While MISO continues to acknowledge that General Electric is behind schedule on delivering a key piece of the RTO’s new market platform, it is tight-lipped in disclosing other project particulars — including who will ultimately take on the bulk of the work.
Initial deliveries from GE are “lagging,” MISO reported to the Board of Directors’ Technology Committee on Tuesday. But executives are offering few public details on other vendors they might be considering, though they still target a 2024 implementation.
The RTO recently told the board that delivery of a new day-ahead market clearing engine is running behind schedule, with GE now expected to deliver at the end of the year instead of in August as originally planned. (See “Vendor Delay on Market Platform Replacement,” MISO Board of Director Briefs: June 20, 2019.)
MISO control room | MISO
On Tuesday, Executive Director of Digital Transformation Kevin Caringer said MISO would only discuss GE’s performance in the Technology Committee’s closed session because the RTO is negotiating contracts with multiple vendors and is committed to securing “the best value” for stakeholders.
He did note the RTO continues to hold monthly executive meetings with GE.
“Our goal is always to adapt and move quickly, either with our own performance or vendor performance,” Caringer said.
MISO is exploring using different vendors for the platform’s model manager and private cloud development, Caringer said. In spring, the RTO said it would divide the platform replacement into a series of smaller agreements with vendors rather than one large contract with an outside party as originally planned. The move will undo its earlier plan to reveal a single chosen vendor at the beginning of 2020 after finishing an evaluation of alternatives to GE. (See MISO Seeking Multiple Vendors for Market Platform Redesign.)
The RTO is expected to launch the market clearing engine in 2022 and have the full new market platform operational in 2024. It now expects to spend about $139.7 million on the project, up from the $133.7 million estimate last year. However, it has also made provision for a 20% — or $26.7 million — contingency fund, which it could later decide to include in the project budget.
Meanwhile, MISO reported that a communication system went down on April 20, forcing it to use a backup system for about 28 minutes. Chief Information Security Officer Keri Glitch said the malfunction was associated with a power strip failure.
WASHINGTON — NERC CEO Jim Robb blinked in seeming disbelief when he walked into a press conference at his organization’s offices here Wednesday and was confronted by 10 reporters — more than twice as many as had shown up when he had his first press briefing almost nine months ago. “I didn’t think I was that interesting,” he joked.
Robb, who took the top job at NERC in April 2018, is not someone who hungers for attention. But the spotlight on NERC has grown nonetheless as it has been drawn into the fuel-wars debate over whether the grid can remain resilient as the resource mix changes. NERC also has drawn attention because of the growing cyber threats and China’s role in technology supply chains.
Just two weeks ago, security firm Dragos reported that XENOTIME, the group behind the 2017 TRISIS malware attack on a Saudi Arabian oil and gas facility, “began probing the networks of electric utility organizations in the U.S. and elsewhere” in late 2018.
A day after the Dragos warning, The New York Timesreported that the U.S. has increased its cyber incursions into Russia’s electric power grid, a move that it noted “carries significant risk of escalating the daily digital Cold War between Washington and Moscow.” Last week, the Times and others also reported that the U.S. Cyber Command had conducted attacks against computer systems that control Iranian missile launches.
Asked whether he was concerned that moves against Russia could make the U.S. grid more of a target, Robb demurred.
“As the CEO of NERC, no [comment],” he said. “These are issues of national defense and military strategy and not electric reliability. So, I have my own opinions that I will talk about over a cocktail sometime, but I think I’ll pass on [commenting in] this forum.”
“That is a very good question,” said NERC Chief Security Officer Bill Lawrence, director of the Electricity Information Sharing and Analysis Center, when he was asked later during a tour of the E-ISAC.
He did not answer either.
“All I can say is we’ve got some really smart people; they’ve got some really smart people,” he said. “And cyber is recognized as another domain by the Department of Defense.”
Outside the ‘Four Walls’
Robb said that although the electric industry’s mandatory standards give it “a very good security posture … when you get beyond the four walls of the electric industry, things get very murky very quickly.” That is illustrated, he said, by the supply chain.
In May, NERC’s Board of Trustees accepted staff’s “Cyber Security Supply Chain Risks” report, which recommended revising the supply chain standards to address electronic access control or monitoring systems (EACMS) and physical access control systems (PACS) connected to high- and medium-impact bulk electric system cyber systems. NERC is planning to send a data request in early July on whether low-impact systems with external routable connectivity should also be covered. (See “Supply Chain Report Recommends Expanding Standards,” NERC Standards News Briefs: May 8-9, 2019.)
Robb said NERC is now developing a Level 2 alert to ask industry about their use of Chinese vendors, a follow-up to the “all-points bulletin” the E-ISAC issued in March regarding Chinese equipment suppliers, including Huawei and ZTE.
Anecdotally, Robb said, NERC has heard examples of Huawei technology in utility push-to-talk communication systems and some security cameras. Huawei also has been found in a small share of rooftop solar inverters in California. “We don’t expect we’re going to find many in the bulk power system,” he said.
Impact of Politics
NERC also is being looked to for reassurance that the grid can remain reliable as natural gas and renewables increasingly replace baseload coal and nuclear generation. The issue will become more acute as some policymakers pursue goals of 100% renewable power.
Robb said the impact of public policy debates on the industry “makes our world that much more complicated.”
“There’s a lot of understandably strong views that may not always be extraordinarily founded by the science,” he said, citing as an example those who confuse geomagnetic disturbances with electromagnetic pulses.
“Resource decisions are heavily driven by public policy, as they should be,” he added. “Public policy tends to be promulgated by people with a relatively short time horizon. And one of the challenges you have in the electric industry is we build assets that last 30, 50, 100 years.”
Robb said reaching a 100% renewable power system will take a new form of battery technology to replace lithium-ion “and probably some other investments that need to be made for things like voltage support and frequency response.”
But Robb is confident the West can survive its “tectonic shift.”
“The West was built around Rocky Mountain coal and Northwest hydro going into Los Angeles. It’s now being reversed. It’s solar out of L.A. going elsewhere. As long as there’s enough time to understand the issues and make sure that the transmission system is reinforced [so] you have the adequate voltage … to make the system operate stably, there’s nothing wrong with that.”
It will take deployable batteries “at extraordinary scale — I think people sometimes miss the scale of the electric industry,” he said.
“Twenty-four hundred megawatts of storage, which I think is what Southern California Edison is pushing for, [is just a start],” Robb said. “It’s a 12-GW peak load. And if you’re going to go for an entirely renewable system, at some point you’ve got to deal with the fact that you’ve got the Marine Layer [which can inhibit solar power] for several days; it may not always be windy. You’ve got to have the whole suite of technologies to get you through those [days], and that requires batteries.
“It’s easy to set great goals, and I think great goals are very important because they’ll galvanize a lot of important technology development. But some of the time frames that some of the [presidential] candidates have talked about, I personally don’t think they’re realistic. But will they spur a lot of great innovation along the way? Absolutely.”
WASHINGTON — Utilities aren’t getting the “actionable” intelligence they need to defend themselves against cyber threats, the head of the Large Public Power Council said Tuesday.
“The classification system relative to classified information came out of a national security perspective — appropriately so — but there’s certain pieces of information that we don’t need attribution on,” John Di Stasio, president of the LPPC, said in a press briefing. “We just need to know: What’s the threat, and what’s the nexus to my operations? I think sometimes the way the system is now, it’s very hard to parse out pieces of classified information. So … you don’t necessarily get something that’s actionable.
“We certainly get heightened security alerts: ‘Pay attention. Keep your eyes open.’ That’s something that we do anyway. But those alerts, in and of themselves, don’t tell you what actions you might need to take in your system.”
“We need actionable intelligence,” echoed Pat Pope, CEO of the Nebraska Public Power District. “We don’t really care who it was done to or who did it. We just need to know so we can protect our own systems.”
“It’s one of the core challenges the [Electricity Information Sharing and Analysis Center] has,” Robb said in a press conference Wednesday. “We can’t release classified information, so we have to work with our government partners to get it to a declassified state to where it can be shared. … The issue has been talked about [and] discussed, but we haven’t been able to break the back of that one.”
Robb, who noted the E-ISAC is 18 months into a five-year plan to expand its staffing and capability, said it is attempting to be “innovative” by issuing “all-points bulletins” on emerging issues.
The CEO said the bulletins have a lower threshold than other alerts. “We don’t have to … kind of assemble the United Nations, if you will, of 7,000 security officers to have a conversation around something. It’s a good way to get a heads-up out to industry about emerging issues as they unfold. One of the things we’re trying to do is to make sure we’re getting information out to industry in a way that’s timely, helpful, but not necessarily wait for every ‘i’ to be dotted and ‘t’ to be crossed, because by that time, you’re probably too late to be helpful.”
Response to Ransomware
The public power executives were asked Tuesday how their companies would respond to ransomware attacks like those that have recently hit Baltimore and Atlanta.
Jackie Sargent, general manager of Austin Energy, said her utility would not pay ransom.
“We actually invested in cyber insurance this year,” she said. “You don’t want to get into … paying ransom because then it just encourages them to continue to do that. So, you have to make sure that [you are] making backups of your system [and that] you have isolation of those backups so that you can reinstate those systems.”
She added, “One of the advantages of being a municipal utility and being part of a city is that we have access to not only our [cyber] resources … but also the city’s resources to help us.”
Di Stasio said the LPPC attempted to help its members plan their responses to cyberattacks with a crisis communication workshop.
It “is really helpful for people to think through: ‘What should I have in place?’” Di Stasio said. “So, the first time I think about it isn’t when [an attack occurs and] somebody says: ‘OK, what are you going to do?’”
ERCOT is seeking more time to hash out the details around a Nodal Protocol revision request that would establish notification responsibilities for the grid operator and its market participants during cybersecurity incidents.
During a workshop Tuesday, ERCOT staff said they will ask stakeholders to table NPRR928 in order to allow more time for comments on the proposal, which outlines a process for market participants to notify the grid operator about cybersecurity incidents. ERCOT is seeking to increase its awareness about the vulnerabilities of third-party systems that interact with its own systems, with an eye toward preventing interruptions to the grid.
A second workshop on the rule change will be scheduled in August or September, staff said.
ERCOT defines a cybersecurity incident as a malicious or suspicious act that “compromises or disrupts” a computer network or system belonging to ERCOT, a market participant or its agent that transacts with the grid operator that “could foreseeably jeopardize the reliability or integrity of the ERCOT system or … market operations.”
“Does an incident compromise or disrupt? Does it jeopardize the reliability or integrity of ERCOT systems or market operations?” Senior Corporate Counsel Brandon Gleason said. “We’re interested in things that are going to have an impact on something. ERCOT’s perspective is we want to know actual events that are occurring and have the potential to impact others.”
“We’re interested in anyone who has access into our system,” General Counsel Chad Seeley said. “We’ve tried to capture every access point into the system.”
Staff said that while ERCOT shares information with various government oversight groups “depending on the nature of the event,” it has no legal requirement to report cyber incidents as they are occurring.
Under NPRR928, the grid operator would send market notices, if necessary, to alert the market to an incident and actions being taken, while also disclosing the identity of any law enforcement agency notified about the event.
The protocol change will help cover those market participants that are not NERC registered entities. ERCOT has 939 market participants, less than 25% of which (191) are registered with NERC and subject to its reliability standards, including CIP-008.
ERCOT system access under NPRR928 | ERCOT
Non-registered entities “don’t have reliability nexuses, but they do have market nexuses,” Gleason said.
FERC on June 20 approved a new NERC cybersecurity rule that expands reporting requirements beyond just those incidents that actually compromise or disrupt reliability tasks on the bulk electric system.
CIP-008-6 now requires NERC entities to report any incidents that compromise, or attempt to compromise, electronic security perimeters, electronic access control or monitoring systems, or physical security perimeters associated with high- and medium-impact BES cyber systems and attempts to disrupt operation of a BES cyber system. (See FERC OKs Cyber Reporting Rule.)
In Texas, the state’s Public Utility Commission, Department of Public Safety, Department of Information Resources and Cybersecurity Council all have cybersecurity oversight over ERCOT. At the federal level, oversight agencies include the departments of Homeland Security, Justice and Energy, the FBI, and FERC, in addition to NERC and others.
The Texas Legislature recently passed three cybersecurity-related bills, none of which affected NPRR928:
Senate Bill 64, effective Sept. 1, directs the PUC to establish a program to monitor utilities’ cybersecurity efforts that provide guidance on best practices and facilitate the sharing of information between utilities. It also requires ERCOT to conduct an internal cybersecurity risk assessment and submit an annual compliance report to the PUC.
SB 475, effective immediately, establishes the Texas Electric Grid Security Council to facilitate the creation, aggregation, coordination and dissemination of best security practices. It is composed of the PUC chair, ERCOT CEO and Texas governor (or designated representative).
SB 936, effective Sept. 1, requires the PUC to engage a cybersecurity monitor to manage outreach, research, develop and facilitate best practices and training, review voluntary self-assessments, and report back to the commission on preparedness.
WASHINGTON — Senior executives of some the nation’s largest public power utilities came to D.C. this week to lobby Congress on tax policy and talk to the executive branch about federal reviews of infrastructure projects. They also squeezed in meetings with FERC.
One issue that was not top of mind was the Trump Administration’s announcement last week it was replacing the Clean Power Plan with less stringent emission rules for coal-fired generation.
So does the Affordable Clean Energy rule matter in the utilities’ long-term plans?
“No,” said Thomas Falcone, CEO of the Long Island Power Authority, during a press briefing with other executives in the delegation from the 27-member Large Public Power Council. “New York [last week] passed its own climate bill in the absence of federal energy policy. That climate bill seeks to have a carbon-neutral economy by 2050 and carbon-free grid by 2040. In New York, we have one coal plant … it’s supposed to shut down by 2020.”
Executives from public power companies in Texas, Washington, Nebraska and North Carolina agreed: Current federal policy is far less important to their decision-making than their states’ rules.
“I don’t spend a lot of time worrying about the ACE rule,” said Pat Pope, CEO of the Nebraska Public Power District.
No Lifeline for Coal
The ACE rule defines the best system of emissions reductions (BSER) as heat-rate efficiency improvements that can be achieved at individual coal plants, not the “beyond the fence line” generation-shifting, fuel-switching and state emission caps required under the CPP. (See EPA FinalizesCPP Replacement.)
Although some praised the policy as a rejection of the Obama administration’s “war on coal,” the ACE rule won’t be a lifeline for coal plants in North Carolina or Nebraska, officials said.
“We’re certainly moving ahead with ways to mitigate our carbon footprint,” said Pope, who noted NPPD is converting one of its smaller coal plants to burn hydrogen.
It’s also planning to offset greenhouse gas emissions by capturing methane from the state’s agriculture industry. “We’re actively exploring ways we can stop those emissions from occurring and credit that toward our coal emissions, and [we’re] still looking at carbon capture and sequestration,” Pope said. “We’re situated in an area where there’s probably more opportunities for sequestration than in other areas of the country. We’re going to take a hard look at that.”
Roy Jones, CEO of ElectriCities of North Carolina, said his company is also phasing out coal. “When I look at the ACE plan, the heat rate improvements in the plan — if they were economical, they’d have already been done,” Jones said.
Pope agreed. “The way we operate, we’re always going after these efficiency improvements. We’re all about lowering the cost to our consumers, running very efficient plants and operations. So the low-hanging fruit of those types of projects is long gone. … I think the incremental opportunities for others [are] going to be pretty small.”
Public power owns no coal in Washington state, said Steve Wright, general manager of the Chelan County PUD. Last month, Gov. Jay Inslee, who has made climate change the centerpiece of his longshot presidential campaign, signed the Clean Electricity Transformation Act, which bans utilities’ use of coal by 2025 and sets a 2045 target for emission-free power.
“The decision [away from fossil fuels] has already been made,” Wright said. “Now we’re trying to figure out how we’re going to make it work.”
Reinvesting in Hydropower
In Washington, that means a continued dependence on hydropower, which supplies 70% of the state’s electricity.
“It’s an aging hydropower system,” Wright said. “The challenge is how are we going to maintain that capability because as you add variable energy — non dispatchable resources — you need something to maintain reliability.
“It’s going to take a very large reinvestment in the system in order for it to be maintained because most of it was built as late as the 1970s, so the youngest plants are 40 years old. There’s a lot of work to do there, but with the right investments, we can make it work.”
‘Holistic’ View
With no stockholders, “having [our] finger on the pulse of community is very important,” said North Carolina’s Jones. “And as we talk to our community about climate change, without exception every one of them has individuals in the community that want to do more with renewables. Rooftop solar, community solar. Things they can do to make their homes more energy efficient and reduce their carbon footprint.”
Jones said North Carolina is almost a quarter of the way towards its goal of a 40% reduction in carbon emissions from 2005 levels by 2040.
To close the gap, Jones said the company is discussing ways to electrify the transportation system. “When we step back and look at the carbon footprint, we’re not just looking at the electric industry. We’re looking holistically in our communities. What are things we can do to reduce that carbon footprint.”
Austin Energy, which has been transitioning to renewable energy and emphasizing energy efficiency and demand-side management, will shut its last two large gas-fired steam units by 2021 and plans to exit from its coal position by 2022, said General Manager Jackie Sargent.
Because of ERCOT’s “robust” market and great transmission access, Sargent said the utility has been able to add wind and solar resources with locational diversity. “So, I don’t see the ACE rule impacting us in a significant way,” she said.
MISO’s exhaustive proposal for overhauling the cost allocations for market efficiency projects (MEPs) came a hair’s breadth from getting FERC approval on Monday — but for one key detail.
FERC rejected the plan — years in the making — after finding MISO’s cost allocation treatment for a new category of local economic transmission projects was at odds with the principle of cost causation (ER19-1124).
MISO filed the cost allocation scheme in February, part of a broader proposal to lower the voltage threshold for MEPs from 345 kV to 230 kV and eliminate a 20% footprint-wide postage-stamp cost allocation method for projects.
The plan also set out to create two new project benefit metrics in addition to the RTO’s existing adjusted production costs metric. One metric would have recognized the value of deferred or avoided reliability transmission projects, while the other would have considered the value of reducing power flows on the contract path on shared transmission from MISO Midwest to South. (See MISO MEP Cost Allocation Plan Goes to FERC.)
The proposal also would have provided limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability.
‘Inconsistent’
MISO’s proposal also sought to create a new project type — the local economic project — meant for smaller, economically-driven transmission projects between 100 kV and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line. The smaller project type would have replaced the current “economic other” project category, the costs for which were also allocated to the specific pricing zone in which they are located.
But unlike an “economic other” project, a new “local” project would not only have to meet a local benefit-to-cost ratio of 1.25-to-1 or greater within its pricing zone, it would also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs.
And therein lay the rub for FERC, which rejected the notion MISO could require a local project to demonstrate a solid regional benefit while still allocating 100% of its costs to the local pricing zone rather than across all zones standing to benefit.
“In this case, [MISO and its transmission owners] do not contend that they are unable to calculate the distribution of benefits for Local Economic Projects with the same granularity as Market Efficiency Projects,” the commission wrote. “Instead, Filing Parties’ proposal suggests the opposite conclusion — that, if MISO implements the proposed benefits metrics, it will be able to more precisely calculate the distribution of benefits … Thus, every time MISO approves a Local Economic Project in its [transmission expansion plan], it will first identify all benefitting zones in the same manner it does for Market Efficiency Projects.”
The commission went on to say MISO had proposed metrics to identify the regional benefits of local projects but “ignored the results of its regional benefit metrics analysis in order to allocate the costs only to the transmission pricing zone(s) where the project is located. This combination of elements within the proposal therefore is inconsistent with the cost-causation principle.”
Multiple protestors, including MISO Industrial Customers, WEC Utilities and the Michigan Public Service Commission, filed with FERC to criticize the misalignment of benefits and costs. Other protestors dubbed the regional and local 1.25-to-1 benefit-to-cost ratio requirement a “double hurdle.”
Competitive transmission developer LS Power went a step further and said the project type has “no ascertainable regional purpose, directly harms ratepayers and benefits only incumbent transmission owners.” LS Power also filed a separate MEP complaint in early June, asking FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)
But the ruling was not all bad news for MISO. FERC acknowledged the work the RTO and its stakeholders put into developing the cost allocation proposal, which “includes compromises resulting from a three-year discussion among diverse stakeholders with myriad competing interests.” The commission said most of the plan appeared to be reasonable and it urged MISO “to consider whether the proposal could be modified to address the cost causation issue … while retaining the benefits of other aspects of the proposal.”
MISO was counting on the new cost allocation for projects in the 2019 MISO Transmission Expansion Plan.
Interregional Filings Also Rejected
FERC on Monday also rejected two interregional cost allocation filings MISO made for PJM and SPP because they contained a cost allocation method like the one MISO proposed for local economic projects. (ER19-1156-000 and ER16-1959-005). MISO had proposed that its share of interregional economic projects with voltages below 230 kV but at or above 100 kV be allocated 100% to the transmission pricing zones where the project is located.
With the rejections, a piece of MISO’s allocation compliance over the longstanding complaint by Northern Indiana Public Service Co. remains unresolved. (See FERC Signals Bulk of NIPSCO Order Work Complete.) FERC said MISO now has 90 days to let the commission know if it plans to use the existing MEP cost allocation method for MISO-PJM interregional economic transmission projects above 100 kV but below 345 kV or propose revisions for a separate cost allocation process. FERC’s 2013 NIPSCO order lowered the minimum voltage threshold for MISO-PJM interregional market efficiency projects from 345 kV to 100 kV.
HOUSTON — Beth Garza’s annual visit to the Gulf Coast Power Association’s Houston chapter Thursday once again drew a roomful of electric industry insiders and observers hoping to glean insights into the state of the ERCOT market.
But first, Garza, director of ERCOT’s Independent Market Monitor, had to remind her luncheon audience what her role is. Asked about her expectations of the market’s performance during the summer, Garza responded, “The cool thing about my job is that it’s the Market Monitor, not the market predictor.”
Garza did allow that forward prices do show a “moderation of expectations” for the summer. She shared a slide that showed ERCOT’s North Hub futures for August at around $120/MWh and the July futures at around $70/MWh.
A year ago, August futures briefly eclipsed $250/MWh in May, when the reserve margin was 11%. It is now down to 8.6%.
“It’s been a wet spring, and wet springs tend to portend not-that-hot summers. I think we will see similar outcomes in the summer of 2019,” she said, echoing ERCOT’s weather forecast. (See “Staff Prep Directors for Summer Expectations” and “IMM Market Report: Load Continues to Climb,” ERCOT Board of Directors Briefs: June 11, 2019.)
ERCOT says it expects to use emergency measures this summer to meet a record forecasted peak demand of 74.9 GW, more than last summer’s all-time system peak of 73.5 GW. The grid operator has an available capacity of 78.9 GW.
The Monitor’s State of the Market report notes ERCOT’s load grew at a 5.3% clip last year. ERCOT expects the growth to continue at a 2.5 to 3% rate through 2022, when peak demand is projected to hit 84.1 GW.
“This continued growth puts us on a path of being short,” Garza said. “If you look at installed capacity … the resources we have today will be insufficient to serve projected load in 2021.”
One luncheon guest asked Garza whether batteries and other forms of energy storage could play a major role in the market.
“The difficulties and challenges around batteries are numerous and hard,” she said. “ERCOT is not alone in the RTO world in wrestling with those questions and trying to figure out what the right answers are. I don’t have easy answers, because there are no easy answers.”
74-MW Wind Farm to Retire in November
ERCOT on Thursday approved West Texas Wind Energy Partners’ request to shut down a 74-MW wind farm in Southwest Texas. The grid operator said its reliability analysis indicated the facility was no longer needed to support system reliability.
The Southwest Mesa Wind Energy Center | NextEra Energy Resources
Southwest Mesa began commercial operation in 1999. With nearly 22.1 GW of installed wind in ERCOT’s footprint as of April, the facility’s retirement will represent a 0.33% cut in wind capacity.
SPP may ask FERC to lower its exit fee in response to the commission’s April order that the RTO eliminate the fee for members who are not transmission owners or load-serving entities.
Staff told the Corporate Governance Committee on June 17 that they believe FERC’s order (EL19-11) suggested the commission may approve a lower amount. SPP faces an Aug. 1 deadline to make a compliance filing and has already submitted a rehearing request to clarify the definitions of TOs and non-TOs. (See FERC Tells SPP to End Exit Fee for Non-TOs.)
The committee agreed in executive session to recommend a fixed $100,000 exit fee to the Board of Directors when it meets on July 30. The current exit fee is estimated at $631,915, nearly twice the $327,191 fee that FERC approved in 2006, when it last required the RTO to impose an exit fee on all members.
Load-serving members would be subject to an additional share of SPP’s financial obligations and future interest based on their net energy for load percentage. LSEs would be defined as distribution or electric utilities that have a service obligation and/or secures energy and transmission service to serve its end-use customers’ demand and energy requirements.
Staff noted the commission’s order said “some level of exit fee that does not act as a barrier to membership and is not excessive could be appropriate in SPP.”
By making the fee a fixed amount, SPP said it would be addressing the commission’s concern that the exit fee can move up or down.
FERC’s order came in response to a complaint filed by the American Wind Energy Association and Advanced Power Alliance, formerly the Wind Coalition. The groups charged that SPP’s exit fee results in unjust and unreasonable rates and creates “a barrier to membership” for non-TOs and non-LSEs.
“What’s being proposed here does not seem to track with cost-causation principles. Such an exit fee that’s not based on any … principles would likely be opposed,” APA’s Steve Gaw said. “We would like to see something that is more in line with what other RTOs have found to be appropriate for membership and stakeholder participation.”
CGC member Denise Buffington, director of federal regulatory affairs with Evergy companies Kansas City Power & Light and Westar, cautioned against the move considering the pending rehearing request.
“If FERC gets this as an alternative … it’s an easy pass for them not to deal with this issue. My preference would be to wait until we get an order on the rehearing request,” she said. “If I were giving legal advice on behalf of the client, I would stick close to what FERC has ordered.”
SPP CEO Nick Brown said staff debated the timing of the alternative proposal but said the recommendation was “to help FERC get the right answer.”
“We’ve continued to debate this [issue] at the request of non-members or members who wished to withdraw but couldn’t afford the exit fee,” he said. “In putting this proposal on the table, we specifically wanted to influence FERC’s thinking and help them to make a decision. We consider this just and reasonable.”
Other committee members favored the lower exit fee. Dogwood Energy’s Rob Janssen said the reduced fee would solve the problem of “zombie members”: those who stayed members “because it was easier than paying the exit fee.”
“I think this change will make them come out of the woodwork and make a decision one way or the other,” Janssen said.
The CGC will also recommend approving the compliance filing, which would change SPP’s governing documents in response to FERC’s order. Staff said it will include what it believes are errors in FERC’s order, for which they are seeking rehearing.
If the board approves the committee’s recommendations in July, they will be promptly filed at FERC to meet the Aug. 1 deadline.
RENSSELAER, N.Y. — NYISO presented the Business Issues Committee the final market design for pricing carbon emissions into its wholesale electricity markets on Thursday, the same day the New York State Assembly passed a bill that will put many of Gov. Andrew Cuomo’s environmental targets into statute.
The Climate Leadership and Community Protection Act (A8429) will require 70% of the state’s electricity be generated by renewable resources by 2030, nearly quadruple its offshore wind energy goal to 9 GW by 2035 and require the economy to be carbon-neutral by 2040. The law also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)
| NYISO
Stakeholders were divided on whether the bill — expected to be signed into law by Cuomo — necessitates increased skepticism on carbon pricing or urgency on the effort.
“It will take time to digest the new information, but having carbon pricing helps reach these goals, said Rana Mukerji, NYISO senior vice president for market structures. “If [load-serving entities] are required to buy renewables, the procurement prices will reflect the benefit renewables derive from having carbon priced into the energy market.”
Representing the Independent Power Producers of New York, Matt Schwall said, “IPPNY continues to be very supportive. … Carbon pricing is now more important than ever. There’s been a lot of time spent developing the idea, and this will help us reach the targets.”
Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers, said he was “skeptical” of how consumers could benefit from carbon pricing under the new law.
Couch White attorney Kevin Lang, speaking for New York City, said he shared Breidenbaugh’s concerns: “Carbon pricing isn’t going to get us incrementally more generation … and I agree that NYISO needs to look at the new law before moving forward.”
Mark Younger of Hudson Energy Economics said, “You can put targets, but that doesn’t mean they’re effective. You can put 7,000 MW of wind in the North Country and meet a target of 7,000 MW of additions, but not get much benefit of zero-carbon megawatt-hours in the state.”
“Action needs to start happening immediately, and we need to be sending price signals that reflect the value, or the damage, of carbon emissions,” said Howard Fromer, director of market policy for PSEG Power New York. “How? The closest thing is the mechanism we’ve come up with here, and carbon pricing is even more important now than it was a year ago.”
Robert Pike, NYISO director for market design and product management, said, “We’re here today just to recognize the culmination of the work that’s taken place over a considerable amount of time.”
Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), said, “A long time ago, we said that a market without a carbon component is inconsistent with our environmental goals. Carbon pricing can help the state reach its goals.”
On Monday, third-party consultant Analysis Group presented to the Installed Capacity/Market Issues Working Group preliminary results of a supplemental analysis examining the impacts of pricing carbon. The study is intended to augment the Brattle Group report process that concluded in December. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Broader Regional Markets Update
Pike presented the monthly Broader Regional Markets report and highlighted item No. 26, noting that the Management Committee in May approved a new external supplemental resource evaluation (SRE) penalty regime.
Approved by the BIC in April, the SRE penalty provisions will boost the ISO’s ability to call on external resources that have sold capacity to New York. Pending FERC approval, the proposal is anticipated to become effective in August.
Pike also highlighted BIC and MC approval last month of revisions to the NYISO-PJM joint operating agreement to address coordination on flowgates similar to the East Towanda-Hillside Tie Line.
Manual Revisions
The BIC approved revisions to several manuals, with most of the changes required by implementation of the Zone J (New York City) reserve region.
Ashley Ferrer, NYISO energy market design specialist, reported that the changes would affect the Ancillary Services, Day-Ahead Scheduling and Transmission & Dispatch Operations manuals.
ISO staff engineer Harris Miller detailed additional revisions unrelated to the Zone J reserve requirements being proposed within the affected manuals.
Ferrer said the proposed New York City reserves would go into effect Wednesday, assuming approval by FERC.
LBMPs, Gas Prices Drop
NYISO locational-based marginal prices averaged $23.10/MWh in May, down about 17.5% from April and about 19.7% from the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $37.57/MWh, a 25% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in lower compared to April. Average daily sendout was 373 GWh/day in May, higher than 371 GWh/day in April and lower than 397 GWh/day in the same month a year ago.
Transco Z6 hub natural gas prices averaged $2.27/MMBtu for the month, off slightly from April and down 11% from a year ago.
Distillate prices were down 8.5% year over year and mixed from the previous month, with Jet Kerosene Gulf Coast averaging $14.64/MMBtu, up a penny from April, while Ultra Low Sulfur No. 2 Diesel NY Harbor dropped to $14.54/MMBtu from $14.72/MMBtu in April.
May uplift increased to 13 cents/MWh from -15 cents in April, while total uplift costs, including NYISO’s cost of operations, came in higher than the previous month.
The ISO’s 23 cents/MWh local reliability share in May was up from 20 cents the previous month, while the statewide share climbed to -11 cents/MWh from -35 cents in April.
The Thunderstorm Alert cost was 19 cents/MWh, up from the usual zero to 1 cent.
Phase 2 of NERC’s Standards Efficiency Review has narrowed its focus to four tasks, tabling two others for potential work by other committees, members of the Phase 2 team said last week.
In a June 17 conference call, the team said it would focus its work on the four initiatives that received the highest response from stakeholders in polling that concluded March 22. (See “Team Reviewing Feedback on SER Phase 2,” NERC Standards News Briefs: May 8-9, 2019.)
The team’s decision followed a June 11 meeting with the SER Advisory Group and FERC staff.
“There was a discussion with the Advisory Group on how [SER] Phase 2 is much different than Phase 1. We’re looking more holistically and long-term at ideas that can streamline things going forward, not necessarily individually at the requirement level,” said SER Phase 2 Chair John Allen, manager of reliability compliance for the City Utilities of Springfield (Mo.). “I thought there was good support from the Advisory Group and at least no indication from FERC staff that we were heading down a road that was not viable.”
The top two priorities — changes to the evidence-retention rules and consolidating information/data exchange requirements — are expected to be completed this year.
The team also will tackle a proposal to move “competency-based” requirements from standards to guidance documents and developing a risk-based standards template; those efforts are likely to extend into 2020, team members said.
“There’s a lot of work that was already done on … evidence retention, so there was a good baseline to start on that. On the data and information consolidation, it’s pretty cut and dried, straightforward,” Allen said.
“These other two are shifts. We’re putting these ideas out there to say, ‘Here’s how we do it today. How can we do it more efficiently going forward?’ To make that successful, we’ve got to get all the right stakeholders together.”
The SER team declined to work on relocating competency-based requirements to the certification program/controls review process, which will be transitioned to the Compliance Certification Committee or the Organization Registration and Certification Programs (ORCP).
It also is dropping an initiative on consolidating and simplifying training requirements. A subgroup of the Phase 2 team “is talking about potentially drafting a [standards authorization request] for the training concept,” said Chris Larson, NERC manager of standards information.
Reducing the Scope of Work
In working on the prototype standards, Allen said, the SER team should “find some way to try to reduce the need or the scope of the work for a future Standards Efficiency Review or Paragraph 81 or whatever you want to call it — a cleaning up of the standards.”
Paragraph 81 is a reference to FERC’s March 2012 order on NERC’s Find, Fix and Track process, in which the commission told NERC it would welcome proposals to revise or remove reliability standards or requirements that are redundant or add little protection to system reliability (RC11-6, et al.).
“If we can put ourselves on a better path going forward where we don’t have to do this every five years, we’ve done some good work,” Allen continued. “That’s really what we’re going to look to in the prototype standard — is how to put some tools out there going forward to help have a more efficient product where we don’t have to go and clean them up every few years.”
“I’ll second that concern,” said John Pespisa, an Advisory Group member from Southern California Edison. “[The] key to not doing this again in the near future is bringing that key concept into this process.”
Randy Crissman, senior reliability and resilience specialist for utility operations at the New York Power Authority, said there is a need for a “communications strategy.”
“How do we help facilitate the adoption and implementation of that type of an approach? It’s going to be a pretty big lift, but if we don’t try it, it will never happen.”
