Xcel Energy CEO Ben Fowke observed earlier this year that time is running out for coal-fired power plants in the U.S.

“I will tell you, it’s not a matter of if we’re going to retire our coal fleet in this nation, it’s just a matter of when,” Fowke said on stage at the EEI Annual Convention in San Diego in June.

For the Public Service Company of Colorado (PSCo), an Xcel Energy subsidiary, that time is now.

On Monday, the utility won preliminary approval for its coal plant retirement plan. The Colorado Public Utilities Commission voted unanimously to allow for the early closure of coal-fired units 1 and 2 at Xcel’s Comanche Generating Station in Pueblo County. The units are capable of producing a combined 660 megawatts of coal-fired generation, which represents approximately one-third of PSCo’s remaining coal fleet.

Under Xcel’s Colorado Clean Energy Plan (CEP), the Comanche coal units will be replaced with a $2.5 billion investment in renewables and battery storage — including of 1,131 megawatts of wind, 707 megawatts of solar PV, and 275 megawatts of battery storage across the state, including in Pueblo. Xcel estimates the transition will save ratepayers between $213 million and $374 million.

The decision comes as Xcel is attracting record-low clean energy prices. In January, the results of Xcel’s all-source solicitation returned a median price bid of $21 per megawatt-hour for wind-plus-storage projects and a median bid of $36 per megawatt-hour for solar-plus-storage.

Bids highlighted in the CEP are even lower. The plan includes wind at pricing of $11 to $18 per megawatt-hour, solar at $23 to $27 per megawatt-hour, and solar-plus-storage at $30 to $32 per megawatt-hour.

By 2026, the CEP will bring PSCo’s energy mix to nearly 55 percent renewable energy, up from 28 percent in 2017. Coal made up 44 percent of Colorado’s electric generation last year, which would decrease to about 24 percent under the plan. Natural gas will remain roughly the same.

Yesterday, solar and energy storage advocates had their second win in less than 24 hours. Following on the dramatic and narrow passage of a bill to mandate 100% carbon-free electricity by 2045, another bill which may contain one of the keys to making that happen has passed the Assembly.

SB 700 will extend the state’s Self Generation Incentive Program (SGIP) through 2026, which by the estimates of the California Solar and Storage Association (CALSSA) will support the installation of nearly 3 GW of behind-the-meter storage.

A very large volume of energy storage will likely be necessary for California to achieve the very high penetrations of wind and solar that will come online as the state approaches 100% clean electricity, a fact which was not lost on the bill’s sponsor.

“If we are going to get to 100% clean energy, we need to be using solar power every hour of the day, not just when the sun is shining,” stated California Senator Scott Wiener (D-San Francisco), the author of SB 700.

However, SB 700 is critical for another reason: it may enable the state’s residential solar industry to survive. As part of the move to net metering 2.0, new residential installations in the state are subject to time-of-use rates. Not only does this add greater complexity to the sales process, but with solar driving down mid-day demand, increasingly the most highly priced hours are after the sun sets.

Increasingly, the solution to this is energy storage, as the addition of batteries allows residential solar customers to store electricity from their PV systems during the day and either use it or export it to the grid during peak evening demand.

However, energy storage systems are expensive, as adding batteries typically doubles the cost of a residential PV system. That’s where SGIP comes in, by providing incentives that can help to put solar plus storage within the reach of more consumers.

The current version of SGIP allows state regulators to collect up to $166 million per year from the state’s three large investor-owned utilities to fund SGIP; however the program was set to expire at the end of 2019. SB 700 will add another five years and up to $800 million in funding for the program.

Germany helped make solar power cheap. As of June this year, it boasts 1 million homes that have installed rooftop solar panels. That means the country produces a lot of renewable energy—sometimes more than it can use.

At such times, German grid operators have had to pay neighboring countries or grids to use the excess electricity. Since the beginning of this year, German grids have accumulated 194 hours (paywall) with negative power prices.

Now Germany is turning to energy storage as a solution to the problem of excess electricity. On Aug. 28, an energy ministry official attended the commissioning (link in German) of the 100,000th home to install a battery-storage system that’s connected to the grid.

Home battery-storage systems can soak up energy from the sun during the day, when typically household consumption is low. Then the batteries can kick after the sun sets and consumption tends to rise. Since 2013, lithium-ion battery costs have fallen by 50%. That’s made the economic case for home battery-storage systems more attractive.

The advantage of having the batteries connected to the grid is that, beyond household usage, grid operators can combine this distributed storage resource to create a virtual power plant. So if a home battery has more energy than the homeowner can use, the excess energy could be sold onto the grid and used by another home that doesn’t have a battery-storage system of its own. Put another way, virtual power plants allow homes to gain the benefits of a battery, such as lower-price electricity, without having to pay upfront for battery installation.

This August brought the collapse of two emblematic energy storage firms.

In the U.S., lead-carbon battery maker Axion Power International filed for Chapter 7 bankruptcy. In the U.K., grid-scale storage system developer Camborne Energy Storage went into administration.

Both firms ran aground after failing to secure cash to fund operations. Axion, of New Castle, Pennsylvania, had $6.6 million in debts and only around $47,000 in assets, according to local press reports.

The company was a veteran of the energy storage industry, having been founded in 2003. As reported in GTM back in 2009,  Axion aimed to give lithium-ion a run for its money with an advanced lead-acid battery equipped with carbon electrodes.

The electrode technology, from a Russian company that had been developing it for superconductors, was supposed to give the battery a lifespan three to four times longer than batteries using traditional lead negative electrodes.

Axion invested about $50 million in adopting it for use in batteries and secured a supply deal with big battery maker Exide Technologies. After having been listed on the over-the-counter bulletin board in 2003, in 2014 the company graduated to Nasdaq.

It struggled, though, and delisted a year and a half later after its stock spent a month trading below $1. Attempts to commercialize the technology ran into difficulties, too.

In March last year, Axion filed an 8-K form with the U.S. Securities and Exchange Commission (SEC), warning shareholders of significant financial hardship after a dozen attempts to get the lead-carbon battery to market.

The company’s production line had not made a battery since 2016, it later emerged. Desperately seeking a way out, Axion pivoted away from manufacturing and toward research and development with a business model based on technology licensing.

Even that didn’t work, though. A 10-K SEC form filed in July revealed that Axion was operating with a skeleton staff of four and pinning all its hopes on a single commercial agreement, with a Chinese company called Fengfan Co Ltd.

From 2015 through 2018, the filing said, “Axion initiated over 30 separate efforts to identify shareholder-enhancing transactions. Except for Fengfan’s interest in partnering with the company, all other efforts have failed.”

A household just outside Berlin has become the recipient of the 100,000th grid-connected residential battery energy storage system in Germany.

Parliamentary State Secretary at the Federal Ministry for Economic Affairs and Energy, Thomas Bareiß attended an official event to mark the system’s commissioning in Eichwalde. Bareiß hailed the event as an “important milestone” that Germany has reached in its energy transition – referred to domestically as the Energiewende.

The politician said that since 2013 battery costs have fallen by over 50%, making the Energiewende more affordable and expanding “flexibility options” open to grid operators for intelligent load management, while bolstering energy security.

National solar trade group BSW Solar’s chief Carsten Körnig thanked the willingness of German people to invest in this technology for the future as well as the incentive programme put in place by the government five years ago, which offers rebates for equipment purchases. Körnig put forward his view that solar storage should become “the standard” if politicians are serious about the energy transition.

The next milestone to aim for, the BSW Solar managing director, is to reach 200,000 systems in the next two years. The country appears to be on a more rapid trajectory to achieving that goal than many others. By way of illustration, there were around 50,000 systems installed by mid-2017. Energy-Storage.news reported in July this year that as many as 37,000 units were sold and connected to the grid during last year, according to the European Market Monitor on Energy Storage (EMMES) from Delta-ee and trade association EASE.

This had outstripped a Delta-EE forecast of around 31,000 units for 2017. In an interview with EMMES author Valts Grintals, the Delta-EE analyst discussed some of the drivers behind this rise, including sales and marketing that is tailored to householders’ needs.

The 100,000th system, which was a Solarwatt MyReserve residential device, joins 1 million homes in Germany now with their own PV system, as announced by BSW Solar in June.

In a paper to be published in the forthcoming issue of Nano, a team of researchers from the China University of Mining and Technology have fabricated an asymmetric supercapacitor (ASC) based on FeCo-selenide nanosheet arrays as positive electrode and Fe₂O₃ nanorod arrays as negative electrode. There is evidence that FeCo-selenide could be a promising next-generation electrode material for energy storage devices.

Supercapacitors have been considered as the most attractive candidate for energy storage devices, and are widely used in the field of portable electronic equipment and electric cars due to their high power density, fast charge/discharge rate, low maintenance cost and long cycling life. Similar to the transition metal bimetallic oxide and sulfides, metal selenides can be considered as a promising candidate for electrode materials, as selenium belongs to the same group element as sulfur.

The FeCo-selenide was synthesized using a two-step hydrothermal process, with Ni foam as substrate and current collector. The as-prepared FeCo-selenide nanosheet arrays on Ni foam shows specific capacitance of 978 F/g (specific capacity of 163 mAh/g) obtained at current density of 1 A/g and cycle stability of 81.2 percent was achieved after 5000 cycles. And the ASC device operating at 1.6 V delivers a maximum energy density of 34.6 W h/kg at power density of 759.6 W/kg, which is higher than that of many other ASC reported previously. The practical application of the ASC device was explored by assembling several capacitors into a series circuit to light 1 LED bulb and light board of “CUMT”. The ASC device exhibited excellent electrochemical performance which provides the evidence that FeCo-selenide could be the next-generation promising electrode material in energy storage devices.

The team at China University of Mining and Technology is currently exploring options to better control the high voltage output and create high-performance ASC. For optimal electrochemical performance and decrease in cost, the team would also like to explore a device based on selenide composites in its application.

MISO is planning to provide storage with make-whole payments for price volatility, subject storage resources to dispatch and regulation performance rules, and exempt storage from certain uplift charges, officials said last week at a special conference call on compliance with FERC Order 841.

The RTO is proposing to use the same uninstructed deviation threshold it uses for other generators, Market Quality Manager Jason Howard said during the call on Aug. 21. MISO is currently refining a proposal to implement a more performance-based uninstructed deviation threshold. (See “Final Uninstructed Deviation Proposal,” MISO Market Subcommittee Briefs: May 10, 2018.)

Electric storage resources will be eligible for day-ahead margin assistance payments when they are dispatched below their day-ahead megawatt commitment and revenue sufficiency guarantee payments when they are dispatched in real time above their day-ahead commitments. They will also receive RSG payments when committed above their real-time economic minimum limit when committed in real time under a must-run commitment.

Storage could also be manually redispatched by MISO operators to contradict their day-ahead schedule or real-time offers, even to zero output, RTO staff said.

The RTO is also planning to exempt storage from its revenue neutrality uplift charge, its demand response resource uplift charge, and load ratio share adjustments and ancillary distributions. However, MISO said there was a potential for storage resources to be assessed real-time RSG distribution charges.

MISO plans to vet its performance rules with its Independent Market Monitor.

“We’ve just begun our collaboration with the Market Monitor … so that they do have an initial glimpse of our thoughts,” Howard said. He added that MISO will return with any rule changes regarding threshold and performance at the Sept. 13 Market Subcommittee meeting.

Some stakeholders asked for more specifics about MISO’s Order 841 compliance filing. The RTO said in June it would respond to Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.)

The City of Portland, Portland State University, and Portland General Electric are collaborating on a program to improve disaster resilience in the city through emergency microgrid structures called PrepHubs. An interdisciplinary team from MIT is supporting the effort.

These prototypes are composed of critical lifeline modules forming a flexible kit of parts that can be combined in different ways, according to the program website. “For example, a sidewalk PrepHub allows you to charge a phone, hear a public announcement, and connect with loved ones,” the site explains. A pocket park version has medical supply storage and water tanks, while a civic plaza type contains sanitation services and cooking supplies.

Earlier this month, the Portland City Council voted to approve the PrepHub agreement. PGE will provide power to the PrepHubs from the grid as well as energy storage devices that are supplemented by solar arrays and pedal-power.

“The hubs will be able to recharge emergency communications, equipment, and cell phones during and immediately after a natural disaster,” the partners say. Each hub also offers secure storage for Basic Earthquake Emergency Communication Node (BEECN) cache equipment.

A PrepHub serves as a meeting point to receive resources, reducing panic and helping communities recover, according to the prototype creators. The first one is expected to be installed on the Portland State University campus in 2019.

Each PrepHub is essentially an emergency microgrid. The $300,000 pilot project aims to ultimately build 40 to 50 additional microgrid statues in Portland parks that will become public landmarks, Microgrid Knowledge’s Lisa Cohn reported. Portland will be the first city to have a grid-connected PrepHub, Conrad Eustis, director of retail technology strategy for PGE told the outlet.

“Successful disaster response depends on partnerships,” said Maria Pope, president and CEO of PGE. “This project will also inform PGE’s work to use technological advances to build a smarter, more resilient grid for customers.”

AECOM and Lockheed Martin have joined forces to build a Battery Energy Storage System (BESS) at Fort Carson, Colorado, using Lockheed Martin’s GridStar Lithium energy storage process.

AECOM officials representing the fully integrated global infrastructure firm said the Fort Carson, Colorado, site would be the largest stand-alone, commercially contracted battery at an army base. The 4.25 MW/8.5 MWh BESS is part of an energy savings performance contract (ESPC) project to reduce Fort Carson’s energy costs and increase its energy resilience.

“During project development, our team surveyed the energy storage industry for the optimum solution for Fort Carson,” Annika Moman, senior vice president of AECOM Power and Energy Services Lead, said. “We decided on Lockheed Martin’s GridStar units due to their unique modular architecture allowing for a flexible design and a reduction in operational risk. Our working partnership with Lockheed was vital to our team and Fort Carson in making this ground-breaking project happen.”

While officials acknowledged the current best primary use-case for the BESS is for demand charge reduction, the system may assume additional missions, such as renewables optimization, frequency and voltage support for Fort Carson’s distribution grid and, potentially, microgrid support.

“Lockheed Martin is pleased to collaborate with AECOM to develop and implement the new military infrastructure that will help Fort Carson increase its resiliency and reduce their electricity costs,” John Battaglini, director with Lockheed Martin Energy, said. “The versatility of energy storage is a key enabler for the military’s aggressive goals of achieving energy resiliency.”

It may not be smooth sailing for Pacific Gas and Electric’s landmark energy storage projects.

Totaling 567 MW, 2,270 MWh, the four projects were hailed as the largest battery storage investment ever proposed when PG&E submitted them for approval at the California Public Utilities Commission (CPUC) in late June. However, comments opposing the projects could slow down their approval and implementation.

Already, the state’s Office of Ratepayer Advocates (ORA) and the Direct Access Customer Coalition (DACC) have filed comments opposing the projects, prompting the CPUC to extend the approval process by at least 120 days. The comments raise questions about whether or not the energy storage projects are needed and whether PG&E’s proposal conforms to the commission’s directives.

The recently-filed comments have had very little public scrutiny, as they were only sent to the relevant parties and have not been posted on the CPUC website.

The cost of reliability

In their comments, the ORA, which is part of the CPUC, argues that the energy storage projects are not needed because the deficiency they are designed to fill will be met with new and planned transmission projects. The ORA claims the projects do not comply with CPUC resolution (E-4909) that authorized PG&E to issue a solicitation for the projects.

The resolution is designed to alleviate the need for an out-of-market contract for Calpine’s Metcalf Energy Center, a 564-MW gas-fired plant in San Jose. Calpine had told the California ISO that it would have to take the plant out of service because it was uneconomic, but the ISO determined the plant is needed, granting a reliability must run (RMR) contract.

In the resolution authorizing the storage projects, the CPUC expressed its concerns about the impact the RMR contracts would have on ratepayers and the lack of competition in the RMR process that can lead to “market distortions and unjust rates for power.”

The commission ordered PG&E to enter into energy storage contracts at “reasonable cost to ratepayers” and to take into consideration the cost and value and the results of previous, similar solicitations. But the ORA argues PG&E did not meet the CPUC’s requirements because the utility did not provide “analysis or explain how the cost of the four energy storage projects are reasonable taking into consideration the cost of the Metcalf RMR contract.” Nor did PG&E compare the four contracts to previous energy storage solicitations, the ORA said.

Costs of the energy storage projects are redacted in the public comments. The comments are not available online because they are not filed with the commission. They are only sent to the relevant parties. By law, the utility is required to respond to comments. The CPUC’s industry division will gather all comments and responses and prepares a draft resolution with its recommendation. The commission then votes on the draft resolution.