Planners must give more weight to potential pipeline outages in electric reliability reviews, NERC said in a report Tuesday.
“In light of the power sector’s rising reliance on natural gas, the loss of gas facilities must be added to the list of potential extreme contingencies used to measure system reliability impacts,” John Moura, NERC’s director of reliability assessment and system analysis, said in a statement announcing the report.
The report shows the impact of natural gas delivery disruptions will vary depending on the location and density of infrastructure. But the reliability authority says mitigation strategies are available to reduce the potential harm to the electric sector.
Natural gas has had an out-sized influence on electric generation. | Matcor
The report, “Special Assessment: Potential Bulk Power System Impacts Due to Severe Disruptions on the Natural Gas System,” listed several key mitigation strategies, including transmission upgrades, dual-fuel capability, power imports, adding incremental and diverse generating resources, firm fuel agreements and battery storage.
NERC said the power sector is seeing a drop in the number of dual-fuel units. Developers are foregoing the added expense of dual-fuel capability in many new projects, it said.
It also suggests dual fuel, backup pipeline capacity, and alternative sources of supply should be required in areas with significant risk.
“Dual-fuel capability increases generation reliability and resilience,” the report said, noting dual fuel is currently limited by environmental regulations restricting how long plants can run on oil. NERC called for temporary air permit waivers before any “sustained natural gas infrastructure disruption,” saying waivers should be incorporated into “resilience-planning initiatives when they are required.”
The assessment does not directly take on the Department of Energy’s directive that FERC strengthen the grid’s resiliency by propping up the finances of coal and nuclear plants, but it does point out the growing importance of natural gas as a fuel supply.
“Natural gas resources have become much more diversified,” Tom Coleman, NERC’s director of reliability assessments, said during a media conference call. “Twenty years ago, we were more reliant on Gulf [of Mexico] supplies. We have much more shale gas in some of the market areas that has really changed the dichotomy. Due to this diversity, we don’t have the same risks we had 20 [or] 25 years ago.”
The report offers recommendations to policymakers, the industry and NERC itself. It calls for regulators to consider fuel diversity when they evaluate system plans and establish energy policy objectives. It also recommends expedited licensing of new transmission and natural gas facilities to diversify risk.
NERC suggests registered entities consider the loss of key natural gas infrastructure in their planning studies, and that the gas and electric industries increase coordination and information sharing “to promote reliability and interdependent system integrity.”
“As our power supply becomes increasingly dependent on natural gas, industry must ensure this just-in-time fuel is as reliable and secure as the power plants that need the fuel to operate,” the assessment says.
The organization also recommends adding planning and operating requirements for analyzing disruptions to its reliability standards. To mitigate common causes of failure, it said its Generator Availability Data System (GADS) database should begin collecting additional information on the duration, frequency and causes of natural gas outages.
NERC conducted the assessment by reviewing existing studies, evaluating gas storage facilities and identifying generation clusters — areas with at least 2 GW of gas generation — to determine potential vulnerabilities.
NERC’s Generation Clusters | NERC
Coleman said the organization studied 24 areas, 18 of which “demonstrated the need for additional follow-up and analysis, based on power flow and stability issues” of the “extreme cases” it ran.
“We wanted to develop a bookend, a worst-case scenario,” he said.
Coleman said natural gas demand has “altered the storage dynamics,” which have historically operated as an inventory hedge by injecting in the summer and withdrawing in the winter.
“With much more electric generation out there, we’re seeing more of an annual injection and withdrawal cycle, versus just a winter and summer dichotomy.”
The report was received coolly by the American Petroleum Institute, which called it “a missed opportunity to properly examine ways to improve the reliability and resilience of North America’s electric grid.”
It said NERC acknowledged “that natural gas supply disruptions are extremely rare events and … that industry is taking steps to prevent such disruptions.”
It cited its joint report with the Natural Gas Council on resilience, which was released in July.
BALTIMORE — Department of Energy officials and FERC Chief of Staff Anthony Pugliese traveled 40 miles from the capital Monday to make their case for coal and nuclear price supports at the National Association of Regulatory Utility Commissioners’ 129th Annual Meeting.
In the morning, Pugliese and Bernard McNamee, DOE deputy general counsel for energy policy, spoke at a breakfast meeting sponsored by the Consumer Energy Alliance. After lunch, Sean Cunningham, DOE’s executive director for energy policy — and a former lobbyist for FirstEnergy and American Electric Power — lectured the audience on how he said FERC had failed to protect the grid against disaster. The audience included Commissioner Cheryl LaFleur — who kept her head down, writing notes and betraying no reaction.
The department’s Notice of Proposed Rulemaking (RM18-1) was a big topic of conversation both at the microphones and in the hallways at the Hilton Baltimore beside Oriole Park at Camden Yards. But LaFleur and Commissioner Robert Powelson, who spoke to consumer advocates in the morning, had little to say on how they will vote next month on the controversial proposal.
FERC Chairman Neil Chatterjee said last week he will seek an interim “lifeboat” to ensure the survival of struggling coal and nuclear plants while the commission ponders long-term rule changes. Chatterjee has said the commission will take action by Dec. 11 on Energy Secretary Rick Perry’s call for “full recovery” of coal and nuclear plants’ costs in RTOs with energy and capacity markets, including PJM, ISO-NE and NYISO. More than 700 comments were filed in response to the proposal. (See NOPR Backers, Foes Seek Last Word at Comment Deadline.)
LaFleur, Powelson Respond
LaFleur declined to comment on Chatterjee’s plan.
“I’ve really tried to spend my time thinking through the issues and not debating in the press. So, for now, I’ll just stick there, I think,” she said, adding, “But it’s less than a month so you’ll be hearing from us.”
Powelson also declined to say if he would support the chairman’s proposal.
“We’ll listen and see what everybody’s saying,” he said in an interview after speaking to the National Association of State Utility Consumer Advocates (NASUCA), which is holding its annual meeting alongside NARUC. “I don’t want to prejudge any outcomes.
“I’m open to having a broader conversation around valuing resiliency; looking at reliability metrics beyond just the capacity construct. And making sure … that we stay above and out of the fuel war conversation. That’s not the FERC’s role.
“I don’t think the secretary’s asking us to revert on organized markets,” Powelson added. “I think what he’s saying is, look at some of the things that are working in these markets and some of the things that aren’t working.”
But at the General Session after lunch, DOE’s Cunningham made it clear he already knows the answers.
“The bottom line is this: Coal and nuclear power remain crucial to the continued functioning of the electric grid,” he said.
He used a revisionist view of the 2014 polar vortex to make his point.
“Because a large portion of gas supply is diverted to home heating, the grid operators struggled to meet demand and gas generators became unavailable. It was then that coal and nuclear plants came to the rescue. Because these plants are true baseload generators with onsite fuel storage, they successfully met the emergency demand,” he said.
In its response to Perry’s proposal, PJM said the NOPR “mischaracterized and misconstrued” the polar vortex, noting “PJM’s system remained reliable despite nearly 14,000 MW of coal retirements” and saying the 22% forced outage rate had been “mitigated” by the Capacity Performance rules enacted afterward.
“Contrary to the DOE NOPR, neither the 2014 polar vortex nor the recent hurricanes justify upending existing competitive energy markets,” PJM said, noting that some coal plants were idled because of frozen fuel and conveyor belts. “While fuel delivery was an issue during the polar vortex, it was not the driving factor behind outages that occurred during the extreme weather event, nor was gas-fired generation the villain, nor coal and nuclear the savior, that the DOE NOPR suggests them to be,” PJM said.
DOE: FERC Slow to Respond
Cunningham painted a dire future without coal and nuclear generation.
“Unfortunately, due in part to years of pressure brought to bear by opponents of coal and nuclear power, many of those plants were and are scheduled to close, which makes any number of disasters — or just a hot day in October or a cold one in April — a significant potential threat to our grid today. What if they had closed? How would that closure have affected the functioning of our hospitals? How would it have affected our police and firefighting capabilities? How would it have impacted the operations of our military?”
Cunningham said FERC has been slow to respond to the threat.
“FERC has been studying these issues for years, but the problem remains,” he said. “Secretary Perry’s proposal was intended to jump start a long overdue conversation — and more importantly, to spur FERC to action.”
“Washington has been stacking the deck against coal and nuclear power for years despite their benefits to the grid,” Cunningham added. “President Trump’s clear direction is to unleash every energy resource to make America energy dominant. … The president has nominated the people for government service who share that vision and are willing to address the regulatory burdens and government overreach that have limited our growth potential. Secretary Perry is doing, and will continue, to do everything in his power to jeep our diverse energy mix in place.”
Chatterjee Aide Chimes In
During the earlier meeting, DOE’s McNamee also defended the NOPR, echoing Cunningham’s response to critics who fear it would disrupt wholesale markets. Electric markets are not free, they said, but are shaped by policies such as the tax credits for renewables. “The fundamental fact [is] that the markets are distorted,” McNamee said.
FERC’s Pugliese responded to complaints that the commission’s deliberations were being rushed because of Perry’s 60-day deadline.
“I don’t think it is” too little time, Pugliese said. “Within PJM, this has been an issue that has been discussed for three-plus years. But for a lot of places around the country it … wasn’t. And so, all the sudden now we get 60 days, and I will tell you first-hand, every group around the country is coming in, every chance they get, to come give us ideas.”
‘Lifeboat’
Chatterjee laid out his “lifeboat” plans in remarks at an industry conference and in an interview Thursday on Bloomberg television.
In a meeting with reporters last month, Chatterjee said FERC’s options include initiating its own rulemaking, convening a technical conference or issuing a final rule based on DOE’s NOPR.
Now, facing legal and political obstacles to winning approval of a final rule, Chatterjee said he is seeking a short-term plan to rescue as many plants as possible while the commission does additional fact-finding.
“What I don’t want to have is plants shut down while we’re doing this longer-term analysis, so we need an interim step to keep them afloat,” Chatterjee told the S&P Global Platts Energy Podium in D.C. “I don’t know that we can get everybody in the lifeboat,” he added.
“My approach is going to be one of no regrets,” he said in the Bloomberg interview. “The worst-case scenario would be we do the long-term analysis, we figure out we actually did need these plants, but they’re gone. They’re offline and we can’t get them back.”
He said his plan will not alter RTO dispatch practices or distort markets.
Chatterjee also disclosed he had met with FirstEnergy CEO Chuck Jones “to really kick the tires on what they proposed [in their comments on the DOE NOPR] and challenge them on some of what they had put forward.” FERC’s ex parte rules, which bar commissioners from private discussions with parties in “case-specific, contested proceedings,” do not apply to rulemakings, according to a 2010 presentation by FERC Associate General Counsel Lawrence R. Greenfield (18 CFR 385.2201(a), (b), (c)(1)(ii)).
FirstEnergy proposed that the commission require RTOs and ISOs adopt a pro forma Resiliency Support Resource (RSR) tariff agreeing to make monthly payments to “fuel-secure, resilient generators.” The payments would be “equal to its full costs of operation and service” and a “fair return on equity,” minus its revenues for capacity, energy and ancillary services.
Chatterjee, a native of coal state Kentucky and a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), has made no secret of his desire to aid coal generators. Powelson, a Republican, and LaFleur, a Democrat, have reacted more warily to the Perry proposal, expressing concern it could damage wholesale markets.
Awaiting McIntyre and Glick
Republican Kevin McIntyre and Democrat Richard Glick, who were confirmed to FERC by the Senate on Nov. 2, are awaiting their swearing-in and have not commented publicly on the proposal. Chatterjee told Bloomberg that he had not discussed the NOPR or his interim proposal with McIntyre, who will replace him as chairman.
“Kevin is somebody with a lot of expertise. He’s a smart, thoughtful guy. … And I hope that he will ultimately be persuaded to follow the course that I’ve laid out,” Chatterjee said.
Perry’s Sept. 28 proposal requested that FERC issue a final rule within 60 days. But even if Chatterjee won the two additional votes he needs to approve a final rule in December, it could be vulnerable to court challenges on the grounds that it was rushed through without sufficient notice to the public and proper evaluation by the commission.
Powelson said he was looking forward to the arrival of McIntyre and Glick — who cannot join FERC until President Trump gives them their signed commissions.
“Having two other colleagues be part of this conversation is important,” he said. “I think we’ve got a lot of work ahead of us over the next 24 days.”
BOSTON — New England’s transition to a clean energy future may depend more on new transmission lines from Canada than on new or expanded natural gas pipeline capacity, panelists said at a regional energy conference last week.
Speaking at the New England-Canada Business Council’s 25th Annual Energy Trade & Technology Conference, Massachusetts Department of Energy Resources Commissioner Judith Judson said the region is heavily dependent on gas-fired generation, which puts stress on the system at times of peak demand in winter.
“A lot of those generators end up switching to oil and emissions become extremely high,” Judson said. “It also means that we see some very high prices, and one of the challenges is balancing a clean energy future with affordability.” However, a key way to reduce greenhouse gas emissions in the heating and transportation sectors is to electrify, she said.
Massachusetts regulators are at the heart of the current Canada-New England energy conversation. In January, the state will select bidders responding to its July request for proposals for 9.45 TWh/year in renewable energy generation. Hydro-Québec partnered separately with Eversource Energy, Avangrid and Transmission Developers Inc. on three different transmission projects for the Massachusetts RFP and has agreements with Boralex and Gaz Métro to add wind power into the energy mix on each project at the state’s request. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
TDI CEO Donald Jessome agreed that something special is happening between Canada and the U.S. His company is partnered with Hydro-Québec on the New England Clean Power Link, a 154-mile underwater and underground transmission line that would transmit 1,000 MW of Canadian hydropower under Lake Champlain to Vermont. The project bid into the Massachusetts RFP.
“This has been going on for over a decade, discussing how we will connect the two regions, [and] how do we bring clean energy in from Canada,” Jessome said. “How do we get that infrastructure in place? A decade ago, when New England governors and Canadian premiers started talking about this and making that a key issue, people started to take notice. In a lot of ways, it’s happening already today.”
William Hazelip, vice president of business development at National Grid, said, “Market-based solutions are very complicated in design and take time [and] a lot of buy-in from stakeholders. … Long-term contracts are really the key to moving forward with financing renewable energy projects.”
Weak Case for Gas?
Slow growth in retail natural gas consumption could weaken the case for increasing New England’s pipeline capacity, according to one panelist.
“The region needs more gas but not necessarily more infrastructure because we’re adding 2% of new clients every year, but the overall load, yearly based, is not really increasing just because of the economics of energy efficiency,” said Martin Imbleau, vice president of operations for Gaz Métro.
Liberty Utilities COO David Pasieka disagreed.
“When you look at the growth for this particular region, with 1 to 2% growth in customers, when you do the long-term projections, we’re out of gas,” Pasieka said. “There are in Massachusetts a couple of LDCs [local distribution companies] that went into moratorium mode, not being able to expand their customer base. As an LDC operator, I need more customers to be able to justify the spend that I’m currently doing.”
Canada used to get gas from the north, but “all those offshore pockets are drying up,” he said. “Between Marcellus and Utica, this is one of the largest producers of natural gas in the world and the price point reflects it. This will be good for customers if we can figure out how to move it from that part of the world to this part.”
Imbleau countered: “The shoulder months are decreasing, but the peak period is increasing, so maybe what we need is seeking a solution not necessarily in underground facilities with a load factor of 100%, but in facilities that are designed to meet the peak load. They may be more expensive, but [they] make more economic sense in the long run, also in a social sense, including LNG peaking spots differing in different regions.”
Technology to the Rescue
Meanwhile, energy storage is fast replicating some of the attributes of gas-fired generation, Hazelip said.
“National Grid just today announced a 6-MW, or 48-MWh, Tesla battery in Nantucket to help defer the need for a third subsea cable to connect the island to the mainland,” Hazelip said. “National Grid Ventures is also developing two 40-MW batteries on Long Island, which will replace gas feeders. That’s something we’ve seen really pick up speed out in California as well. It’s gotten to the point [that] in some parts of the country, constrained parts of the system, where it’s very difficult to site gas infrastructure, batteries are a great choice. They’re becoming cost-effective, and you can get them built in a much shorter amount of time, and they provide other great benefits that the gas peakers wouldn’t.”
National Grid partnered with Citizens Energy on the Granite State Power Link, an HVDC transmission line to deliver 1,200 MW of new wind power from Canada, and the Northeast Renewable Link, a 23-mile AC line from Rensselaer County, N.Y., to Hinsdale, Mass., to deliver 600 MW of new wind, solar and small hydro into the New England grid.
Imbleau highlighted what Gaz Métro subsidiary Green Mountain Power is doing in Vermont by installing rooftop solar panels and including them in the rate base, as it does with batteries.
“The concept is that it benefits the overall system,” Imbleau said. “It’s a classic example of where the regulatory regime followed technology. Honestly, it’s not happening generally because technology’s probably at 4.0 and regulatory regimes are at 1.0, if we’re generous, so just allowing a regulated entity to play a role, not in the R&D sector, not in the technology that’s available off the shelf, but in the middle spot where there’s a barrier of entry and the technology has a social, economic and environmental benefit.”
Already Happening
Attorney Kevin Conroy of Foley Hoag noted that all of the top 100 largest corporations in the U.S. have set individual renewable energy goals — and many are seeking 100% renewables.
“How are they going to get 100% in some of the communities that they’re operating in?” Conroy said. “Guess what’s happening? Small hydro and solar developers are out meeting with Amazon and Walmart and everyone’s putting solar panels on their roof or doing community solar initiatives. Those things are happening, and it’s happening quite rapidly in California, and I see it in Missouri and see it moving very quickly to this part of the world.”
VALLEY FORGE, Pa. — PJM’s Glen Boyle presented the Operating Committee last week with a proposed solution to address FERC’s proposed primary frequency response rule.
The proposal, which came from meetings of the Primary Frequency Response Senior Task Force, would rely on individual resources to provide the capability with specific performance settings; PJM doesn’t plan on requiring units to maintain operating headroom.
“We didn’t see need for that right now,” Boyle said.
PJM is considering either a cost-of-service payment, where the resource owner files with FERC for cost recovery for performing during an event, or determining that the frequency response capital investment is already included in the cost-of-new-entry (CONE) calculation. The focus comes in response to a 2012 NERC report found that only 30% of units were providing primary frequency response and a Notice of Proposed Rulemaking last year from FERC that would require all new units, excluding nuclear, to provide the service. (See FERC Has More Questions on Frequency Response NOPR.)
“As far as looking at a pure, market-based mechanism, that’s something that PJM would be open to, but we’ve had some difficulties with identifying what the actual requirement is, as it changes on a literally minute-by-minute basis,” Boyle said.
He also highlighted concerns about measuring units’ responsiveness. “So there are some pretty significant challenges to a market-based compensation,” he said. Tom Hyzinski of GT Power Group agreed it would be difficult to develop a market to compensate a minute-by-minute response.
Several generator representatives, including Hyzinski and Calpine’s David “Scarp” Scarpignato, balked at exempting certain technology types and not compensating frequency response beyond capacity payments. Hyzinski suggested developing a product based on a resource’s ability to provide the service.
“You can’t have resources that don’t provide primary frequency response participating in the same capacity market and taking the same capacity payment,” he said, questioning whether the capacity market currently compensates for the capability to provide frequency response.
“I think you’ll want to look at a way that, if they can’t provide it, they somehow purchase … it,” Scarp said.
“That is another option that’s still out there on the table,” Boyle acknowledged.
Scarp said frequency response is an element of resiliency, and “PJM is saying in a lot of forums that it wants to value resiliency.” He asked that PJM staff working on the frequency response issue engage with those focused on resiliency.
Restoration Drills
PJM’s Ryan Lifer reviewed the results of the annual fall restoration drills held recently. There were 108 transmission owner participants, 17 from generators and 47 PJM staffers, Lifer said.
User feedback was positive for a centralized website where participants could upload all information in one location, he said. PJM plans to complete the site in time for the annual spring restoration drill, which will be held May 15-16. Communications checks will happen on May 14. Alternate dates are set for May 21 through 23.
PJM Expects Cold Winter Season
System operators are planning for a colder winter this year than in the past two, PJM’s Augustine Caven said. Analysts expect a weak La Nina effect to develop, causing colder conditions, along with above-average precipitation in the Great Lakes region and below average to the south.
“Southward shifts in the polar vortex caused unusually cold weather this past August, and the expectation is that if this trend continues, we’re anticipating greater risk of arctic cold,” Caven said. “In short, we expect a significant cold winter season, and we’re taking steps to be prepared.”
TOs Must Approve PJM Licensing of DIMA
PJM wants to offer its Dispatcher Interactive Map Application (DIMA) to all TOs, but there’s a catch. Because DIMA requires some confidential TO information to work optimally, all TOs will have to sign off on the plan, and those that want to use it will have to sign nondisclosure agreements and pay PJM a licensing fee.
PJM’s Ed Kovler and Jacqui Hugee outlined the advantages, including compiling data from multiple resources into one geospatial display, and the requirements, which include several Operating Agreement changes.
PJM Holds Ground on Expanding ‘Hot Weather Alert’ Definition
PJM’s Chris Pilong said that the RTO still plans to revise its “Hot Weather Alert” definition to include lower temperatures “during the spring and fall periods if there are significant amounts of generation and transmission outages that reduce available generating capacity.”
The revisions, part of a periodic review of Manual 13, have sparked concern among stakeholders who feel the alert should be very narrowly defined.
“It seems like we’re taking a Hot Weather Alert and turning it into a ‘hot weather and warm weather/stuff is out’ alert,” said Adrien Ford of Old Dominion Electric Cooperative. “My question for you to consider is … should we consider making them separate?”
American Electric Power’s Brock Ondayko said he’s “still opposed” to the procedure PJM is trying to develop. He had initially voiced his opposition when Pilong announced it at October’s OC meeting. (See “Grid Operator Communications Changes Spark Debate,” PJM Operating Committee Briefs: Oct. 10, 2017.)
CARMEL, Ind. — MISO and its stakeholders will devote time to eight projects in 2018, including five-minute settlement calculations, external local resource zones and multiday energy market commitments.
The eight market improvements that MISO management selected from the annual Market Roadmap process were a smaller-than-usual crop of projects in order to make space for the RTO’s ongoing effort to replace its computer market system platform. MISO usually devotes time to about 20 market improvements per year.
“We are trying to significantly scale back, because a lot of resources are needed for the market system enhancement,” MISO Senior Manager of Market Strategy Mia Adams said during a Nov. 9 Market Subcommittee meeting.
In 2018, MISO and stakeholders will work to implement:
Tighter thresholds on uninstructed deviations from dispatch instructions;
Automatic generation control for fast-ramping resources;
The designation of external resource zones in the annual capacity auction — a long-running agenda item at MISO’s Resource Adequacy Subcommittee meetings;
Short-term capacity pricing and reliability standards so energy can be provided within 30 minutes when needed;
Improved combined cycle modeling that can mimic more combinations of combined cycle units;
A multiday energy market that would keep generators with long start-up times switched on for more than one day; and
Rules to factor seasonal needs and risks into the capacity auction — a topic on which MISO is expected to release a white paper next month.
The 2018 work plan does not correspond with the final composite rankings of project importance by MISO, stakeholders and the Independent Market Monitor. For instance, devising a market resource definition for energy storage won top importance overall, but the effort is expected to remain in an idea-gathering stage in 2018. (See “Stakeholders Give Energy Storage Top Spot in Roadmap,” MISO Market Subcommittee Briefs: Aug. 10, 2017.) Other highly rated market projects, including automatic generation control, short-term capacity pricing, improved combined cycle modeling, seasonal consideration and a multiday energy market made the 2018 work plan but won’t be tackled in the order of their assigned importance. Four of the six of the top-rated projects originated from stakeholder requests; the other two came from the Monitor.
Automatic Generation Control Design Work Underway
MISO is currently working on a conceptual design for automatic generation control (AGC) software that will deploy its 400 MW of fast-ramping resources more quickly by regulating either up or down. MISO Executive Director of Market Design Jeff Bladen said the RTO is a year away from a final design stage. It hopes to implement AGC by late 2019.
Uninstructed Deviation
The RTO is nearing a final approach on stricter rules for uninstructed deviation.
Monitor David Patton has proposed a new deviation threshold based on a generator’s ramp rate instead of the current 8% deviation threshold from dispatch signals.
Last month, Ameren Missouri urged MISO to keep the percentage threshold, saying it could be constricted to 7% or 6% over time. The company also asked MISO to only focus on generators that don’t move for an hour within dispatch instructions. (See Ameren Calls for Milder MISO Response to Uninstructed Deviations.) Since then, multiple stakeholders have voiced support for Ameren’s proposal.
Patton said his proposal will result in lower dispatch costs and day-ahead margin assistance payments. He also said the new calculation would save consumers money and result in better reliability.
“It’s surprising there’s not a vocal segment of the market behind this change,” Patton said. “I think asking generators to move at half of the rate they’ve offered with a 20-minute grace period is reasonable.” MISO and Patton will continue to refine an uninstructed deviation proposal in 2018.
MISO Asks for 5-Minute Settlement Delay
MISO will ask FERC for permission to delay the implementation date for its five-minute settlements for four months, Bladen confirmed. The RTO will ask for a July 1, 2018, effective date instead of the existing March 1 target in a filing expected within the next week. The extra time will be used for testing, and Bladen said MISO will let stakeholders know when different testing stages begin.
MISO is also moving back the go-live date on its new computer settlements system, aiming for early 2018 instead of a fourth-quarter implementation. The extra months will also be used for testing the new system.
Are you up for a pop quiz today? OK here we go, and please no peeking ahead to the answers.
Q1. In their comments to FERC on the Department of Energy proposal, how many times did FirstEnergy and Murray Energy use the word “baseload” to refer to the generation they want subsidized?
4
40
400
Q2. What does “baseload” mean according to DOE’s Energy Information Administration, in percent of hours that a plant runs?
About 40% of the time
About 80% of the time
About 100% of the time
Q3. What percent of hours did FirstEnergy’s W.H. Sammis coal plant, our clunker poster child, run last year?
About 40% of the time
About 80% of the time
About 100% of the time
Q4. In their comments to FERC, how many times did FirstEnergy and Murray Energy use the word “premature” to refer to retirement of the generation they want subsidized?
17
117
170
Q5. How old are FirstEnergy’s Sammis units slated for retirement?
18 years
38 years
58 years
Q6. The ages of FirstEnergy’s Sammis units are…
More than the average retirement age of coal plants for every year since 1999.
Less than the average retirement age of coal plants for every year since 1999.
Q7. How much would it cost consumers to subsidize the Sammis units?
$1 million.
$1 billion.
No one has the foggiest idea.
The Answers
The answer to Q1 is c, FirstEnergy and Murray Energy use the word “baseload” an amazing 400 times. Truth by repetition.
The answer to Q2 is c, about 100% of the time. The meaning of a “baseload” plant is one that “produces electricity at an essentially constant rate and runs continuously,” per DOE’s EIA glossary.[1]
The answer to Q3 is a, about 40% of the time. EIA data show Sammis 2016 generation as 8,112,503 MWh[2] relative to Sammis plant capacity of 2,220 MW. So the Sammis capacity factor is 41.7% (8,112,503 MWh divided by 2,220 MW divided by 8,760 hours/year).
Sammis Power Plant | Robert S. Donovan / CC BY-NC 2.0
Let’s pause here to observe that FirstEnergy’s Sammis plant, running about 40% of the time, cannot be a baseload plant, which by EIA definition must run about 100%. It is not even close.
And this isn’t some recent phenomenon due to low natural gas prices and/or renewable penetration. The EIA data show that the Sammis plant has had a poor capacity factor since 2009.
And I haven’t cherry-picked the Sammis plant. The Sammis units are the largest units that FirstEnergy has identified for future retirement to PJM.[3]
That’s why Sammis is our clunker poster child!
OK, back to the answers.
The answer to Q4 is c, FirstEnergy and Murray Energy use the word “premature” an amazing 170 times.
The answer to Q5 is c, 58 years. The retiring Sammis units were built from 1959-1962, per the FirstEnergy website,[4] and they’re scheduled to retire in 2020.
The answer to Q6 is a. The average retirement age of coal plants for every year since 1999 has never exceeded 54 years.[5]
Let’s pause here to observe that the retiring Sammis units are old, almost as old as me. They’re well past the average annual retirement ages of coal plants.
So there is absolutely nothing “premature” about the Sammis units retiring.
The answer to Q7 is of course, c. Nobody has the foggiest idea what it will cost consumers to subsidize the non-baseload, old Sammis units.
And the cost won’t just be squandered consumer money. Keeping clunkers like Sammis around will keep out new power plants that are three times as reliable as the clunkers.[6] Not to mention losing the environmental/public health benefits of cleaner generation.[7]
CARMEL, Ind. — MISO stakeholders will vote on whether to broaden export limits for its upcoming capacity auction after WPPI Energy called for the RTO to act.
WPPI engineer Steve Leovy said MISO has not been distinguishing imports sourced outside the RTO from those sourced inside in calculating its capacity export limit (CEL), making available transmission capacity appear scarcer than it really is. MISO calculates capacity import and export limits for each local resource zone to assure that cleared capacity can be delivered.
“We have a small amount of excess capacity in Zone 1, so we stand to have an adverse financial impact if the limit binds,” Leovy said at last week’s Resource Adequacy Subcommittee meeting.
Leovy said Zone 1’s CEL is 516 MW, but the zone cleared 613 MW in the 2017/18 Planning Resource Auction. Zone 1 — which covers portions of Wisconsin, Minnesota, the Dakotas and Montana — has more contributing external resources than any other zone in MISO, Leovy said.
“We’re concerned with what we see is improper clearing in the coming Planning Resource Auction,” Leovy said. He asked MISO to calculate “appropriate, accurate” limits for the 2018/2019 auction. His motion, calling for the RTO to ensure alignment between the PRA and CEL calculations, will be voted on in an email ballot through Nov. 15.
MISO was planning to update CELs with the creation of external resource zones, but the proposal is now on hold until the 2019/20 planning year. (See MISO Postpones External Zones Until 2019 Auction.)
Laura Rauch, MISO resource adequacy manager, said the RTO still plans to create new CELs that correspond with any new external zones that MISO designates. “Our concern is moving a piece of this forward without the rest of it,” she said.
Rauch also said MISO’s capacity import limits (CILs) and CELs are linked, and it would be inappropriate to update one without the other.
MISO’s CIL calculation was changed to account for counterflows created by exports to neighboring balancing authorities in response to a FERC order in 2015 (EL15-70, et al.). Leovy said a similar change is needed for CELs.
Some stakeholders said that while they could see others supporting an export limit change, they doubted stakeholders wanted to change CILs and local clearing requirements.
‘Shopped Around’
NRG Energy’s Tia Elliott said Leovy made a motion that didn’t result in action during a similar presentation at a spring 2016 Loss-of-Load-Expectation Working Group. “I’m concerned that maybe that this is being shopped around,” Elliott said.
“Thanks for the reminder that this is something that we’ve been discussing with MISO for quite some time. MISO is aware that this is an issue,” Leovy responded. “All I’m asking for is a vote to the timeline to get this fixed, and I don’t think this is forum-shopping or dodging the stakeholder process.”
Elliott also pointed out that the limits have already been set for the upcoming planning year in MISO’s loss-of-load-expectation study, and said changing them now would complicate the process.
Leovy said MISO may be able to implement a fix that doesn’t involve revising its Tariff, because it defines CELs as the megawatts of planning resources that can be “reliably exported” from a local resource zone. He believes the language supports transmission providers modeling the physical location of load and planning resources, giving MISO enough information to differentiate between external and internal capacity.
“So long as a [transmission owner] provides PJM with all of the required information, PJM studies that information and ensures it can reliably [integrate], then PJM must proceed,” Senior Counsel Jim Burlew said during a special informational meeting Tuesday. “PJM is the only entity to make a determination if a TO can integrate, and that’s based only on reliability.”
RTO officials said that procedure is based on the existing Tariff and Operating Agreement language. But members were not satisfied.
“I think the members have some concerns, and I think that PJM has a bit of an obligation to first of all hear, and second of all address, the concerns that may be raised in this forum,” American Municipal Power’s Ed Tatum said. “Why do they want to join the party?”
CFO Suzanne Daugherty, who chairs the Markets and Reliability Committee, agreed that “PJM has an obligation … to make sure you know what’s going on.” But she said CEO Andy Ott “is authorized to accept” membership applications if they don’t hinder reliability, as is the case with OVEC.
“This is consistent with several other parts of the Operating Agreement,” she said. “It’s an open party; there’s no cover charge.”
Tatum continued to press, saying “there is discretion,” and that PJM would be “well advised” to take in further perspectives from members before deciding. Members are concerned that OVEC’s integration will result in significant upgrade costs and increase the existing generation oversupply without providing more load for PJM generators to serve. Tatum said he is specifically concerned about costs from supplemental projects for aging transmission infrastructure and reliability improvements that could be needed if one or both of OVEC’s generating units retire.
OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service a uranium enrichment plant near Piketon that ceased operations in 2001. The department ended the 2,000-MW contract in 2003 but maintains a load that can be 45 MW at its maximum but is generally less than 30 MW.
The company’s two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — are already pseudo-tied into PJM, and its eight “sponsors” can sell their portions of the output into the RTO’s markets. The generation would become internal to PJM following membership, eliminating the pseudo-ties.
“It might be older than Ed Tatum, and although I’m advocating strongly to not be replaced, it might need to be replaced,” Tatum said of OVEC’s transmission infrastructure. “We see major upgrades looming here … and that’s one of the concerns we have. … What we have here is a very unique situation in which you have very little load to allocate to.”
Kyger Creek Power Plant
“Our infrastructure has been consistently maintained for 50 years, meets all NERC requirements and will meet all PJM requirements,” OVEC attorney Brian Chisling said.
OVEC’s representatives didn’t provide many additional details. When Tatum asked about plans for transferring OVEC’s existing load, Chisling said it involved a “feature” of Ohio’s Certified Territory Act and referred him to a proceeding of the Public Utilities Commission of Ohio (15-0892-EL-AEC).
Daugherty explained that any required upgrade would be billed to OVEC’s zone and then distributed proportionally to the eight companies that own OVEC.
PJM’s Mark Sims explained that OVEC is “required to have a plan” for upgrades before it joins but doesn’t need to have upgrades done.
VALLEY FORGE, Pa. — PJM Market Implementation Committee members last week expressed frustration over a proposal from the Independent Market Monitor on price-responsive demand (PRD) requirements, saying they hadn’t been given any time to review it prior to voting on the issue.
Ruth Ann Price of Delaware’s Division of the Public Advocate apologized on the Monitor’s behalf and took responsibility for requesting the late submission, but the measure failed to garner stakeholder backing. The proposal was so unexpected that it didn’t make it into the presentation PJM posted on the issue. It received 28 votes in support, or 15%, far below the 50% threshold for approval.
Two other proposals — one from PJM and the other from Calpine’s David “Scarp” Scarpignato — did receive enough support and will be presented at the Markets and Reliability Committee meeting on Dec. 7. Because of the Thanksgiving holiday, PJM moved the November MRC to the first week of December.
At issue is how PRD will be held to Capacity Performance requirements. PRD was developed before CP existed, but PRD bids cleared the annual Base Residual Auction in May for the first time since the new construct was implemented. PJM has proposed extending annual requirements developed for demand response to PRD and trigger CP penalty assessments during performance assessment intervals when the LMP is greater than the PRD price curve. Scarpignato’s “Proposal C” would make the assessment triggers any performance assessment interval. (See PJM Grilled on Price-Responsive Demand Rule Changes.)
DR provider Whisker Labs had presented another proposal but retracted it in favor of the Monitor’s proposal. The IMM argued that all PRD eligibility and performance should be measured from the participant’s peak load contribution (PLC). Both the planned PRD and the amount finally registered should be measured as the PLC minus the participant’s firm service level (FSL) and performance should be measured as PLC minus the actual load, the Monitor proposed.
“The key difference is that in our proposal, it is based on the total consumption in the summer period,” the IMM’s Skyler Marzewski said.
Carl Johnson, representing the PJM Public Power Coalition, and Dave Pratzon of GT Power Group objected to the proposal’s late inclusion because neither had had a chance to review it and make voting recommendations to their membership.
“It’s tough when totally new proposals come in at the last minute with no explanation,” Pratzon said.
Monitor Joe Bowring explained to RTO Insider in an email following the meeting that his staff provided PJM with its proposal on Oct. 29, more than a week before the MIC, and attempted to present it at a meeting of the Demand Response Subcommittee the following day. He said they were told they could not present on such short notice.
“The IMM’s proposal was included in the posted matrix on Monday prior to the Wednesday MIC meeting,” Bowring said. “The IMM agrees that there was some miscommunication among the IMM, the DRS and the MIC.”
Pratzon requested an explanation for basing all measurements off the PLC. Marzewski said the measurement should reflect how much the participant can reduce from its overall peak demand, not how much it can reduce at that moment. PJM proposed using different peak-demand calculations for summer and winter measurements.
He remained unmoved.
“As of right now, I’m not seeing the justification for the different treatment,” he said.
Gregory Carmean, the executive director of the Organization of PJM States Inc., argued the baseline should be the load that the RTO would have purchased if not for reduction.
“It’s PJM that’s trying to turn this into a seasonal product” by changing the definition of the PRD measurement between summer and winter, he said.
Delaware’s Price, Joe DeLosa of the Delaware Public Service Commission and Greg Poulos, executive director of the Consumer Advocates of the PJM States, also voiced support for the Monitor proposal.
Advocates “want residential customers to be able to respond to price,” Poulos said.
Dave Mabry, representing the PJM Industrial Customer Coalition, argued that the purpose of PRD is to get “the customer back to paying for the capacity that he needs.”
“There isn’t a payment that flows back,” he said.
Scarp argued that point, and PJM’s Pete Langbein confirmed the performance is paid as a credit.
“Call that a payment, call that a credit, but that’s effectively what will happen,” Langbein said.
Scarp said “PRD was supposed to get away from” the “hypothetical difference” between what was scheduled to be used and what was actually used.
James Wilson of Wilson Energy Economics, who consults for consumer advocates in several PJM states, disagreed that the proposal increases winter-adequacy risks. PJM’s reserve requirements study always shows zero loss-of-load expectation (LOLE) in winter, he said, and “there’s a huge margin of excess winter capacity before we get anywhere near where that changes.”
Big Support for Jurisdiction Mention in DERS Charter
Stakeholders voted overwhelmingly to include explicit deference to state and local regulatory authority in the charter for the new Distributed Energy Resources Subcommittee. (See “DER Subcommittee Charter Sent Back to MIC,” PJM MRC/MC Briefs 10-26-17.)
FirstEnergy had proposed what it hoped was an uncontroversial amendment, which stated “Market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the relevant electric retail regulatory authority (RERRA).”
DER companies saw it as a potential barrier to market entry.
“The vagueness of ‘respect the … standards and protocols’ concerns us,” said Tom Rutigliano, who represents providers of distributed resources.
“I think it’s just a matter of clarification. It’s motherhood and apple pie — we have to follow these things. I really wonder why there’s the apprehension to having it in there. … I really don’t understand all the pushback,” FirstEnergy’s Jim Benchek said.
Exelon’s Sharon Midgley agreed. “This would give us a lot of comfort moving forward if this is added,” she said.
They got their wish. The original version of the charter received 17% approval, or just 26 votes in favor, while the amended version received 92% approval, or 160 votes in favor.
Seasonal DR Aggregation Registration Rules
EnerNOC’s Steven Doremus presented a proposed revision to PJM’s DR aggregation registration rules, arguing that the current method fails to maximize use of available resources. The proposal accompanied the first read of a problem statement and issue charge.
The current method is to take as the CP capability the lesser of the registrant’s summer or winter capability. The CP capabilities of the registrants are then added together for a total capability, but this leaves a substantial amount of DR undispatchable.
“The problem we see is this is not the most efficient way to register the customers,” Doremus said.
EnerNOC proposed adding up the summer and winter capabilities of all registrants and using the lesser of the two summations at the overall CP capability “to maximize the value.”
“It wouldn’t change the value; it wouldn’t change the annual requirement,” PJM’s Langbein said of the proposal. “It’s just how do we sum up winter and summer capabilities to ensure there’s an annual capability at the [Reliability Pricing Model]-resource level.”
Meetings Reduction
Responding to a request from the Members Committee, PJM staff reviewed the status of all issues assigned the MIC and subcommittees. Of the 23 issues, seven are completed and will be closed. Three others have proposals awaiting endorsement votes.
At the October Members Committee meeting, Vice Chair Mike Borgatti of Gabel Associates announced that the MIC, MRC, Operating Committee and Planning Committee will be directed to determine if any timelines can be relaxed to “free up a little room in the schedule.” The directive came at the request of stakeholders, who have been complaining about the roughly 500 stakeholder meetings PJM conducts each year. (See “Reducing the Workload,” PJM MRC/MC Briefs.)
Adrien Ford of Old Dominion Electric Cooperative thanked PJM for developing the review and taking a “leadership role” in streamlining the issues.
Account Cleanup
PJM will be automatically terminating accounts on its website that have been locked longer than nine months. The terminations will reduce security risks, as well as improve system performance, staff explained.
PJM.com has 141,000 accounts, but 60,000 have already been terminated. Of the remaining 81,000, approximately 37,000 have been locked for more than nine months, or about 46%. Only about 20,000 accounts are actively used.
Accounts can be restored, but account managers at member companies have been notified to review employees’ accounts and delete any unneeded ones.
CARMEL, Ind. — MISO is proposing to once again revise the equation behind its yearly resource adequacy survey issued in partnership with the Organization of MISO States.
The new adjustment for the 2018 OMS-MISO survey adds a “likelihood” weighting to account for the in-service dates of potential new capacity still in the queue, said MISO Resource Adequacy Coordinator Ryan Westphal.
Including queue resources “is a pretty new process, so there’s no history of a success rate yet,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.
Last year marked the first time the survey began including in its weighted resource adequacy averages a 35% capacity share of projects in the definitive planning phase of the interconnection queue. But MISO at the time didn’t contemplate adding likely in-service dates into the equation. The RTO is now proposing to weight projects represented within that 35% share based on the likelihood they’ll complete the queue by a certain year.
Under the proposal, next year’s survey will weight according to status — 10% for projects not yet started and in the first phase of the queue, 25% for projects in the second phase and 50% for those in the third phase. All projects with signed generation interconnection agreements will count fully toward offsetting resource adequacy requirements. MISO will also credit new wind and solar resources at 16% and 50%, respectively, of nominal capacity.
The new approach to weighting will result in a far lower forecast of potential resources. In last year’s survey, MISO predicted that 2.2 GW of potential resources in the definitive planning phase would come online in 2019. By applying the new weighting to the 2018 survey, MISO expects only 0.1 GW of potential resources will come online in 2019. By 2020, MISO sees 0.7 GW in operation instead of an earlier prediction of 3.3 GW. The in-service forecast climbs to 2 GW in 2021, but that represents just more than half the 3.8 GW predicted last year.
Comparison of MISO potential resources in OMS-MISO Survey | MISO
Before this year, MISO stakeholders had criticized the survey as being too alarmist for not including any potential new resources without signed interconnection agreements. Inclusion of a portion of those resources in this year’s survey showed MISO will have 2.7 to 4.8 GW of excess resources from 2018 to 2022, a departure from the shortfalls predicted in previous years. (See Capacity Survey Shows MISO in the Black.)
Saying the new survey style could “dramatically” impact some zones, Exelon’s David Bloom asked for a zone-by-zone comparison showing how predictions for potential new generation will change from this year to the next.
“By changing the assumptions from year to year, I think what MISO is doing is changing results,” said Kevin Murray, representing the Coalition of Midwest Transmission Customers. “You’re going to go from reporting a surplus in 2019, to reporting a deficit simply by arbitrarily shifting assumptions.”
Westphal asked stakeholders to keep in mind that the change deals only with potential resources still in the queue, which the survey only began including last year. He said all generation with signed interconnection agreements will continue to be counted.
“Did the queue get worse in the last year? Did a bunch of resources drop out? What happened to lose about 2.1 GW in 2019?” asked Indianapolis Power and Light’s Ted Leffler.
Laura Rauch, MISO manager of resource adequacy coordination, said the 35% of new generation used in last year’s survey was not adjusted for the more realistic in-service dates.
“Last year, we took the in-service dates that owners provided with their queue application. Some of those generators hadn’t been studied yet,” Rauch said. She said updated in-service dates for potential wind resources have the biggest effect on MISO’s numbers.
Madison Gas and Electric’s Megan Wisersky said she was concerned change would spark public concern about capacity shortfalls.
“You look at how the survey gets used and abused out in the public,” Wisersky said. “Two things happen when the survey is released to people who don’t deal with these kinds of things every day. One: I know what happens when you show these types of deficits — things get dicey. Two: [People ask if] the queue process is leading to resource inadequacy. And that’s what I’m worried about when people without knowledge of these get ahold of them.”
Westphal said MISO has time to collect stakeholder advice and refine the survey over the next several months.
