by Jeff St. John
December 01, 2017

Thanksgiving is behind us, and the holidays are only weeks away. But for the energy industry groups lined up in opposition to the biggest intervention in U.S. energy policy in decades, the big deadline to watch this year is December 11.

Neil Chatterjee, FERC chairman for now: ‘There is no conspiracy here.’

December 11 is when the Federal Energy Regulatory Commission (FERC) is set to decide what to do with Energy Secretary Rick Perry’s request to overturn decades of energy market regulatory precedent to provide cost recovery status to coal and nuclear power plants. As the one member of the five-person commission who’s publicly supported the idea of giving coal and nuclear power plants this protected status in the name of grid reliability and “resilience,” FERC Chairman Neil Chatterjee is under particular pressure to deliver a detailed interim rule to do just that. 

This week, Democrat Richard Glick was sworn in as FERC’s fourth commissioner, complicating the voting equation for DOE’s plan. And when Republican Kevin McIntyre is sworn in, he will replace Chatterjee as commissioner, limiting his authority to make decisions on which agenda items are tackled first, and in what order. This week’s delay in McIntyre's official swearing-in has drawn speculation from opponents to the DOE proposal that Chatterjee might use the delay to push through interim financial protections for the power plants in question before he’s replaced. 

Chatterjee responded to these rumors at a Tuesday event in Washington, D.C., declaring, “There is no conspiracy here. There is no intentional delay or dragging things out to some nefarious end,” and telling reporters that they were ”reading way too much into the timing of what people's personal situations are on getting sworn in.” 

Glick, who was sworn in on Wednesday, said in his Senate confirmation hearing that FERC “does not have the authority, nor should it, to prop up a failing technology,” while the two seated commissioners, Republican Rob Powelson and Democrat Cheryl LaFleur, have both voiced objections to Perry's proposal.

Another coal plant done and gone

Amidst the Trump administration’s efforts to provide financial support to the coal industry, the tally of coal-fired power plants closing their doors continues to rise. This week’s casualty was the 1.2-megawatt Pleasant Prairie facility in Kenosha, Wisc., which will close down as early as next year as its owner, WEC Energy Group and utility We Energies, turn to natural gas, wind and solar for its future power needs. 

It’s the 24th such announcement since President Trump took office, and the 266th nationally since the start of last decade, according to the Sierra Club. We Energies has been slowly reducing its reliance on coal-fired power, which now makes up just less than half its overall generation mix. The last big closure announcement along these lines was last month, when Vistra Energy announced plans to close two coal power plants in Texas -- just weeks before it agreed to acquire rival natural-gas utility Dynegy for $1.74 billion in stock. 

Another polar vortex? ISO-NE says it’s prepared

The 2014 polar vortex, the week-long cold snap that grounded air traffic, snarled interstate traffic, and killed more than a dozen people, also shut down many New England power plants at the same time that heating energy demand was spiking. DOE’s NOPR relies heavily on that crisis in justifying its proposal to give special treatment to power plants that can supply 90 days of fuel on site -- a status only coal and nuclear plants can reasonably achieve, and which isn’t linked with improved grid reliability. 

Still, with a cold winter predicted for the Northeast, grid operators ISO New England and New York ISO are preparing their contingency studies for the coming season, with inevitable reference to the polar vortex.  

NYISO reported Thursday that it has the capacity and operating reserves to manage the coming extreme cold weather conditions, which it projects will reach a peak demand of 24,365 megawatts. That’s a bit more than last winter’s 24,164 megawatts, which was milder than average, but a lot less than its 25,738-megawatt peak in January 2014. Meanwhile, NYISO’s has 44,557 megawatts of capacity resources on-line, including 41,454 megawatts of generation, 2,311 megawatts of energy imports, and 792 megawatts of demand response.

ISO-NE also reported more than adequate capacity and reserves for the upcoming winter season this week, with an extreme cold-scenario peak demand of 21,895 megawatts -- nearly a gigawatt below its 22,818-megawatt record from Jan. 15, 2004 -- more than matched by 30,999 megawatts of resources with an obligation to be available at those times. It also laid out some useful guidance on how much natural-gas-fired generation is at risk of not being able to get fuel when needed, landing at more than 4,000 megawatts. 

DOE funds CHP for natural-gas-fired grid resiliency 

The Energy Department’s crusade to upend federal energy market regulations to favor coal and nuclear power is purportedly geared to alleviate the threat of relying too much on natural gas, as well as wind and solar. Meanwhile, in another department, DOE’s Office of Energy Efficiency and Renewable Energy just gave out $24 million to support an ongoing effort to bring natural-gas-fired combined heat and power (CHP) systems to a bigger customer base. 

The grants will help fund regional CHP Technical Assistance Partnerships -- largely university and research organization teams that help end customers explore, analyze and potentially invest in on-site CHP systems. It’s an active organization -- since 2009, it has worked on 1,900 CHP projects, with 441 of them, or an estimated installed capacity of 8 GW, in the project pipeline for installations. 

The TAPs are looking for opportunities where CHP systems could “increase resilience to natural disasters and improve grid and electric delivery reliability,” as well as to validate the work of different technology vendors and installation partners from region to region. San Diego-based Center for Sustainable Energy will serve California, with the rest of the money going to universities in seven states. 

This year’s hurricanes have brought the value of microgrids home to many utilities and state regulators, boosting a market that’s still dominated by simple industrial and institutional self-powered sites, but increasingly built out of more distributed energy assets. GTM Research reported this week that installed and planned U.S. microgrid capacity in 2017 will reach 348 megawatts, or 106 percent growth over the previous year. Microgrids also contributed 154 megawatts of capacity to a growing commercial market this year, according to the new U.S. Microgrids 2017: Market Drivers, Analysis and Forecast report. 

EnerNOC, Enel and Australia find flexibility in DERs

EnerNOC’s acquisition by Italy’s Enel for $250 million this summer prompted much speculation about how the demand response provider and energy intelligence software vendor might be transformed by its purchase. While we’ve heard some dispirited messages from former employees, the company is still expanding its reach internationally -- an upside of being part of one of Europe’s big distributed energy contenders. 

EnerNOC brings its own longstanding relationships in key international markets to the table as well. That includes Australia, where it’s had a presence since it bought demand response provider Energy Response in 2011. This week, it announced that it's offering up to 70 megawatts of Frequency Control Ancillary Services -- fast-responding flexibility to ensure grid stability in times of crisis -- that’s made up entirely of distributed demand-side resources, a first for the Australia’s National Electricity Market. 

Australia is a hotbed of solar growth, with some 5.6 gigawatts of rooftop PV and another 496 megawatts of utility-scale solar installed as of mid-2017, according to the Australian Photovoltaic Institute. Meanwhile, its growing share of wind power, much of it sited in remote areas, has been linked to broader grid failures like the September 2016 blackout across the state of South Australia. The continent is also one of the fastest-growing markets for battery-based energy storage, ranging from its bevy of behind-the-meter residential and commercial contenders, to mega-developments like Tesla’s 100-megawatt project-bet

Younicos: New batteries for remote places

German startup Younicos had raised more than $75 million, including $50 million from First Solar, and boomed to the rank of one of the world’s biggest battery-based energy storage software providers and project developers, when in 2014 it bought the deployed assets of bankrupt Xtreme Power. It spent much of the next two and a half years replacing Xtreme’s ill-fated lead-acid batteries by the megawatt, and this July exited its role of prominence in a disappointing fashion, agreeing to a $52 million acquisition by generator rental company Aggreko. 

This week, Younicos announced two projects, one to replace another old Xtreme project, and another located in an extreme environment. The first is on Alaska’s Kodiak Island, and will replace the 3-megawatt unit with new lithium-ion batteries, meant to help the island’s grid manage high levels of wind power. 

The second is a 1-megawatt, 1.3-megawatt-hour lithium-ion system for Statoil’s Batwind floating wind farm project off the coast of Scotland. Statoil announced plans to add batteries to the project last year, and hopes to use them in an experimental fashion starting next year, and then “assess next steps” from there. 

Forums to watch: California rate design for a DER future

California, the leader in PV, EVs and behind-the-meter batteries, is in the midst of overhauling its mass-market residential electricity rate structures to take them into account. By 2019 everyone will be switched to time-of-use prices, complete with options for owners of solar, storage, demand response, plug-in vehicles, and other combinations of distributed energy resources. These changes will wash through the market in ways that are hard to calculate, but are likely to be as important an economic driver as the state’s other avenues to value DERs as distribution grid assets or wholesale energy market players. 

On December 11 and 12, the California Public Utilities Commission will hold a two-day workshop on “innovative rate design concepts” along these lines, with the twin goals of keeping costs for electricity consumers low, while encouraging renewable energy and “making more efficient use of storage and other demand management technologies.”

The first day will feature unpopular ideas with the distributed energy crowd, like demand charges and “other approaches to recovering the costs of providing adequate generation, transmission, and distribution capacity to ensure reliable electric service.”

Day two will focus on real-time pricing and other dynamic rates, including the technologies that will allow customers to respond without being overwhelmed or punished.