Page 1272 – RTO Insider

October 2, 2017

Counterflow: Cash for Clunkers Redux

By Steve Huntoon

Remember the Cash for Clunkers program? Inefficient cars paid to go away.

The Energy Department’s directive to FERC last week is Cash for Clunkers with a twist: inefficient generators paid to stay.

The original Cash for Clunkers was an economic stimulus for new stuff to replace the old stuff. The DOE’s Notice of Proposed Rulemaking subsidizes the old stuff to stop the new stuff: a sort of stimulus in reverse. (See related story, Perry Orders FERC Rescue of Nukes, Coal.)

So we might say the DOE version is a Twisted Sister sort of twist on the original.

Bailing out the Retiring, Retired and Canceled Clunkers, and then Everyone Else

We know with certainty that the DOE proposal subsidizes the inefficient because those are the plants that will opt for the federal rate guarantee instead of market-based rates. How will this play out?

DOE says there are 34 GW in projected retirements over the next five years. Under the DOE proposal, none of that would retire and instead would go on the federal dole.

And then there’s the 71 GW that already retired over the last six years but will likely return, like “Night of the Living Dead,” for that federal rate guarantee.^[1]

And how about all those canceled nuclear projects?

So we’ll have around 100+ GW of uneconomic clunkers crashing the markets, and of course crashing market prices. This will force all the economic plants that depend on legitimate market prices to join the federal dole.

Natural gas plants will do this by simply adding 90 days’ worth of oil tanks.^[2]

What will all this cost consumers? DOE doesn’t even try to answer that question, but here’s one way of looking at it. First, we can assume that FERC won’t want thousands of individual rate cases for all the power plants in all the RTOs.^[3]

So FERC would need some sort of standard compensation. Let’s say it adopts a cost of new generation, maybe $400/MW-day.^[4] Generation in the RTOs is around 530 GW; add the roughly 70 GW of retired clunkers that will return from the dead for about 600 GW on the federal dole. That’s about $88 billion annually.

So we are talking about tens of billions of dollars a year squandered first on what are, by definition, uneconomic resources, and then by paying economic resources that are rendered uneconomic by the clunkers and forced onto the same federal dole.

I can’t help noting how Republicans blasted the original Cash for Clunkers,^[5] which had a one-time cost of $3 billion. The DOE version is tens of billions of dollars every year, forever.

Resiliency

DOE says that its proposal is about “resiliency” (the new buzzword for reliability). But the retiring plants really are clunkers, as this PJM slide excerpt illustrates (I’ll translate the jargon after the slide):^[6]

PJM FERC Steve Huntoon DCF analysis — | *PJM*

The deactivating (retiring) stuff has an outage rate — equivalent forced outage rate-demand (EFORd) — that is three times the new stuff (14.56% versus 4.42%). Yet DOE wants to subsidize these clunkers so they won’t retire.

And that somehow is going to improve resiliency, again in a Twisted Sister sort of way.

90 Days of Fuel Supply on Site

A few words about the fuel supply requirement. DOE relies heavily on PJM’s experience in the polar vortex of 2014 and claims that natural gas supply was the major problem. It was not. As this PJM chart plainly shows, natural gas interruptions affected 9,300 MW, accounting for less than 25% of total forced outages of 40,200 MW:^[7]

FERC baseload power energy department DOE — | *PJM*

The FERC testimony of Mike Kormos, PJM’s executive vice president at the time, directly contradicts DOE’s main claim: “Natural gas interruptions removed less than 5% of the total capacity required to meet demand on Jan. 7, [2014], while equipment issues associated with both coal and natural gas units made up the far greater proportion of forced outages.”^[8] (Emphasis added.)

Beyond equipment issues, another basic flaw in a metric like fuel supply on site is that coal piles freeze, as some did in the polar vortex. Years of coal supply on site would be worthless if frozen. And of course, nuclear plants can’t run during refueling and other outages. Years of nuclear fuel on site would be worthless during those outages.

Here’s a fun fact you won’t find in the DOE NOPR: Baseload (combined cycle) natural gas plants average lower forced outage rates (4.29%) than baseload coal plants (7.71%), and have about the same as nuclear plants (3.51%).^[9] It’s these overall forced outage rates that matter — not a single metric like fuel supply on site.

As for 90 days specifically, DOE provides zero rationale for that. In the polar vortex, the generation emergencies in PJM aggregated 20 hours.^[10] What is magic about 90 days (other than being tailored to the average coal plant stockpile)?

FERC and RTOs like PJM have learned from the polar vortex to reward performance and penalize nonperformance, instead of using a meaningless metric like days of fuel supply on site.

PJM hasn’t had a single system generation emergency in more than three years — that’s more than 26,280 hours of reliable operation. And PJM locks down adequate, reliable generation resources years in advance.

Bottom line: DOE proposes to take a system that is incredibly reliable and squander tens of billions of dollars on uneconomic resources to make it less reliable.

J&R Gone Missing

Absent from the DOE NOPR is an explanation of how its proposal would satisfy the lodestar requirement of the Federal Power Act that all rates be just and reasonable.^[11]

Subsidizing uneconomic clunkers in organized markets is the antithesis of just and reasonable rates. It would be a repudiation of everything that FERC has sought to accomplish over the last 25 years.

Maybe Rick Perry was right all along: DOE should be abolished.

If you’re one of those owners, you might want to hold the wrecking ball. Or come to think of it, maybe you wouldn’t: more rate base if you wreck and rebuild. ↑
The Wall Street Journal cites unidentified experts for the notion that only nuclear and coal plants will qualify under the DOE proposal. That is wrong. Installing oil storage at natural gas plants is routinely done. Of course, if rate base becomes the game, LNG tanks would be used instead. ↑
PJM alone has about a thousand generating units that do or could qualify for the federal rate guarantee. http://pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2020-2021-rpm-resource-model.ashx?la=en. ↑
There’s a straight-faced argument for that: If new generation investment costs that much, existing generation should be compensated at the same level. Otherwise we would be incenting existing generation to retire that would cost less to keep around than paying for replacement new generation. ↑
https://www.seattletimes.com/nation-world/cash-for-clunkers-in-trouble-politics-or-prudence/. “Senate Republican leaders railed against the program Monday, calling it a model of government inefficiency and out-of-control spending.” ↑
http://pjm.com/-/media/committees-groups/committees/mrc/20170928/20170928-item-07-2017-irm-study-presentation.ashx (slide 7). ↑
http://pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014-cold-weather-events.ashx (page 26). ↑
https://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=13502869, (page 11, n. 4). ↑
http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx (click on Brochure 4 for 2012-2016 and compare EFORd (column AC) for the fuel types). ↑
http://pjm.com/-/media/committees-groups/committees/elc/postings/performance-assessment-hours-2011-2014-xls.ashx?la=en. ↑
DOE gives lip service to the statutory requirement by using the term “just and reasonable” twice in its proposed regulation. It’s like saying “bring me a blue rock that is red.” ↑

September 29, 2017

PacifiCorp Seeks 1,270 MW of New Wind

By Jason Fordney

Western utility PacifiCorp is seeking bids for up to 1,270 MW of wind power to integrate into its system by the end of 2020.

Successful proposals for new or repowered wind projects must demonstrate that they qualify for the federal production tax credit and can achieve commercial operation by Dec. 31, 2020, according to the company’s request for proposals.

The RFP is for “new or repowered wind energy interconnecting with or delivering to PacifiCorp’s Wyoming system with the use of third-party firm transmission service and any additional wind energy located outside of Wyoming capable of delivering energy to PacifiCorp’s transmission system that will reduce system costs and provide net benefits for customers.” The minimum project size is 10 MW.

ERCOT ISO-NE PacifiCorp Wind Power — Benchmark bids for PacifiCorp’s RPF are due on October 10. | *PacifiCorp*

Portland, Ore.-based PacifiCorp said it would consider a “build-transfer” agreement where the developer assumes responsibility for construction and transfers the facility to PacifiCorp, or a power purchase agreement for up to a 30-year term.

“These new wind resources are a key part of the company’s plan to both meet customer energy needs and continue our cost-conscious transition to less carbon-intensive energy,” said Stefan Bird, CEO of PacifiCorp’s Pacific Power unit.

PacifiCorp will hold a bidder conference on Oct. 2, with notices of intent to bid due Oct. 9 and benchmark bids due by Oct. 10. RFPs for Wyoming-based projects are due on Oct. 17 and non-Wyoming projects on Oct. 24. Agreements will be executed by April 16, 2018, according to PacifiCorp’s schedule. The RFP requires approval from Utah and Oregon regulators.

PacifiCorp included in its 2017 integrated resource plan a proposal to add new wind resources. (See PacifiCorp IRP Sees More Renewables, Less Coal.) The wind energy will be procured in association with the new 500-kV Aeolus-Bridger/Anticline transmission line, a segment of PacifiCorp’s Energy Gateway, a 2,000-mile transmission project that has been developed over the past 10 years. The wind solicitation is part of the IRP’s “Energy Vision 2020” initiative, which also includes plans to repower and improve the utility’s current wind portfolio.

PacifiCorp is a subsidiary of Berkshire Hathaway Energy and serves 1.8 million customers in six states through its Pacific Power and Rocky Mountain Power subsidiaries. PacifiCorp operates 72 generating units with nearly 11,000 MW of capacity, which is currently 62% coal, 15% natural gas, 7% wind and 5% hydro, and the rest coming from biomass, solar, nuclear and geothermal.

September 29, 2017

Entergy Abandons Palisades PPA Termination

By Amanda Durish Cook

Entergy on Thursday said it will continue to operate the Palisades nuclear plant until early 2022 under the terms of its original agreement with Consumers Energy, representing an about-face for the companies after they announced last winter they planned to terminate the arrangement.

The two companies now say they will honor the terms of their 15-year power purchase agreement, which will keep the Michigan nuclear unit running until April 2022. The companies signed the deal in 2007 after Entergy paid Consumers parent CMS Energy $380 million for the plant.

Palisades nuclear plant Entergy — Palisades plant | *Entergy*

Charlie Arnone, Entergy’s top official at Palisades, said last week’s ruling from the Michigan Public Service Commission factored heavily into the decision to terminate the buyout of the PPA. The Sept. 22 order (U-18250) permitted Consumers to issue securitization bonds for just $142 million of the $184.6 million in qualified costs needed to buy out the PPA. Consumers planned to make a one-time, $172 million payment to Entergy.

The PSC said Consumers’ substitute capacity plan was not solid enough to grant the requested funds, and customer savings as a result of exiting the PPA wouldn’t be as significant as the company had estimated.

“Having certainty around the replacement portfolio is integral to the commission’s determination on whether a regulatory asset should be granted because it will ultimately affect electric reliability and whether savings will be achieved,” the PSC wrote in its decision. “Accordingly, the replacement portfolio is the underpinning of the commission’s evaluation and approach to the regulatory asset determination.”

The PSC pointed out that major components of Consumers’ plan — which included the purchase of a gas-fired plant and the expansion of the 60-MW Filer City coal plant in Michigan — “are either not near the conclusion of the regulatory process or, in the case of the gas plant purchase, have not yet been filed,” even at the “tail-end” of a seven-month proceeding.

Consumers spokeswoman Katelyn Carey said the decision not to pursue a 2018 Palisades shutdown was made after careful review by both parties.

“Moving ahead under the terms of our current Palisades’ power purchase agreement through 2022 is the best path forward. We appreciate the thoughtful, deliberate approach by all parties during the process and remain committed to delivering affordable, reliable, safe and clean energy to our customers across Michigan,” Carey said in a statement.

Entergy last December announced it would close Palisades on Oct. 1, 2018, citing unfavorable market conditions for nuclear generation and more economic alternatives. (See Entergy, Consumers Announce Closure of Palisades Nuke.)

In a press release Thursday, the company said that it “remains committed to its strategy of exiting the merchant nuclear power business.”

“We greatly appreciate the continued patience of our employees and the local community in Southwest Michigan throughout this regulatory process, and we will continue to focus on the plant’s safe and reliable operations,” Arnone said. “Entergy will continue to make all necessary investments and maintain appropriate staffing, in accordance with strict licensing standards.”

Local media outlet MLive reported that some of Palisades’ 600 employees celebrated the news.

Entergy said it expects to free up $100 million to $150 million in cash flow through keeping the PPA in place. Revoking the termination also enables the company to amortize and depreciate refueling outage costs and capital expenditures, with those cost to be included in operational results, rather than incurred as expenses.

As recently as late July, officials from the Nuclear Regulatory Commission were attending citizen meetings on Palisades’ decommissioning process, with some nearby residents concerned about on-site storage of radioactive materials. NRC said that a reserve account for Palisades contained $425 million to cover the potentially 60-year decommissioning process.

During a February earnings call, Consumers CEO Patti Poppe said CMS would improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. She added that Consumers’ substitute capacity plan for the “above-market” PPA would have replaced a single, big-bet capital project with many smaller options carrying less risk, and that CMS could replace other PPAs by building its own plants.

September 29, 2017

MISO Study to Examine Incremental Impact of Renewables

By Amanda Durish Cook

MISO’s proposed multiyear evaluation on the future impact of integrating renewable energy will consist of 10 separate studies, with each focused on projected grid conditions at steadily increasing levels of renewable penetration.

But the RTO’s sweeping approach is drawing mixed reactions from stakeholders.

MISO policy studies engineer Jordan Bakke said the evaluation will first model current renewable penetration — about 8% of the resource mix. It will then examine growing system complexity in increments of 10% renewable resource penetration, concluding with an RTO system powered 100% by renewable sources.

MISO study renewable penetration — Existing renewables in MISO footprint | *MISO*

At each 10% checkpoint, MISO will assess systemwide ramping capability, operating reserves, transmission congestion, voltage and frequency stability, and loss-of-load expectation, among other data.

“Between some milestones, the system complexity might not increase much, but at other points, it could increase a lot — and those are our inflection points,” Bakke said during a Sept. 27 Planning Advisory Committee meeting. “We currently don’t know where these inflection points lie.”

The evaluation will attempt to identify when the growth of renewables and the retirement of baseload units require changes in the structure or operation of the system, something MISO has not attempted to answer until now, Bakke said. (See MISO to Conduct Long-Term Renewable Integration Study.) It also aims to predict:

How and when system reliability will be impacted by heavy renewable output;
Whether there are limits to the amount of wind and solar generation MISO can support;
How long until energy storage becomes a requirement;
What parts of the grid will be stressed first; and
How much renewable energy can be deployed before substantial system changes are needed.

The study will also explore what solutions will best mitigate system stressors, Bakke said, whether they be new transmission lines or buses, energy storage, better dispatch availability, demand response measures or better coordination efforts.

Bakke said he would return to later PAC meetings to discuss what MISO has discovered at each study milestone. The study doesn’t have a definitive end date, but Bakke said MISO would likely examine the effectiveness of continuing the study after a year.

Wind on the Wires’ Natalie McIntire said the study may not be “helpful or accurate” given that MISO has not yet reached a 10% renewable penetration and will take several years to achieve a 50%. Transmission could look very different by then, she noted.

“We’ve seen a lot come on in a relatively short amount of time,” countered Bakke, adding that MISO is especially interested in studying the system at a 30-60% renewable penetration, which may become a reality.

Other stakeholders pointed to the high number of renewable projects lined up in MISO’s interconnection queue, which could quadruple wind capacity in some parts of the footprint.

“We started out calling this a breakpoint study,” said MISO Director of Planning Jeff Webb. “If the systems breaks here, what do you do to fix it? And if it breaks here, what do you do to fix it?”

Some stakeholders said the study seems like a high-risk, low-reward endeavor, considering that advances in renewable technologies could solve their own shortcomings by then. Others suggested that generation and transmission owners might question the relevance of study results going out to 2050.

“We’re asking what things do we need to care about in 10 years, and what things do we have to care about in 30 years,” Bakke explained.

Xcel Energy’s Drew Siebenaler said that the study could yield a “holistic look” at renewables and system capability. “We fully support this effort as long as it takes,” he added.

September 29, 2017April 9, 2024

Money and Cooperation Drive New York REV

By Michael Kuser

NEW YORK — New York’s Reforming the Energy Vision initiative aims to fulfill a twofold objective, according to the state’s top energy official: attract the capital needed to integrate renewable energy into the grid while simultaneously motivating utilities to work with clean energy startups instead of treating them like enemies.

“Everything has to change,” New York State Chairman of Energy and Finance Richard L. Kauffman said Tuesday at Greentech Media’s New York REV Future 2017 conference in Brooklyn.

Government is changing too, the state’s first “energy czar” said. While state agencies “used to just do one-time grants,” they are now working to develop sustainable business models for the electricity sector.

REV Changing the Role of the Utility

Kauffman said he sees “green shoots of change” as evidence of New York’s evolving energy framework, such as Consolidated Edison’s Brooklyn-Queens Demand Management program (BQDM), a $200 million effort designed to defer infrastructure spending through energy efficiency, distributed energy resources and demand response. (See NYPSC Extends Con Ed Demand Program.)

“Its non-wires requirement — that was a big deal and that has spread to Central Hudson … and we’re close to National Grid — thousands of rate cases,” he said.

And while the solar industry has shown a profound change in its willingness to engage with state agencies, utilities have “a real struggle to figure out how to be partners [with DER providers] instead of competitors.”

But integration of DER will be key to the evolution of the grid, he said.

“There’s no question that storage has to be a critical part of the system, which is getting peakier and peakier. Yet the value of storage is not adequately captured yet,” Kauffman said. “Utilities procure power, but up to now have not had any financial incentive to reduce peak power purchases.”

Moderating a panel on REV policy, Greentech’s Katherine Tweed asked where to draw the line to mark the right mix of energy resources: “BQDM is the greatest experiment in the world … but people say Con Edison’s going to build that substation when they need it.”

Con Ed Vice President for Distributed Resource Integration Matt Ketschke said, “Most DER doesn’t line up with Con Edison because most of it is not in the business of power generation. … Our real goal is ultimately to eliminate the need for those substations.”

Theatrical Disruption

Three protesters from the New York Energy Democracy Alliance disrupted Kauffman’s talk with a bit of guerrilla theater to highlight the difficulty they say some 800,000 low-income people in the state have paying their energy bills under REV.

The skit began when a man several rows from the stage stood up and identified himself as a renter having trouble paying his utility bills.

After he had asked Kauffman how REV would address the concerns of “low-income communities of color,” two women on either side of the man stood up, pretending to be Kauffman’s security guards.

“Silence!” shouted the women, who wore capes reading “REV = Not Your Business” and “REV = Not a Democracy.”

“This is not the place for the complaints of the working class.”

They went on to bow at Kauffman, a former Goldman Sachs banker, mocking him as the “all-powerful energy czar.”

They finished their skit within a couple minutes — escorting the man out of the conference room before the real security could arrive — and exited to scattered audience applause.

Kauffman took the disruption with humor, saying he was “well aware that accountability is key and that well more than 800,000 New Yorkers have trouble paying their electric bills.”

The electric power system “is financially inefficient as well as energy-inefficient,” Kauffman said.

“So, guilty as charged — I do have a financial background,” he said. But Kauffman said that background only motivates people inside the industry to make the system more efficient.

‘Where Policy Meets Reality’

Nilda Mesa, director of urban sustainability and equity planning at Columbia University’s Urban Design Lab, opened the conference by saying that energy efficiency should be treated like a renewable resource “because the greenest electron is the one that’s not used.” Eventually, “financing people can start to understand the engineering language,” she said.

Scott Weiner, deputy for markets and innovation at the New York Department of Public Service, pointed to the challenge of shifting “from a paradigm of net metering to more market-based uncertainty that exists through the value of DER methodology,” particularly for the solar sector.

“But the industry has stepped up,” he said.

Financing is key to the transformation of the grid, Weiner said: “If I could take out my magic REV wand, I’d like to see the investment community, the people who provide project financing, more directly engaged.”

Todd Glass, energy lawyer with Wilson Sonsini Goodrich & Rosati, asked how project financiers could judge utilities, considering the wide spread between various utilities’ cost of service estimates. Weiner said, “Figuring out the marginal cost of service can be hard to do; that’s where policy meets reality.”

September 29, 2017

Perry Orders FERC Rescue of Nukes, Coal

By Rich Heidorn Jr.

Energy Secretary Rick Perry on Friday ordered FERC to rescue at-risk nuclear and coal generation in deregulated states by ensuring they receive “full recovery” of their costs.

Perry’s extraordinary Notice of Proposed Rulemaking, invoked under Section 403 of the Department of Energy Organization Act, requires FERC to complete a final rule within 60 days after publication of the NOPR in the Federal Register.

Separately, DOE announced it had conditionally approved a $3.7 billion increase in the federal loan guarantees for the over-budget and behind-schedule Vogtle nuclear project. Georgia Power and its partners, Oglethorpe Power and the Municipal Electric Authority of Georgia, had previously received guarantees of $8.3 billion to support construction of Vogtle Units 3 and 4.

Spent nuclear fuel pool | *Simone Ramella via Wikimedia Commons*

In a letter to FERC, Perry cited coal and nuclear retirement statistics and DOE staff’s recommendations in the grid study it released in August. The study said FERC “should expedite its efforts with states, RTO/ISOs and other stakeholders to improve energy price formation in centrally organized wholesale electricity markets” to ensure “baseload” coal and nuclear generators receive compensation for their “resilience” to fuel supply disruptions. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)

Coal generators typically keep 60 to 90 days of fuel at plant sites; operators of nuclear plants refuel every 18 to 24 months.

60 Days to Act

“Now that a quorum has been restored at the commission, I am confident that the commission will act in an expeditious manner to address this urgent issue,” Perry said his letter. “To that end, in the enclosed NOPR, I direct the commission to consider and complete final action on the rule proposed therein within 60 days from the date of the publication of the NOPR in the Federal Register. As an alternative, I urge the commission to issue the proposed rule as an interim final rule, effective immediately, with provision for later modifications after consideration of public comments.”

Perry said the final rule should take effect within 30 days of publication in the Federal Register and that each RTO and ISO submit a compliance filing within 15 days of the effective date of the rule.

Perry began his letter by invoking President Trump’s campaign slogan, saying “America’s greatness depends on a reliable, resilient electric grid powered by an ‘all of the above’ mix of generation resources.”

The secretary went on to cite the 2014 polar vortex, Superstorm Sandy and Hurricanes Harvey, Irma and Maria as evidence that “much more work needs to be done to preserve these fuel-secure generation resources” to ensure sufficient power, “voltage support, frequency services, operating reserves and reactive power.”

“Distorted price signals in the commission-approved organized markets have resulted in under-valuation of grid reliability and resiliency benefits provided by traditional baseload resources, such as coal and nuclear,” he said. “The rule will ensure that each eligible reliability and resiliency resource will recover its fully allocated costs and thereby continue to provide the energy security on which our nation relies.”

Polar Vortex

When PJM lost as much as 22% of its generating capacity to forced outages during the polar vortex, Perry noted, the RTO needed generation from coal plants scheduled for retirement to prevent rolling blackouts, with American Electric Power reporting that it deployed 89% of its coal units scheduled for retirement. Nuclear plants, he noted, had an average capacity factor of 95% during the crisis. He did not mention that some coal plants also were unable to operate because of frozen coal piles and other problems.

Lignite coal conveyor at plant | *FEECO International*

Perry cited DOE’s January 2017 Quadrennial Energy Review, which reported that 37 GW of coal capacity retired between 2010 and 2015, more than half of all generation retirements during the period. The report predicted coal would also represent half of the 34.4 GW of retirements projected between 2016 and 2020, with natural gas plants (30%) and nuclear (15%) making up most of the remainder.

The secretary quoted NERC’s warning that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.” Unmentioned was that NERC’s most recent State of Reliability report concluded “bulk power system reliability remained … adequate” in 2016, repeating the group’s findings from 2013–2015.

At a 2013 technical conference, FERC stopped short of NERC’s warning, saying that the shift in generation from coal toward gas and renewables “may result in future reliability and operational needs that are different than those of the past.” (See Capacity Market Attracts Praise, Criticism at FERC.)

“The fundamental challenge of maintaining a resilient electric grid has not been sufficiently addressed by the commission or the commission-approved ISOs and RTOs, and the lack of a quorum at the commission has undoubtedly thwarted the issuance of rules,” Perry continued in his letter. “But the continued loss of baseload generation with on-site fuel supplies, such as coal and nuclear, must be stopped. These generation resources are necessary to maintain the resiliency of the electric grid. Failure to act expeditiously would be unjust, unreasonable and contrary to the public interest.”

Asked for comment, FERC spokeswoman Mary O’Driscoll said only, “We have received the proposal and are reviewing it.”

DOE’s proposed rule would require RTOs and ISOs to implement market rules that allow the generators with a minimum 90-day fuel supply on site “full recovery of costs.”

“These resources must be compliant with all applicable environmental regulations and are not subject to cost-of-service rate regulation by any state or local authority,” Perry said. “The rule requires the organized markets to establish just and reasonable rate tariffs for the full recovery of costs and a fair rate of return.”

Analysts at ClearView Energy Partners said Perry’s action makes it likely that some method of compensating “essential reliability services” (ERS) could be in place in RTO markets by next spring, “although we caution that it may differ from the NOPR and reflect substantive variations across regions.” NERC has described ERS as including frequency and voltage support, and ramping capability.

“In our view, DOE has placed the essential reliability services issue at the top of FERC’s near-term electric agenda (even though we thought FERC might be leaning that way anyway). We also believe this rulemaking pushes consideration of the non-peak pricing proposal sketched out by PJM and other general price formation rulemakings aside between now and December, at least, should FERC hit DOE’s aggressive timeline.”

Industry Reaction

Predictably, Perry’s order sparked widely divergent reactions.

Maria Korsnick, CEO of the Nuclear Energy Institute, praised what she called Perry’s “decisive … remarkable action,” which she said addresses two “fundamental problems” in the electric sector.

“One is markets that fail to value everything that is important to our electricity system. … Our pricing system is badly broken and … is based almost entirely on short-term price. As a result, nuclear reactors, which provide benefits that everyone agrees we need, find themselves struggling to survive when the nation needs them most,” she said.

“The other problem is that electricity is essential to modern life but only gets noticed if the electricity fails to flow, as has happened most recently in Texas, Florida and Puerto Rico. It is taken for granted, and it does not command the attention it needs from policymakers all across the nation. This course needs to change.”

“We commend Secretary Perry for initiating a rulemaking by FERC that will finally value the on-site fuel security provided by the coal fleet,” said Paul Bailey, CEO of the American Coalition for Clean Coal Electricity. “The coal fleet has large stockpiles of coal that help to ensure grid resilience and reliability. We look forward to working with FERC and grid operators to quickly adopt long overdue market reforms that value the coal fleet.”

The American Wind Energy Association said Perry’s proposal “would upend competitive markets that save consumers billions of dollars a year.”

“The best way to guarantee a resilient and reliable electric grid is through market-based compensation for performance, not guaranteed payments for some, based on a government-prescribed definition,” said Amy Farrell, AWEA’s senior vice president for government and public affairs.

“This looks like federal cost-of-service regulation, and a major retreat from competition in electricity,” said Rob Gramlich, a consultant who worked for AWEA for several years after serving as an aide for former FERC Chairman Pat Wood III.

Mary Anne Hitt, director of the Sierra Club’s Beyond Coal campaign, said the NOPR ignores FERC’s role as an independent agency.

“The Federal Power Act clearly states that FERC cannot favor one energy source over others in its rulemakings, and Perry’s ask — without evidence or common sense — seeks to prop up dangerous coal and nuclear plants that can no longer compete in the wholesale market,” she said. “We are prepared to take to court any illegal rule that props up dirty fossil fuel plants or weakens clean energy’s market access.”

Graham Richard, CEO of Advanced Energy Economy, said FERC should reject what he called a “Perry Energy Tax” on consumers.

“Simply put, this proposed rule has something for everyone to dislike. If you’re a believer in competition and free markets, this rule would insert the federal government squarely into the middle of market decisions. If you are driven by keeping energy costs low, this rule would impose higher energy costs on consumers for no tangible benefit by forcing electricity customers to pay to keep uneconomic power plants in operation,” Richard said. “Finally, if you are driven by innovation and technology, this rule purposefully puts a thumb on the scale for existing, century-old technology at the expense of modern advanced energy that is currently winning based on price and performance.”

RTO Response

ISO-NE spokesman Matthew Kakley said the RTO was reviewing the NOPR while it completes work on a fuel security study. “New England’s wholesale markets have been competitive and brought forward the resources necessary for reliable operations. With the region’s resource mix evolving, ISO New England is conducting an operational analysis of fuel security risks under a range of potential resource scenarios, and we plan to release the study results next month.”

SPP spokesman Derek Wingfield said the RTO was awaiting FERC’s response to the NOPR. “As always, we remain committed to partnering with DOE, FERC and others in our industry to ensure our markets and other services are designed to protect our nation’s electricity infrastructure,” he said.

CAISO is aware of the NOPR and will continue working “with state and federal energy regulators and stakeholders to maintain and strengthen grid resiliency and reliability,” said spokesman Steven Greenlee.

PJM, NYISO and MISO all said they were reviewing the directive.

“As you can imagine, with this just out, we’ll need time to review, analyze and understand,” said PJM spokesman Ray Dotter.

Vogtle Guarantees

While Perry’s NOPR is intended to preserve the current nuclear fleet, his approval of additional loan guarantees is intended to ensure that hopes for a new generation of units are not crushed under the weight of Vogtle’s delays and cost overruns. Vogtle Units 3 and 4 are the first nuclear plants to be licensed and begin construction in the U.S. in more than three decades.

“I believe the future of nuclear energy in the United States is bright and look forward to expanding American leadership in innovative nuclear technologies,” Perry said. “Advanced nuclear energy projects like Vogtle are the kind of important energy infrastructure projects that support a reliable and resilient grid, promote economic growth, and strengthen our energy and national security.”

Rory D. Sweeney, Jason Fordney, Peter Key, Amanda Durish Cook, Tom Kleckner and Michael Kuser contributed to this story.

September 28, 2017

New Texas PUC Chair DeAnn Walker Takes the Gavel

By Tom Kleckner

AUSTIN, Texas — DeAnn Walker will chair her first open meeting of the Public Utility Commission of Texas on Thursday after her recent appointment, which couldn’t come at a busier time for the commission.

DeAnn Walker ERCOT PUCT — Walker | *Courtesy DeAnn Walker*

The Sept. 28 agenda includes an update on Hurricane Harvey restoration efforts, consolidated dockets related to a proposed swap of transmission assets between Oncor and Sharyland Utilities, and Lubbock Power & Light’s request to move its load from SPP to ERCOT.

The PUC is also in the midst of rulemaking projects to improve price formation in ERCOT’s energy-only market, reliability-must-run service and determining rate case procedures for transmission and distribution providers.

And then there’s Sempra Energy’s $9.45 billion bid to acquire Oncor, the state’s largest utility. A federal bankruptcy court has already approved Sempra Energy’s purchase of Oncor and its bankrupt parent, Energy Future Holdings, but the California company must still gain the PUC’s approval. (See Bankruptcy Court Advances Sempra Bid for Oncor.)

The commission has rejected two previous acquisition attempts by Hunt Consolidated and NextEra Energy.

Texas Gov. Greg Abbott last week announced Walker’s appointment as PUC chair to replace Donna Nelson, who stepped down in May. Walker, who served as a senior policy adviser to Abbott on regulated industries, will fill out the remainder of Nelson’s term, which expires in September 2021. (See Texas PUC Chair Nelson Stepping Down.)

ERCOT REV FirstEnergy Corp. William Scherman — PUC Commissioners Anderson (L), Marquez conduct August open meeting. | © *RTO Insider*

Commissioners Ken Anderson and Brandy Marty Marquez have kept the three-seat PUC running while waiting on a new chair. Anderson has served on the commission since September 2008 — a record tenure — though his term expired Aug. 31. Marquez’ six-year term expires in September 2019.

Walker returned to the PUC on Sept. 21, after previously working at the commission from 1988 to 1997 as an assistant general counsel and then as an administrative law judge. She spent 15 years at CenterPoint Energy as director of regulatory affairs and as an associate general counsel, before joining Abbott’s staff.

Walker is a member of the State Bar of Texas. She received her bachelor’s degree from Southern Methodist University and her law degree from the South Texas College of Law.

September 28, 2017

CAISO Requests FERC Rehear PGE Rate Decision

By Jason Fordney

CAISO and Pacific Gas and Electric have asked FERC to reconsider its decision last month to approve only some of the utility’s requested transmission rate incentives related to more than $1 billion in planned grid improvements.

The ISO and the utility on Sept. 25 filed separate requests for FERC to rehear a determination that PG&E had not justified all of its proposed “abandoned cost” recovery, which allows it to recover from its customers the costs of abandoning construction for reasons beyond its control. (See FERC Approves PG&E Transmission Cost Recovery.)

FERC CAISO PacifiCorp TSRs — Timeline and cost of PG&E’s proposed projects | *PG&E*

PG&E in its rehearing request called the incentive request “narrowly tailored” and said it faces significant challenges in developing the greenfield projects that are not in an existing right of way (EL16-47). The utility had requested 100% recovery of costs for any of the eight projects if they are abandoned, but FERC approved incentives for only three of them. The utility said it has already invested $68 million in construction and that the projects face risks, including environmental permitting, siting authority and potential impacts of from California’s renewable energy goals.

“Consequently, under a rigid application of the effective-date limitation imposed in the orders under review, PG&E now faces an unexpected risk of loss equal to 50% of that initial $68 million investment,” the company said, adding that “if allowed to stand, this outcome will create a disincentive for PG&E to make similar investments in the future.”

PG&E said that while the requested incentives would allocate to ratepayers 100% of the risk of abandonment for reasons beyond a utility’s control, “FERC’s orders here shift 50% of that risk for a defined period (before the issuance of a project specific declaratory order) to the utility and its shareholders. This reallocation makes investment in new transmission projects riskier and less attractive.”

CAISO’s filing contended that each project meets FERC’s standard because it was approved by the ISO as part of a regional planning process and that “CAISO approved these specific projects to meet identified reliability needs on the CAISO system.” Project sponsors such as PG&E have an obligation to obtain approvals and rights if the projects are approved as part of the ISO’s annual transmission planning process.

CAISO said it has canceled other projects approved in annual plans and that it is currently assessing whether to cancel other previously approved projects, so “the risk of abandonment is not hypothetical.” When developing its 2015-2016 plan, the ISO canceled 13 PG&E low-voltage transmission projects it had previously approved.

Southern California Edison on April 7 filed a similar request for abandoned cost recovery upon which the commission has yet to rule (EL17-63). The petition requested approval of incentives for a package of transmission improvements totaling about $1.3 billion, approximately $903 million of which are recoverable in transmission rates.

While the California Public Utilities Commission had objected to PG&E’s incentive rate request, FERC rejected the state regulators’ arguments about PG&E’s transparency and cost control.

Earlier this month, FERC in a different proceeding also rejected a protest from the PUC over incentive rate adders the commission had approved for PG&E in 2016. (See FERC Upholds PG&E ISO Incentive Adder, Rebuffs CPUC.)

September 26, 2017

Stakeholders Envision Gigawatts of DER in MISO Footprint

By Amanda Durish Cook

ST. PAUL, Minn. — Representatives of MISO sectors gathered Wednesday to discuss how a greater number of distributed energy resources could interact with the grid. Topics ranged from the gig economy to state jurisdiction to the socioeconomic barriers preventing some from obtaining those resources.

Vice President of System Operations Todd Ramey said DER “such as rooftop solar systems and microturbines” are not as widely used in MISO as in other RTOs.

MISO DER MISO Annual Stakeholders' Meeting Howard Schneider rooftop solar — Johnson | © *RTO Insider*

“However, the MISO region could see a substantially higher penetration of distributed energy going forward as the costs of the resources continue to decline and if cities, states and the federal government continue to adopt policies that encourage their use,” Ramey said.

By 2030, installed photovoltaic resources could top 17 GW, while demand response and energy efficiency deployments could exceed 6 GW and 8 GW, respectively.

Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, kicked off the discussion by engaging stakeholders, MISO staff and board members in a sing-along of Fleetwood Mac’s “Don’t Stop.”

“‘Don’t stop thinking about tomorrow.’ That’s the trend. There hasn’t been much DER activity so far, but we plan for it,” Johnson said.

Defining DER

MISO presented a draft definition describing DER as power generation, storage or load-modifying resources connected either through a utility’s distribution system or behind the meter. DER can include photovoltaics, combined heat and power, cogeneration systems, reciprocating engines, combustion turbines, microturbines, wind turbines, back-up generators, energy storage and even DR and energy efficiency, according to the definition.

Most sectors, including the Organization of MISO States, agreed with MISO’s take. OMS organized an early August workshop in which state regulators and industry officials similarly explored DER topics, and has since formed a temporary work group to consider how to incorporate the resources into the grid. (See Stakeholders Hash out Future of DER at OMS Workshop.)

“Consumers [are] moving to being customers of the grid,” said John Moore, attorney for the Natural Resources Defense Council, who likened the energy customer transition to that of licensed drivers and the rise of Uber’s ride-share program.

Director Baljit Dail seized on the Uber analogy. “There may be a whole new player that comes into the mix and provides a platform for people with DER to sell,” Dail said.

Entergy’s Matt Brown said there will probably be a future need to designate a minimum megawatt participation limit on DER to include them in whatever market definition the RTO eventually settles on. “MISO might not be the appropriated entity to draw those lines,” Brown added.

“The advantage that we have here is that we really have some time to make some really elegant solutions,” Northern Indiana Public Service Co.’s Paul Kelley said.

“Let’s not lose sight of [the fact] that getting paid within MISO is not a trivial matter,” Dynegy’s Mark Volpe said. He said suppliers must go through the process of creating commercial pricing notes, signing agreements with MISO and posting collateral to get set up on the wholesale distribution level — none of which is an easy task.

State Jurisdiction

Minnesota Public Utilities Commissioner Matt Schuerger said that while DER rules will fall under state jurisdiction for resource adequacy, MISO, industry leaders and generation and transmission operators will play a vital role in coordinating and planning. “I think state regulators will need information from MISO to help make decisions,” he said.

Arkansas Public Service Commission Chairman Ted Thomas reiterated a warning issued by former FERC Commissioner Tony Clark at the OMS DER workshop, saying states will get rules mandated to them by FERC if they fail to write their own.

“States can [wait to] act and wait for FERC to act, and what we’ll get is a velvet glove around an iron fist — one size fits all,” he said.

MISO footprint rooftop solar DER — Soholt | © *RTO Insider*

Wind on the Wires’ Beth Soholt pointed out that many Midwest manufacturing plants are already beginning to alter their energy supply mix to meet renewable goals. “You’re going to continue to see this trend ripple through large energy customers,” she said. Soholt said MISO planning might need to look past demand, including at customer preference. She said as long as demand growth remains the single most important factor in transmission planning, MISO will not have a complete picture of the future.

“I think people think, ‘demand is going down, so we don’t need to plan as much transmission or generation. Customers want a particular kind of mix. … I worry about that if we just look at demand in and of itself, that’s not capturing all the value that these resources have to offer,” she said.

At a Sept. 21 Board of Directors meeting, Executive Vice President of Operations Clair Moeller told board members that MISO is overall moving to a “less peak, more load served” model with the contributing factor of electric vehicles.

Missouri Public Service Commission economist Adam McKinnie agreed that the “haircut of load growth” has been an obstacle in recent transmission planning studies by consulting firm Applied Energy Group.

McKinnie said some states, including his own, collect rooftop solar data, and those numbers could be passed on to MISO planners.

“This could be an example of how the states could gather and provide MISO with information, so MISO doesn’t have to guess,” he said.

Dail urged stakeholders to give MISO guidance on DER market rules. “You didn’t want a MISO that picked winners and loser in regards to technology,” he reminded them.

Moore said MISO must avoid “siloing,” referring to the tendency for DER information to remain in just one database.

“Is there siloing occurring at the distribution level that prevents a complete picture of how much distributed energy is bubbling up?” he asked.

Socioeconomic Differences

Brown said MISO and industry leaders must also pay attention to distributed energy trends in wealthy communities versus poverty-stricken areas, contrasting the incomes in the toney Twin Cities suburb of Maple Grove with those of Flint, Mich., both in the MISO footprint.

“It’s easy to lose sight of how large our footprint is. It’s easy to make sweeping statements like ‘customers want this’ or ‘customers want that,’ but we have to remember the range of customers we have,” Brown said.

Director Thomas Rainwater thanked Brown for bringing up the socioeconomic disparity across the footprint.

“I happen to live within 40 minutes from Flint,” Rainwater said. “One of the great inventions of the last 100 years is the electrification of households and the health and economic benefits that it brings … but there are those that have been left behind. I think that we can all agree that while solar is great and wind is great, the early [residential] adopters are in the upper strata. We need to not lose sight of that.”

Director Todd Raba said regulators and industry officials have an “ethical” obligation to pay attention to keeping costs low for their poorest customers.

September 26, 2017

Metcalf Reliability-Must-Run Draws Scrutiny

By Jason Fordney

CAISO this week will gather feedback on its proposal for reliability payments to keep Calpine’s Metcalf gas-fired plant from going offline, a decision drawing scrutiny amid a larger conversation about local resource adequacy (RA) planning.

The ISO relies on reliability-must-run (RMR) contracts to keep resources online that are slated for retirement but are still needed for reliability. It has a stakeholder call scheduled for Sept. 26 to gather feedback on its recent proposal to designate Metcalf as an RMR resource.

CAISO FERC Metcalf substation reliability-must-run agreements — CAISO is Considering an RMR Contract for Calpine’s Metcalf Energy Center | *Calpine*

The contract is slated for a vote by the CAISO Board of Governors in early November, leading some to complain about a quick decision timeline. The board also faced some scrutiny in March when it designated Calpine’s Yuba City and Feather River gas-fired plants as RMR contractual facilities. (See CAISO RMRs Win Board OK, Stakeholders Critical.)

Calpine in June told CAISO that it intends to take the Metcalf plant offline at the end of this year. The company’s request that the ISO study the reliability impact came back in the plant’s favor. “Analysis has indicated that Metcalf Energy Center is in fact required in order to meet the relevant criteria for reliable system operation,” the ISO said in a notice for the call.

At its most recent meeting Sept. 19, the board voted unanimously to extend the current reliability RMR contract for three 55-MW oil-fired units at Dynegy’s Oakland facility. CAISO says it will not renew a contract with AES for the synchronous condensers at its Huntington Beach plant, and those units are expected to shut down.

At the board meeting, Pacific Gas and Electric Director of ISO Relations Eric Eisenman said “these continuing RMR designations show that the market is changing,” pointing to new solar and other resources. He added that “the RA process, especially the local process, needs improvement.”

The RMR contract for Metcalf will put tens of millions of dollars of costs onto ratepayers, he said, asking the board to work with regulators “to improve the local RA paradigm sooner, not later.” He expects more RMR designations for 2019, which will almost certainly raise customer costs.

Noting that CAISO informed stakeholders of the possible RMR designation for Metcalf in early September ahead of the Nov. 1 vote, he said: “We are feeling kind of jammed when it’s tens of millions of dollars.”

Local RA Adjustments Planned

Part of the problem is the way the RA for load-serving entities is measured, CAISO Vice President of Market and Infrastructure Development Keith Casey said at the meeting. RA is currently measured across a broad area, but individual capacity areas within that territory might have inadequate resources.

“We cannot operate being short in a specific area, and I think Metcalf is probably indicative of that deficiency in design,” Casey said. The ISO is working with the California Public Utilities Commission on the problem, and “I am optimistic we will have a proceeding soon to take on some of the deficiencies around the local RA design.” In a Sept. 12 memorandum to the board, Casey said “reliability-must-run contracts remain an important backstop instrument to ensure reliability when other alternatives are not viable.”

RMR contracts are pursued when an LSE does not purchase sufficient capacity to meet local reliability criteria, or when CAISO needs reliability service such as voltage support, black start or dual-fuel capability. RMR can also be used to address local market power or protect availability of a given resource that could retire in the absence of a contract. LSEs are required to provide the RA showing by Sept. 15 of each year and have until Oct. 31 to submit their final year-ahead RA showings. CAISO must notify a potential RMR unit by Oct. 1 of each year whether it will extend an RMR contract.

The number of facilities under RMR contracts has dropped significantly since the implementation of the RA program and the addition of other types of resources. In 2006, CAISO had 9,963 MW under RMR, which dropped steeply to 3,995 MW in 2007. Today, in addition to the Oakland units under RMR, CAISO has about 1,500 MW under black start contracts and about 160 MW under dual-fuel extension status.

CAISO Says Puente Plant Needed

Reliability needs have also led CAISO to conclude that a new gas-fired plant on the California coast cannot affordably be replaced with other alternatives. CAISO on Aug. 16 released its study on the 260-MW Puente Power Project, but NRG Energy has run into heavy opposition to its proposal to build the plant on an existing site in Oxnard to replace its retiring Mandalay and Ormond Beach plants.

The California Public Utilities Commission authorized Southern California Edison to enter into a long-term RA contract with NRG for the plant’s capacity, and the California Energy Commission is reviewing the construction and operating permit for the facility. The project was approved because 2,000 MW of generation in the area is due to retire by 2020 because of once-through-cooling regulations.

As part of its review process, the CEC accepted CAISO’s offer to study whether demand response, energy efficiency, renewable generation and combined heat and power could offset the need for the Puente project. CAISO last month issued its findings in the Moorpark Sub-Area Local Capacity Alternative Study, after gathering comments from market participants.

After examining three scenarios, the ISO concluded that Puente would be the cheapest alternative at a cost of $299 million. The most expensive scenario was “incremental distributed resources plus grid-connected battery storage (if the Ellwood Generating Station is retired)” at $1.1 billion, more than triple the cost of Puente.

RMR revenue helps keep natural gas a player in the CAISO market as environmental opposition toward fossil fuels is on the uptick. Gas remains the largest component of CAISO’s fuel mix, making up about 54% of its installed capacity of 71,400 MW, followed by renewables at 29%, large hydro at 12% and nuclear at 3%. Oil, coal and “other” comprise about 2%.

However, conventional generation such as natural gas makes up only 9% of CAISO’s interconnection queue of 325 projects totaling 58,000 MW, while 68% are renewable projects and 20% are energy storage devices.

Aside from RMR, CAISO also has a risk-of-retirement program called the Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) initiative, which is generally regarded as a better alternative to RMR. (See CAISO Finalizes Risk-of-Retirement Program Changes.) That package of market rules is also due for a vote from the board at its November meeting.