its approval,” explained PPL Communications Director Paul Wirth. “We sited the line in our Pennsylvania service territory and worked our commission and PSE&G did the same in New Jersey. The commissions are familiar with us and we are familiar with their processes.”

The line’s route was essentially pre-determined by the existing 230 kilovolt line’s right-of-way (ROW). As would-be builders of high voltage projects in the Midwest, the high plains, and the Pacific Northwest have told Utility Dive,settling on a route can be a huge challenge.

Permitting—the first obstacle

Roseland-Susquehanna’s first challenge was securing permits.

One of the keys was a special use permit allowing passage through the Delaware Water Gap National Recreation Area (DWGNRA), a national recreation area managed by the Department of the Interior’s National Forest Service, PSE&G Projects & Construction Manager Jason Kalwa explained. That required an Environmental Impact Statement (EIS) obtained under the terms of the National Environmental Policy Act (NEPA) process.

“The RRTT helped get that,” Kalwa said. Transwest Express (TWE) Director of Communications Kara Choquette recently told Utility Dive the RRTT had maintained progress but wasn’t sure it speeded the process. Idaho Power's Boardman-to-Hemingway Project Manager Doug Dockter said it has neither helped nor hampered his project. But the Roseland-Susquehanna builders praised the RRTT.

“We had been in planning since 2008. The RRTT helped focus the attention of the numerous federal agencies involved,” explained PSE&G Communications Director Karen Johnson. “It helped keep the decision-making process on schedule. Being on that list said ‘this line is important to address reliability concerns in this part of the country.’”

“It wasn’t only the National Park Service,” Wirth said. “We needed permits from the Army Corps of Engineers. We needed permits from the U.S. Fish and Wildlife Service. We needed the Federal Aviation Administration because of the height of the towers in an air traffic corridor. The RRTT coordinated and streamlined that.”

Construction—the next hurdle

Getting the permits was one hurdle. Equally challenging was the construction, which started in 2012 and had to be done in accordance with the permits while overseen by a National Park Service (NPS) team.

“We had to comply with a number of plans that outlined the various requirements of the special use permit,” Kalwa said. “But the Park Service was reasonable. Just like we are responsible for ensuring the reliability of the electric system, they are responsible for protecting their park. I didn’t think any of their requests were unreasonable.”

The three rules in all environmentally sensitive work are to avoid impacts, minimize impacts, or mitigate impacts. From regular meetings with NPS personnel, in which Kalwa took the lead for both utilities, crews got instructions to tread lightly, use protective fencing, be cautious about matting, and watch vehicles’ speed.

Because of the stringent permit requirements and a short outage window before service from the 230 kV line had to be replaced by service from the 500 kV line, "we realized a joint team was the best approach,” Wirth added.

“The key to success, especially with the National Park Service, was listening to their concerns and finding ways to reduce impacts with those avoidance and minimization measures,” Kalwa said. "It might be something as simple as putting up a fence or limiting construction vehicles or lowering the speed limit. Small things went a long way.”

A $66 million mitigation fund established by PSE&G and PPL covered the extra care as well as thorough post-construction restoration and monitoring, Kalwa and Johnson said.

The power to fly

Segment one, near Roseland, went through the Troy Meadows wetlands. To avoid environmental impacts, Kalwa had his crews do the work with a helicopter-like air crane instead of building roads to the ROW path and trucking in ground crews and a crane. Lighter-weight lattice towers were used.

“It was a real environmental win,” Johnson said. “We flew all the equipment inpiece by piece. As they were lowered, construction crews on the towers bolted the pieces into place.”

By eliminating the costs of road building, mitigation, and restoration, Kalwa and Johnson speculated, using the air crane did not add significantly to the next project's cost, and might have even saved money. “Removal and demolition took all of about two hours,” Kalwa said.

PPL did standard construction with tubular steel towers, Wirth said. “They were brought in on trucks and craned into place.”

Restoration—keeping the promise

Restoration in the National Park segment was more challenging than on other segments. The NPS required special mitigations like weed-free topsoil and provisions for wood turtles. “It was different,” Kalwa said. “But we want to make it equal to or better than it was before.”

There are also five-year, nine-year, and life-of-the-line ongoing monitoring requirements. Specialists paid from the mitigation fund make sure that the restored habitats support healthy populations of species like wood turtles and rattlesnakes.

“It proves you can build a project like this and maintain your commitment to the environment and your customers,” Johnson said.

“One of the other major challenges of siting a new high voltage line is the tendency of people not to want it where they live,” Wirth added.

“But we’re pretty sure they want their lights to come on when they flip the switch,” he went on. "Infrastructure in this country needs to be upgraded. This project is a great example of how that can be done, even when there are significant challenges, if you bring the right people together.

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ORIGINAL REPORTING: WHAT DOESN'T STAY IN VEGAS: HILLARY CLINTON'S ENERGY POLICY, NV ENERGY'S SOLAR LEASING PLAN, AND MORE

What doesn't stay in Vegas: Hillary Clinton's energy policy, NV Energy's solar leasing plan, and more; Clinton keynotes the National Clean Energy Summit as utility CEOs talk new business models

Herman K. Trabish, September 8, 2014 (Utility Dive)

UD-CES7.0b-09-05-2014 (1)

The U.S. electric grid is changing and some utiliti1es have begun building new business models for the future.

Forward-leaning utilities are already working with state regulators to understand and capture the value of distributed energy resources, according to Presidential Counsel on Climate Change and Energy Policy John Podesta.

“We’ve seen that among the aggressive utilities, but others are now stepping up,” Podesta added in a private conversation on the sidelines at Senator Harry Reid’s seventh annual Clean Energy Summit in Las Vegas.

Partnering to capture new value was the topic of the utility panel at the conference. “Shrinking electricity demand is the new normal,” said Rocky Mountain Institute Co-founder and Chief Scientist Amory Lovins, kicking off a conversation with two leading utility heads. “It has shrunk in five of the last six years and the last three years in a row.”

“There is flat demand but in renewables there is a lot of growth because of coal plant retirements,” replied Sempra U.S. Gas & Power President and CEO Patricia Wagner. “That’s where we see a lot of opportunity.”

“Our ten year residential load growth forecast is about 1% per year but that is largely offset by energy efficiency. So we see a flat growth rate in the residential sector,” agreed NV Energy President and CEO and former Berkshire Hathaway Energy Renewables President Paul Caudill.

But with rooftop solar the growth rate is so “huge” that utilities cannot turn away, Caudill and Wagner agreed.

New customer choices

“As customers figure out they have choices, it’s usually a good idea to offer them what they want before someone else does,” Lovins said. “Of the strategies, 'ostrich' is not a good one. Taxing or charging customers will make them leave the grid faster. You could finance. Or offer rooftop solar as your branded product. Or be an integrator of technically qualified offerings.”

“The cost of rooftop solar is very competitive,” Caudill said. “The decision the consumer has is whether to spend the upfront capital or do a lease with a third party provider. We want to partner with third party providers in the solar business to achieve a win-win for everybody.”

Wagner said Sempra is focused on utility scale solar and large scale storage. It is planning to bid into RFPs in California where investor-owned utilities are moving to meet a first-ever U.S. energy storage mandate that requires 200 megawatts by 2014 and 1.325 gigawatts by 2020.

“Bulk storage and fossil fuel back-up are the most expensive ways to get grid flexibility,” Lovins said. "The cheaper stuff is demand response, efficiency, diversification by type and location, dispatchable renewables, distributed thermal storage, and EVs.”

That is the loading order California established, Wagner agreed, which is why Sempra’s initial participation will be on a small scale. “But we think utility scale renewables are going to be a big part of the mix,” she added.

Utility scale renewables with storage makes more distributed resources possible, Wagner said. “In Maui, our grid connected 21 megawatt wind farm, with 11 megawatts of battery storage, is making it possible for our partner, Maui Electric, to integrate more rooftop solar. I think you will see more of that.”

Lovins asked if the Maui project was part of a micro-grid. It isn’t, Wagner answered. “We are willing to do micro-grids if that is what our customers want but there is a lot of regulation around it.”

Customers’ concerns come first, Caudill agreed. Driven by demand for increased efficiency, NV Energy has moved from smart meters to home energy audit reports and automatic energy use updates.

NV Energy's strategy: Partner with solar leasing companies

The obstacle to NV Energy owning rooftop solar is that “some folks see it ascompetition with commercial market third party providers,” Caudill said. “But the penetration of residential solar is less than 3%. The opportunity is to establish a rate that is fair for all customers. Not everybody can have solar on their roof. Not everybody has a FICO score over 680. We can move forward, provide the opportunity, and partner with third party providers so there aren’t winners and losers.”

Because of solar's peak coincidence, it is conceivable utilities could soon not use any fossil generation on sunny afternoons, Lovins said, and the “inside-out utility” is a way to get there sooner. “Instead of starting by forecasting demand and building generators to meet it and wires to push it out, you start with a distribution planning area,” he explained.

Calculate the end use, then address it with targeted demand side programs, or better distribution service management, or more distributed generation. “Only if none of that is enough do we build more generation.”

“It makes sense to start with the lowest cost solution from the customer’s perspective,” Wagner agreed. “But when you have a big system it might be a little more difficult.”

“Distributed generation is here, Caudill said. “But none of this works if our customers have to pay substantially more. Utilities can’t ask customers to pay an additional $0.50 per kilowatt-hour to $0.60 per kilowatt-hour over the next 10 to 15 years.”

Studies find the benefits of PV for the system are often bigger than their costs, even with little or no accounting for their energy, Lovins replied. “There is a contradiction when some utilities say you can buy green power for a premium and others say they are investing in green power because it is so cost effective.”

Renewables are location dependent, Wagner replied. “They are not created equal.”

The Clinton energy policy takes shape

Those hoping to catch a glimpse of likely presidential candidate Hillary Clinton's energy policy were not disappointed.

“China and other competitors are racing ahead with big bets on renewables,”former Secretary of State Hillary Clinton said in her wide-ranging keynote address. “We cannot afford to cede leadership in this.”

She was even more passionate about opportunities in energy efficiency. “Think of the savings, think of the jobs,” she said. “If utilities become as committed to building new capacity through efficiency as they are through new supply, we really will make progress.”

Just as important, she said, is a smart grid. The soon-to-be unveiled iPhone 6 will plug into an electric grid built in the 1950s that uses 1960s and 1970s technology. “With a 21st century smart grid, we could avoid blackouts that cost businesses and consumers billions of dollars a year. If the public and private sectors put aside politics and come together, we could do this before the iPhone 7 comes out.”

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ORIGINAL REPORTING: HOW NEW TRANSMISSION WILL BRING WYOMING WIND TO CALIFORNIA

How new transmission will bring Wyoming wind to California; President Obama’s transmission plan aims to bring remote renewables to load centers.

Herman K. Trabish, September 10, 2014 (Utility Dive)

The national energy mix is changing and new transmission is helping make it all possible.

Utilities from National Grid to Arizona Public Service are proposing renewables projects made increasingly practical and cost effective by affordable and flexible U.S. natural gas supplies. Only new transmission lines are necessary to deliver high capacity solar and wind resources to load centers that need them.

As Texas Governor, former President George Bush said he spurred his administration to get the state’s now U.S.-leading wind industry started and then turned to "bottlenecks to getting wind to the marketplace." The groundwork was laid for new transmission lines that now deliver over 12,000 megawatts of remote wind power to electricity-hungry Texas cities.

Progress on transmission across the rest of the West, however, has been delayed by jurisdictional and permitting complications.

The implications are global. “The country that harnesses the power of clean, renewable energy will lead the 21st century,” President Obama said last year while signing an executive memorandum that focused the Federal Rapid Response Team for Transmission (RRTT) on seven crucial projects.

“Our project was designated for RRTT attention,” Transwest Express Director of Communications Kara Choquette told Utility Dive.

The Transwest Express — a $3 billion, 3,000 megawatt capacity, 725 mile high voltage direct current (HVDC) line — would carry Wyoming winds with a capacity factor well over 40% along a route through Utah, Colorado, and Nevada. Interconnections in Utah and at the Hoover Dam could take wind-generated electricity as far as Los Angeles.

The hurdles to building transmission

Aimed at streamlining Federal agencies’ permitting, review and consultation procedures, the RRTT was created in 2009 to resolve the kind of delays the Transwest Express faces.

“RRTT has maintained our progress. I don’t know if it has made it faster,” Choquette said. “Where we are today speaks for itself. The original right of way application was filed with the [Bureau of Land Management] in 2007. The final Environmental Impact Study (EIS) should be published by the end of this year. Seven years of permitting. It just takes a long time.”

It was easier and faster in Milford, Utah, where a DC transmission line runs through, carrying the Intermountain Power Plant's coal-generated electricity to Los Angeles. Few people came to the public meeting held there to introduce the Transwest Express, Choquette recalled. “When I asked about the lack of interest, one of them pointed out the window, 'You’re just going to build another one of those. OK. We know what that is.'”

Wherever possible, the Transwest Express was routed along existing transmission lines, highways, or railroads, Choquette said. But Federal agencies like the Bureau of Land Management (BLM), the Bureau of Reclamation, and the Western Area Power Administration (WAPA) are required by the National Environmental Policy Act (NEPA) to consider “a reasonable range of alternatives.”

Along one section of the route, Choquette said, a delay was caused because BLM picked an alternative to Transwest’s proposal. Officials for three separate counties, two in Wyoming and one in Colorado, filed a joint resolution withthe BLM in support of Transwest’s original route. The BLM has reportedly decided, finally, to defer to their preference.

At the most densely populated section of the route in Henderson, Nevada, homeowners came to meetings prepared to vigorously resist a proposed two mile wide corridor that, on maps, looked like it encroached on their properties.

“People thought we wanted the entire corridor,” Choquette said. "Once homeowners realized the route would be inside the corridor on the far side of other existing transmission lines, they were fine with the project.”

Streamlining the process

The National Environmental Policy Act (NEPA) process “serves an important purpose,” American Wind Energy Association Senior Counsel Gene Grace told Utility Dive. “But there are some reforms that could streamline the process without sacrificing its goals.”

A crucial fix, Choquette believes, would be establishing a deadline. “Permitting drives the whole development process," she said. "Our strategy is to de-risk the project for investors by getting it to a higher level of permitting certainty. But making the financial commitment to do all the detailed and expensive planning is riskier when there is no certainty of a fully determined route.”

Wildlife also presents uncertainties. “The rules change,” Choquette said. “When we started, there were no sage grouse corridors in Wyoming. Then they were there in 2009.”

The state of Wyoming has been proactive in wildlife protections, she added. “They realized they needed to both encourage energy infrastructure and protect the best habitat. So they created a transmission corridor next to existing lines and infrastructure. The BLM incorporated Wyoming’s strategy into its sage grouse protection plan.”

Like the Hoover Dam, which went online in 1936 and was “the original renewables project,” Choquette said, “we want to make sure this is done in the right place in the right way from the beginning.”

Not for the faint of heart or wallet

Lines like the Transwest Express were conceived as a way to get great renewable resources to where load was growing and state mandates required them, explained Exeter Associates Principal Kevin Porter, who does transmission research for Lawrence Berkeley National Labs.

But today load is no longer growing and states have met their interim mandates. “Things are pretty tough for transmission right now," Porter said. "The Wyoming wind resource is very good but may not be good enough to support the expense.”

These projects, Choquette said, quoting a Wyoming official, “are not for the faint of heart or the faint of wallet. You persist because it is needed.”

By sourcing a portion of California power from Wyoming wind, “annual generator cost-savings range from around $500 million to around $1 billion,” Choquette said, citing NREL’s California-Wyoming Grid Integration Study. Over a 50 year transmission lifespan, that is billions for California.

While a cost-benefit ratio of 1.1 or 1.2 typically justifies spending for new transmission, Choquette said, the Transwest Express’ ratio would be at least 1.62, according to the NREL study. Factoring in various avoided costs, it could reach a 3.6 cost-benefit ratio.

“These transmission systems are valuable for delivering remote resources that can’t be supplied in any other way,” former Federal Energy Regulatory Commission Chair Jon Wellinghoff told Utility Dive. “The other great thing about them is that, like new subway lines, businesses grow up along them. If you put in these lines, they provide the opportunity for people to site remote central station solar systems and look for nearby wind resource areas.”

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