MISO is planning to file with FERC in October a proposal to create two new benefit metrics to appraise new market efficiency transmission projects.
Following on its promise to create more specific benefit metrics, the RTO will propose to consider the cost of avoided reliability projects and reduced settlement payments on SPP’s transmission between MISO Midwest and South. (See “New Benefit Metrics,” MISO Planning Subcommittee Briefs: June 12, 2018.)
“We’re looking for physical reductions at this point,” MISO Director of Strategy Jesse Moser said during an Aug. 14 Planning Subcommittee meeting. He said MISO is initially seeking a “straightforward” approach to determining whether a project will reduce annual payments to SPP for flows above the contract path capacity between Midwest and South. MISO may be open to more in-depth analyses on contract path reductions in the future, he added.
Moser said transmission owners and state regulators must be able to work together to allow MISO to use avoided reliability projects to gauge the monetary value of an MEP.
“You’re really asking a transmission owner to take a project off their books,” which requires regulator approval, Moser said.
Moser said if a TO is unwilling to drop a project, MISO members could always pursue the RTO’s alternative dispute resolution process.
“We don’t expect that to occur, frankly,” he added.
Inverter Connections Testing?
MISO is debating which route it should take to ensure that inverter-based generation interconnecting to weaker sections of its grid doesn’t disrupt operations.
After reviewing stakeholder suggestions, MISO said it could require inverter-based generators to conduct their own Electromagnetic Transients Program (EMTP)-type study and perform to a standard. It could also revise its own generator interconnection agreement to disallow “momentary cessation” of active power output from inverter-based resources in order to prevent them from tripping offline unnecessarily.
Generator interconnection engineer Warren Hess said MISO is seeking the best approach to prove the system won’t suffer degraded reliability from inverter-based generation interconnections.
“We do want you to demonstrate that your machine can operate with no adverse impacts,” Hess said.
In feedback, multiple stakeholders said MISO should require a test for inverter-based generation, with some saying each interconnection customer be required to provide under- and over-voltage trip settings as part of their definitive planning phase application process of the queue.
But some stakeholders said requiring an EMTP study by default could become a burden, claiming that some inverter-based generation will connect to a strong point on the system and won’t require testing.
“These studies can be time-consuming and costly … it’s not just a simple thing,” said Wind on the Wires’ Rhonda Peters.
Others pointed out that allowing too many inverter-based generators on the system aggravates reliability issues.
MISO Frequency Performance up to Snuff
Final results from MISO’s NERC-required under-frequency load shedding study show that generators are performing to standard.
The RTO studied seven under-frequency load-shedding islands in MISO Midwest and initially found that the frequency performance in four exceeded the NERC requirement. (See “Generators Miss 1st Pass in Under-frequency Study,” MISO Planning Subcommittee Briefs: June 12, 2018.)
All seven islands now meet both a frequency and volts-per-hertz performance threshold, said Anton Salib of the RTO’s expansion planning group. MISO tested the islands by simulating a disturbance to cause imbalance between generation and load, Salib said.
As a result, MISO said no changes are needed to its current treatment of the islands.
MISO will conduct its next under-frequency load shedding study in 2020, when MISO South is due for five-year testing.
Critics are attacking the motives of New England’s major utilities, which last month asked FERC to clarify its July 2 order denying an ISO-NE request to waive certain Tariff provisions to keep Exelon’s Mystic generating plant running.
The RTO filed the request after Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022. (See NEPOOL Debates Fuel Security, Cost Allocation.) In rejecting the request, the commission ordered ISO-NE to revise its rules to allow cost-of-service agreements for plants needed to address fuel security issues (ER18-1509).
On Aug. 1, National Grid and Eversource Energy, on behalf of their electric distribution companies (EDCs), filed a motion for clarification and expedited action on the commission’s waiver order.
The utilities said the commission “must clarify that the central purpose of ISO-NE’s July 1, 2019, filing of permanent Tariff revisions is to assure that New England adds needed new infrastructure to address the fuel supply shortfalls and associated threats to electric reliability.”
In comments filed with FERC, critics of the EDCs’ request were blunt in their opposition.
Massachusetts Attorney General Maura Healey on last week submitted an answer to what she termed the EDCs’ “self-serving” motion.
“Eversource and National Grid — both of whom could profit significantly from potential investment in pipeline infrastructure in the ISO-NE region — encouraged the commission to address the issues outlined in the waiver petition by mandating ‘investment in new infrastructure — in the case of New England, namely natural gas pipeline capacity,’” Healey said.
natural gas compressor station | Metropolitan Engineering
Eversource and National Grid are co-developers with Spectra Energy Partners on the Access Northeast project, a proposed $3.2 billion expansion of the Algonquin Gas Transmission pipeline in New England. (See DC Circuit Denies Rehearing on Algonquin Pipeline.)
Procedural Grounds
The Environmental Defense Fund (EDF) filed comments asserting that “FERC should reject the EDCs’ motion on procedural grounds alone. … The commission is not obligated to accept a filing solely based on the party-bestowed title. Instead, FERC examines the substance of the pleading.”
EDF said the utilities correctly identify a fundamental misalignment between the gas and electric markets, but that their proposed cure would exacerbate the disconnect.
“Imposing long-term financial obligations on captive ratepayers for costly long-lived infrastructure would contravene the commission’s pro-competition regulatory model and upset the price signals sent by a rational market, undercutting the investment expectations upon which billions in recent energy infrastructure was underwritten,” the group said.
EDF also argued the utilities are seeking to impede that stakeholder process, saying the RTO “has already refined its thinking on fuel security issues, revising its nomenclature from ‘fuel security’ to ‘energy security.’ This is an important recognition of the role that resources such as demand response, variable energy resources and storage can provide. The [utilities] give short shrift to these alternatives, summarily dismissing their potential contributions.”
NextEra Energy Resources also filed an answer saying the utilities’ motion “is a procedurally impaired request for rehearing or complaint and seeks a remedy that is beyond the commission’s statutory authority under the Federal Power Act.” The EDC proposal would undermine the role of ISO-NE as a neutral market operator and “result in New England wholesale energy market outcomes that are unjust and unreasonable,” the company said.
The Conservation Law Foundation contended that the EDCs cited no legal error or new facts but nonetheless requested “major additional — and quite novel — determinations of law and fact about which the commission has received no argument or supporting evidence.”
The CLF contested the utilities’ assertion that natural gas pipeline constraints are the cause of the fuel security situation in New England, citing testimony of ISO-NE Vice President of System Operations Peter Brandien, who said fuel supply issues result from a broad set of operational concerns and factors that are potentially responsive to a broad range of market solutions that the RTO and its stakeholders are only now beginning to explore and discuss.
‘Expensive Approach’
“In addition to not disclosing their interest in the Access Northeast project, the EDCs also do not disclose the significant body of evidence submitted in past state proceedings on the need for added pipeline capacity, which is far from conclusive,” NextEra said.
The company said that if the potential need for new pipeline capacity is limited to a few peak days each year, “as projected by the Eversource EDCs’ own expert,” the proposed new pipeline capacity would be “a very expensive approach to addressing a winter peak resource sufficiency concern, with the Eversource EDCs’ expert projecting a $526 million annual cost, after taking into account the return on the capital investment and [operations and maintenance] costs annually to operate the capacity.”
The New England Power Generators Association filed an answer calling “absurd” the utilities’ contention that long-term cost-of-service contracts are a form of market design improvement.
“The EDCs’ requests for findings are outside the scope of this proceeding and are more properly styled as a complaint or request for rehearing rather than a motion for clarification,” NEPGA said.
The commission ordered improvements to the market design and reaffirmed its support for market solutions but “provided no further direction with respect to the longer-term market improvements, much less that they include long-term pipeline capacity contracts,” NEPGA said.
Healey asked the commission to summarily dismiss the clarification motion and see it “for what it is — a bald attempt by monopoly utilities that stand to profit from new pipeline infrastructure trying to saddle electric ratepayers with the costs of a pipeline that private investors are unwilling to fund.”
INDIANAPOLIS — For years, MISO executives have been warning about the coming of a future electric grid that upends traditional utility operations. The time of reckoning may be close at hand, according to industry experts speaking last week at the RTO’s second biennial Market Symposium.
MISO billed the event as a preparation for wholesale market design that includes the trends of “digitalization, de-marginalization and decentralization.”
CEO John Bear said that when he tells people he works in the energy industry, few are “wowed” by how fast the technology and innovation moves.
“But that’s changing,” Bear said, adding that 88% of MISO’s 90-GW interconnection queue is composed of renewable generation.
“The future is really already here in varying degrees,” said MISO board member Mark Johnson. “The bulk electric system, depending on where you live, already operates differently. … Bidirectional flows on the grid are more prevalent and will continue to occur.”
‘Fork in the Road’ for Markets
FERC Commissioner Richard Glick said the industry is at “the proverbial fork in the road in how we view markets.”
Glick said he is astounded at today’s wind penetration levels, which exceed any forecasts he provided while working as a wind energy lobbyist. “Lobbyists don’t lie, but you know, we pick the highest [statistics],” he joked.
Today’s energy industry is divided into two camps, Glick said, with one supporting returning to a centralized grid with an emphasis on older-technology power plants that offer resilience.
“The other camp is saying you can’t put the genie back in the bottle. … And I’m certainly in that particular camp,” he said, adding that “people just aren’t investing” in centralized power plants. “I hope we move forward, and don’t move back to the system of the past.”
However, Glick thinks the transmission system will remain a key factor in future markets.
“Decentralization doesn’t mean no transmission system,” Bear agreed. “It means a different transmission system.”
Transmission and Distribution Blurring
Several speakers agreed that transmission will become increasingly synonymous with the distribution system.
Gabe Murtaugh, CAISO regulatory policy developer, said the future transmission system will “connect households instead of a power plant that’s 500 to 1,000 miles away for load.”
“We’ve spent the last several years making sure there’s a bright white line between T&D, and that’s changing,” said ScottMadden partner Cristin Lyons.
Rocky Mountain Institute’s Mark Dyson said blockchain technology deployed at scale in the grid will further blur transmission and distribution. Other speakers said MISO could eventually become a founder network for blockchain technology.
But Grid Strategies President Rob Gramlich said he thought the RTO could use more transmission infrastructure first, but only if it aligns its interconnection queue and transmission planning process.
Electrification and Data
Experts agreed that there’s a natural role for electrification in the future grid.
“We’re looking at a world of declining load, and utilities are looking at their bottom lines and saying, ‘Holy cow, either my rates have to go up or my load has to go up,’” Lyons said.
“We’ve seen stagnant load growth for the past 15 years, but I think that’s about to change,” said Andy Lubershane, director of research at Energy Impact Partners. He predicted that electrification of transportation, space heating and indoor agriculture will soon drive up load.
Rob Threlkeld, General Motors global manager of renewable energy, said the utility and the automotive industries are more aligned than they ever have been because of the innovations disrupting both.
Responding to an audience question, Threlkeld said he’s not sure if GM will pivot to producing home storage batteries, styling itself after Tesla, but added he wouldn’t be surprised if his company eventually develops them.
Threlkeld said customers are used to managing several activities via smart phone applications, but that same understanding does not yet apply to distributed energy resources: “The electricity market is really new to them.”
Lubershane said data can reveal what motivates customers to purchase smart devices, and they’re not always energy management reasons. He said while Ecobee customers mostly give the smart thermostat verbal commands to adjust the temperature, the second-most used command is to play music.
“I don’t know if disruption is really the word. It’s more an evolution,” said Ryan Wartena, president of energy software company Geli. “If we don’t have metering on the low-voltage distribution system, it’s going to make this [evolution] difficult.”
Georgia Institute of Technology professor Pascal Van Hentenryck said coordination of DER optimization is a major challenge facing energy markets.
Panelists debated the role of the vertically integrated utility in a world where load has leveled off and new generation is often not utility-owned. Some said it was the role of utilities to aggregate and optimize use of DERs and behind-the-meter resources. Wartena said DER aggregators should eventually be able to hand control of DER aggregations over to MISO to shape the load.
Other panelists said now is the time for RTOs to standardize data collection and maintain open architecture computer programs to increase visibility of DERs. Sandia National Labs’ Jean-Paul Watson pointed out that MISO’s markets are currently inhibited by computer programs devised in the late 1990s.
Kate Sherwood, 3M senior director of grid modernization, said data are needed to forecast use of harder-to-control distributed renewables.
“Uncontrolled environments require more data to manage,” Sherwood said.
Lyons predicted it will take another 10 years before the industry can realize the benefits of collecting so much data by turning them into actionable grid insights and better managed energy use. “In five years, we’re going to have a lot of data, but we won’t have cracked the code,” Lyons said. She also said states are taking a lead in creating privacy provisions for customers so their home patterns are aggregated for analysis and not individually revealed.
Dyson said MISO is in the thick of a retirement movement. “I think what we’re seeing today is a trend of retirements — coal retirements. And we’re asking if we can replace that generation with renewables. My answer is ‘yes,’ but you’re asking the wrong question,” he said. “The question is not, ‘Can I replace the coal-fired asset?’ The question is, ‘Can I provide all of the services that the coal asset provided?’ And the answer to that question is ‘certainly, and at a lower cost.’”
Dyson said that within a few years it will be difficult to justify the costs of natural gas-fired water heaters in homes. He predicted heat pumps at a neighborhood level could save consumers millions of dollars.
Propped Up Pricing?
Michael Hogan, senior adviser for the Regulatory Assistance Project, said there’s a “real risk” that electrification becomes difficult to manage for grid operators in terms of pricing.
“We’ve gotten away so far with pricing wholesale energy very simply. … We need to talk about security-constrained economic dispatch, not simple economic dispatch,” Hogan said.
“I think the ISOs are getting caught between a rock and a hard place,” said Lawrence Makovich, IHS Markit vice president and senior energy adviser, pointing to renewable incentives, subsidies for some non-carbon-emitting generators and not others, and carbon credits in only some states.
“I see serious market distortions as a result of this. … We’ve gotten to a point where we’ve suppressed prices. If we didn’t have distorted markets, you wouldn’t have to pay for flexibility,” he said, referring to pricing for ramping capability.
Makovich said California can either be cited as a roadmap or a cautionary tale because the state’s carbon emissions have not decreased from 2002 levels despite renewable adoption because artificial market forces rendered zero-emission nuclear plants uneconomic.
“It’s easy to paint a horror picture of California, and I can do the same of Germany,” Hogan responded. He said ERCOT is a better example of renewable integration because its transmission system is truly an energy island. Despite a record-setting summer, ERCOT has not had to curtail load, he noted.
“We’re not seeing ERCOT trying to move in and patch this and patch that … with micro-procurement policies. They’re getting the prices right,” Hogan said.
Makovich agreed that pricing from ERCOT’s operating reserve demand curve seemed to work this summer, raising prices enough to allow some generators to postpone retirement. But he cautioned that the attractive prices might keep more clunky and expensive generation in the market too long.
Hogan agreed that previous generation investments must be jettisoned before the new crop of investment resources can move in. “There’s a problem that market prices are paying for the wrong resources. … We do have a problem of [needing to move] uneconomic resources out of the market before we see real pricing emerge.”
No Operator Bots
Alberto Ruocco, a partner at research firm Gartner, cautioned against artificial intelligence making grid decisions autonomously.
“I think, wisely, the industry has come back and said that’s not the goal,” Ruocco said. He said that while machine learning can work through a lot of data, human operators should be on hand to make decisions. “I don’t think we should abdicate something as important as the operation of the grid. … I think complete delegation of control is not realistic.”
But more digitalization is inevitable, panelists said.
“It’s not ‘if,’ but ‘when’ you need to adapt your digital business model,” said Stephanie Woerner, a research scientist at the MIT Sloan Center for Information Systems Research. She said her recent research found that digital disruptions could threaten an average 28% of future revenues for companies across all industries.
Richard Doying, MISO executive vice president of market development strategy, said it has now become risky to postpone decisions to accommodate new technologies in the energy market.
Bear summed up the discussion by quoting President Dwight D. Eisenhower: “Plans are worthless, but planning is everything.”
CALGARY, Alberta — Canadian Electricity Association CEO Sergio Marchi took advantage of several opportunities during last week’s NERC Board of Trustees meeting to complain that he and other Canadian stakeholders have been excluded from Department of Homeland Security cybersecurity briefings.
“We’re forbidden to participate because we are considered, quote unquote, foreigners,” said Marchi, whose association represents integrated utilities, independent power producers, transmission and distribution companies, power marketers and industry suppliers. “The irony is most of our CEO representatives happen to be American citizens.”
Marchi said that over the last year, he and the two Canadian CEOs on the Electricity Subsector Coordinating Council (ESCC), ENMAX’s Gianna Manes and Hydro One’s Mayo Schmidt, have been shut out of the classified briefings.
NERC responded that the Canadians have been excluded because they don’t have the proper security clearance. It added that it is working with industry and government partners to increase the functionality of the Electricity Information Sharing and Analysis Center (E-ISAC) portal, which gathers, analyzes and shares security data across the North American grid.
“NERC as a private company does not have authority to grant or sponsor clearances or to provide access to classified briefings in the United States or in Canada,” CEO Jim Robb said in a statement provided to RTO Insider. “However, NERC will ensure that all NERC events are inclusive of all our North American stakeholders. Simply getting information is only piece of the security pie, and the E-ISAC is in a unique place to analyze and triangulate information to identify threats and mitigation actions to share information that North American stakeholders need to protect their systems.”
Marchi told RTO Insider that the exclusion from the ESCC briefings has become more of an issue under the Trump administration.
“It’s frustrating, and whether it’s NERC or Bruce Walker [the Department of Energy’s NERC representative], they haven’t been able to pinpoint who is blocking us and why,” he said. “This is an example, where everyone says we should be in the meeting, but we don’t know who [is preventing us] and why we are kept out of the meeting. We’re hopeful we can make progress, and the next time the council meets, we can be on the same team.”
Robb acknowledged the issue while briefing trustees on the ESCC’s recent discussions. He said improving information sharing with Canadian industry members is “complicated territory.”
Marchi said the CEA was willing to give Robb a “proper runway” to improve the process.
A former member of the Canadian Parliament and cabinet minister, Marchi also objected to what he said was a 25% budget increase for the E-ISAC as part of NERC’s overall 9.5% budget increase.
“Our Canadian utilities receive the same information from Canadian sources, but it’s quicker and of higher quality,” Marchi said. “Why should we pay twice for information that is of less quality, and that is late on arrival?”
In his statement, Robb pointed out that Canadian stakeholders were able to file comments on the 2019 budget and business plan as part of NERC’s “open and transparent” budget process. He said the organization takes their concerns seriously.
“[We] had multiple meetings, phones calls and written exchanges with [Canadian stakeholders] to discuss the 9.5% increase,” Robb said. “While we acknowledge [their] concerns, we believe the budget approved by the NERC Board of Trustees is the right answer for industry based on all feedback we received.”
Robb acknowledged that the Canadian government has, at times, “authorized release of information to Canadian industry sooner than the U.S. government.” He said NERC recently executed a memorandum of understanding with the Canadian Cyber Incident Response Centre to help improve E-ISAC access to the Canadian government’s security information.
Marchi said the CEA will monitor the next budget cycle and “consider our options” at that time. He said the E-ISAC’s relationship with U.S. security organizations is “an important piece of that puzzle.”
“It’s very important those relationships are picture perfect, if a new investment to the E-ISAC will create the outcomes they’re intended to,” he said. “We need to continue to work closely as our industry evolves at a rapid pace and cyberattacks continue at a great pace. This work must be done in a cost-effective and efficient manner, because both regulators and customers demand and expect it.”
NERC Board Chair Roy Thilly said improving the involvement of Canadian utilities in the E-ISAC “is a very high priority” for the trustees. “We ask the Canadian utilities to work with us to help you provide that value.”
Earlier in the week, the NERC board and Canadian regulators held their annual meeting. NERC said Canadian regulators were briefed on cybersecurity, including the E-ISAC long-term strategic plan and the organization’s reliability assessment and performance analysis capabilities.
Robb Reflects on Cross-border Interconnections
Robb noted several significant milestones during his president’s report, pointing to NERC’s 50th anniversary and the 15th anniversary of the 2003 blackout in the Northeast. As Robb put it, a vegetation contact in Ohio led to power failures in Ontario and “returned the favor” for 1965, when a transmission line tripped in the Canadian province and blacked out Manhattan.
“These anniversaries and our meeting in Canada have given me a chance to reflect on the interconnected nature of our grid and the importance of our international collaboration,” he said. “The Electric Reliability Organization [ERO] is an agency for driving a common approach to reliability and security. We have a tremendous amount of work to do together, and it is a high priority for all of us.”
Robb said the early returns on NERC’s six-month-old, five-year strategic plan have been “very positive,” but that there is a “tremendous amount of work to do.”
“It’s a very complex system to defend,” he said of the grid.
The continuing retirements of coal- and nuclear-fired generation, combined with the rapid deployment of variable resources and natural gas plants, is a problem “no one agency or individual forum can solve,” Robb said.
He said NERC has started work on a guideline to bring “greater clarity” regarding what kind of contingencies need to be studied.
“There are serious issues in the Northeast and desert areas of the Southwest,” Robb said. “We need to move along very quickly on this.”
CEO: AESO’s Challenges Same as Everyone Else’s
The Alberta Electric System Operator (AESO) faces steep challenges in meeting legislative mandates to phase out its coal-fired generation — which accounts for 40% of its installed capacity — and produce 30% of its energy from renewables by 2030. Adding to the challenge, it has very little hydro and no nuclear power in its generation mix.
But that’s no different than the challenges facing other jurisdictions, CEO David Erickson said.
“With the integrated nature of the grid in North America, working together to solve those problems is important,” he said. “That’s the only way to get through this transformation, with the increasing penetration rate of renewables, cyber threats and changing generation mix. Those are real challenges we need to work together to solve. The ISO/RTO community has a big role.
“That said, NERC has an enormous role to get through this. I encourage the industry, I encourage NERC to work together. Whether we like it or not, we’re in this together. There’s a better path that’s more efficient and a lot more effective, if we do this together.”
CALGARY, Alberta — Where once there was one, there will now be several players offering reliability coordinator (RC) services for most of the Western Interconnection.
How many RCs there will be, and who they are, should come into better focus on Sept. 4. That’s the unofficial deadline NERC and the Western Electricity Coordinating Council (WECC) have placed on Western balancing authorities and transmission owners to declare their RC.
The only certainty is that it won’t be Peak Reliability, which has been providing the RC function for the entire interconnection except Alberta since WECC was bifurcated in 2014, with WECC retaining Regional Entity functions. Peak announced last month that it will wind down its services by the end of 2019, having determined it will be financially unable to compete with CAISO’s and SPP’s RC services.
“Things have been moving quickly,” WECC CEO Melanie Frye told NERC’s Board of Trustees last week. “We’re hoping to get a bit more clarity on where everybody is looking to go, and whether they’re intending to go with [CAISO] or SPP, or whether some other option will emerge.
“That will allow us to see where the seams start to emerge and whether it will result in swiss cheese, where you have a small BA choosing one RC provider, but everyone else around them choosing another,” she said during the board’s Aug. 16 meeting.
Both CAISO and SPP have been aggressively pursuing potential members. CAISO said in January it will become its own RC and offer that function to other Western entities. SPP, which still hopes to integrate some of the Mountain West Transmission Group into its RTO, has filed a request with WECC to provide RC services to two Western Area Power Administration companies and says it has received interest from 26 other parties. (See WAPA Formally Requests SPP’s RC Services.)
North of the border, the Alberta Electric System Operator (AESO) already handles its own RC services, while BC Hydro is “leaning to forming” its own RC in British Columbia, Frye said.
“Ultimately, it will be the BAs and the transmission owners that make sure they have a certified RC,” Frye said. “I think we’re making progress there. We’ve had very good engagement with all of the potential RC providers. At a technical level, a lot of that planning is starting to take place, and that’s very healthy.”
As the RE for the Western Interconnection, WECC has hosted a series of stakeholder forums to discuss a future with multiple RCs. The agency will be responsible for ensuring the RCs are certified to perform the registered function; ensuring the BAs and TOs are aligned with a certified RC; and monitoring compliance with reliability standards. WECC has scheduled on-site certification visits with CAISO for March and SPP next summer.
The loss of a Western-wide RC has several stakeholders concerned.
RC Certification Timelines in the West | WECC
Utah Public Service Commissioner David Clark said it was his “personal hope” that whichever entity handles the RC function has “a governance structure that is independent and a process that’s transparent.”
“However this settles out, I hope the function will be performed in a way that is transparent … particularly to state energy advisers and state regulators and consumer advocates,” he said.
“I understand there are market considerations involved, but this has to be done very carefully,” warned NERC Trustee Dave Goulding, who chairs the organization’s Enterprise-wide Risk Committee. “As NERC, we don’t want to get into a situation where reliability is compromised.”
Not to worry, Frye said. “The focus on WECC’s work and NERC’s work will be on the intricacies of the interconnection and making sure that reliability across the seams with the RCs is maintained,” she told RTO Insider.
To that end, Frye, who is just completing her first month as WECC’s CEO, said the RE will be asking for a variance to the reliability standard that requires Western RCs to model the entire interconnection and all its remedial action schemes.
“We’ve started to engage this week at an executive level with the utilities, to ensure we have that connection-wide view,” she said.
Frye and WECC have the support of NERC and its CEO, Jim Robb, Frye’s predecessor at the RE. Robb joked that Frye is a “complete upgrade over the previous guy,” and he listed reliability coordination in the West as the second of four priorities that NERC is focused on in addressing industry risk.
“WECC and NERC are approaching this completely in lockstep around the changes that are happening in the West and [ensuring] that the resulting infrastructure works as well as possible, as with same heightened performance as a single RC,” he said. “We’re working very hard with WECC to understand the needs they have for these RCs.”
CAISO has notified WECC that it intends to seek certification as an RC. Frye said the ISO intends to go live within its BA footprint on July 1, 2019, and it will add its new members later in the fourth quarter. CAISO is meeting with Peak to coordinate data exchange and operations.
SPP also plans to go live with its RC functions in the last quarter of 2019. The RTO already has a West-wide model in its energy management system.
“SPP is proceeding along a slower timeline, but obviously, both need to be up and running before the December date Peak has announced,” Frye said.
CALGARY, Alberta — The NERC Board of Trustees last week approved Wisconsin Public Service Corp.’s (WPSC) and Upper Michigan Energy Resources’ requests to move to ReliabilityFirst from Midwest Reliability Organization. NERC staff determined the transfer of the companies’ facilities would have a negligible impact on other grid users and operators, noting that the two utilities’ facilities have more geographic and electrical boundaries with RF than MRO.
Wisconsin Electric Power Co. acquired WPSC in 2015 and established UMERC as a new company in 2017. It applied for the registration transfer request in December.
The board also approved the 2019 Electric Reliability Organization enterprise business plan and budget and the budgets for the seven Regional Entities; approved a requirement that transmission and generation owners provide NERC with their geomagnetic monitoring data to support ongoing research and analysis of geomagnetic disturbance risks; and adopted three reliability standards:
The New England Power Pool Markets Committee on Tuesday debated ISO-NE’s proposals for conducting fuel security reliability reviews and allocating the costs of resources retained as a result.
The fuel security issue became a pressing matter following a July 2 FERC ruling that called the RTO’s request to waive several Tariff provisions “an inappropriate vehicle” for keeping the Mystic Generating Station running (ER18-1509). Exelon plans to retire the 2,274-MW plant when its capacity obligations expire in May 2022.
FERC found the RTO’s Tariff was not just and reasonable because it lacks a way to address fuel security concerns that could result in reliability violations as early as 2022. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
FERC’s July 2 show cause order set an Aug. 31 deadline for ISO-NE to submit interim Tariff revisions for filing a short-term, cost-of-service agreement to address fuel security concerns and a July 1, 2019, deadline for filing long-term Tariff revisions.
ISO-NE said it plans to review retirement de-list bids and Substitution Auction demand bids and may reject either type of bid for fuel security or reliability reasons. The RTO will notify market participants with retirement de-list bids that are needed for fuel security at the same time they receive the retirement determination notification from the Internal Market Monitor.
The RTO also said it may reject a reconfiguration auction demand bid if the resource has been identified as a fuel security resource in an FCA. It is proposing a “status quo” approach for Forward Capacity Auction 13, by which resources retained for fuel-security reliability will be entered as price takers, the same approach applied to resources retained for transmission reliability. “FERC has found such treatment just and reasonable in that context; fuel security is another reliability retention,” the RTO said in a presentation.
It said it will work with stakeholders to develop alternatives to the status quo for FCA 14 and FCA 15.
Price Suppression Concerns
Brett Kruse, Calpine’s vice president for governmental and regulatory affairs, told RTO Insider his company and other generation owners are concerned that pricing the Mystic units at zero in FCAs 13, 14 and 15 will suppress prices, fears they expressed in protests in the docket.
Kruse noted that FERC’s order rejecting the fuel security waiver outlined ways to treat Mystic’s out-of-market capacity to mitigate price suppression. “Notwithstanding FERC’s clear concern about price suppression, ISO-NE has since told us — and reiterated clearly this week — that they will not consider either of FERC’s suggested approaches, instead reverting back to their original position of putting Mystic in at zero,” Kruse said in an email.
Who Pays?
ISO-NE proposed to allocate out-of-market costs incurred to retain resources for fuel security regionally based on real-time load obligations (RTLOs). The new Tariff provisions would apply to FCAs 13, 14 and 15. The RTO said it was proposing regional cost allocation based on FERC’s prior ruling on allocating costs of its winter reliability program (ER13-1851).
| ISO-NE
The NEPOOL Reliability and Markets committees will meet separately on Aug. 22 to vote on the proposal ahead of an Aug. 24 review and vote by the Participants Committee.
Some stakeholders expressed concern at Tuesday’s Markets Committee meeting that the RTO’s Pay-for-Performance program may not spread the costs for ensuring fuel security equitably. Under the program, launched June 1, costs for performance bonuses are supposed to be funded mostly by penalties on nonperforming resources and not directly by customers.
George McCluskey, assistant director for wholesale electric markets at the New Hampshire Public Utilities Commission, told the committee that his agency is concerned PFP will not eliminate fuel security risks because of state emission policies that limit operation of existing dual-fuel units and discourage investment in new dual-fuel capability.
“If resources are retained to address unmitigated fuel security risks, the out-of-market costs should be allocated to states whose emissions policies restrict market response to PFP,” McCluskey’s presentation said.
ISO-NE has identified Massachusetts and Connecticut as states with emissions policies that restrict market response. New Hampshire disagrees with Connecticut’s inclusion in that list and thinks costs should be allocated to Massachusetts only.
The RTO has also suggested that it may rely on reliability-must-run contracts for units needed to meet winter system reliability needs, for both fuel and transmission security, proposing that such units recover costs through regional allocation.
The Maine Public Utilities Commission opposes regional cost allocation, saying in a presentation that ISO-NE “offers no reason why it departs from long standing cost-causation principles” and that RMR costs should be assigned to local reliability areas.
“Regional allocation of RMR costs for units that are both transmission and fuel-insecure will mask underlying transmission issues,” the PUC said.
The commission noted that Mystic Unit 7 was retained for transmission security purposes in FCA 12 and said an analysis of Mystic Units 8 and 9 could reveal a similar need, but that ISO-NE has not conducted a study.
Mystic Generating Station
If Mystic 8 and 9 are needed for local reliability needs, the PUC said, congestion would occur at the Maine-New Hampshire interface in a fuel security event, meaning load shedding in Maine would not provide fuel relief to southern states and the state’s consumers would not benefit from avoiding load sheds.
“Maine, or any other reliability region, should not pay for RMR contracts related to fuel security unless Maine, or any other reliability region, can be seen as a beneficiary of the RMR,” the commission said.
Dan Dolan, president of the New England Power Generators Association, told RTO Insider his group strongly opposes ISO-NE’s proposal to apply an out-of-market approach to FCA 15 and potentially FCA 16, calling it an abdication of the grid operator’s market design and price formation responsibility.
“We have two fundamental issues: ensuring that this type of an out-of-market approach to fuel security ends as soon as possible and that resources held do not undermine the economic price formation in the Forward Capacity Market,” he said.
Calpine, NextEra Energy and Direct Energy are sponsoring an amendment that would allocate costs to network load instead of ISO-NE’s proposed allocation to real-time load obligations. Kruse said he expects support for their amendment from public power and state-represented entities.
Kruse noted that ISO-NE is using the transmission security RMRs as precedent for pricing treatment, but not for cost allocation.
Unlike the winter reliability program, whose costs were capped in advance and ranged from $30 million to $70 million annually, Kruse said, Mystic’s RMR costs will probably exceed $200 million per year. Because load-serving entities will add risk premiums to their expected costs, “the scope is significantly larger,” Kruse said. “Additionally, some LSEs may decide to sit out the market for now and not expose themselves to this pricing risk. Effectively, New England consumers will pay significantly more if the cost is allocated to RTLO instead of network load.”
SACRAMENTO, Calif. — Gov. Jerry Brown’s controversial plan to transform CAISO into an RTO took an unexpected turn Thursday in the State Senate’s Appropriations Committee.
The committee’s members were set to vote on the plan’s first step, AB 813, either killing it or sending it to the Senate floor. Instead, the bill was withdrawn from Appropriations and sent back to the upper house’s Rules Committee.
The move likely was intended to give proponents time to work out a deal to allow the state-chartered CAISO to transform itself into an independent organization positioned to expand into the vast Western energy market.
“The Senate is taking the time needed to get this right, which is so important because full integration of the western electricity grid is vital to California’s clean energy future,” the Natural Resources Defense Council, a supporter of the measure, said in an email immediately after the move was announced.
The measure now could languish in Rules or be sent directly to the Senate floor as the legislature nears the end of its two-year session Aug. 31. Previous efforts to authorize CAISO’s expansion have stalled during the past two years in the face of strong opposition both inside and outside of California. (See Governor Delays CAISO Regionalization Effort.)
Regionalization Risks
AB 813 would authorize CAISO’s Board of Governors to submit a plan to the California Energy Commission to change the ISO’s governance structure to include transmission owners from outside California. If adopted, it would be the first step in a multiyear process to make CAISO an RTO for the West.
Those who’ve opposed AB 813 include the Sierra Club, municipal utilities and ratepayer advocates. They contend the measure would lump California in with coal-producing states such as Wyoming and put California at risk of greater interference from federal regulators under the Trump administration.
“I don’t buy the argument that we have to regionalize to take advantage of opportunities elsewhere,” said Barry Moline, executive director of the California Municipal Utilities Association, which represents publicly owned utilities throughout the state.
Moline told RTO Insider that the Western Energy Imbalance Market is already doing a good job at allowing energy to be bought and sold as needed among Western states, without building new transmission lines from wind farms in Wyoming to consumers in California.
Creating more renewable energy sources in California and using in-state transmission lines would further the state’s aims without adding risk, he said.
Moreover, he said, AB 813 would benefit wealthy out-of-state investors and conglomerates that want California ratepayers to pay for infrastructure from which they’d profit.
“There’s a lot of transmission companies and a lot of renewable resource developers that want to deliver kilowatt-hours into California,” Moline said. “These folks want to make money off of California.”
The proposal’s champions include Brown, CAISO, some environmental nonprofits and companies that stand to profit. It was introduced by Assemblyman Chris Holden, chairman of the Assembly Utilities and Energy Committee.
Those arguing for the bill said it would further California’s ambitious renewable energy goals by tapping into Wyoming windmills and Arizona solar arrays, while spreading sustainable energy throughout the West.
“This is the direction the grid is heading in,” said Carl Zichella, NRDC’s Western transmission director. “We need to be able to operate the system as a congruent whole.”
A set of amendments adopted Aug. 7 was meant to ease the concerns of those who worried about linking deep-blue California with the red states of the interior West.
“The purpose of the amendments is to reassure people that the progress California’s been making on renewable energy and climate change are not likely to be interfered with,” Zichella said.
The new language included a requirement that a California TO, retail seller or publicly owned electric utility not join or remain a member of an RTO with a centralized capacity market.
The amendments also insisted the state not undermine its ambitious scheme for achieving reductions in greenhouse gases and for purchasing electricity from renewable energy and zero-carbon sources.
The Aug. 7 changes, however, were apparently insufficient to ensure the measure’s passage through the Appropriations Committee before Friday, the last day for fiscal committees to meet and report out bills.
AB 813 can now be amended in the Rules Committee and sent to a vote of the full Senate before the last day of August, bypassing Appropriations. The bill passed the Assembly last year.
If it clears the legislature, Brown would then have until Sept. 30 to sign the measure into law. If it proves too complex and divisive for quick resolution, Brown could call a special session of the legislature this fall.
OMAHA, Neb. — When SPP CEO Nick Brown welcomed Walmart as one of the organization’s newest members last month, he made a point of noting the company was the first in the RTO’s large retail customer sector, which has been vacant since 2003.
A big deal for SPP, maybe, but old hat for Walmart. The retail giant is a member of every U.S. grid operator except CAISO, though that could eventually change.
“It depends on the regulatory environment there,” Chris Hendrix, Walmart’s director of markets and compliance, told RTO Insider.
As it is, Walmart is involved in most states that are open to retail competition, along with markets in Canada and the U.K., the latter through its Asda affiliate. Other markets, national and international, could follow “depending on how they’re structured,” Hendrix said.
“It’ll be easier for me to tell you what markets we aren’t in,” he said, ticking off Delaware, Michigan, Rhode Island and D.C.
Walmart’s foray into electricity markets began simply enough in 2003, when it joined ERCOT as a retail electric provider (REP) through its Texas Retail Energy entity. The wholly owned company has a customer of one, procuring power for Walmart, Sam’s Club and other subsidiaries and their many stores and distribution centers.
“Initially, it was all about lowering our costs,” Hendrix said. “We’re like other REPs [in Texas], only we don’t have sales people or customer service reps.”
Hendrix, who brought 15 years of energy experience in both the gas and electricity sectors when he joined Walmart in 2003, is part of a team of 15 former energy insiders and company associates “doing all types of things.”
Everything, that is, except sales. There’s no need to market outside the Walmart family of companies.
“We can be in control of our own destiny,” Hendrix said. “We can buy power how and when we want to, as opposed to being beholden to somebody else’s buying schedule at the utility, or the market products they can come up with. We access the wholesale market when and how we see fit.”
No Middleman
Hendrix said Walmart benefits from its membership in SPP and other grid operators by gaining access to hourly pricing and managing it for the company’s needs.
“We cut out the middleman, and we leverage our credit as Walmart,” he said. “The cost savings come from leveraging our credit, as well as operational efficiencies from having less people and services that we have to offer.”
Asked to quantify Walmart’s energy savings, Hendrix demurred.
“Cutting out the middleman’s margin is basically the savings,” he said. “Our goal is everyday low prices, and along with that, everyday low costs. Anything we can do to lower the cost helps the business opportunities of Walmart.”
At the same time, Walmart’s involvement with RTOs and ISOs has been instrumental in the company’s sustainability program. The retailer has been working toward a goal of operating with 100% renewable energy since 2005.
Walmart has been the eighth largest corporate purchaser of wind and solar power globally since 2008 with 781 MW, according to Bloomberg New Energy Finance, and it gets about 28% of its electricity from renewables. Just before the presidential election in 2016, the company announced it intended to get half its power from wind and solar energy by 2025, passing Google as the world’s top buyer of renewable power.
Nothing has changed, despite the Trump administration’s lack of support for renewables.
“Our goals and objectives have not changed at all since they were first introduced … and more specifically, in November before the election,” Hendrix said. “By the time it’s all finished, 35% of our load in Texas will come from wind. That’s a significant number, but it’s still not a 50% number. We’re looking to do a lot more, because we can’t get there with on-site solar. It has to be large-scale solar and large-scale wind.”
Hendrix said one of the side benefits of participating in energy markets is purchasing renewables on a wholesale basis. To participate in most of the markets it’s in, Walmart had to become a member of the grid operators. SPP doesn’t have that same requirement, but its 18 GW of installed wind capacity was too enticing to pass up.
“As we do a lot more renewables, a lot of that … is in the SPP territory,” he said.
Walmart’s annual $6,000 membership fee is a small price to pay. As the executive responsible for regulatory and legislative matters for the company’s retail and wholesale energy businesses, Hendrix also gets to have a vote in SPP’s stakeholder process.
“We decided, as we have been in all those other markets and we have seen the benefits of being on those committees, it made sense to join SPP,” he said. “We try to understand what’s happening with the ISO’s policies and try to steer them in the direction that we think is best. We’ll always advocate for competition and free markets.”
SPP’s hefty exit fee — about $673,000 for non-transmission owners, the RTO estimates — has scared away some potential members, but not Walmart.
“We don’t intend to go anywhere,” Hendrix said. “It works out to $6,000 a year. We think we get the benefit of being involved in the market.”
PJM may soon have to choose between continuing to greenlight its “largest-ever” congestion-reducing transmission project or risking a public relations war with opponents of the project who live in its proposed pathway and have gained influential allies in their fight to have it shelved.
The $340.6 million project proposed by Transource Energy would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border — one between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; and another between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.
PJM and regulatory filings refer to the project as “9a,” while Transource has dubbed it the Independence Energy Connection.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource
“Until now, landowners have considered Transource to be their opponent, but unless PJM soon exercises its right to withdraw the project, we will hold PJM responsible,” wrote the opponents — consisting of three landowner groups in Harford, York and Franklin counties — in a June 30 letter to the RTO’s Board of Managers.
“PJM will become the target of our media outreach, our legislative efforts and, potentially, our legal efforts as we hold PJM responsible for the tremendous costs incurred by landowners who will ultimately emerge victorious,” the letter warned. “Further PJM support of this project will be viewed as an abuse of process.”
Project 9a
PJM selected Transource’s market efficiency proposal in August 2016 to reduce congestion along the RTO’s AP South interface. As part of PJM’s implementation of FERC Order 1000, the congested interface was included in its inaugural window for proposing such projects and received the most attention, attracting seven of the 17 total proposals submitted. (See AP South, Cleveland Draw Congestion Relief Proposals.)
At the time, PJM CEO Andy Ott called it “PJM’s largest-ever market efficiency project,” projecting it would save ratepayers $622 million in congestion costs over 15 years. The eastern portion would relieve the Graceton-Conastone 230-kV line, which was the most congested line in PJM’s 2016 long-term analysis. Its congestion costs in 2017 were $51.8 million and were expected to rise over the next 10 years to $68.88 million in 2027.
Another line leading into Graceton, the 230-kV Bagley-Graceton, was third on the list with $23.59 million in 2017 congestion costs and estimates of $59.57 million in 2027. A third line in the area, the 500-kV Peach Bottom-Conastone, was second on the current list with $32.78 million in congestion costs, which are expected to drop precipitously to $1.9 million in 2027.
FERC approved a formula rate for the project in January 2017 and a settlement this January on Transource’s return on equity, but it refused to reconsider whether the company should be allowed to make single-issue rate filings or recover all costs if the project is canceled through no fault of the company.
Transource received permission, starting on Jan. 31, 2017, to recover all “prudently incurred costs” if it must abandon the project for reasons “beyond Transource’s control.” All costs prior to that are subject to a cost-sharing policy FERC ordered in Opinion 295, through which Transource could recover 50% (ER17-419).
‘Do the Right Thing’
But opposition has developed among residents who live around the proposed paths, and they have orchestrated an awareness campaign that netted support from high-level elected officials on both sides of the state border. U.S. Rep. Scott Perry (R-Pa.) wrote a letter to FERC in March, calling on the commission to reconsider whether Order 1000 “puts impacted private citizens at a distinct disadvantage” in opposing projects. FERC Chairman Kevin McIntyre responded in April, outlining how projects are selected through Order 1000’s competitive solicitation process and assuring Perry that PJM re-evaluates its decisions annually.
Maryland Gov. Larry Hogan wrote to PJM’s Board of Managers on July 10 to “express concerns” that “the project will take prime agricultural land out of production, including land that is in permanent agricultural easements.” He sympathized with “the need to reduce power congestion in Maryland” but requested that the project be halted pending a re-evaluation or rerouting using existing rights of way, along with greater engagement with residents and state agricultural and energy agencies.
PJM says it never received Hogan’s letter.
“We have no record of receiving it,” PJM spokesperson Susan Buehler told RTO Insider in an email.
But the PJM board did receive the letter from opponents, who mentioned McIntyre’s “favorable response” and called for the project to be removed from the Regional Transmission Expansion Plan because the benefits have dropped substantially since the RTO last analyzed it.
“While we understand that PJM feels a responsibility to Transource to allow them to fail gracefully at the state level after a protracted review, the facts demand that PJM cancel this project immediately,” they wrote.
The opponents argued that near-universal local opposition and unknown environmental impacts should induce staff “to use your professional and moral judgment to do the right thing.”
Citing testimony from PJM’s Paul McGlynn to the Maryland Office of People’s Counsel (OPC), they argued system changes since last year’s annual analysis have reduced the potential benefits while costs have likely risen. The reference was to a data request from the OPC to PJM as part of the Maryland Public Service Commission’s review of Transource’s application for a certificate of public convenience and necessity for the project. In a portion of the data request provided to RTO Insider by the opposition, McGlynn appears to indicate that the congestion savings have fallen from the $620 million expected when the project was approved to $245.75 million in the most recent analysis.
However, that number is not a direct input in PJM’s analysis of such projects. That analysis, which was performed last September and posted in January, still produced a benefit-to-cost ratio of 1.32, exceeding PJM’s 1.25 threshold for considering a proposal. PJM was unable to independently verify the document cited by the opposition but confirmed that the information McGlynn would have used came from the analysis that resulted in the 1.32 benefit-cost ratio. Any changes in the variables will be included in the next analysis coming in September.
“PJM is currently conducting a third evaluation of the project, and we are using up-to-date data in doing so,” PJM spokesperson Jeff Shields said in an emailed statement. “In the past, the PJM board has canceled several major transmission projects in the region — including the [Mid-Atlantic Power Pathway] and [Potomac-Appalachian Transmission Highline] projects in 2012 — as a result of such re-evaluations.”
Impact on the Ground
The opposition argues that PJM does not give enough consideration to utilizing existing infrastructure. They point out that PPL’s existing Conastone-Otter Creek 230-kV line, which largely mirrors the proposal’s eastern path, has capacity to run another line.
PJM confirmed that PPL offered a proposal among the 41 submitted to address the AP South interface congestion, but its benefit-cost ratio did not meet the 1.25 threshold. A PPL representative said the company’s proposal “involved adding equipment to an existing substation.”
[Editor’s Note: An earlier version of this article incorrectly reported, based on information provided by PJM, that PPL had not submitted a proposal.]
Because it’s PJM’s largest market-efficiency project, “they want it to go through at any cost to land owners and local communities,” said Patti Hankins of Harford County, who joined the opposition in 2017 after learning property belonging to her husband’s cousin would be impacted.
Opponents are also concerned about the safety of high-voltage lines and the potential impact on destination agriculture, such as Shaw’s Orchard Farm Market in White Hall, Md., and other farm-to-table operations. New construction should be the last resort, they argue.
“The impact on the ground is so significant that there should be no new construction until it’s absolutely necessary,” said Aimee O’Neill, a Maryland resident and president of grassroots group Stop Transource Powerlines MD, a signatory to the opposition letter.
Political Action
O’Neill has been lobbying state legislators to pass five bills that would require developers to use existing transmission infrastructure where possible before building new. Opponents of the bills, which O’Neill hopes will be reintroduced in the legislature’s 2019 session following mid-term elections, argue that state regulatory oversight is satisfactory and that such laws would significantly upset plans to replace much of the regional grid that is nearing the end of its usable life.
“Maryland is not prepared to protect the interests of the people in the face of a changing energy environment,” O’Neill said. “There’s really nothing wrong with requiring those upgrades to be completed in existing easements with existing equipment, and what we’ve learned is that unless there is legislation requiring that … people [opposing new projects] are doomed to go through this time and again.”
Every property owner along the proposed routes has objected to the project, so Transource will need eminent domain authority to take them, O’Neill said. The company is currently working through permitting and eminent domain proceedings with regulators in both states.
A Transource representative said the company would not a comment on the opponents’ letter because it is directed to PJM.
