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Why Toyota’s Next Move Is Solid-State Batteries

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Toyota plans to commercialize solid-state electric vehicle batteries by the early 2020s, Reuters confirmed this week.

If the Japanese automaker can pull that off, it could leap ahead of the competition in terms of energy density, range and safety.

Toyota popularized the turn away from internal-combustion engines with its Prius hybrid, but its clean transport innovation has slowed in recent years. The company maintained focus on hybrids and hydrogen fuel-cell cars, which other EV makers tend to dismiss as dead ends.

That policy came to an end late last year when Toyota launched an internal venture dedicated to commercializing a purely electric car. “Japanese automakers finally wise up to the electric future” was how auto blog Jalopnik reported that decision.

With Tesla, BMW, Nissan and Chevy scaling up EV production already, Toyota will have to hustle to catch up, and solid-state could certainly help. This advance represents something of a holy grail for battery makers, and has been notoriously hard to pull off.

First, here’s the science of why we need solid-state in the first place, as told to me by Josh Garrett, CTO of Solid Power, which makes solid-state electrolytes.

“One of the main challenges with lithium-ion type technologies is, you can increase the energy and power, or you can improve or maintain your safety, but you can’t do both,” he said. “Solid-state is really the one known viable path toward increasing both at the same time.”

Solid-state’s safety properties could unlock a lithium-metal anode, which represents the chemical ideal in terms of how much charge it can store per unit of mass and volume. It’s also highly volatile, as one may recall from dropping it into a beaker of water in chemistry class and watching it catch fire.

If you put a lithium-metal anode into the kind of battery cell made today, it suffers from uneven plating, which produces spiky protuberances known as dendrites. If a dendrite continues to grow, it can shoot across the cell’s protective barrier layer and touch the positive electrode, causing a short, Garrett said. That generates lot of heat.

“The combination of your volatile electrolyte with the cathode materials, which are typically unstable and also contain oxygen, basically creates these thermal runaway reactions, and that’s when you have a fire that you’re probably not going to put out for a while,” he explained.

Not a good look for mass-market consumer cars.

In solid-state, theory predicts more even plating, so dendrites shouldn’t be much of a problem in the first place, Garrett said. If they do form, the more inert, non-volatile electrolyte denies the fuel that would stoke a fire. The individual cell could get hot and be ruined, but it will be “a very uneventful failure.”

That’s the quick version, at least. Many fine peer-reviewed publications beckon with the fully fleshed-out details.

It’s important to note that actually achieving this vision will take a lot of lab work. One of many challenges is securing perfect contact for the flow of ions. A liquid electrolyte conforms easily to the electrodes, because it’s a liquid against a solid. Two solids, not so much.

“Imagine two marbles put together: There’s only going to be point contacts, and that really limits where the ions can travel between the electrolyte and the electrode,” Garrett said.

As always with batteries, optimizing one characteristic, like connectivity or stability, can affect other aspects of performance. The key is achieving across-the-board improvements without sacrificing the necessities.

Solid Power, for now, is trying to commercialize its solid electrolyte combined with a lithium-metal anode and a more conventional nickel-manganese-cobalt lithium-ion chemistry. This design can produce an energy density increase of one-quarter to one-third at the cell level, compared to the cells in a Tesla Model S, Garrett estimated; additional gains are expected at the pack level.

Nobody has started mass-manufacturing solid-state rechargeable batteries yet, he noted — but Toyota has assembled considerable resources behind that goal. The company is paying particular attention to the pack- and system-level improvements made possible by solid-state technology, which can then influence overall vehicle design.

Toyota will have to hustle to meet the early 2020s deadline, but the science is clear about what the payoff will be. Autonomous driving has been garnering considerable attention, but solid-state batteries could become the new automaker arms race to watch.


source: http://feeds.greentechmedia.com/~r/GreentechMedia/~3/ULyHABNw-LE/toyotas-next-move-solid-state-batteries

Be the first to comment - What do you think?  Posted by Editor - July 31, 2017 at 6:20 am

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Having Fewer Offshore Wind Equipment Manufacturers May Be a Good Thing

In most industries, the presence of a healthy number of original equipment manufacturers (OEMs) can increase competition and cut costs. That may not hold true in offshore wind.

Because offshore wind cost reduction is heavily dependent on experience, it could be an advantage to only have a handful of OEMs, said Jonny Allen, underwriter at the renewable energy insurance firm GCube.

“We’ve seen a wide range of expertise being utilized for offshore wind, and that’s produced a very stark contrast in performance,” he said. “For any new entrant to get into offshore successfully, the experience and balance sheet of contractors is going to be absolutely key.” 

Maximizing offshore wind plant profits is achieved by picking teams that already know the ropes, he said. In terms of OEM selection, that means eliminating from consideration companies beyond the top tier of turbine makers. As it is, there isn’t much to choose from.

According to the European wind industry association WindEurope, at the end of 2016, just one OEM, Germany’s Siemens Wind Power, accounted for nearly 69 percent of all offshore capacity, with almost 8.6 gigawatts of generation installed.

Trailing behind it were Denmark’s MHI Vestas Offshore, with more than 2 gigawatts and 16 percent of the market; then Senvion of Germany, with 783 megawatts and just over 6 percent; and Adwen of Spain, with 660 megawatts and around 5 percent.

Three other OEMs, including GE Renewable Energy, offshore wind development pioneer BARD and former Finnish manufacturer WinWinD, accounted for a meager 4 percent of capacity, or 502 megawatts, between them. 

It seems unlikely that other OEMs could now enter the market without having to charge a premium, putting them at a severe disadvantage.

At the same time, offshore wind developers are likely to put a dual emphasis on high quality and low costs as a way of meeting highly aggressive cost-reduction targets. 

Experience is not just key when it comes to selecting OEMs. It’s also important for project development teams, Allen said.

Poorly performing projects have been developed by companies that were either too small to have a well-rounded team, or too large to have a tight focus on offshore wind development, he said.

Skills and experience are extremely important for an insurance company like GCube, which provides cover for more than 30 gigawatts of wind generation worldwide. GCube actively tracks what happens to people who have worked on plants with suboptimal track records, Allen revealed.

Similarly, offshore wind farm performance tends to improve when the team that built the project remains on board to oversee its operations and maintenance.

“Where we’ve seen issues is when one part of an organization builds a wind farm and then new personnel comes in,” said Allen. “Those companies that develop and continue to operate [the plant] tend to have better availability, and the performance of the asset is better.”

There are two other factors that GCube identifies as important for success in offshore wind. One is spending time and money on site assessments and other planning activities.

In Europe, for example, some German projects had seen large development overruns after unexploded ordnances were discovered on the seabed during construction.

The other success factor is relying on outside support for the creation of a competitive supply chain.

“Investment and support, especially from government and trade bodies, is key to giving developers efficient and economic access to the local supply chain, whether this be skills, resources or direct manufacturing,” said Allen. “China is a good example of this utilization, which could be replicated in other industrial powerhouses, such as France and India, both of which we will be closely monitoring in the coming years.” 


source: http://feeds.greentechmedia.com/~r/GreentechMedia/~3/f70QuPzP0ks/why-having-few-offshore-wind-turbine-manufacturers-may-be-good

Be the first to comment - What do you think?  Posted by Editor - at 6:10 am

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Australia to Build One of World’s Longest EV Highways

By Joshua Robertson, The Guardian

Queensland will have a 1,200 mile (2,000 km) network of electric vehicle charging stations that make up one of the world’s longest electric vehicle highways within six months.

The state government announced on Thursday it would build an 18-station network stretching along Queensland’s east coast from Cairns to Coolangatta and west to Toowoomba.

The stations, which recharge a vehicle in 30 minutes, will offer free power for at least a year in what the environment minister, Steven Miles, said was a bid to boost the number of electric cars on Queensland roads, currently about 700.

“This project is ambitious, but we want as many people as possible on board the electric vehicle revolution, as part of our transition to a low-emissions future,” Miles said.

Busy highway lights.
Credit: Ramon Llorensi/flickr

The $3 million network had “the potential to revolutionize the way we travel around Queensland in the future”, he said.

Queensland’s “electric highway” will span a comparable distance to the “west coast electric highway” in the U.S., which runs from California to Oregon and Washington state. However it is dwarfed by the Trans-Canada EV highway, which, at about 5,000 miles (8,000 km), is the world’s longest.

But the U.S. in total now boasts 16,107 stations and 43,828 charging outlets, according to the U.S. Department of Energy. Tesla drivers can reputedly make journeys of 12,500 miles (20,000 km).

The Queensland stations, which will range from the capital Brisbane to the small sugar town of Tully, would be powered with “green energy” bought through renewable energy credits or offsets.

Miles said a state household energy survey showed half of Queenslanders would consider “an electric vehicle, plug-in hybrid or regenerative braking hybrid” when buying a new car in the next two years.

While lower prices and longer-lasting batteries were driving global uptake, most in the survey said “improvements to public fast-charging infrastructure would further tempt them into purchasing an EV”, Miles said.

Car executives from Audi, BMW, Hyundai, Jaguar Land Rover, Mercedes Benz and Mitsubishi lined up to praise the move and called on other states to follow.

The Audi Australia managing director, Paul Sansom, said electric car drivers travelling “the vast distances in between our capital cities … need to have confidence that they will be able to find a charging station when they need it, even if they’re driving in an unfamiliar region”.

“This is the current expectation around frequency of petrol stations, and it’s, rightly, what consumers will demand as EVs become more prevalent.”

Behyad Jafari, the chief executive of the Electric Vehicle Council, said the state government had shown “national leadership” with “a signal to the market that Queensland is serious about electric vehicles”.

This gave the industry “certainty to unlock investment to grow our economy and create new, high skilled jobs”, he said.

“I encourage all governments across Australia to follow suit, particularly as this support will help to provide motorists with increased choice of cars that are cheaper and healthier to operate.”

Queensland is Australia’s biggest carbon polluter, with the transport sector making up the state’s second largest source of carbon emissions with 21.1m tonnes in 2014, having almost doubled since 1990.

Passenger cars make up almost half of transport emissions, according to the state environment department.

The $3m contract to build the network has been awarded to Brisbane technology company Tritium, which began as a solar car racing parts manufacturer.

Reprinted with permission from The Guardian.


source: http://feedproxy.google.com/~r/ClimateCentral-News/~3/YDQAtCayIuM/australia-one-of-worlds-longest-ev-highways-21656

Be the first to comment - What do you think?  Posted by Editor - at 6:00 am

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NRG and Direct Energy Couldn’t Make Residential Solar Work. What Does It Teach Us? [GTM Squared]


source: http://feeds.greentechmedia.com/~r/GreentechMedia/~3/x8XAwYMetnc/nrg-and-direct-energy-couldnt-make-residential-solar-work

Be the first to comment - What do you think?  Posted by Editor - July 30, 2017 at 6:30 am

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The Top Utility Regulation Trends of 2017—So Far

Back in December, Advanced Energy Economy published a list of the top 10 public utility commission actions of 2016. With 2017 halfway done, we wanted check in on the top public utility commission actions so far this year.

Not surprisingly, the challenges PUCs are grappling with are wide-ranging and diverse: sweeping changes in rate design, utility business model reforms, grid modernization investments, distribution system planning, electric vehicle charging infrastructure and rates, renewable energy tariffs, and interconnection requests, to name a few. Without further ado, here is a status check of the top 10 matters before PUCs in 2017 — so far. 

1. Foundational investments for a modern grid

At its core, grid modernization is about investing in grid-facing and customer capabilities that enable a two-way communication system between the end user and the utility and that facilitate the seamless integration of distributed assets into the grid. So far in 2017, several utilities have proposed grid modernization plans, while a few states have begun broader conversations to overhaul their systems.

In February, the Public Utilities Commission of Ohio approved AEP Ohio’s Phase 2 gridSMART project, which among other things includes the installation of almost 900,000 smart meters by 2021, a $20 million investment in volt/VAR technology, and the installation of distribution automation circuit reconfiguration. In April, PUCO also opened an initiative called PowerForward to review potential regulatory policies and technological innovations that could modernize the grid and enhance the customer electricity experience.

In February, Vectren in Indiana filed a $500 million, seven-year grid modernization plan that includes investments in distribution automation technology, advanced metering infrastructure and an advanced distribution management system. Also in February, Orange and Rockland Utilities in New York filed an application that included an expansion of its existing AMI roll-out to a full deployment for an additional $98 million.

In May, Entergy Mississippi received approval to deploy advanced meters, as well as a two-way communications network, a meter data management system, an outage management system and a distribution management system for all of their residential and commercial customers.

And in June, Hawaiian Electric Co. filed a revised $205 million draft grid modernization plan (they are expected to release the final plan on August 29) that includes a targeted smart meter deployment, the installation of advanced inverters to enable private rooftop solar adoption and the expansion of their communication network to increase visibility into its distribution system.

2. Distribution system planning in a distributed energy future

Rapid improvement in advanced energy technologies and an influx of distributed energy resources (DERs) — such as solar PV, combined heat and power, demand response, energy efficiency, energy storage, fuel cells and electric vehicles — have led states to reconsider how they undertake distribution-level resource planning. By expanding distribution planning to consider DERs, in addition to traditional infrastructure investments, and by properly valuing DERs for both the benefits and costs they provide, the grid can become more flexible, reliable, resilient and clean, all while saving money for customers.

New York, California and Hawaii have been busy on this front for a couple of years, but now several other states are also getting into the game. In April, the Minnesota Public Utilities Commission issued a distribution system planning questionnaire in its grid modernization proceeding. The questionnaire sought input from stakeholders (AEE Institute submitted comments) to identify potential improvements in utility planning processes, especially in regard to the growth of DERs.

Also in April, the Rhode Island Public Utilities Commission, Division of Public Utilities, and the Office of Energy Resources started a modernization initiative called Power Sector Transformation. AEE Institute and our state partner, the Northeast Clean Energy Council (NECEC) submitted joint comments.

In June, United Illuminating Co. and Connecticut Light and Power Co. submitted DER integration pilot plans as required by Connecticut Public Act 15-5. Their pilot plans include demonstration projects on hosting capacity analysis maps to provide customers and third parties more transparency into their distribution systems. They also include DER and load forecasting to inform distribution system planning, and a DER portal and management system to facilitate the two-way sharing of information between customers and the utility.

Also in June, DTE Electric Company filed a draft five-year distribution system maintenance and investment plan as required by the Michigan Public Service Commission in its most recent rate case. Keep an eye out for Consumers Energgy’s draft distribution system plan, which the utility is expected to file by August 1. 

3. No lack of regulatory activity in the Golden State

The California Public Utilities Commission (CPUC) is laying the foundation for numerous regulatory reform initiatives (including several transportation electrification proposals, which will be discussed separately). However, a couple of actions stand above the rest.

In May, the CPUC issued a staff proposal to build on the existing long-term procurement planning  process and adopt a process for integrated resource planning (IRP), as California grapples with the challenges inherent in a changing electricity system. The IRP is intended to optimize the state’s electricity suppliers’ resources and help in meeting the state’s policy goals — most notably the economy-wide greenhouse gas emissions reduction goal of 40 percent from 1990 levels by 2030. AEE has been involved throughout this process and has submitted initial comments and reply comments to the commission.

The closely related Integrated Distributed Energy Resources (IDER) and Distribution Resource Plan (DRP) proceedings have been in a working group phase during the first half of 2017. The Distribution Planning Advisory Group (a spinoff from the IDER proceeding) has been meeting to work on a program to test Commissioner Florio’s regulatory incentive proposal and value DERs. California’s locational net benefits analysis and the integration capacity analysis working groups (spinoffs from the DRP proceeding) submitted reports in March on improvements to the methodologies for DRP demonstration projects. The working groups also submitted reports on near-term improvements to the locational net benefits analysis and integration capacity analysis methodologies, as well as other topics that should be considered for longer-term refinement.

Also in May, commission staff released a grid modernization white paper as part of the DRP proceeding to evaluate investments to support DERs. And in June, commission staff issued a proposal on a distribution investment deferral framework to establish a process to identify, review and select opportunities for third-party-owned DERs to defer traditional poles and wires investments. 

4. New York: Valuing DERs and implementing distribution system planning

New York has continued to make waves with its Reforming the Energy Vision proceeding and several additional proceedings that have spawned as a result. One of which is the Value of DERs proceeding, where the commission in March adopted an interim methodology for valuing DERs. Specifically, the order maintains net metering for existing solar customers until January 1, 2020, and then slowly reduces the compensation for new solar users from the retail rate toward a “value stack” methodology that is based on the utility’s avoided costs and other DER values (including wholesale, distribution and environmental benefits).

The New York Public Service Commission has also been busy refining the utilities’ distributed system implementation plans (DSIPs), which were required by the REV Track Two order in May 2016. Initial utility-specific plans were filed last summer (by Con EdisonCentral HudsonNational GridOrange and Rockland and New York State Electric and Gas and Rochester Gas and Electric), with the utilities jointly filing a supplemental DSIP in the fall, and a joint filing and supplemental filing on identifying and sourcing non-wires alternative projects that were submitted this past March and May, respectively. The DSIPs are one of the most important components of the REV process, as they could ultimately transform how utilities plan. Specifically, DSIPs are intended to outline how utilities plan to modernize their distribution grids and integrate a higher penetration of DERs, both of which will facilitate increased participation by third parties in a distributed marketplace.

And in March, the PSC, working with the New York State Energy Research and Development Authority, filed a final Phase 1 Implementation Plan for Gov. Cuomo’s Clean Energy Standard mandate of 50 percent renewable energy by 2030. 

5. Addressing shortcomings in the cost-of-service regulatory model

The traditional cost-of-service regulatory model worked well over the past century because it incentivized utilities to build out our electric infrastructure, while increasing sales allowed these costs to be spread out over a growing customer base. However, new trends are threatening to undermine the existing model and have led policymakers and other stakeholders to explore redefining how utilities can make a profit.

In March, the New Mexico Public Regulation Commission initiated an investigation into its ratemaking policies, considering possible positive and negative financial incentives and re-examining how regulated assets should be defined and their costs recovered. In March, the Pennsylvania Public Utility Commission pushed forward in its alternative ratemaking investigation, asking for feedback on experiences with different methodologies, including performance-based regulation (AEE Institute filed comments here). And in June, the Vermont Public Utility Commission opened an investigation to review emerging trends in the utility sector and examine if changes should be made in how utilities are regulated.

Over the past year, the New Hampshire Public Utilities Commission has been investigating utility cost recovery and financial incentives. In March, a working group submitted its final report to the commission, recommending, among other things, the implementation of performance-based regulation. In May, as part of Rhode Island’s Power Sector Transformation, Rhode Island regulators held a workshop and issued a request for stakeholder comment on utility business model reforms and how financial incentives can shape policy outcomes (AEE Institute and NECEC submitted joint comments).

And in May, the Michigan Public Service Commission initiated a proceeding to evaluate potential changes to cost recovery for utility demand response programs. Specifically, the MPSC is developing a framework for the evaluation and cost recovery of DR investments, including potentially giving utilities an opportunity to earn a return on demand response investments. In addition, the MPSC held a kickoff meeting on July 24 to begin a broader performance-based regulation study, with a commission report due to the legislature in April 2018. 

6. Fixed charges, demand charges and time-varying rates

Rate design has continued to be a hot-button issue in 2017, as utilities look for new ways to recover their costs in a changing energy landscape of low load growth and more DERs. As a result, PUCs have been looking for rate designs that fairly value DERs, allow utilities a reasonable opportunity to collect their costs, equitably allocate costs across and within customer classes, and send price signals to customers that align with public policy goals. Some of the designs that have been adopted have served some of those purposes more than others.   

In May, the California Public Utilities Commission issued a proposed decision adopting San Diego Gas & Electric’s new residential time-of-use (TOU) rate designs with a later-in-the-day on-peak period (3 p.m. to 9 p.m.) and a spring super off-peak period (10 a.m. to 2 p.m. on weekdays in March and April). In February, the Arizona Corporation Commission approved a 30 percent increase in Tucson Electric Power’s residential fixed charge. However, TEP also received approval for a more sophisticated TOU rate design with a plan to make the rates default for new customers starting in 2018. TEP’s TOU rate plan is just one example of the broader move toward rates that better align with the costs of operating the grid.

Unfortunately, the fixed-charge trend still persists, despite some setbacks. Higher fixed charges secure utility revenues but fail to accomplish the other goals listed above, and recent proposals in this arena have largely been denied or significantly reduced. In March, Oklahoma Gas and Electric was denied its bid to double the residential fixed charge and add a demand charge for mass-market customers. Also in March, Duke Energy Ohio proposed a transition to a straight-fixed variable rate (a structure founded on the principle that fixed costs are recovered through the fixed charge and only variable costs are recovered through variable charges) for residential customers, which would increase the residential fixed charge from $6 to $22.77 per month and increase the low-income fixed charge from $2 to $18.77 per month. And in June, Duke Energy Progress in North Carolina proposed a 75 percent increase in the residential fixed charge in its new rate case.

Utilities have also been actively considering new rate designs exclusively for distributed generation (DG) customers — a contentious issue for many in the industry. DG advocates have countered that these new rate designs, especially demand charges, have been proposed without demonstrating a cost shift and would undercut DG’s value proposition and hinder adoption.

In January, Eversource Energy in Massachusetts proposed a new optional TOU rate for small general-service customers, as well as a new three-part rate (with a fixed charge, a variable charge and a non-coincident demand charge based on the minimum system cost of service) for new distributed generation customers, which it called a monthly minimum reliability contribution charge. In February, El Paso Electric in Texas asked for a separate rate class for residential DG customers with a three-part rate design and a TOU rate and an optional three-part rate design for residential customers. And in March, Oncor Electric Delivery Company in Texas proposed a minimum bill (based on the customer’s non-coincident peak demand) for the delivery component of a DER customer’s bill.

7. Changes in retail-rate net energy metering

Whereas increases in the fixed charge or demand charge component of a bill lowers the level of DER compensation under net energy metering indirectly, pressure is increasing in some states to consider changes in net metering itself.

In January, the Maine Public Utilities Commission approved revisions to its NEM rules, grandfathering existing customers under current rates for 15 years and establishing a 10-year transition period, with new DG customers in each subsequent year compensated slightly less than those who signed up the year before. This transitional approach is intended to maintain the same payback period for rooftop solar customers by slowly reducing the incentive level as the cost of rooftop solar declines.

In March, Arizona Public Service filed a settlement agreement that follows the same general principle, grandfathering existing NEM customers for 20 years and establishing a transitional step-down rate for new customers. In May, Indiana passed a bill reducing its NEM rate for new customers over the next five years until it is close to the utility avoided-cost rate. And in June, Nevada passed a net metering bill that immediately restored net metering, albeit at a slightly lower rate (and with compensation declining, ultimately to 75 percent of the retail price, as adoption increases). The decision finally put to rest a contentious debate that raged throughout 2016.

In March, Arkansas adopted changes to its net metering rules, adding a 25-kilowatt cap for residential customers and a 300-kilowatt cap for non-residential customers, with longer-term changes to net metering still to come. In June, the New Hampshire Public Utilities Commission lifted its 100-megawatt NEM cap, grandfathered existing customers through 2040, and reduced the NEM credit for new customers to full retail energy and transmission rates but just 25 percent of the distribution rate. Finally, in April, the Connecticut Public Utilities Regulatory Authority suspended its open docket on broader rate-design reforms until the completion of a new docket to value the costs and benefits of DERs and evaluate the potential for new rate methodologies for DG customers.

8. Electric-vehicle charging infrastructure and rates

The rise in electric-vehicle adoption, spurred by falling EV prices, more extended-range EV options and the expansion of public EV charging stations, has led many states to look at time-of-use EV rates that more closely align with the costs of operating the grid. They’ve also started to grapple with whether regulated utility companies should be allowed to own and operate EV charging stations in competitive markets.

In January, San Diego Gas & Electric, Pacific Gas & Electric and Southern California Edison filed transportation electrification proposals with the California Public Utilities Commission. SDG&E filed a $244 million proposal, which includes $18 million for six priority review pilots on charging infrastructure and EV education and incentives (with a decision expected in October) and $225 million for 90,000 residential charging stations (with a decision expected in April 2018). PG&E filed a $253 million proposal, which includes $20 million for five priority review pilots and $233 million for two five-year charging station buildouts. SCE filed a $573 million proposal, which includes $19 million for six priority review pilots and $553 million for a medium- and heavy-duty charging infrastructure program.

In May, Chairman Gladys Brown of the Pennsylvania Public Utility Commission filed a motion initiating an investigation to review the statewide rules and utility tariffs pertaining to third-party EV charging stations. Ameren continued a back and forth with the Missouri Public Service Commission about installing six EV charging stations that started in August 2016. After initially being rejected in October, with the commission citing a discriminatory charging rate, Ameren filed a revised tariff, which was again rejected in April. This time the commission justified its decision by saying that the commission does not have jurisdiction to regulate utility-owned EV charging stations. However, Ameren did not give up without a fight, and in May the utility filed for a rehearing. But in June, it was once again denied, putting the issue to rest.

Several other utilities have also proposed pilots. In April, Pepco in the District of Columbia proposed a $1.6 million EV pilot program through 2019 to test incentives and evaluate and obtain information on potential EV impacts on the distribution system. In April, Gulf Power Company in Florida received approval in its recent rate case for a revenue-neutral EV pilot program. And in June, the Utah Public Service Commission authorized an EV incentive and TOU pilot program for Rocky Mountain Power.

9. Renewable energy tariffs

As renewable energy has become more competitive on price and corporations have increasingly set sustainability targets, more companies are looking for 100 percent percent renewable energy offerings. To give these corporate customers the renewable energy they want, utilities in vertically integrated markets are turning to renewable energy tariffs.

In February, the Minnesota Public Utilities Commission approved two pilot programs — Renewable*Connect and Renewable*Connect Government — proposed by Xcel Energy. Renewable*Connect is a 75-megawatt program open to all customers, but aimed at large businesses that want access to renewable energy (and the associated renewable energy credits). The Renewable*Connect Government pilot, on the other hand, will power the State Capitol Building, Senate Building and State Office Building with an additional 3.3 megawatts of renewable energy.

In May, Dominion in Virginia filed an application for six voluntary renewable energy tariffs, collectively called Schedule Continuous Renewable Generation. While offering greater access to renewable energy, the Dominion proposal would have significant ramifications for renewable energy developers. Virginia law allows customers to obtain renewable energy from non-utility companies if the incumbent utility does not offer a 100 percent renewables option — a right recently affirmed in a State Corporation Commission decision involving Direct Energy. But if the Dominion proposal is approved, its 100 percent offering would give Dominion the exclusive right to sell renewable energy in its service territory, and competitive suppliers would be boxed out of the market.

Also in May, Consumers Energy Company in Michigan filed an application for a three-year, voluntary large-customer renewable energy pilot program. The program includes two options to allow the customer more flexibility, a subscription-based program, which allows multiple customers to get part of the output of renewable energy facilities, and a “sleeved” power-purchase agreement program, under which large purchasers contract for power from a specific facility through the utility.

10. Qualifying facilities under PURPA

Though decades old, the Public Utility Regulatory Policies Act (PURPA) of 1978 has created some new tensions. PURPA requires utilities to purchase power from qualifying facilities (QFs) — non-fossil fuel small power producers or co-generation facilities — at predetermined rates if the QF’s costs are less than the utility’s own avoided cost (the cost the utility would have incurred to supply the power itself or obtain it from another source). Now, as prices for QFs have fallen (either because of the wind and/or solar potential in certain regions, favorable incentives, or any combination of the two), certain states are facing an influx of interconnection requests.

As a result, some utilities say they are getting stuck with long-term contracts from QFs that are increasing their costs and possibly reducing their reliability. Renewable energy developers and advocates counter that slashing contract terms and reducing PURPA rates would make it impossible for them to obtain financing and would deprive ratepayers of the benefits of a more diverse resource portfolio. The end result has been a flurry of contested proceedings around the country.

In April, the South Carolina Public Service Commission adopted a settlement agreement in South Carolina Electric & Gas’ annual avoided-costs proceeding, resulting in a 70 percent decrease in avoided capacity costs governing power purchases under PURPA. In May, Rocky Mountain Power in Wyoming proposed to cut almost in half the rates they pay QFs, decreasing its 20-year levelized avoided-cost price from $52.15 per MWh to $31.48 per megawatt-hour. And in June, Portland General Electric filed a petition with the Oregon Public Utility Commission to modify its contacts with QFs. Specifically, PGE asked the commission to lower the eligibility cap for solar QFs from 10 megawatts to 3 megawatts, and to either declare a solar QF above 100-kilowatt capacity ineligible if the owner already owns QFs for more than 10 megawatts of solar or lower the eligibility cap for solar QFs to 2 MW.

For a full rundown of recent state PUC PURPA petitions and investigations, see the table below.

Recent State PUC PURPA Petitions and Investigations

Idaho

Idaho Power’s AVU-E-15-01 and IPC-E-17-01, and Rocky Mountain Power’s petition PAC-E-15-03

Montana

Northwestern Energy’s D2016.6.39 and Greycliff Wind Prime’s petition D2015.8.64

North Carolina

Duke Energy’s petition E-100 Sub 148

Oregon

Pacific Power’s UM 1734 and Portal General Electric petition UM 1854

South Carolina

South Carolina Electric and Gas Company’s petition in 2017-2-E

Utah

Rocky Mountain Power’s petition 15-035-53

Washington

The Utilities and Transportation Commission’s investigation: U-161024

Wyoming

Rocky Mountain Power’s petitions 14220 and 14736

***

This post originally appeared on blog.aee.net and was republished with permission from Advanced Energy Economy. Links this post reference documents in AEE’s policy-tracking software platform, PowerSuite. Click here to learn more.


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Species Invasions and Global Warming a ‘Deadly Duo’

By Damian Carrington, The Guardian

Invasions by alien species and global warming form a “deadly duo”, scientists have warned, with the march of Argentine ants in the UK a new example. The public are being asked to be on alert for invaders such as the raccoon dog and Asian hornet, as eradication can be near impossible after a species becomes established.

As trade and human travel has become globalised many thousands of species have crossed oceans or mountain ranges and become established in new regions, with some causing “invasional meltdown” and over a trillion of dollars of damage a year.

Argentine ants are marching into the UK as the world warms.
Credit: Matthew Townsend/flickr

Scientists from around the world are gathering this week in Durham, UK, to assess the issue. Prof Rob Colautti of Queens University in Canada warned: “There are very clear economic and human health consequences.”

The combination of invasive alien species and climate change was a “deadly duo”, said Prof Helen Roy, at the UK’s Centre for Ecology and Hydrology: “Changing climate might facilitate the establishment of some species that otherwise might not have been able to establish.”

“For example, the Argentine ant is a species that we know has some indoor populations in London [and elsewhere], but in the last couple of years we have seen those indoor populations spread outdoors,” she said. “A little bit more climate warming for the UK and we could see the Argentine ant settling in very well.”

“Of all the non-native species, than ants are concerning,” Roy said. “We describe the Argentine ant as an ‘ecosystem engineer’, because it has quite far-reaching, cascading impacts.” Displacing native ants can upset delicate ecosystems of plants and insects, while the Argentine ants themselves are attracted to warm places and can interfere with electrical wiring.

Furthermore, Roy said, Argentine ants can form “super colonies” in invaded regions, as they are not kept in check by the neighbouring colonies that are present in its native south America: “That seems to have broken down in the invaded range. You get these much larger populations of these ants than you would in other places.”

Asian hornet, an invasive species.
Credit: Gilles San Martin/flickr

The UK, like other islands including New Zealand and Japan, is a hotspot for invasive species. Prof Mark van Kleunen, at Konstanz University in Germany, said. “For islands, the hypothesis is that islands have fewer native species than mainland regions, which means there is more ecological space that can be filled by newcomers.” But he noted many UK alien species have been present since the middle ages: “Your rabbit came from the Iberian peninsula.”

The UK suffers billions of pounds in economic damage every year from well established invaders, such as Japanese knotweed, giant hogweed and mink. The harlequin ladybird is a newer invader, first seen in 2004, but now makes up 80-90% of all ladybirds seen in England and seven of the eight native species have declined since it arrived.

“We know that the harlequin ladybird is fantastic at eating aphids, so we might imagine it is going to be fantastic at pest control for farmers,” said Roy. But she said native ladybirds had their own roles and that variety is crucial to a resilient ecosystem: “Some [natives] emerge earlier in the spring, others get up earlier in the morning.”

The arrival of the quagga mussel in the UK in 2014 prompted warnings of the “invasional meltdown” seen elsewhere, where entire ecosystems are transformed. “It changes the whole chemistry and physical nature of a water body,” said Roy. In North America, the spread of the zebra mussel has caused enormous damage.

The quagga mussel was the number one threat on a list compiled by Roy and colleagues. Also high on the list are the Asian longhorn beetle, American lobster, African sacred ibis and the Emerald ash borer beetle, as well as the Argentine ant. The Asian hornet was first spotted in the UK in September, but was eradicated.

However, Roy said people should remain on the lookout and could report sightings using an app: “We know there are high numbers in France and that is not far away.” She also said raccoons have been sighted in the UK, and should also be reported, along with any sighting of raccoon dogs, an unrelated species from Asia that were once sold as pets.

The scientists said it was often impossible to get rid of an invader once established, like the grey squirrel, making prevention using checks and information provision at borders even more important.

“There are some very simple measures that can be put in place to provide biosecurity to prevent the arrival of the most damaging species,” said Roy. “It is not about stopping people moving or trading.”

Reprinted with permission from The Guardian.


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Wildfire Season Is Scorching the West

The West is ablaze as the summer wildfire season has gotten off to an intense start. More than 37,000 fires have burned more than 5.2 million acres nationally since the beginning of the year, with 47 large fires burning across nine states as of Friday.

Smoke rises from the Goodwin Fire, which burned more than 28,000 acres in Arizona through mid-July.
Credit: Prescott National Forest/flickr

The relatively early activity is quickly becoming the norm, with rising temperatures making the fire season longer than it used to be. The warming fueled by greenhouse gases is also helping to create more and larger fires as it dries out more vegetation that acts as fuel for fires.

This new fire situation means that western states need to be begin to rethink how they prepare for and combat fires, as well as how fire-prone land is developed.

Five large fires (those of 1,000 acres or more) are currently raging across California, the largest of which is the Detwiler fire near Yosemite National Park, which has burned more than 80,000 acres since it ignited on July 16. That fire is now 75 percent contained, but it destroyed dozens of buildings, including 63 homes.

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Montana currently has the most large fires of any state, with 14, including the massive Lodgepole Complex fire (a series of smaller fires that merged into one), which has burned more than 270,000 acres in the eastern portion of the state. That fire is also well-contained, but has burned through tens of thousands of acres of rangeland, displacing thousands of cattle and burning several structures. An intense drought there has rapidly cured the grasses that have fueled the fires.

Oregon has seven large fires burning, while Nevada has six and Idaho five.

Scorching temperatures and dry conditions in recent weeks have helped fuel these fires across the region, which have burned 2 million more acres than at this point in last year’s wildfire season.

Compared to the 10-year average of wildfire activity, this year is below average for the number of fires, but above average for the total number of acres burned. A very active wildfire season in the Central Plains pushed up the acres burned; a wet winter meant grasslands were ripe with fuel, and once hot and dry weather came and fires ignited, they could take off more quickly than fires that burn through forested areas, Robin Broyles, a spokesperson for the National Interagency Fire Center, said.

A 2016 Climate Central analysis showed that the annual number of large fires has tripled since the 1970s and that the amount of land they burn is six times higher than it was four decades ago.

Number of wildfires in these states

While multiple factors, including land use and tree disease, influence fire activity, climate change is playing a role in those trends. A study published in October found that rising temperatures accounted for nearly half of the increase in acres burned, as they helped to dry out forests and extend the length of the fire season.

The fire season is 105 days longer than it was in the 1970s, the Climate Central analysis found.

The lengthening of the fire season has become clear in California, which usually didn’t see major fires until the Santa Ana winds kicked in in the fall and vegetation had dried out over several months.

Now bouts of hot, dry weather are coming earlier and earlier, setting the stage for prime fire conditions. Southern California already has a nearly year-round fire season, Scott Stephens, a professor of fire science at the University of California, Berkeley, said.

With those hot periods likely coming earlier and earlier in spring and summer as global temperatures continue to rise, “you’re going to have a longer period where fire can ignite and move,” Stephens said.

Acres burned by wildfires in these states

While the past few years in California have seen wildfires fueled by the record-setting drought in the state that killed off swaths of trees, this fire season has been helped by the opposite conditions. Ample winter rains allowed grasslands to flourish, so when hot, dry conditions came in June, those grasses were quickly cured into perfect fire fuel, Stephens said.

With the shifts in the fire season, policymakers and fire managers may have to begin to rethink some of their strategies for preventing fires, particularly as the longer fire season eats into the time that managers have to conduct prescribed burns to burn up potential fuel, Stephens said. Areas may also have to do more prescribed burns during drought years, to reduce fuel loads, he said.

Funding for firefighting — the costs of which have topped $1 billion in 12 of the past 15 years — may also have to be rethought. Instead of having a seasonal firefighting team, funding may have to be put in place for a year-round one, Stephens said.

Hot and dry conditions are expected to persist across the West over the next few days, which could help more fires start and spread. Areas in the path of next month’s solar eclipse, particularly drought-plagued Montana, are also concerned about the influx of eclipse watchers who may not be aware of the fire danger or the precautions they’ll need to take in order to avoid accidentally setting one.

“It’s really important that people recognize” that danger and are aware of the various fire restrictions in place, Broyles said.

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VW, in Settlement, to Build Electric Vehicle Stations

Volkswagen will build a massive network of electric vehicle charging stations across California as part of a settlement over its diesel emissions scandal.

The California Air Resources Board has voted unanimously to approve the $200 million plan as the first of a number of steps the German automaker has proposed to take to help cut greenhouse gas emissions in California. In total, the company has agreed to spend $800 million on zero-emissions electric vehicle infrastructure in the state over 10 years.

A Volkswagen diesel engine.
Credit: Tony Hisgett/flickr

The plan calls for 2,500 vehicle chargers to be installed at more than 350 stations across California, complementing a nationwide network of charging stations the company is installing in 38 states. Stations will be spaced an average of about 70 miles apart in California.

In 2015, the state and the Environmental Protection Agency found that Volkswagen had installed a “defeat device” in its diesel vehicles that would improve vehicle performance and cut pollution during emissions tests.

When the vehicles were being driven under normal conditions, they would emit nitrogen oxide pollution up to 40 times the levels that the EPA allows. The discovery of Volkswagen’s cheating led to three criminal felony counts, $2.8 billion in penalties and an agreement to prevent future violations.

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The air resources board approved the first part of Volkswagen’s plan on Thursday, giving the company permission to build the electric vehicle charging station network. It intends to use a percentage of the money to create a “green cities” program providing disadvantaged and low-income communities with access to electric vehicles.

The program will focus on neighborhoods in two cities, Sacramento and another to be named. Volkswagen’s subsidiary, Electrify America, will commit $44 million to Sacramento to build charging stations, provide electric vehicles for ride sharing and other electric vehicle-related projects.

An electric vehicle charging station in California.
Credit: dj venus/flickr

Volkswagen issued a statement saying Electrify America is pleased with the board’s decision and is looking forward to implementing its zero-emissions vehicle investment plan.

California Air Resources Board Chair Mary D. Nichols said in a statement that Volkswagen can proceed with building electric vehicle charging stations in areas of the state that do not currently have them.

“This will help the state as a whole, and especially some of our disadvantaged and underserved communities, to shift to the cleanest vehicles on the market to help clean the air and fight climate change,” she said.

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The Largest Wind Farm in the U.S. Is Growing in Oklahoma. It’s a Sign of the Times

A new wind farm that could become the largest in the U.S. will be taking shape across the blustery plains of the Oklahoma Panhandle over the next three years, helping to wean four Southern states off of electricity produced with climate-polluting coal.

American Electric Power (AEP) and wind developer Invenergy plan to complete a $4.5 billion wind farm called the Wind Catcher Energy Connection by 2020, along with a 350-mile electric power line. The project, announced this week, will supply Oklahoma, Arkansas, Louisiana and Texas with 9 million megawatt hours of wind power, enough electricity for about 800,000 homes.

A wind farm near Weatherford, Okla.
Credit: Travel Aficionado/flickr

AEP’s announcement is a sign that electric companies are gaining greater confidence in the future of renewables, even as the Trump administration casts doubt on established climate science and works to reverse many of the Obama administration’s energy and climate goals.

The Trump administration has aimed to slash or defund most federal support for wind, solar and other renewable energy. But energy experts say there is too much momentum behind the rise of renewables for those pro-coal policies to slow wind and solar farm development.

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“It shows that the president’s cramped view of energy does not and cannot defeat economics and the public’s desire for clean energy and clean energy’s symbolism as progress,” said Jeremy Firestone, director of the Center for Carbon-free Power Integration at the University of Delaware.

Many states have set climate goals requiring a certain amount of their electricity to come from renewables by 2030. To succeed in those efforts, a Berkeley Lab report published this week shows that those states will have to increase the amount of clean energy they produce by 50 percent over the next 13 years.

New wind, solar and other renewables are being built at a fast enough rate in those states that they may easily meet those targets, said Galen Barbose, a Berkeley Lab research scientist and the report’s author.

AEP is investing billions of dollars in Wind Catcher in order to own the wind farm outright. Until recently, most electric companies would buy electricity from wind farms owned by a different company without investing much in the farm itself.

AEP spokeswoman Melissa McHenry said the company sees a substantial return on equity investments, so it makes more sense for AEP to own the entire wind farm rather than just purchase electricity from it.

She said a federal tax credit available for wind energy production makes wind power cost competitive with electricity generated using coal and natural gas.

A wind farm in southwest Oklahoma.
Credit: Larry Smith/flickr

“We’re increasingly hearing from customers large and small that they want additional clean energy resources,” McHenry said. “We’ve largely been a coal-fired utility. Now, we have additional resources proving to be cost effective so we’re investing in those resources.”

Mark Z. Jacobson, a civil and environmental engineering professor specializing in renewables at Stanford University, said AEP’s plan to purchase Wind Catcher shows that wind power costs have dropped so low that utilities realize they can make more money owning the wind farm outright.

Wind Catcher’s claim to fame as the largest single wind farm in the U.S. comes with an asterisk, however.

Another project of similar size is being developed in Iowa, but it will be composed of multiple separate wind farms. A 3,000-megawatt wind project on two sites is being proposed in Wyoming, and its developers call it the biggest in the world.

“We will have to see which is the largest in the end,” Firestone said. “If it is two adjacent wind projects, each 1.3 gigawatts each, are they individually smaller or together the largest?”

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Climate Change Means More Fuel for Toxic Algae Blooms

For two days in early August 2014, the 400,000 residents in and around Toledo, Ohio, were told not to drink, wash dishes with or bathe in the city’s water supply. A noxious, pea green algae bloom had formed over the city’s intake pipe in Lake Erie and levels of a toxin that could cause diarrhea and vomiting had reached unsafe levels.

The bloom, like the others that form in the lake each summer, was fed by the excessive amounts of fertilizer nutrients washed into local waterways from surrounding farmland by spring and summer rains. Efforts are underway around the Great Lakes ­— as well as other places plagued by blooms, like the Gulf of Mexico and Chesapeake Bay — to reduce nutrient amounts to control the blooms, which can wreak havoc on the local ecology and economy.

The sickly green color marks a toxic algae bloom in the western part of Lake Erie in August, 2014. The bloom caused the city of Ohio to temporarily ban drinking water from the city supply, which is pulled from the lake.
Click image to enlarge. Credit: NASA Earth Observatory

But new research shows that climate change is going to make those efforts more and more difficult. As warming temperatures lead to increases in precipitation, more nitrogen, one of those nutrients feeding the blooms, will be washed into the nation’s waterways, the work, detailed in the July 28 issue of the journal Science, finds.

The biggest increases in such nitrogen loading will likely come in the Midwest and Northeast, areas already seeing the biggest uptick in heavy downpours.

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The findings show the urgency of coming up with policies to reduce nutrient overloads, and the importance of keeping climate change in mind when devising them.

“It really drives home the point that we need to do something now,” Tim Davis, who studies algae blooms at the Great Lakes Environmental Research Laboratory, said. He was not involved with the study.

Costly Blooms

Algae blooms are vast mats of microscopic organisms that, like plants, need sunlight, water, and nutrients to flourish. When an overabundance of nutrients like phosphorous and nitrogen from fertilizers are washed into lakes and coastal areas by rains, they can cause an explosive burst that forms a bloom.

Such blooms form each year in the Great Lakes, particularly in shallow Lake Erie, the Gulf of Mexico and Chesapeake Bay, as well other areas. They can pose serious risks to public health from the toxins they release and can be poisonous to marine and lake life. When a bloom finally dies, it can also suck up all the oxygen in the water, creating what is called a hypoxic, or dead zone, that can also kill fish.

A dead fish washed ashore by the green-tinged waves of Lake Erie during a 2009 algae bloom.
Click image to enlarge. Credit: Tom Archer/Michigan Sea Grant

The impacts can have major economic ramifications, causing billions of dollars in damage to commercial fishing and recreational activities.

Nitrogen in particular plays a key role in fueling coastal algae blooms, and has been found to make the blooms in Lake Erie more toxic.

Most research to date on how changing climate conditions might affect algae blooms has been focused on particular basins and watersheds. The Great Lakes, especially Lake Erie, have been the focus of intensive study and the subject of a longstanding effort by the U.S. and Canada to reduce nutrient loads into the lakes.

Because not every area can get that kind of attention, Anna Michalak, of the Carnegie Institution for Science, and her colleagues wanted to get a bigger picture look at how climate change might alter how much nitrogen is washing into the nation’s watersheds and see if they could pinpoint the areas of greatest risk.

More Rain = More Nitrogen

Using 21 climate models from the most recent Intergovernmental Panel on Climate Change report, they looked at how changes in both overall and extreme precipitation would influence the amount of nitrogen entering waterways, keeping things like fertilizer use constant.

They found that by the end of the century, if greenhouse gas emissions continue on their current trajectory, increased rainfall will cause a 20 percent rise in the amount of nitrogen loading in waterways of the continental U.S.

The largest increases were in the Northeast (with a 28 percent increase in nitrogen), the upper Mississippi-Atchafalaya basin (24 percent) and the Great Lakes (21 percent). That result wasn’t surprising given that the Midwest and Northeast have already seen heavy downpours increase by 37 and 71 percent, respectively, since 1958, the largest increases in the nation, according to the 2014 National Climate Assessment.

Nitrogen loading in the nation’s waterways averaged for 1976-2005 (a) and how precipitation will increase that loading by mid-century (b) and by the end of the century (c) if greenhouse gas emissions continue on their current trajectory.
Click image to enlarge. Credit: Sinha, et al./Science

To counteract the increase just from the influence of precipitation would mean that the nitrogen being introduced to the land would have to be reduced by 30 percent.

“That is massive,” Michalak said, and would be a significant ask of farmers struggling to maintain crop yields.

In the particular example of the Mississippi-Atchafalaya system, the Environmental Protection Agency has already mandated that nitrogen loads be reduced by 20 percent below 1980-1996 levels. To meet that goal in the face of the increases coming from rains would mean reducing fertilizer use by a whopping 60 percent.

The study also looked to broaden the view beyond the U.S. by looking for watersheds around the world that were similar to some in the U.S. and seeing how nitrogen loading might change with precipitation. They identified India, China and Southeast Asia — home to the majority of the world’s population — as areas that could see major rises in nitrogen loading in the future.

The study makes clear that local managers and policymakers will need to rethink some of the ways they combat nutrient pollution and society will also have to develop technological solutions to reduce nutrient pollution, from implementing more efficient agricultural practices to potentially recycling various forms of nitrogen in sewage into animal feed, according to a commentary piece also published in Science.

If you want to manage nutrient loading “you need to account for the fact that the climate is changing at the same time,” Michalak said.

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