Page 1344 – RTO Insider

March 14, 2017March 12, 2024

Overheard at the Infocast ERCOT Market Summit 2017

AUSTIN, Texas — Infocast gathered industry experts in the Texas state capital to share their insights on the “challenging times that lie ahead for ERCOT.” Panelists examined changing market rules, the impact of gas prices on generators, how the delivery of new wind and solar power will change market dynamics, and the revamping of ancillary service market rules during the sessions Feb. 27-March 1.

Donna Nelson, chairman of the Public Utility Commission of Texas, said the state’s competitive market has benefited from lessons learned in California, which opened its electric market to choice in 1998, four years before ERCOT did the same. That has helped the PUC, which oversees the Texas grid operator, to prepare for the 28.6 GW of wind capacity sitting in ERCOT’s interconnection queue.

“Right now, I’d say our market is working because we have a healthy reserve margin and we have fossil-fuel generation to cover [wind energy’s] variability,” Nelson said. “Over time, if that [wind] generation is built, we’ll have to look at what it takes to keep the fossil fuels on. There’s a tension between the workings of the competitive market and reliability. We’ve made a lot of adjustments to the market over time — we want to keep the lights on too — but we have to look at reliability from a short-term to long-term perspective. That’s something the commissioners will continue to watch.”

Nelson recalled a time when integrating 10,000 MW of wind power into ERCOT was considered an “iffy” proposition. “So here we are at 18,000 MW,” she said. “That’s a lot of investment, but lest you label me a renewable hater, it’s made because of the [Production Tax Credit]. When you see other forms of fossil fuel generation is not invested, you ask, ‘Why is that the case?’

“The PTC provides an incentive of $23/MWh. When you look at the average price of power in the ERCOT market, you can see an incentive of $23/MWh has the potential to distort the market,” Nelson said, noting the ERCOT market prices energy based on the amount of generation needed. “If wind bids in at a low price at night, that sets prices in the early morning hours. It’s gotten to the point where [the fossil-fuel plants] generate all their revenue in the summer. You’re going to see less and less of that. You’ll see wind lowering the price in the summer, as well.”

Over time, she said, that will lead to further retirements of fossil-fuel plants. “We won’t have the fossil-fuel generation to back up wind’s variability.”

Dealing with Low Gas Prices in the ERCOT Market

Several panelists discussed ERCOT’s low power prices, their effect on the generating fleet, and forecasts for the future. The ISO’s $24.64/MWh average price in 2016 was the lowest since the market opened in 2002. Natural gas accounted for almost 44% of ERCOT’s power last year, with coal accounting for 29%, wind 15% and nuclear 12%.

Bob Helton, Dynegy’s director of market design and policy for Texas, said he doesn’t expect to see much of a rise in natural gas prices any time soon. “We know the administration is not going to stop fracking … take that for a given. We’re going to have low [gas] prices in the future,” he said.

That will put further economic pressure on ERCOT’s coal units, which have been struggling to compete in the market.

“If prices are low, it’s cheaper to buy off the market … than burn our coal plants,” said John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy, which plans to retire 950 of its 2,300 MW of coal capacity in 2018. “We went through 54 days without burning a single lump of coal last year.”

While Bonnin also said “there’s still a place [for coal capacity] in the summer,” Potomac Economics’ Beth Garza, director of the ERCOT Independent Market Monitor, pointed out much of Texas’ coal fleet was built between 1975 and 1980.

“We’re now in 2017. That would seem to be an economically rational life span for many of these assets,” Garza said. “They’re going to run until something big breaks, and it just won’t get fixed.”

Manan Ahuja, senior director of North American power for S&P Global Platts PIRA, said nuclear units are also at risk in the ERCOT market. “Would these potentially be retired?” he said. “These nuclear units have not made money in the last couple of years. Reliability issues apart, we think the economics are certainly under threat, though they are down in the pecking order as compared to some coal and gas-peaking units.”

ERCOT: Not Really that ‘RUCed Up’

Garza’s recent comment that the Monitor considered 2016 to be “all RUCed up” came up again during the week, once by Garza herself. But were ERCOT’s reliability unit commitment activities — a near quadrupling to 269 “unit days” — last year really that egregious? (See “IMM Year in Review: Low Prices, Windy, Lots of RUC,” ERCOT Board of Directors Briefs.)

“I don’t get bent out of shape about the RUC activities,” said ERCOT COO Cheryl Mele. “I think the operators are doing a good job” reducing the impact on market prices.

“A lot of RUC is a sign the market is working very effectively,” said ERCOT’s Resmi Surendran, senior manager of wholesale market operations and analysis. “If we give the [RUC] instructions, we’re looking more holistically at the whole system. The ERCOT market design gives the right incentive to participate in the day-ahead market.”

Surendran said the ISO’s total net make-whole payments for the last five years has been almost $40 million — the same amount as PJM’s monthly make-whole payments. (However, PJM’s energy and capacity market has a peak load of 165 GW, more than double ERCOT’s energy-only 69 GW.)

Last year, $1.2 million in make-whole was paid to entities that were short generation and another $1.4 million clawed back from generators with offers in the day-ahead market.

While the number of RUC events still concerns Garza, she agreed the financials tell a different story. “Even with the [RUC activity] increase, the cost of doing that … seems to tell me that, yeah, we had a bunch of RUC activity, but I don’t think it was all that inefficient,” she said.

Wind Subsidies Distorting the ERCOT Market?

Appearing on a panel addressing “collapsing” power prices, NRG Energy Director of Regulatory Affairs Bill Barnes said ERCOT’s market is “energy-only in theory” and that “subsidized wind generation” is a problem.

“What we have in ERCOT is very different [from energy only]. It’s been released into the wild, and a lot of things are exerting influence over it,” Barnes said. “NRG invests in renewables. We believe in renewables, but those that stand on their own two feet. We’re beginning to see the impact of those subsidies on the market today.”

Hannes Pfeifenberger, a principal with The Brattle Group, argued combined cycle plants with low heat rates and improved technology have done more to depress prices than wind energy.

“We’ve seen technology costs being reduced so quickly that by the time the PTCs expire, these technologies will be in the market no matter what,” he said. “One thing we have to realize is that baseload will be less valuable in the future, no matter whether the PTC expires or not. More flexible plants will be a market outcome. We will see more retirements because gas prices will remain low.”

“There aren’t price signals right now to build [baseload] generation because we have excess reserves. That’s market 101,” said Katie Coleman, a partner with Thompson & Knight. “I agree with Bill that the PTC and the proliferation of wind is a problem. Anytime you introduce subsidies into a market, you have distortions. Potentially assigning some transmission costs to wind, assigning ancillary costs to wind … those are things I think merit further conversations.”

“This market can solve its problems,” said Philip Moore, vice president of development for Lincoln Clean Energy, who linked the low prices to natural gas and wind. “ERCOT has shown an amazing ability to address the oncoming wind and its own transmission problems very efficiently. ERCOT will find ways to accommodate the energy-only market.”

Solar Envy

While a potential flood of new wind energy has grabbed much of the attention, additional solar power is coming over the horizon, too. Charlie Hemmerline, executive director for the Texas Solar Power Association, said 2016 was the solar industry’s best yet, with 14.8 GW of additional installed capacity creating a 42.4-GW total nationally. Texas ranks ninth nationally with 1,215 MW of capacity.

ERCOT, which almost doubled its solar capacity to 556 MW last year, could see another 2 GW come online by 2021. “Twenty other states have significant solar activity, which means there’s heavy competition attracting people to the state of Texas,” Hemmerline said. “We’re in the mix, but we’re not leading the pack. Our real focus as an industry is to make sure we can make that happen. Our legislative ask of folks is to do no harm. Let’s not do anything to stop this investment or remove anything that would harm us along the way.”

Much of Texas’ utility-scale solar can be found in the wide-open spaces of West Texas.

“The thing we like at ERCOT about West Texas solar is it’s a time zone away from our load centers,” said Paul Wattles, the ISO’s senior analyst for market design and development. “If you’re generating in Pecos County at 2 or 3 in the afternoon, it’s serving peak load in Houston,” he said. “I think you will see more intelligent siting. I think you will see them to where they can make a lot of money during the critical part of the day.”

Residential solar is playing an increasingly large role in the market as well. Wattles said Oncor just passed 10,000 rooftops, thanks in part to what he calls “solar envy.”

“I hear Plano is going crazy” with installations, he said, referring to the Dallas suburb. “Those numbers are dwarfed by California, but it’s something that wasn’t there 10 years ago.”

“Solar envy is definitely a thing,” Hemmerline said. “As people see it, they want it too. [Residential solar] has been here a long time as a someday concept, but when you’re seeing more of your neighbors doing it, it’s propagating to where the costs make it a reasonable decision.

ERCOT is paying attention. “Solar is going to start commanding a larger share of the [distributed generation] fleet,” Wattles said. “My group is concentrating on the big stuff right now, but the little stuff is coming really fast.”

CREZ Project has Benefits, but Stability Issues

ERCOT’s Competitive Renewable Energy Zones (CREZ) project resulted in 3,600 miles of transmission carrying 18.5 GW of West Texas and Panhandle wind energy east to urban load centers at a cost of $6.9 billion. The wind industry’s growth also led to $38 billion in investment across 60 Texas counties and almost 23,000 jobs, according to Susan Williams Sloan, vice president of state policy for the American Wind Energy Association.

“It’s a testament that CREZ brought a lot of benefits to the state,” Sloan said, adding it has also yielded $60 million in annual lease payments to rural Texas landowners. “It’s a new crop for landowners, and allows them to have a passive income. Over the years, there’s even been some landowner wind associations formed to attract wind to their community.”

“We don’t have all our wind in West Texas anymore,” said Sharyland Utilities’ Bill Bojorquez. “We have wind in the south, in the Panhandle and coastal. We don’t have wind peaking at the same time of the day.”

Increasingly, that remote wind generation has led to some stability problems on the ERCOT grid.

“Traditionally, we saw thermal issues. That was the main thing we had to operate and plan around,” said Jeff Billo, ERCOT senior manager of transmission planning. Now, he added, “We’re seeing generation that’s more removed, and we’re seeing more asynchronous generation.”

Fossil Fuels Still Viable Alternatives

Golden Spread Electric Cooperative COO J. Jolley Hayden said his company is moving away from power purchase agreements to quick-starting gas units because of market dynamics. “As the markets get more robust, that’s the resource we’re looking at,” he said.

Using aircraft carriers (coal plants) and PT boats (quick starters) as images, Hayden said, “The big aircraft carriers … if they’re in organized markets, they’re struggling right now. They’re running, and they’re out of the money. The PT boats’ flexibility is essential. The more dynamic the market is, the more flexible you have to be to keep your costs low.”

Coal resources still have their supporters, however. Ingmar Sterzing, vice president of power supply and energy services for Pedernales Electric Cooperative, said coal plants “absolutely” still provide a benefit and their potential value is not priced in the market.

“It’s physical fuel that’s available at the plant, with a supply of 45 to 60 days. That’s unlike any other resource in ERCOT except nuclear,” Sterzing said. “If you’re really in a pinch, coal is there and it’s available. It’s very reliable. Once those coal plants are gone, it’s going to be very difficult to bring them back. You try permitting a new coal plant, and it’s eight to 12 years. You’re going to be stuck with a limited set of options.”

Customers More Informed, Still Hard to Move

Mark Bruce, one of the architects of Texas’ competitive market and principal with Cratylus Advisors, said he is “tickled pink” to see his vision become reality. “The stakeholders wanted to empower customers to become more efficient and make their own decisions,” he said.

But challenges remain.

“We’re seeing sluggish [load] growth. Efficiency is creeping in as customers get more information. They are putting their own generation behind the meter, using storage, getting familiar about time of use. There are more bears in the woods. Our old models don’t fit with the way this is going.”

Michele Gregg, director of external relations for Texas’ Office of Public Utility Counsel, reminded attendees not to forget about retail customers. “We need to remember customers want to spend very little time on electricity,” she said.

“We spend a lot of time in industry meetings talking about what innovation they need … what the customers want and reducing load. The average customer has no idea what load is. They get a bill once a month, they know that bill is too high. In the retail market, the [retail electric provider] is the only one they want to do business with.”

The bills may be high, but the customers still tend to stick with their legacy providers. TXU Energy, which dominates north and central Texas, has seen its rate of departing customers drop from 8% in 2010 to 1% in recent years.

Asked how he would crack the TXU and Reliant Energy legacy markets, Andrew Elliott, director of supply and portfolio management for ENGIE Resources, did not have a ready answer.

While the residential market is not his primary focus, Elliott offered up a story involving his mother-in-law. He said he tried to explain to her she had her choice of retail electric providers, but she would have none of it. “‘This is my electric company. I’ve always paid them.’

“We would love to have the rollover customers,” Elliott said, before repeating the original question. “So how do you crack the TXU-Reliant legacy customers? I don’t know.”

Ancillary Services’ Future in ERCOT

Austin Energy’s commitment to participate in ERCOT’s ancillary services market is a challenge because of the ISO’s average prices, said Kahlil Shalabi, the municipality’s vice president of energy market operations and resource planning.

“[ERCOT’s] pricing is … much different than any other market,” Shalabi said. “If you look at the past month here in Austin, the price dips down close to zero in the morning, then goes all the way up to $18 [per MWh] in the afternoon. If you’re lucky, it goes up to $500 once a month for 15 minutes.

“We’re not looking at future ancillary services pricing for future resource decisions,” he said. “We do see price separation between our load zone and the rest of ERCOT. We want to use our generation to protect our customers when those price spikes happen.”

“The robustness you see in Cal-ISO and PJM with advanced technologies and storage is due more to acceptance by those markets, rather than prices,” said John Fernandes, who left RES for Invenergy after the summit as its director of regulatory affairs. “Those ISOs are setting up constructs that draw developers to those markets. When a system operator chooses to modernize the system to play to the strength of advanced technologies, that generates as much interest as price alone.”

That is why Duke Energy Renewables’ Thomas Paff, manager of RTO/ISO coordination, said his company is not yet buying storage in the ERCOT market.

“We do have some battery systems in PJM where it’s totally different than the outlook here,” he said. “We are making money, but it’s really not that much.”

March 14, 2017

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — PJM’s Asanga Perera came to last week’s Market Implementation Committee meeting prepared to seek forgiveness. But instead of mea culpa, his message was: “Help Wanted.”

PJM’s Tariff requires that it post monthly financial transmission rights auction results within five days, but a series of emails to stakeholders made it clear that wasn’t going to happen this month. PJM was eventually able to post the solution on March 1, and all paths were awarded for the full period.

That said, Perera noted this is the second time in as many years that results of the March auction have been late. An analysis found three contributing factors. Bid volumes and transmission outages played a role, he said, but the major issue was overlapping periods.

Every quarter, four auction periods occur simultaneously, stretching PJM staff and resources to their limits. Perera noted that some staff worked throughout the night to make even the relaxed deadlines. In March, the markets for March, April, May and fourth-quarter auctions are available. The other months with four open periods are June, September and December.

Perera solicited stakeholder feedback, noting that the issue may impact approval of residual auction revenue rights.

In other FTR news, PJM said it will file Tariff changes documenting its new FTR forfeiture rules by April 19. The rules will be retroactive to Jan. 19 — the date of FERC’s order finding PJM’s current rules not just and reasonable — once the appropriate tool is built. The new approach will include several tests to determine the FTR’s impact. Additionally, the forfeiture is only for FTR profits. PJM plans to discuss FTR thresholds and review related Tariff and manual changes at the April MIC meeting. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)

PJM will also be bringing for endorsement next month revisions to Manual 6 to conform with FERC’s FTR compliance order in January, along with other compliance directives.

Vitol Accepts Simplified Solution to Spot-In Issues

Vitol’s Joe Wadsworth, who has urged PJM for years to rectify issues with its spot-in transmission service procedures, said he is willing to accept a smaller revision that would better align daily timelines for when the service is granted.

Wadsworth had been campaigning for a much more sophisticated market-based solution that would apply only to the NYISO seam. The Independent Market Monitor objected that any changes to border operations should apply to all seams. (See “Spot-in Transmission Analysis Expanded to all Interfaces,” PJM Market Implementation Committee Briefs.)

“I always hate to surrender, but I don’t think it makes sense to pursue [the more-sophisticated plan], especially if PJM doesn’t support it,” Wadsworth said. “But there’s significant room for improvement there, not just on the issue I’ve raised but on other issues too.”

He said the challenge with stakeholder leadership — in this case, on cross-border issues — is trying to wrangle both grid operators. Although he said the issue deserves a more comprehensive look by NYISO and PJM, PJM wouldn’t support NYISO’s requirement that it distribute any costs it incurs to PJM stakeholders. The grid operators have been unwilling to proactively address the issue without his insistence, Wadsworth said.

PJM agreed that the issue deserves a closer look.

“It’s tough to say there’s not things to improve there,” said PJM’s Adam Keech, who oversees market operations. “To the extent that stakeholders wanted to take a look at the issue, I would probably say we should look at all the interfaces and not just New York.”

Calpine’s David “Scarp” Scarpignato asked about the prudence of making seams changes without acknowledgement from the other grid operator. PJM’s Chris Pacella, who has led the analysis on the spot-in issue, said PJM has changed its internal procedures — deadlines in this case — and not heard back from NYISO about any problems.

Suction Level Revisions Endorsed Despite Stakeholder Reluctance

Stakeholders approved by acclamation amendments brought by the Independent Market Monitor to a problem statement and issue charge to address minimum tank suction level (MTSL) costs. The vote was quick even after NRG Energy’s Neal Fitch pointed out that the issue was likely considered when annual revenue requirements for black start units were initially discussed.

Left to right: PJM’s Asanga Perera, Chrissy Stotesbury, and Chantal Hendrzak | © *RTO Insider*

“I have to believe this topic was discussed then, so why are we discussing it again?” he asked.

PJM’s Tom Hauske explained that, under the current rules, generators can over-recover their costs for keeping the fuel available. (See “PJM Looking to Avoid Lump-Sum Billing on New Black Start Units,” PJM Market Implementation Committee Briefs.)

The Monitor provided an illustration of a generator with a fuel tank capacity of 4 million gallons and an MTSL of 800,000 gallons, 48,000 gallons of which is the black start portion.

PJM’s original method would allow recovery of the carrying costs on the full 800,000 MTSL, while the Monitor would allow recovery of costs for only 48,000 gallons. “The actual incremental amount of MTSL that results from the addition of black start capability is zero,” the Monitor explained.

Hauske also presented an updated issue matrix for the initiative on annual revenue requirements for new black start units. “At this point in time, I think we’re pretty close” to consensus, he said.

NOPR Analysis: Uplift Bad, Fast Start not Good

PJM staff gave the MIC their analyses of recent FERC Notices of Proposed Rulemaking, making clear they have some strong opinions. Regarding the NOPR on uplift, PJM’s Rebecca Stadelmeyer said the RTO doesn’t support it.

Asked if she could explain why, she said: “Absolutely, I’d love to. I thought we might skip right over that.”

FERC’s first proposal would create two categories for real-time uplift costs associated with deviations: systemwide and congestion management, and charge uplift only in accordance with cost-causation principles. Stadelmeyer said it could be done, but that PJM doesn’t support any parts of the NOPR. (See “Members Approve Uplift Proposals,” PJM Markets and Reliability and Members Committees Briefs.)

More important, Stadelmeyer said, was FERC’s second proposal to distinguish between helpful and harmful deviations and allocate uplift only to harmful ones.

“We’ve continuously said that we cannot find a non-subjective way to isolate whether those deviations help or harm the system,” she said.

There was also some disagreement on the intentions of the NOPR. DC Energy’s Bruce Bleiweis said it stated “fairly strongly” that costs should be allocated to load.

“That wasn’t our read,” Keech said. “If they wanted it to be allocated to load, they probably would have said that.”

On the fast-start NOPR, PJM appeared largely indifferent until it came to relaxing the eco-min of fast-start resources. Doing so “will likely create significant over-generation concerns,” PJM wrote in its presentation. The change could exacerbate already complex uplift allocation methods. (See FERC: Let Fast-Start Resources Set Prices.)

“No analysis could be indicative or identify what the tradeoff would be,” PJM’s Lisa Morelli said. “It would not be a wash. There would likely be a difference between the uplift paid to fast start and the [lost opportunity cost] of resources.”

FirstEnergy’s Jim Benchek asked her to guess at which would be higher, but she said she wouldn’t. Citigroup Energy’s Barry Trayers said that it appeared that much of FERC’s opinion came from a “MISO foundation,” along with lessons learned, when other ISOs/RTOs might have more robust and efficient procedures.

The Monitor largely agreed with PJM’s opposition. “[For] those of you who haven’t read our comments, we think the NOPR is a terrible idea,” Bowring said. “We don’t think the solution is to change the definition of fast start. We think the appropriate way to handle this is to think of it as a tradeoff.”

– Rory D. Sweeney

March 14, 2017

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM’s two-day spring restoration drill succeeded in recovering from a hypothetical blackout, but operators couldn’t re-establish the area control error because the simulation lacked necessary state-estimator data.

“We’ll work on that for next year,” PJM’s Ryan Lifer told members at last week’s Operating Committee meeting.

On Day 1, the initial focus was on energizing black start units to establish cranking paths to ensure safe shutdown of all nuclear facilities. Transmission owners, all of whom were required to participate for NERC compliance, were informed there was no outside assistance. By Day 2, participants were allowed to call in outside resources. PJM worked with members to identify possible tie opportunities, and Lifer said “quite a bit more” were established compared to previous drills. However, there could have been more.

pjm operating committee synchrophasors — | *PJM*

“I think a lot of members focused on establishing internal load before making ties, so we need to encourage building up [reinforcing] the RTO,” he said.

PJM Seeks to Tap Synchrophasors’ Potential

Synchrophasor technology has advanced to being “really in the sweet spot from transitioning from science project to useful product that we can use in the control room,” PJM’s Ryan Nice explained.

Synchrophasors are meters that provide instantaneous real-time data, like SCADA systems but with considerably less delay. The information could be very valuable, Nice said, but only if it’s utilized in a meaningful way. “If you don’t do anything with the data, no value is being generated,” he said.

Part of the issue with synchrophasors is that no one knows their true potential. There is potential, Nice said, for revolutionary applications, such as increasing infrastructure resiliency and compiling the data into system-management tools that can react in real time. One tantalizing possibility is using the data for state estimation without any energy management system (EMS) SCADA input, he said, which would create a state estimator that is almost entirely redundant to the EMS SCADA. Because state-estimator data underpins so much of what PJM does, “even a very marginal improvement in the state estimation improves a whole plethora of other services,” he said.

First, however, resources must be allocated to foundational research, such as simulator training and model validation.

“To buy your roll of the dice [and] get your shot at the really high-value, real-time [applications], you’ve got to do these lower quadrants,” he explained.

For example, PJM has installed some synchrophasor-related applications in its control room, but they aren’t supported well and operators haven’t been trained effectively on how to use them. Nice’s group is developing a simulator for oscillation detection that will interact with trainees like “Choose Your Own Adventure” children’s books. Trainees will be presented with a situation and given options to respond. The simulator will provide feedback on the consequences of the trainee’s decision, along with the next decision to make. It’s a “deeper cut of training than we’ve ever been able to pull off before with this information,” Nice said.

Oscillation detection is important to prevent major system imbalances, but oscillations are very difficult to identify because they can happen between any two points. “This new technology is agnostic about points A and B and just searches for oscillations everywhere,” Nice said.

While the technology is exciting for system operators, stakeholders were concerned about what such critical advances might mean for industry standards and compliance requirements.

Exelon’s Ken Braerman asked if and when Nice expected synchrophasor information to become operationally critical and for his prediction on how many compliance standards would be promulgated affected individual stakeholders.

“We are hyper-sensitive to these issues, and right now we do not consider synchrophasor applications to be NERC or Critical Infrastructure Protection standards-critical,” Nice said. “You can live without this, but it’s good data to have. Right now, we don’t know when we cross that threshold that you can’t live without this.”

Countdown to GridEx

GridEx, NERC’s biennial grid-resilience exercise, is scheduled for Nov. 15 and 16, PJM’s LeRoy Bunyon said. This year’s exercise will focus on cyber and physical attacks that degrade bulk-power system operations.

Of particular interest will be the “cyber kill chain,” which creates a multilayered defense against online attacks. Bunyon said it helps to determine how deep hackers have infiltrated once their presence is identified: “Have they picked the lock? Have they opened the door? Are they in your kitchen? Are they carrying the safe out the door?”

The event organizers will gather lessons learned and develop a report for senior leadership.

– Rory D. Sweeney

March 14, 2017

PJM Planning Transmission Expansion Advisory Committee Briefs

VALLEY FORGE, Pa. — General assumptions regarding winter operations will need to be replaced with actual data to improve PJM’s winter resource adequacy analysis, staff told the Planning Committee last week.

“There’s a propensity for our load model to under-forecast the winter load,” PJM’s Tom Falin said. “This is of concern to us.”

The analysis also found that while the generation forced outage rate for winter rose just 1% from 2007 to 2015, winter’s standard deviation is 4%, more than double the 1.7% for summer. Falin presented a graph that highlighted the increased uncertainty, showing that in one winter week, the forced outage rate could be anywhere from 4 to 12%. Noting that as many as 181 transmission elements, including lines and transformers, were on planned maintenance at some point during January, he questioned whether they could result in deliverability problems.

winter resource adequacy PJM — Plot of Mean With Band of + / – One Standard Deviation | *PJM*

“To get a handle on that will be a challenge for us,” he said, adding that it’s another area that’s not being fully captured in PJM’s loss-of-load expectation (LOLE) studies.

One area to look at might be equivalent forced outage rates – demand (EFORd), which measures the probability that a unit will fail when needed. PJM’s current EFORd calculation is an annual measurement that is independent of other EFORds, weather and other variables.

Falin questioned whether it made sense to develop EFORds that consider seasonal variables. Additionally, the class averages for wind and solar are based on summer measurements, which underestimates wind’s winter availability while overestimating that for solar.

Another issue is modeling. PJM’s modeling tool, PRISM, “is going to say there’s virtually a 0% chance of a 13% outage rate,” Falin said. “The problem is we’ve seen it.”

“We may be getting to a point where wind [generation] captures a big-enough share where we should start capturing turbine’s actual performance and not just assume it’s 13%,” he said.

In November, stakeholders approved a problem statement and issue charge to review PJM’s load forecasting and planning models and methodologies to determine whether the RTO is properly calculating the amount of capacity needed in winter to meet its LOLE targets. The initiative was proposed by economist James Wilson on behalf of consumer advocates for Maryland, New Jersey and Delaware. Wilson and others have questioned why the summer-peaking RTO requires identical amounts of capacity in summer and winter. (See PJM Stakeholders Reject CP Rule Changes, OK Additional Study.)

Staff Moving Forward on Memorializing Competitive Planning Process

PJM staff presented the PC with the first product of their meetings on redesigning the Transmission Expansion Advisory Committee, a new Manual 14F: Competitive Planning Process. The manual mostly codifies processes that previously had been done informally. (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)

PJM’s Mike Herman, who is overseeing the project, said he had been told by Dave Anders, the keeper of all institutional knowledge regarding the RTO’s stakeholder process, that he can’t remember the last time it created a new manual. “So we in planning must be doing something right,” Herman joked.

While PJM acknowledged it’s already received substantial feedback about the manual, staff urged stakeholders to provide all comments for next month’s meeting.

“We would like to move this along next time,” Vice President of Planning Steve Herling said. “We would really appreciate people going through it [and bringing any issues to the April meeting]. The only way we’re going to find out if this works really well if you all test it out and tell us what you like.”

Public Service Electric and Gas’ Alex Stern foresaw an enforceability issue. “Although it is true that PJM hasn’t policed incumbent transmission owners to ensure they are building to minimum design standards, they’ve never had to because state officials more than do that job,” he said. When there’s a problem, customers often call state officials, who call the local utility.

“What happens next is typically things get fixed so that calls … don’t happen further and customer service is at an appropriate level,” Stern said. “State officials aren’t going to know [whom to contact at non-incumbent transmission developers]. When something’s not working, they’re likely going to call their local utilities and PJM’s government relations people.”

Herman also presented proposed administrative updates to Manual 14B to change all occurrences of “special protection system” to “remedial action scheme” per a change to the NERC glossary of terms.

New Design Requirements and Procedure Developments Presented

The Designated Entity Design Standards Task Force introduced its first product at the PC meeting: a document setting standards for overhead transmission. The task force will also be developing standards for substations, system protection, control design and coordination, staff said.

PJM also presented its planned structure for complying with standards released last fall by NERC on geomagnetic disturbance events. The structure includes a five-year implementation schedule that won’t produce assessment results until 2021. Full GMD vulnerability results won’t be available until 2022, when PJM plans to begin developing any necessary corrective plans.

PJM Offers Four RMR Contracts

PJM told the TEAC it has offered generation owners in New Jersey and Virginia reliability-must-run contracts for four units, all of which have received FERC approval.

The New Jersey units — Rockland Capital’s coal-fired B.L. England Units 2 and 3 in the Atlantic City Electric transmission zone — were asked to run until previously approved baseline transmission upgrades are completed. The upgrades were expected to be completed within the next two years, but delays to related projects have made the timeline indeterminate.

PJM also is asking Dominion Energy to keep operating its Yorktown coal-fired Units 1 and 2 until a transmission solution is approved. The plants, on Virginia’s middle peninsula, have been the focus of years of controversy. Their license was extended to April, but environmental groups have been pushing for their closure. Dominion has sought support for installing a 500-kV line from the mainland to the south, but environmentalists have fought that as well. Without approval of the transmission line, PJM has identified reliability issues that would arise if the Yorktown units close. (See Dominion Says Blackouts the Only Solution for Va. Peninsula.)

— Rory D. Sweeney

March 14, 2017

SPP Briefs

The odds of SPP and MISO conducting a second joint study dropped last week with the announcement that the RTOs’ respective regional reviews are not lining up as expected.

spp miso z2 task force — Bell © *RTO Insider*

The two RTOs had hoped to conduct a broad joint study starting as soon as this year that would evaluate regional and interregional projects on the same timeline, eliminating a major stakeholder complaint. (See SPP-MISO IPSAC Turns Attention to 2017 Study.) However, staff told the MISO-SPP Interregional Planning Stakeholder Advisory Committee on Thursday that their respective timelines are not lining up as expected.

“That created issues in scoping and planning. We hope to provide more detail and a schedule,” Adam Bell, SPP’s interregional coordinator, told the IPSAC. “We’re both very committed to doing a study to the extent it makes sense. We’re looking at what flexibility SPP has and what flexibility MISO has to work through the challenges this has presented.”

Bell said MISO’s Regional Transmission Overlay Study (RTOS), which will end in December 2019, is targeting the end of next year to determine transmission projects that can address the RTO’s shifting resource mix. (See MISO Begins 3-Year Tx Overlay Study.) However, SPP’s transition to its new Integrated Transmission Planning process won’t result in the release of an economic study until October 2019.

Under the current timelines, MISO would spend 2019 building a business case around an approved portfolio. SPP is not scheduled to begin building its economic model until the third quarter of 2018.

“The timing is a little off in our ability to go through the process as we had originally envisioned,” Bell said. “It looked like they would match up very well. We would have board approvals at the same time, do interregional work. … Jumping into something before we have all that worked out is not something we need to do.”

Bell reassured stakeholders the two RTOs would still conduct “some sort” of joint planning in 2017 as part of their desire to take a more comprehensive look at reliability and economic transmission upgrades. He said staff would work with their regional stakeholder groups to resolve the misaligned timelines. A follow-up conference call has been tentatively scheduled for April 24.

“We all see the benefit of doing this broader study,” Bell said. “We pretty much know when things will start and finish. We’re trying to see now if there is any flexibility” in the timelines.

Several stakeholders were confused as to why staff had waited until the IPSAC meeting to bring the issue into the open. ITC Holdings’ Marguerite Wagner pointed out one of the goals of SPP’s new ITP process, which was approved last July, was to align it with MISO’s timeline.” (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)

“As far as I know, the SPP process has been developed for months,” said the Wind Coalition’s Steve Gaw. “I’m not sure why it’s this meeting [that you discovered] you have an issue.”

“We’ll get back at the RTO regional level and work on the schedules a little bit,” promised MISO Director of Planning Jeff Webb. “It’s a good opportunity to get them back in alignment.”

The IPSAC spent much of the meeting reviewing each RTO’s planning processes and efforts being made to improve them. The first joint study between the two entities failed to produce a single interregional project; they have focused their efforts since on improving their coordination. (See SPP, MISO Conclude Joint Study Empty-Handed.)

“Someone smarter than me once said the definition of insanity is doing the same thing over and over and expecting different results,” said Eric Thoms, MISO’s manager of planning coordination and strategy. “We want to be more forward-thinking and understand why we are getting drastic differences in our interregional outcomes and studies.”

As an example, MISO’s Ling Lao detailed to stakeholders how the RTOs calculate the adjusted production cost (APC) differently for the Coordinated System Plan (CSP), a separate interregional effort from the joint study. The calculation is used for allocating costs between the two entities.

Lao said the MISO-SPP joint operating agreement outlines the APC-calculation methodology at a high level, similar to SPP’s regional methodology. SPP uses the load LMP for pricing purchases and generation LMP for pricing sales. MISO, on the other hand, uses the generation LMP for pricing both purchases and sales in its metrics.

The load LMP is usually higher than the generation LMP when the system is congested, yielding higher project benefits or APC savings, Lao said. Thoms said MISO is currently evaluating changes to its APC calculation in its Regional Expansion Criteria & Benefits Working Group.

“Using different calculation methodologies introduces equity concerns,” said SPP Director of Interregional Relations David Kelley. “It doesn’t necessarily mean we know one method is better than the other. Could it be MISO is underestimating its benefits? Yes, but on the other side of the fence, you would say SPP is overestimating its benefits.”

The APC was part of a screening process that has whittled the CSP’s list of seven potential joint transmission projects down to three. (See “SPP-MISO IPSAC Turns Attention to 2017 Study, SPP Briefs.)

Staff said the three preliminary projects passing the study criteria are:

A second 345/115-kV transformer in western Minnesota;
A 161-kV line near Kansas City; and
A 345-kV line and a 345/161-kV transformer near Springfield, Mo.

AECI Joint Projects Move Forward

The Springfield project would be in the same area where SPP’s joint CSP with Associated Electric Cooperative Inc. identified two projects: a 50-MVAR reactor at Springfield’s 345-kV Brookline substation, and a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line.

SPP’s Seams Steering Committee took up both projects during its March 8 meeting. The Brookline reactor has an estimated cost of $1.1 million, below the $5 million minimum for SPP seams projects. However, staff said it sees a benefit in continuing forward with the project.

The SSC will meet again March 24 to discuss the project, in hopes of making a recommendation to the Markets and Operations Policy Committee in April.

The Morgan transformer was included in the 2017 ITP 10-Year assessment that was approved by the MOPC and SPP’s Board of Directors in January. The project, valued at $9.2 million, is contingent on reaching a cost-allocation agreement with AECI.

SPP’s monthly market-to-market report to the committee showed MISO sent another $250,762 in M2M payments to its seams partner in January, thanks to a net 230 hours of binding. SPP paid MISO just more than $51,000 for 126 hours binding over 11 temporary flowgates.

MISO has made $14.5 million in M2M payments since the RTOs began in the process in March 2015. When SPP completes two years of the M2M process in March, it will be at the same stage MISO and PJM were when they developed their targeted market efficiency projects on their seam.

The projects address historical congestion issues on the MISO-PJM seam, and MISO and SPP said they are committed to following a similar approach later this year. The process focuses on small, low-cost, short-lead-time upgrades targeted at specific, historical congestion issues.

Z2 Task Force Narrowing its Alternatives

The Z2 Task Force met in Dallas on March 8 to review PJM and MISO’s processes for incremental long-term congestion rights, which the group is considering as an alternative to its current crediting system for transmission upgrades. (See SPP Z2 Task Force Looks for Best of Proposals.)

The task force developed a list of alternatives for sponsored upgrades, transmission service upgrades and generation interconnections. ILTCRs remain a potential solution in each of the three categories, along with the existing Z2 processes, albeit with some modifications.

spp strategic planning committee transmission — KCP&L’s Denise Buffington | © *RTO Insider*

American Electric Power’s Richard Ross and consultant Dennis Reed will also bring proposals to the group’s next meeting. The task force plans to narrow down the list of proposals and then develop the details in order to meet a July deadline with the MOPC.

“We’re a task force,” Kansas City Power & Light’s Denise Buffington, the group’s chair, reminded her team. “We can propose language, but we are going to address the policy question with the board first.”

Buffington said it would be up to the board whether a task force or some other group drafts new policy language.

March 14, 2017

Microgrid Kool-Aid and National Security

By Steve Huntoon

The microgrid Kool-Aid keeps gushing out of the firehose. I wrote a while back about why microgrids are an irrational throwback to the utility islands of the late 19th century.[1]

In a nutshell, microgrids cannot improve on the efficiency of centralized, least-cost dispatch. And in terms of adding reliability, authoritative case studies by the New York State Energy Research and Development Authority found that microgrids would make sense only if annual customer outage time was measured in weeks, rather than the reality of a couple hours.

Yet microgrid proposals continue to proliferate. Especially where subsidized with Other People’s Money.[2]

This column focuses on a microgrid study involving our military bases.[3] This is important not only because taxpayer money is involved, but because our national security is involved.

This study, by a consultancy called Noblis, with assistance from ICF, concludes that replacing backup diesel generators at individual military buildings (the status quo) with diesel/natural gas microgrids at military bases would save money. Their concept is shown in the study’s Figures 4 and 5.

The study includes an incredible amount of modeling and data, no doubt costing its sponsor, Pew Charitable Trusts, a ton of money.

Yet the study is profoundly wrong. The profound error is shown by this “Ownership of infrastructure” pie chart from a Government Accountability Office study,[4] showing who owns the infrastructure responsible for significant outages.

You can see that 87% of outages on military facilities arise on the military’s own distribution systems. Microgrid generation would be dependent on these distribution systems to deliver electricity to individual buildings. Thus, microgrids would cause individual buildings to lose backup for 87% of outages — eliminating the vast bulk of backup.

How could such a profound error be made? The study wrongly assumed that distribution system outages aren’t significant, saying: “Although inside-the-fence problems account for some (unknown) share of all outages, on-base problems can generally be solved through improved maintenance of the base and straightforward investments (e.g., keeping trees trimmed and putting wires underground).”

Instead, on-base problems account for 87% of all outages.[5] And if they were easily avoided, they would be.

In Rumsfeldian parlance, on-base problems are not a “known unknown,” but instead are a “known known.” The study’s profound error was not recognizing this known known.

And another important national security consideration: cybersecurity. The Noblis study talks a lot about cybersecurity, but nowhere does it acknowledge that for microgrids to function as intended, they must have communications links with the greater grid, exposing them to the same cyber risks as the rest of the grid. Backup generators at individual buildings do not need any communication link outside the building.[6]

Beyond these two vital national security considerations, please note one other glaring oversight in the study. This one involves the estimated cost of microgrids.

The study goes through a lot of hypothetical numbers to come up with a capital cost of $17.4 million for a hypothetical microgrid of 24 MW, which works out to $725/kW.

Problem: The Defense Department’s most recent microgrid project at Marine Corps Air Station Miramar in San Diego cost $20 million for 7 MW.[7] That works out to $2,857/kW, which is about 400% of the study’s cost estimate. The study mentions the Miramar microgrid but somehow doesn’t connect the dots to its project cost.

An ounce of fact is worth a pound of hypothetical.

And speaking of fact, the nation’s “flagship” microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.[8]

You can’t make this stuff up.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.

[1] http://energy-counsel.com/docs/Microgrids-Wheres-the-Beef-Fortnightly-November2015.pdf.

[2] Not all the news is bad. Pennsylvania’s consumer advocates got PECO Energy to abandon a $35 million microgrid dalliance, and it appears hundreds of millions for Commonwealth Edison microgrids got cut from the Illinois Future Energy Jobs Act, approved in December, which provides zero-emission credits for Exelon’s nuclear generators.

[3] http://noblis.org/media/b6a465e0-4200-42d8-9377-5f20251e52c0/docs/Environment/Power%20Begins%20at%20Home-%20Noblis%20Website%20Version_pdf.

[4] http://www.gao.gov/assets/680/671583.pdf. Figure 3: Disruptions lasting eight hours or longer in fiscal years 2012-14 as reported to GAO by 18 Defense Department installations inside and outside the continental U.S. The data include wastewater and potable water disruptions, but the vast majority of the disruptions are electric.

[5] This is consistent with outage causation outside of military facilities. About 90% are attributed to the distribution system, as opposed to the higher voltage transmission system. See http://www.eei.org/issuesandpolicy/electricreliability/undergrounding/documents/undergroundreport.pdf, Figure 3.3. (Compare the customer interruptions on the combined transmission/distribution system to interruptions on the distribution system alone). One driver of this is that the transmission system is designed with redundancy, so that if one element (a transmission line, a transformer, etc.) fails, there is no loss of service. The distribution system generally is not designed with such redundancy.

[6] Individual backup generators also would seem less vulnerable to electromagnetic pulses (EMPs) because they are simpler, not connected to the grid, and do not operate unless there is an outage. Noblis says that EMPs are “beyond the scope of this report” (footnote 10), which begs the question: “Why?”

[7] https://microgridknowledge.com/military-microgrid-projects/.

[8] http://www.eenews.net/stories/1059996047 (“The university’s two 13.5-MW Trident turbines were running full-bore when power from the utility abruptly went dead. With no time to shed their load, the turbines also shut down, and the campus lost electricity.”)

March 14, 2017

MISO to Fix Recently Discovered Tariff Mistake

By Amanda Durish Cook

CARMEL, Ind. — MISO will file with FERC to correct a recently uncovered eight-year-old Tariff mistake related to the RTO’s day-ahead margin assurance payment.

The RTO has found that Module C of its Tariff contains language saying that any resource that incurs an excessive or deficient energy deployment charge during one hour will be “ineligible for [day-ahead margin assurance payment] in that hour and all remaining hours in the day-ahead transmission provider commitment period.”

day-ahead margin assurance miso tariff — Page from MISO Module C Tariff | *MISO*

The problem: MISO prohibits the receipt of the day-ahead margin assurance payment only for the hour in which the resource incurred the charge; it does not observe an hours-long disqualification. The Business Practice Manuals limit payment ineligibility to the single hour the charge was incurred. A longer disqualification would restrict dispatch flexibility, the RTO said.

Despite the discrepancy between the Tariff and manuals, settlements have reflected guidelines in the latter since the beginning of MISO’s ancillary services market in 2009, said Jeff Bladen, executive director of market design. The erroneous language does not represent current or historical practice, Bladen said, and the error is not repeated in BPM language or MISO training manuals.

“The practice described in the Tariff was neither the intended method nor has it ever been used by MISO before or since 2009,” Bladen said at a March 9 Market Subcommittee meeting.

MISO will submit a Section 205 filing with FERC to remove the Tariff language and payment eligibility will carry on as usual, Bladen said.

“MISO immediately reported the issue to the FERC Office of Enforcement,” Bladen said. The error was uncovered during “unrelated” Tariff research.

Bladen said neither MISO nor its Market Monitor support resettlements, and no gaming was discovered.

David Sapper of Customized Energy Solutions asked what efforts the RTO could make in the future to catch Tariff errors.

“We are regularly undertaking compliance reviews. … We are subject to FERC compliance reviews,” Bladen said. “The level of obscurity of this Tariff language is evidenced by the fact that this wasn’t uncovered during those reviews.”

March 14, 2017

Overheard at NECA Renewable Energy Conference

AUBURNDALE, Mass. — About 200 people attended the snow-delayed Northeast Energy and Commerce Association Renewable Energy Conference on March 6. Here’s some of what we heard at the conference, which was rescheduled after a February snowstorm forced cancellation of the original date.

Offshore Wind

Offshore wind was a frequent topic in the opening session on emerging trends in renewables, which featured Matthew Morrissey, vice president of Massachusetts operations for Deepwater Wind.

NECA renewable energy conference — Morrissey (L) and Fioravanti | © *RTO Insider*

The company, which began operating the nation’s first ocean-based turbines off of Block Island, R.I., in December, won a contract from the Long Island Power Authority in January for a 90-MW wind farm off the island’s Southern Fork. It also hopes to grab a piece of the big prizes to come: Massachusetts and New York have set goals for a combined 4 GW of offshore wind by 2030.

Unlike in Europe, which has a mature offshore industry, the U.S. does not have a fully developed supply chain for developers. Thus, Morrissey said, his company has been tapping the expertise and supply chains of offshore oil and gas drillers.

“There is a lot of commonality between the expertise and innovation that the United States has developed in that industry — putting large structures in the water — and we wanted to tap that both for our benefit but also because … we have to keep costs coming down, and in order to do that you have to have local, stateside … manufacturing,” he said.

Morrissey and fellow panelist Richard Fioravanti, a principal with engineering and scientific consulting firm Exponent, said they were not overly concerned about the federal government reducing its role in energy research under the Trump administration.

“I see [renewable power] as a large, growing opportunity, and when there are opportunities, money follows,” Fioravanti said.

“I would say that 10 years ago, a slowdown in research would have been a problem,” Morrissey said. “But for the 10 or 15 or 20 years, the industry giants — like Siemens and General Electric and Vestas — [will be] driving innovation from a blade design point of view. And a lot of the foundation work they’ve done in the last 20 years — both in the U.S. oil and gas industry as well as the European offshore wind — with fixed bottom foundations, will drive the growth and cost curve downward … regardless of R&D coming out of Washington.”

Morrissey said the offshore industry also can seek support in D.C. by touting its job creation potential.

“When you look at the kind of places with offshore wind-created economic opportunity, those places tend to look like post-industrial, urban forgotten cities like Fall River or New Bedford [Mass.] or other cities like that along the Atlantic seaboard, which actually tend demographically to look a lot like southern Ohio or western Pennsylvania [where Trump did well in the November election]. So we think that there is an underlay of opportunity to talk to the Trump administration about.”

New England’s Duck Curve

Michael Giaimo, senior external affairs representative for ISO-NE, used “duck curve” slides to demonstrate how growing solar photovoltaic penetration is affecting the RTO’s ramps and system peaks. The RTO had 1.9 GW of behind-the-meter solar PV as of the end of 2016, more than two-thirds of it in Massachusetts.

While increasing PV boosts the need for ramping capability during the daylight, it does not affect the system peak in the winter, which typically occurs at about 7 p.m.

But PV generation could begin causing minimum generation emergencies in spring afternoons once PV generation reaches 3 GW, the slides showed. In the summer, increasing amounts of PV will push the net load peak later in the day, from 5 p.m. at current penetration, to 6 p.m. once penetration reaches 3 GW and 7 p.m. at 6 GW or higher.

“The low demand on a normal traditional day is like in the 3 a.m. timeframe,” Giaimo explained. “When you start getting about 3,000 or 4,000 MW of solar, our new low demand for the day happens about 3 in the afternoon. We [are going] from a system that had a low at 3 a.m. to now a system that has a low at 3 p.m.”

A Handful of States Writing the Rules on Community Solar

Eric Graber-Lopez, president of BlueWave Capital, talked about the delayed promise of community solar, noting that solar power adoptions still retain a “barbell” shape, with more than 90% of the market in residential rooftop panels or utility-scale facilities.

Legislative and regulatory debates, net metering capacity limits, program transitions and interconnection problems “have pushed back the promise of community solar,” Graber-Lopez said. “The U.S. installed about half of what it expected to install in 2015, and it was expected to install about two-thirds [of earlier estimates] in 2016.”

Community solar — which Graber-Lopez argues is a “proxy” for distributed generation in states such as Massachusetts — provides a way for renters, apartment dwellers and low-income housing residents to participate. “The problem is there’s no such thing as a DG industry. It varies state by state,” he said.

Massachusetts has been number two to California in DG deployment every year since 2014. Massachusetts, Colorado, Minnesota and New York account for 97% of the national pipeline for community solar over the next five to six years, he said.

“So there’s a lot of talk about the deployment of DG — and by extension the deployment of community solar — but the fact is that there are four states that are setting the standard for how this industry is going to look going forward,” he said.

Another 10 states are pursuing regulations or legislation “trying to either create, stop, modify or enhance DG,” he said.

Ex-DOE Official Hopes Climate Progress is in Economy’s ‘DNA’

In a keynote speech, Kevin Knobloch, chief of staff for the U.S. Department of Energy between 2013 and 2017, said the Trump administration may not do as much to reverse Obama-era climate policies as some fear.

President Trump and EPA Administrator Scott Pruitt, who have expressed skepticism over humanity’s role in global warming, are expected to attempt to cancel the Clean Power Plan. Trump also may withdraw the U.S. from the Paris Agreement on climate change.

But Knobloch, a former president of the Union of Concerned Scientists, said the renewable energy gains made during Obama’s term won’t be reversed.

“The Department of Energy’s early and robust investment in clean energy and low-carbon technologies, with similar investments by industry and the research universities, coupled with forward-leaning and clear public policies, have contributed to dramatic cost reductions and increased deployment of clean energy and ultra-efficient technologies,” Knobloch said. “And clean energy companies, like many of you represented here in this room, are consequently … well positioned to lead and compete in the rapidly emerging multi-trillion-dollar market for clean energy technologies.”

He noted that 195 countries signed the Paris Agreement to reduce their carbon emissions. That’s “195 markets for clean energy, renewable energy,” he said.

Knobloch said the dramatic budget cuts proposed by Trump to EPA and other domestic agencies to fund Defense Department increases would require undoing Congress’ sequestration rules.

He also noted that Congress’ last two major energy bills — the Energy Policy Act of 2005, which authorized loan guarantees for greenhouse gas control technologies and tax credits for alternative energy producers, and the 2007 Energy Independence and Security Act, which updated energy efficiency standards for appliances, residential boilers and other equipment — were approved with bipartisan support. He predicted Republicans such as Sen. Charles Grassley (R-Iowa) would fight any early termination of the wind production tax credit, which is due to be phased out over three years, ending after 2019.

“We also know that it is not so easy to reverse rules like the Clean Power Plan or the energy efficiency rules … with their extensive … rounds of formal public comment periods, prospects of legal challenge. These are all designed on the foundation of laws that were directed by the Congress.

“My hope is having achieved or made dramatic progress toward a lot of those goals, that renewable energy, energy efficiency … is now in the DNA of the economy,” he said. “Those jobs are real. Those tax payments are real. The business plans and technology investments are all real and that that will carry on.”

Lack of Tx in Multistate RFP Puzzles Developer

About 900 of New England’s 1,300 MW of wind is in Maine. But the resources can’t fully access the markets because of insufficient transmission. So Stephen Conant, senior vice president of Anbaric Transmission, said that he was mystified when officials running a clean energy solicitation for Connecticut, Rhode Island and Massachusetts included no transmission projects in their shortlist of projects last October.

Anbaric had proposed a project to unlock Maine’s bottleneck and another project to deliver New York wind power and Canadian hydropower into Vermont. (See New England States Move Toward Renewables Contracts.)

“There’s all kinds of theories out there,” Conant said during a panel on the role of transmission and energy storage in integrating renewables, when asked to explain why his and other transmission projects were shut out. “We’re all sort of scratching our heads.”

Also in that session, Dan Berwick, general manager of the energy storage division at Borrego Solar Systems, said he was not dismayed by the limitations of current battery technology, which remains expensive for many large-scale, long-term storage applications.

“I’m pretty convinced we don’t need a technological breakthrough right now — that the reductions in cost and the improvement in quality and performance that we’re going to see through increasing repetitions and scale is capable of delivering a four- or five-fold decrease in … cost.”

– Rich Heidorn Jr.

March 14, 2017

PJM Fuel-Cost Policy Changes to Take Effect in May

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM expects to implement its new fuel-cost policy rules on May 15, PJM’s Jeff Schmitt told the Market Implementation Committee last week. That would require generators to file any policy changes by March 15 to guarantee approval before the transition date.

PJM fuel-cost policy — Schmitt | © *RTO Insider*

Despite its looming implementation, the new rules continue to raise substantial questioning from stakeholders, which PJM is attempting to address with a FAQ document.

On Feb. 3, FERC largely accepted PJM’s proposed rule changes, siding with the RTO in requiring that policies be verifiable and systematic but not algorithmic, as Monitoring Analytics, the Independent Market Monitor, had proposed. (See FERC Seeks More Details on PJM Fuel-Cost Policy Proposal.)

The Monitor said the policies should be based on a simple average of broker quotes, bilateral offers or a weighted average index price posted on the Intercontinental Exchange (ICE) trading platform. The commission said the Monitor’s insistence that policies be “algorithmic under all circumstances” ignores how natural gas markets operate during stressed conditions that may make them illiquid, potentially understating generators’ real costs.

The Monitor contends the term “algorithmic” is misunderstood by PJM and by FERC. Algorithmic simply means a step-by-step process to get from a defined input to an output; it is therefore virtually impossible to have a verifiable policy that is not also algorithmic, it says.

Schmitt, the manager of market analysis, said PJM’s verification documents the steps taken daily to develop cost-based offers that do not change based on variables. He walked through the documents necessary for an approved policy, including filing a numerical example for each cost-based offer, likely on a spreadsheet, in the Monitor’s Member Information Reporting Application. While generators’ decisions won’t be challenged during the policy review, it’s critical for them to note whether they include emissions and variable operations and maintenance in their offers, he said. The Monitor has required a numerical example for all approved fuel-cost policies for more than two years.

Stakeholders expressed concern that the rules for dual-fuel generators appeared to not allow the flexibility to switch between fuels as desired, essentially requiring a forced outage. PJM and the Monitor said that the preferred resolution would be to create a cost-based offer for each fuel type.

FERC made “a pretty strong statement” on the separate fuel-type offers, and that “flies in the face of only needing one cost-based offer for dual-fuel units,” said Catherine Tyler Mooney of Monitoring Analytics.

“If we commit you on a gas schedule, and you run on oil, that risk exposure is 100% yours,” said Adam Keech, PJM executive director of market operations. “Our intention is not to put you on a forced outage when you have fuel.”

As long as a generator has an approved cost-based offer, “we think [it] should be able to switch as needed based on physical requirements,” Monitor Joe Bowring said.

PJM and the Monitor also addressed ongoing questions about their relationship in approving policies. The sides appeared to have settled their differences, as the tone of their comments were markedly less confrontational than they had been at recent meetings. (See Stakeholders Caught in PJM-IMM Dispute over Fuel-Cost Policy.)

“Once we’ve been through reviewing the policies, it makes it easier for PJM,” Bowring said. “I can’t think of one we’ve approved that PJM hasn’t approved. … It’s proven efficient to go through us first.”

“It’s been helpful for PJM folks to be in listening mode during the IMM negotiations,” said Stu Bresler, PJM senior vice president of operations and markets.

However, the Monitor’s late submittal of proposed revisions in Manual 15 regarding its role in the policy-review process created some heartburn among stakeholders. Before the agenda had even been discussed at the beginning of the meeting, Gary Greiner, director of PJM market policy at Public Service Enterprise Group, questioned why the Monitor had been allowed to file such a late addition. Bowring responded that when his group must respond to late filings, it becomes impossible to avoid filing them late himself.

Mooney explained that the Monitor’s proposed changes would enunciate the separation between it and PJM in the approval process.

“Working together is happening, but it should be clear that the reviews are separate,” she said.

Bob O’Connell of Panda Power Funds questioned why the Monitor elected to propose that it “may” provide its recommendation regarding policy approval to PJM in writing. He requested that it be changed to “shall.”

“Not having that recommendation in writing is troublesome,” he said.

Bowring responded that the Monitor plans to provide its recommendations in writing and that it is always very clear with market participants about issues with fuel-cost policies.

March 14, 2017

MISO Market Subcommittee Briefs

CARMEL, Ind. — MISO will make two changes to improve its year-old emergency pricing structure by this summer in addition to the two emergency pricing floors rolled out last year, RTO staff said during a March 9 Market Subcommittee meeting.

The first change: Commitment costs of offline fast-start units will be allocated into the minimum runtime when calculating the offer floor for emergency prices.

day-ahead margin assurance payment miso market subcommittee — Akinbode | © *RTO Insider*

The second: Emergency-committed units dispatched at their economic minimum prices will be allowed to set those emergency prices.

The two changes were the only selected among the five proposed by MISO staff after a July 2016 emergency event resulted in depressed prices. (See “MISO May Tweak Emergency Pricing Floors,” MISO Market Subcommittee Briefs.)

MISO engineer Oluwaseyi Akinbode said the modifications are meant to produce more efficient prices.

“If you believe what the planners are saying, there’s a chance we will get into these emergency conditions this summer, and we want to be prepared for that,” Akinbode said.

New User Group Aims to Improve Ease-of-Use in MISO Apps

MISO will later this month debut a new Application User Group for people who use the RTO’s technology.

April Peterson, a representative from MISO’s asset registration team, said the group will focus on improvements and common challenges market participants face when using the RTO’s computer market applications. She said attendance is also open to MISO software vendors and IT specialists that are contracted to make software changes.

Peterson said MISO aims to hold conference calls monthly, with the first call scheduled for March 23.

Potential Cost Recovery Gap in Manual Redispatch

Day-ahead resources can see gaps in cost recovery when they are manually redispatched offline — and a Tariff change could remedy the problem, MISO staff said.

When the RTO decommits a day-ahead resource, the day-ahead margin assurance payment does not take into account the resource’s minimum down times or start-up costs for reimbursement, said Jason Howard, MISO market quality manager.

Howard said yet-to-be-written Tariff language could “close the gap.”

“The manual redispatch might only last four hours, but a minimum down time for a resource might be seven hours,” Howard explained. “Our current day-ahead margin assurance payment does not account for these situations.”

Proposed Tariff language will be presented at a future Market Subcommittee meeting.

— Amanda Durish Cook