The New England Power Pool Reliability Committee last week voted to recommend that ISO-NE approve pool-supported pool transmission facility (PTF) costs totaling more than $39 million for three projects by Eversource Energy.
The first project involves $24 million in PTF costs for work associated with the rebuild of the 69-kV 667 line in Connecticut, with none of the costs associated with the upgrade considered localized.
The work would replace 52 wood structures with steel pole structures to mitigate deficiencies such as woodpecker damage, rot, cracks and deteriorated steel mechanical connections, Eversource engineer Bob Case said.
Based on a show of hands, all three motions passed with none opposed and no abstentions. All sectors had a quorum except End Users.
The second project has PTF costs of approximately $7 million for work associated with the 115-kV 1180 line cable replacement between Norwalk Harbor and Ely Avenue Junction.
The project will replace nearly a mile of 2,000-kcmil HPFF cable with 2,500-kcmil cable to mitigate continuous increases in dissolved gas analysis levels, which potentially result in reliability concerns as well as safety and environmental risks.
The third project has PTF costs of nearly $8.2 million for similar work associated with the 115-kV 1608 line cable replacement between Norwalk Harbor and Ely Ave, replacing 8,500 feet of 2,000-kcmil cable.
Capacity Cost Compensation
The RC also voted to recommend that ISO-NE approve West Medway Jet 4 and Jet 5 as dynamic reactive resources meeting the Capacity Cost Compensation Program eligibility requirements defined in Tariff Schedule 2.
The approval calls for the Schedule 2 business procedure compliance costs to be designated as eligible for Schedule 2 capacity cost compensation associated with the qualified reactive resource designation, to be effective Nov. 1, 2019.
Providing adequate reactive supply and voltage control service (VAR service) from reactive resources, as defined in the Tariff, is necessary to maintain reliable voltage levels on the New England transmission system. Schedule 2 defines the extent to which reactive resources are compensated for providing VAR service and transmission customers are charged for utilizing the service.
Operating Procedure Revisions
The RC voted to recommend that the Participants Committee support revision of ISO-NE Operating Procedure No. 2 to incorporate a new reference document and clarify the RTO’s role in approving the scheduling of planned equipment maintenance and outages.
ISO-NE lead operations analyst Kory Haag presented for a future vote the initial proposal for revisions to Operating Procedure 11E related to black start resource administration and a designated black start resource (DBR) test log.
The proposed revisions clarify recording the amount of time the DBR is in stable operation to be consistent with Northeast Power Coordinating Council Directory 8 covering system restoration and incorporate minor grammatical fixes.
Proposed Plan Applications
The committee voted to recommend that ISO-NE approve NextEra Energy Resources’ 150-MW Lone Pine Solar facility in Maine and related transmission projects.
NextEra will install a station transformer, while Central Maine Power plans to build a new three-breaker 345-kV ring bus configured substation to accommodate interconnection of the project to the existing Section 391 line between the Buxton and Scobie Pond substations. The proposed in-service date of the project is Dec. 31, 2022.
The RC also approved a power purchase agreement by New England Power for a static synchronous series compensator at the Fitch Road substation in Clinton, Mass., with a proposed in-service date in March 2020. The compensator is a modular power flow control device to inject a leading or lagging voltage in quadrature with the line current, providing the functionality of a series capacitor or a series reactor, respectively, on the 69-kV W-23 circuit.
The RC recommended that ISO-NE approve implementation of Freepoint Solar’s 20-MW solar array in Peterborough, N.H., to interconnect with a line tap on the Eversource 34.5-kV Line 313 between South Peterborough and the Monadnock substation. It also approved Freepoint’s 20-MW solar array in Thornton, N.H., to interconnect with a line tap on the Eversource 34.5-kV Line 342B north of the Beebe River substation. Both projects would have a December 2022 in-service date.
The RC in one vote approved implementation of 58 individual PPAs by New England Power, known as the Western Massachusetts Distributed Energy Resource Additions Cluster (Group 1) Generation and Transmission Project. Based on a show of hands, the motion passed with none opposed and three abstentions, all from the Publicly Owned Entity sector.
Estimated Operating Reserve Deficiency
Fei Zeng, ISO-NE’s lead analyst for resource studies and assessments, reviewed the estimated hours of system operating reserve deficiency for Forward Capacity Auction 14 (2023/24) calculated with and without Mystic 8 and 9.
Zeng said the analysis can be considered an extension of the installed capacity reserve (ICR) calculation and uses the same model and underlying assumptions. The analysis simulated all the hours of year and only found reserve deficiency hours during the summer months without the Mystic units.
A comparison of results between FCA 14 (2023/24) and FCA 13 (2022/23) show a spread of expected reserve deficiency hours. | ISO-NE
The estimated annual hours of operating reserve deficiency for capacity commitment period 2023/24 (FCA 14) are higher than 2022/23 (FCA 13).
The probability of deficiencies occurring is lower for the extreme high load levels (high exposure to load-shedding conditions) in the FCA 14 forecast than in FCA 13, resulting in fewer loss-of-load events and a reduction to ICR. However, the probability of operating reserve deficiencies occurring is higher for the intermediate high load levels (high exposure to reserve shortage conditions) in the FCA 14 forecast, resulting in more reserve deficiency hours, Zeng said.
The RC will consider the issue again in December, he said.
FERC was skeptical Thursday of a proposal by the new owner of a submarine transmission cable running under San Francisco Bay for an increase in its transmission revenues and a $10 million annual reserve for 50 years in case of wildfires (ER19-2846).
In September, Trans Bay Cable, now owned by NextEra Energy Transmission, proposed revising its transmission owner tariff to increase its annual transmission revenue requirement from $133.9 million to about $157.3 million. It also sought to extend an incentive return on equity adder of 13.5% based on its unique benefits to the San Francisco Bay Area. (See FERC OKs Trans Bay Cable Sale to NextEra.)
The company argued that “the project provides significant benefits to consumers that outweigh Trans Bay’s total TRR and displace the need for in-city generation [in San Francisco],” FERC said. “Specifically, Trans Bay states that the project provides between $143 million and $261 million in societal and ratepayer benefits per year.”
The Trans Bay Cable runs for 53 miles under San Francisco Bay.
In addition, Trans Bay “proposes in the instant filing to collect a reserve fund of approximately $10 million per year over the next 50 years to address the uninsured [wildfire] risk, which according to Trans Bay amounts to at least $463 million,” FERC said.
Trans Bay operates a 53-mile, 400-MW transmission line buried beneath the bay, with converter stations at either end, in San Francisco and the city of Pittsburg.
“Trans Bay notes that while the project’s design limits wildfire risk, it cannot wholly prevent fire ignition resulting from its equipment due to its location, particularly related to the possibility of a fire at its Pittsburg converter substation,” FERC wrote.
Protesters, including a group of six cities on the bay and the California Public Utilities Commission, challenged the 13.5% ROE adder and the wildfire reserve fund.
Trans Bay provides transmission between two PG&E substations in San Francisco and Pittsburg, Calif. | SteelRiver Infrastructure Partners
“Six Cities and CPUC note that the project’s location underwater reduces wildfire risk, and that the urban nature of the above-ground components suggest low risk,” FERC wrote.
The company has received a 13.5% ROE adder since its start in 2005. But the CPUC and others argued that “since Trans Bay is no longer a start-up company or independent transmission company after its acquisition by NextEra [last spring], it no longer qualifies for an incentive ROE, and that the commission should instead apply a base ROE.”
FERC preliminarily agreed with the protesters.
“Our preliminary analysis indicates that Trans Bay’s proposed TRR has not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” the commission wrote. “Trans Bay’s proposed TRR, including the requested 13.5% ROE and the establishment of a wildfire risk reserve fund, raises issues of material fact that cannot be resolved based upon the record before us.”
FERC accepted the company’s proposed TRR, suspended it for the maximum five-month period, subject to refund, and set all issues for hearing and settlement judge procedures.
A settlement judge must report to FERC on the parties’ progress within 30 days.
SAN ANTONIO — The National Association of Regulatory Utility Commissioners held its 131st Annual Meeting and Education Conference last week, bringing state and national utility regulators, federal and state policymakers, industry representatives, consumer advocates and other stakeholders to south-central Texas.
Here is some of what we heard during the four-day event.
A ‘Fabulous’ Leftover
Texas Public Utility Commission Chair DeAnn Walker moderated the leadoff panel, which discussed the changes facing competitive markets and the cost and potential benefits of restructuring.
Independent consultant Alison Silverstein said markets have become more complicated since they were created to balance supply and demand through competition. So much so, she said, that she lamented being unable to find clip art for her presentation to illustrate her point: that of an elephant standing on a stool and juggling a chainsaw, flaming batons and a flowerpot.
“A lot of things have changed: falling prices; older baseload generation retiring; little demand growth,” Silverstein said. “All of these things are incredibly complicated. Competition works, but the current market design is not working well. We need market changes for the next 20-plus years to deal with high decarbonization, variability and uncertainty.”
Silverstein listed the four factors of market design:
What competes in the market?
What are the market rules for ancillary service, dispatch and price calculations?
Who buys — and how much — in the spot market vs. self-supply or bilateral contracts?
What is the missing money mechanism (i.e., capacity payments or an operating reserve demand curve)?
Asked by Walker what regulators should focus on, Silverstein pointed to the markets’ ease of entry and exit.
“You don’t want old, expensive resources cluttering up your market,” she said. “Focus on energy efficiency, because your customers need as much energy efficiency as possible. Changes in technology and economics have changed completely what resources are available, and changes in society have changed what customers are willing to put up with.
“We need a lot of market changes to deal with uncertainty and variability,” Silverstein said. “Just because you’re in charge of market prices, don’t think those are the only dials that matter. There’s an awful lot of stuff going on that can screw up the best markets.”
Mason Emnett, Exelon’s vice president of competitive markets, said capacity markets “are not working out” in some portions of the country and suggested the answer could be regional resource adequacy.
“I think there’s a possibility, a hope, that the regions with capacity markets could evolve into something that is optimized over a larger footprint,” Emnett said. “We have hope that regional adequacy markets can evolve, but we’re not holding our breath. Those types of changes take years to develop.”
“When he talks about resource adequacy, that’s a fabulous leftover from the generation-centric days,” Silverstein said.
“You don’t have to have a sky-high resource margin or a resource adequacy construct in order to keep the lights on. That proves the fact that markets do work,” Silverstein said.
“Don’t let anyone say a 7.4% reserve margin doesn’t make you sit on the edge of your seat every day. It does,” Walker said in agreeing with Silverstein. “Generators have to come to the table to be on and produce during those [low-resource] days, but we had a huge impact from demand response. When prices hit $9,000, [industrial] loads come off. That’s something we’re learning.”
Glick Concerned with FERC Nominating Process
FERC Commissioner Richard Glick, the only federal commissioner to show up at NARUC and the only Democrat on the soon-to-be-four-person panel, shared his concerns over the agency’s nomination process during a “Nick & Glick” Q&A session with outgoing NARUC President Nick Wagner.
Glick said he has issues with the process, in large part because the tradition of pairing nominees for two or more vacancies was ignored with the recent nomination of General Counsel James Danly to fill one of two vacancies on the commission. (See FERC General Counsel Tapped for Commission.)
He said changes to the Senate’s filibuster rules have made it difficult for Democrats to have any say in the matter. Former Commissioner Cheryl LaFleur’s Democratic seat has been vacant since she left in August. Republicans will enjoy a 3-1 majority when Danly joins the commission.
“What does it say the next time a Democratic president and a Democratic Senate don’t pick any Republican nominees?” Glick said. “That was not the way the process was designed. I hope we can go back to a more normal process.”
Glick also hopes for a return to the days when FERC operated in a more bipartisan manner. He said a couple of protesters of FERC’s recent pipeline approvals showed up at his house on Halloween, unnerving his 10-year-old son.
“We have our share of protesters … but going to someone’s house? That’s beyond the pale,” Glick said.
Asked by Wagner about the relationship between state regulators and FERC, Glick said that low gas prices have resulted in additional zero-marginal-cost resources beyond renewables and “more contentious” markets.
“No doubt, state policies impact the wholesale markets, and that was true the day they invented energy policy in general,” he said. “The more traditional generators are essentially insisting those continued subsidies are depressing the markets. But [fossil fuel] technologies have been subsidized for a long time. If we only recognize the more recent subsidies, particularly renewables and nuclear, we are being short-sighted. Over the long term, these other subsidies have a long-term effect over the markets.”
Glick also recounted how he became a FERC commissioner. At the time, he was a staff member for U.S. Sen. Maria Cantwell (D-Wash.), and he recalled telling her that if a FERC position came open, “sure,” he would be interested.
“Sometimes we’re in the wrong place at the wrong time,” Wagner cracked.
New President: Remember the Customer
Newly installed NARUC President Brandon Presley — yes, he’s related to Elvis, a fellow Mississippian — showed off his public speaking chops with a stem-winder of an acceptance speech that highlighted his theme for the upcoming year: “Bridging the Divide.”
“At the end of the day, you serve the people of this country in all 50 states and [the] territories,” Presley said, encouraging his fellow commissioners and regulatory staff to avoid the use of the term “ratepayer.”
“They’re a customer. A person. We’ve got to keep that in the forefront of our minds,” he said. “Many challenges exist for the least; the last; the left out; those people who are marginalized in our society. We have the biggest impact on their lives because we affect the cost of living for those people and those businesses. We have to keep this organization focused like a laser on the customer.”
To that end, Presley said he plans to appoint a task force to look at how best to bring broadband service to rural communities, such as those in the northeastern portion of Mississippi that he represents. He said his goals include identifying and closing other gaps that impede regulators and industry from better representing the public interest.
“We know that gulf exists. We know the brain drain in rural America is real,” Presley said. “We’ve got to find a way as a national association to solve this problem. I hope in the next year, we can be progressive; we can be alert and on the lookout for opportunities to make real, impacting decisions and policies that translate back to the people.
“There’s no greater satisfaction in life than knowing that you left something better than you found it,” he said.
Presley was first elected to the Mississippi Public Service Commission in 2007, winning re-election in 2011, 2015 and 2019. He served as mayor of his hometown of Nettleton from 2001 to 2007, being elected at the age of 23. Presley is a member of MISO’s Advisory Committee.
Joining Presley as NARUC officers are First Vice President Paul Kjellander, with the Idaho Public Utilities Commission, and Second Vice President Judith Jagdmann, chair of the Virginia State Corporation Commission.
On Friday, Presley added to the Executive Committee by naming North Carolina Utilities Commissioner ToNola Brown-Bland as treasurer and Arkansas Public Service Commissioner Kim O’Guinn as one of two appointed members.
Brown-Bland was appointed to the NCUC in 2009 and reappointed in 2017. O’Guinn was appointed to the PSC in 2016.
State Commissioners Evaluate PURPA NOPR
“At long last, it is finally here — the PURPA NOPR!”
That invitation to a panel discussion on FERC’s Notice of Proposed Rulemaking for changes to the 41-year-old Public Utility Regulatory Policies Act did the trick. An overflow audience overwhelmed the seating, grabbing empty spaces on the floor to listen to regulators and consumer advocates discuss the potential changes to rate-setting and which markets qualify for an exemption from PURPA’s “mandatory purchase obligation.” (See FERC to Reshape PURPA Rules.)
FERC’s proposed top-to-bottom changes include the elimination of a fundamental principle of the rules: fixed-price contracts at an “avoided-cost” rate for qualifying facilities. Utilities and state commissions have been among those complaining about PURPA, though most ISO/RTO members are exempt from the rule.
“PURPA has given me more grey hairs per policy than most I’ve worked on,” said Megan Decker, chair of the Oregon Public Utility Commission. Noting FERC declined to extend a deadline for comments on the NOPR, Decker said, “I hope that denial does not reflect FERC’s intention to not engage with a number of compromise solutions put forward. We don’t want continued uncertainty.”
“Idaho has a pretty tormented history with PURPA,” PUC Commissioner Kristine Raper said. “The NOPR was very responsive to the technical hearing. They clearly discounted cogeneration in the NOPR, and they looked at things like cost. These are all the things Idaho has tried to bring to the attention of FERC. FERC has narrowed the way states can interpret those rules.”
“The PURPA NOPR does a terrible job of distinguishing between competitive markets and those regions that don’t have wholesale competition,” said Katherine Gensler, vice president for the Solar Energy Industries Association. “PURPA’s structure is basically a balancing act between telling utilities to purchase a product and sellers that have to accept the price. Utilities have to buy a product they often claim they don’t want, and the seller has to accept the price published by the utility commissioners. This NOPR shifts that balance … moving away from the developers’ rights to give greater authority and power to the utility state commissions.”
Former FERC Commissioner Philip Moeller, now executive vice president of regulatory affairs for the Edison Electric Institute, argued that the NOPR would give states additional flexibility in approving QFs.
“This is about cost. Who’s paying? Are your constituents, your customers, overpaying for the projects? Most people think that’s a bad thing, unless you’re the one getting overpaid.”
FERC Commissioner Glick, who dissented against the NOPR, said what “perturbed” him the most was that the first 50 pages describe PURPA as no longer being a necessary statute.
“You can make a reasonable argument that that’s the case … but it’s our duty to administer [PURPA] and carry it out,” Glick said. “Congress has told us we need to facilitate small power production. To the extent a utility has a procurement practice or a market setup that allows all entrants to fully participate, you can get out of the PURPA requirements. If everyone has access to the procurement process, that seems to be best for users and consistent with Congress’ intent.”
Gold Still Sees Place for Renewables
Wall Street Journal reporter Russell Gold, whose “Superpower: One Man’s Quest to Transform American Energy” details Mike Skelly’s failed attempt to use HVDC lines to ship renewable energy across the country, called for changes to the current regulatory system “because of what’s coming.” (See Book on Tx Developer Transmits Climate Hope.)
He noted ERCOT has 22 GW of wind energy and 2 GW of solar — “[Solar] used to be fine if you wanted to warm water,” Gold said, referring to the efficiency advances for solar resources — and that the numbers will only increase as technology continues to improve and renewable energy prices stay low.
“There’s no blackouts and no one’s panicking,” Gold said. “Coal and nuclear are having trouble competing. Natural gas is soon going to have problems competing. The question for utilities and utility regulators is how long do you want to hold on to a coal plant that is above market prices? You have the potential for lots of inexpensive renewable electricity.”
But to bring that energy to market, he said, “you need to stitch this country together with HVDC transmission lines.”
In the end, not even the determined Skelly could do that.
“The biggest problem was that it was hard to get [landowners] to accept the sacrifice for the greater good of less carbon and clean power,” Gold said.
Speaking before a friendly audience, Gold couldn’t resist putting in a plug for his book.
“I’ve been told my book does the impossible,” he said. “It turns the regulatory process into a page-turner.”
Reality ‘Sinks in’ for Undoing Mexican Reforms
A two-person panel on the slowing energy reforms in Mexico said reality is “beginning to sink in” for President Andrés Manuel López Obrador’s administration as it marks its first year in power on Dec. 1.
José María Lujambio Irazábal, a partner with Cacheaux Cavazos & Newton in Austin and a former general counsel for Mexican Energy Regulatory Commission, and Peter Nance, managing director for Que Advisors, said AMLO, as he is more commonly known, has made it clear that he will neither expand nor fully implement the energy reforms begun before his 2018 election and may even reverse some of the measures. (See Overheard at GCPA Mexico Power Market Conference.)
“If [Enrique] Peña Nieto proposed something,” Nance said, referring to AMLO’s predecessor, “we’re against it because of those guys.”
Some of the pushback has come from the Federal Electricity Commission (CFE), the state-run monopoly. The latest market reforms, begun in 2015, split up its generation into six different companies in an effort to break up its hold on the market.
“The work was not finished. It was really a matter of resistance from CFE,” Lujambio Irazábal said.
“Some people have long memories and believe in the state and the role of the state in these entities,” Nance said.
CFE’s aging fossil plants have increased operating costs. Faced with an operating reserve margin reportedly as low as 0.7% and a succession of blackouts in the Yucatan Peninsula, the government earlier this year announced plans to build five combined cycle gas-fired plants with an aggregate capacity of 2.76 GW and has made overtures to public-private partnerships.
“In special situations, it might be possible to have private partnerships,” Nance said of the new reality. “You just can’t put five power plants on the balance sheet.”
FERC on Thursday found that CAISO, ISO-NE and MISO had largely complied with Order 841, but it ordered changes to some of the grid operators’ proposed tariff revisions.
With CAISO, FERC found its compliance filing, with “certain modifications,” met the requirements of Order 841, intended to remove barriers to the participation of electric storage resources in organized electric markets (ER19-468). But the commission determined the ISO had not fully complied with the requirement that it prevent electric storage resources from paying both wholesale and retail rates for the same charging energy.
“In other words, we find that CAISO has not proposed a participation model for electric storage resources that fully eliminates the potential for duplicative retail and wholesale billing for charging by electric storage resources that later resell that charging energy back to the wholesale markets,” FERC wrote. “We are requiring CAISO on compliance to modify its Tariff so that it does not charge an electric storage resource wholesale rates for charging energy for which the electric storage resource is already paying retail rates.”
Invenergy’s Grand Ridge Battery Storage Facility in Illinois | BYD
In the case of ISO-NE, FERC determined the RTO’s Tariff revisions hadn’t adequately dealt with “the application of transmission charges to electric storage resources” (ER19-470).
“ISO-NE proposes to exempt electric storage resources from all applicable transmission service charges (i.e., charges for regional network service and local service) when they are dispatched to charge,” the commission said. Order 841, however, required “any electric storage resource that is charging for the purpose of participating in an RTO/ISO market … should be assessed charges consistent with how the RTO/ISO assesses transmission charges to wholesale load under its existing rate structure.”
“ISO-NE does not meet these requirements because its proposal exempts all electric storage resources that are charging for later resale from transmission charges that are applicable to other load,” FERC wrote. “Therefore, we direct ISO-NE to submit on compliance within 60 days of the date of this filing, Tariff revisions that comply with this aspect of Order Nos. 841 and 841-A by applying transmission charges to an electric storage resource.”
FERC also found MISO had mainly complied with Order 841 but rejected its plan to assess transmission charges to electric storage resources dispatched to withdraw energy pursuant to their downward ramping capability (ER19-465).
“We are not persuaded by MISO’s arguments that this dispatch is not providing a service,” FERC said. “Order No. 841 specifies that electric storage resources should not be assessed transmission charges when they are dispatched by an RTO/ISO to provide a service such as frequency regulation or a downward ramping service.”
FERC also granted MISO more time than the other grid operators to implement the order.
“While the commission … declined to provide the RTOs/ISOs with additional time for implementation, we find here that MISO’s request to implement the requirements of Order No. 841 after the deadline established … is reasonable based on the specific circumstances outlined in its filings,” FERC said.
San Diego Gas & Electric’s 30-MW battery energy storage facility in Escondido, Calif. | SDG&E
MISO announced in April that it would seek at least another year to comply with the order, saying the intricacy and expense of incorporating storage into its markets was greater than it originally expected. The RTO is trying to create a new market platform, making compliance with Order 841 by December infeasible, it said. (See More Time Needed for Storage Compliance, MISO Says.)
“We note that MISO’s request to defer the effective date of its compliance filing was not opposed,” FERC said. “Therefore, we grant MISO’s request to defer the effective date of its compliance filing to June 6, 2022.”
McNamee, States Want Opt-out
As he did in the compliance filings of PJM and SPP in October, Commissioner Bernard McNamee issued concurring statements that said the commission “should have, at the very least, provided states the opportunity to opt out of the participation model created by the storage orders.”
McNamee was not on the commission at the time Order 841 was issued but expressed his “continuing concern” that FERC had exceeded its statutory authority by not allowing states to determine whether storage may use distribution facilities to access the wholesale markets.
He also noted that state regulators, utilities and public power groups have asked the D.C. Circuit Court of Appeals to overturn part of the order, challenging the commission’s refusal to allow states to opt out. (See States, Public Power Challenge FERC Storage Rule.)
Order 841, 20 Months Later
FERC first issued Order 841 in February 2018, requiring each RTO/ISO to establish a participation model for storage resources to ensure they are eligible to provide all energy, capacity or ancillary services of which they are capable, while also enabling them to set clearing prices as both a buyer and seller. Grid operators also need to establish a minimum threshold for participation that doesn’t exceed 100 kW.
Order 841 “will enhance competition in these markets and help ensure that they produce just and reasonable rates,” staff told commissioners at the time. (See FERC Rules to Boost Storage Role in Markets.)
FERC, grid operators and stakeholders then had a year to review, revise and implement the plans by Dec. 3.
FERC staff issued deficiency letters to all six RTOs and ISOs in April over their proposed energy storage rules, pressing for definitions, tariff citations and details on issues including metering, make-whole payments and self-scheduling. (See FERC Asks RTOs for more Details on Storage Rules.)
In October, FERC issued its first two orders implementing its rulemaking, mostly accepting PJM’s and SPP’s proposals but also objecting to some aspects. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
For instance, FERC rejected SPP’s proposed provisions related to aggregation of storage resources, because Order 841 did not address aggregation. It gave SPP 60 days to submit a compliance filing removing the provisions.
The commission also established a paper hearing procedure to investigate whether PJM’s 10-hour minimum run-time requirement was unjust and unreasonable as applied to capacity storage resources.
FERC has yet to rule on NYISO’s compliance filing. Speaking to reporters after the commission’s open meeting Thursday, Chair Neil Chatterjee said he was “confident we will move forward with New York ISO when it’s ready.”
FERC last week approved the New York Power Authority’s request for transmission rate incentives for its portion of a new AC transmission line (EL19-88).
The commission approved NYPA’s request for:
recovery of 100% of prudently incurred plant costs if the project is abandoned for reasons outside of the authority’s control (abandoned plant incentive);
inclusion of 100% of construction work in progress (CWIP) in rate base (CWIP incentive); and
a 50-basis-point return on equity for the risks of developing the projects (ROE risk adder).
Segment A will add 350 MW of “Central East” transfer capacity by replacing National Grid’s two existing 80-mile 230-kV transmission lines with a new 86-mile, double-circuit 345-kV line from the Edic substation in Oneida County to the New Scotland 345-kV substations, and adding a new Princetown 345-kV switchyard between them. It is expected to cost $750 million, with NYPA’s share at $281 million.
Segment B will add 900 MW of transfer capacity between upstate and southeast New York. It includes a new double-circuit 345/115-kV line from a new Knickerbocker 345-kV switching station to the existing Pleasant Valley substation, a rebuild of the Churchtown 115-kV switching station, an upgrade of the existing Pleasant Valley 345/115-kV substation and 50% series compensation on the 345-kV Knickerbocker-to-Pleasant Valley line.
The two projects are projected to cost a combined $1.2 billion and provide production cost savings of up to $1.2 billion and $9.6 billion in reduced demand congestion charges over 20 years. The projects also will avoid transmission refurbishment costs of $839 million and provide capacity benefits of approximately $1.9 billion.
The two AC transmission projects are projected to cost $1.2 billion and provide production cost savings of up to $1.2 billion and $9.6 billion in reduced demand congestion charges over 20 years. | NYISO
The projects are expected to be in service in December 2023. In its request, NYPA noted that NYISO requires both to be completed at the same time, and that the failure of one may lead to the abandonment of the other, “thus enlarging the potential for the loss of NYPA’s investment.”
“We find that NYPA has demonstrated that each of the requested incentives that we grant here, and the incentives package as a whole, address the risks and challenges faced by NYPA in undertaking Segment A,” the commission ruled.
The commission in 2015 said it would grant NY Transco — affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric — the same transmission rate incentives requested by NYPA if NY Transco were selected for any of the AC projects (ER15-572). (See Divided FERC Trims ROE on NY Tx Projects, Orders Hearing.)
FERC last week ordered Ameren Illinois to revise its accounting for some expenses but otherwise rejected the latest round of challenges by Southwestern Electric Cooperative to the utility’s annual formula rate update (ER18-1122).
Southwestern challenged multiple inputs to Ameren’s 2018 formula rate update.
Ameren Illinois linemen | Ameren
The commission ordered Ameren to make a compliance filing within 30 days:
Moving expenses associated with responding to formal challenges before a regulatory body into Account 928 and exclude them from the annual transmission revenue requirements (ATRR), “consistent with” the commission’s rehearing order on Southwestern’s 2017 formal challenge (ER17-1198-002). (See Challenge to Ameren Illinois Rate Rejected Again.)
Moving any expenses related to donations for charitable, social or community welfare programs from Account 566 to Account 426.1 (Donations), which is not included as an input to formula rate. The commission said it could not determine whether Ameren appropriately recorded only transmission-related expenses to Account 566. “To the extent Ameren Illinois is including donations for charitable, social or community welfare purposes as part of its contribution and membership expenses, we require Ameren Illinois to report the specific items and amounts as part of the compliance filing and also remove them and account for this removal in its next true-up,” the commission said.
Eliminate costs of association membership fees associated with lobbying activities from accounts included in the ATRR.
WASHINGTON — ReliabilityFirst’s annual meeting last week featured discussions on cybersecurity, GridEx V, electromagnetic pulses and the health of the Electric Reliability Organization. Here’s some of the highlights of what we heard.
Clarke, Gallagher Tout ‘Alignment’
In a keynote speech, NERC Trustee Bob Clarke said the regions are more in alignment with each other and ERO leadership now than at any time in his more than six years on the board.
Clarke made his comment in response to a question from RF board Vice Chair Simon Whitelocke, who asked, “How can we support NERC’s strategic vision?”
“I think the key is it’s not NERC’s strategic vision; it is the ERO entity,” Clarke responded. “When the regional CEOs … work together to come up with the vision and the strategic plan … it’s important that we all work together and implement it.
“When I joined the NERC board in February 2013, it was very different than it is now. There were constant tensions and issues that seemed to divide the ERO. Under [then Chair] Fred Gorbet’s leadership, this started to change. We established biannual meetings with the regions’ CEOs, chairs and vice chairs. We also established annual meetings with our Canadian colleagues. This open dialogue exchange started a dramatic turnaround in the entire ERO.”
Clarke also credited CEO Jim Robb for the changes.
“The cohesiveness of the group … is the best it’s ever been. It’s working extremely effectively now,” he said. “At times, when I first came on the board, there would be dissonance; there would be contrary views about things. Now, that’s not the case. The regional CEOs are working really effectively. [It is] very important to have that ‘we’re in this together’ attitude. It’s not a we/they situation anymore.”
RF CEO Tim Gallagher was similarly optimistic in remarks about the conclusion of his two-year term as chair of the regional entity CEOs.
“I’m really proud of the progress that we’ve made in improving the relationships and collaboration in that room,” Gallagher said. “A lot of it is from Jim Robb’s leadership and the approach that he’s taken. … I’ve been doing this job for almost 15 years, and I spent six or seven years on the NERC staff. A lot of my career before that was spent in NERC activities. [This is] the most excited and enthusiastic I’ve been since I started doing all this 30-some odd years ago. … The amount of collaboration in that room and innovation and sharing is just fantastic.”
Midwest Reliability Organization CEO Sara Patrick will replace Gallagher as chair of the RE CEOs.
CCTs, Wind Dominate RE Additions
Combined cycle generators and wind farms represent the bulk of new registered entities in RF,
Ray Sefchik, director of reliability assurance and monitoring, told the board’s Compliance Committee. Other new registrations came from transfers of assets, mostly generation, he said.
As of Oct. 23, RF had 243 registered entities, a number that grew to 247 by Nov. 14. “So that’s pretty dynamic,” Sefchik said. “It changes every week.”
RF’s total is more than all but the Western Electric Coordinating Council, with about 385, and SERC Reliability, which is about the same size.
Finance Committee Agrees to Keep Financial Advisor
The board’s Finance and Audit Committee agreed to continue using Glenmede Investment Management to manage its operating reserve funds and continue its “enhanced cash strategy” after a phone conference with Glenmede portfolio manager Stephen J. Mahoney.
“Most of the other regions don’t have an account like this,” RF Senior Vice President and Treasurer Ray Palmieri said. “They might just put it in a money market fund.”
“Some of them do CDs [certificates of deposit],” said Carol Baskey, manager of finance and accounting.
Clarke said the NERC board decided not to require “commonality” in investment strategies among REs. “There’s not even a commonality on the amount of reserves that are budgeted,” he said. “Each region has their own guidelines, and it varies. And we decided not to try to impose something on the regions.”
Mahoney said there was no reason to change RF’s investment strategy. “As an operating reserve, your duration is rather short. You want to pick up yield in money funds and overnight rates.”
Moving to investments with a six-year term would only add about 60 basis points to the yield of the short-term alternatives, he said. “I don’t think it’s worth it. … I would not change … unless you want to take more risk.”
“No,” committee Chair Patrick Cass said. “Capital preservation is No. 1 for us.”
The committee delayed a vote on the Statement of Policy and Procedure for Investment of Corporate Funds at the suggestion of Cass, who said it was “inconsistent with how you guys really manage the money” and should be revised.
“If we’re going to approve it, I want it to reflect how you manage the money [so that] if we all get hit by a bus, somebody could pick it up and say, ‘Yeah, I understand exactly what they were doing,’” Cass said.
GridEx Observations
In his president’s report, Gallagher gave members a recap of GridEx V earlier this month, calling it the “best of NERC.”
“The participation was outstanding this time. There were 429 different entities that partook of this. Fourteen of them were gas-only utilities, which is the first time I think we’ve had that kind of interaction.” Also participating were 25 state offices and 29 FBI regional offices, Gallagher said.
He said the testing included supply chain concepts, loss of communication channels and natural gas infrastructure interruptions.
“Under certain circumstances, the Department of Energy can issue emergency orders. So, they actually got to test how those emergency orders would be implemented and, if they needed to be amended, how would you amend it. There’s really interesting lessons coming out of that. Hopefully that’s enough of a teaser for you to read the [after action] report when it comes out” in March, he said.
Larry Bugh, RF chief security officer and director of event analysis and situation awareness, said the RE’s participants included its IT, corporate communications and event analysis staffs, and that the lessons included ways to improve its incident response plans and communications with registered entities.
“It was a very successful opportunity to really test our endurance and our ability to work together,” NERC Trustee Rob Manning said. “And it seemed to be very successful.”
Clarke agreed. “It’s never enough, but we’re going in the right direction.”
Elections
The members elected at-large member Joe Trentacosta, chief information officer for Southern Maryland Electric Cooperative (SMECO), to the board and re-elected independent director Brenton Greene, former CEO of Applied Communication Services.
Trentacosta replaces Ken Capps, who is retiring as SMECO’s vice president for engineering and operations and chief operating officer.
Whitelocke, vice president of ITC Holdings, will replace Lisa Barton as chair, and Lynnae Wilson, Indiana electric lead for CenterPoint Energy, will replace Whitelocke as vice chair. Barton, executive vice president of utilities for American Electric Power, will remain on the board.
Greene Cites Limits to EPRI EMP Study
Greene said the Electric Power Research Institute’s study on electromagnetic pulses was “excellent” but limited, saying the report considered “the 10% [of the grid that] was the easiest segment” to model.
“The modeling started failing beyond that,” he said, citing observations of a former colleague now with the Department of Homeland Security.
“My understanding is that [FERC Office of Energy Infrastructure Security Director] Joe McClelland was seeking something on the order of $400,000 [to develop] a far more comprehensive model — to take what EPRI did and do a 100% modeling of that.
“My gut feel is that might be a very good place for NERC and FERC to place some investment to … get a more accurate picture,” he said.
McClelland did not immediately respond to a request for comment.
The comments of Greene, a Navy veteran, echoed the critique of the Electromagnetic Defense Task Force (EDTF), a group with ties to Maxwell Air Force Base. The group said the EPRI report underestimated the risks the grid faces and should not be used as the basis for mitigation. (See Critics: EPRI EMP Report Understates Risks.)
Greene also talked about the need to turn to an older generation of communication in the wake of an EMP attack.
“If there’s an EMP event … you’ve just lost all satellite communications. You have no internet. You have no telephone. There is no radio, no television. If you have something with a microchip in it, it probably failed. It puts you into a scenario where what is the backup of all backups that would work? And you need to be thinking about things like [high-frequency] radio … ham radio.”
Bugh said there was testing of HF radios during GridEx V. It was “a new generation, but still of the kind of technology that would be resistant to [EMP],” he said.
FOLSOM, Calif. — During a daylong planning session Monday, CAISO engineers examined options for transmission upgrades to resolve reliability concerns and reduce natural gas generation’s role in meeting local capacity requirements.
The ISO is in the second of its three-phase 2019/20 transmission planning process (TPP). On Monday, it held the third of four stakeholder meetings to go over its findings and proposals. The goal is to provide the Board of Governors with a transmission plan to approve by March.
The annual TPP looks ahead 10 years, assessing CAISO’s grid based on economic, policy and reliability considerations.
“In addition to those, we’re also doing this sidebar where we’re looking at potential [opportunities] for reducing reliance on gas-fired generation in local capacity areas,” said Neil Millar, CAISO’s executive director of infrastructure development. Reducing dependence on gas can create a need for economically beneficial transmission projects, he said.
California has a legal mandate to dramatically reduce its greenhouse gas emissions and increase its reliance on renewable energy sources by 2030. The 2019/20 TPP’s planning horizon extends through 2029.
Over the course of several hours, engineers presented the results of their detailed examination of the state to identify areas and subareas where transmission upgrades could cut local capacity requirements (LCRs) and eliminate or reduce the need for gas-fired generation. The long-term LCR assessment began in 2018.
In Southern California, billions of dollars in proposed projects could potentially reduce thousands of megawatts of LCRs, though planners questioned the cost-benefit ratio of many large projects and the potential adverse impacts on the sprawling, interconnected grid in Los Angeles and San Diego counties.
In Northern California, spending $30 million on the Tesla-Delta switchyard 230-kV line reconductor in the Contra Costa subarea would reduce the need for gas to meet local capacity needs from 1,207 MW to 299 MW, CAISO planners found.
In the Tesla-Bellota subarea of Stockton, reconductoring about 200 miles of overloaded 115-kV lines, at a cost of $143 million, could completely eliminate the need for 365 MW of gas generation to meet local demand.
Both those projects, and many others on the list, were submitted by CAISO.
Reliability Projects
Planners also presented proposals for reliability projects costing less than $50 million each that require only the approval of CAISO executives. Projects that cost more than $50 million require board approval and will be included in the draft transmission planning report due Jan 31.
The proposals are intended to meet NERC standards, Western Electricity Coordinating Council criteria or ISO planning standards, which can be stricter than NERC or WECC requirements.
Pacific Gas and Electric, for example, has proposed installing a 230/115-kV transformer bank in the San Francisco Bay Area, at an estimated cost of $3 million to $6 million to prevent overloads and meet NERC reliability requirements.
PG&E has also proposed reconductoring 9 circuit miles of the overloaded 115-kV Wilson Oro Loma line in the Fresno area to meet NERC reliability standards, with a price tag of $11.3 million to $22.7 million.
Written stakeholder comments on the presentations in Monday’s meeting are due Dec. 2.
RF Managing Enforcement Counsel Kristen Senk made the observation during a Compliance Committee presentation on 2019 enforcement activities at RF’s annual meeting Wednesday.
“I’m really proud of the team that’s here for the work that they’ve done. It’s getting harder to process violations,” Senk said. “I think entities probably realize this too. The violations themselves are getting more complicated. On the CIP [critical infrastructure protection] side, there’s some new technologies out there. Our [subject matter experts] are spending a lot of time trying to learn those technologies and working with the entities that understand [them].
“On the [operations] side, we’ve seen some really complicated … facility ratings issues. And also, the further we get into compliance, the more compliance history an entity has,” she continued. “So, for every new violation we process, we look at all the prior violations that were similar for that entity. So that list is just growing longer each year.”
2019 Statistics
RF had received 360 violations as of mid-November, so it may end the year with a slightly lower total than in 2018, Senk said. About 78% of this year’s violations were self-reports (vs. 76% for the ERO overall), with 22% resulting from audit findings.
Annual violation intake | ReliabilityFirst
“That’s good news,” Senk said. “We want to see mostly self-reports.”
RF and WECC receive and identify more potential violations than other NERC regions. | ReliabilityFirst
Senk noted that audit findings in 2019 more than doubled from the number in 2018. “That might sound alarming, but we’re actually not too concerned. … We did have a few more audits in 2019. … We also had some late audits in 2018 that kind of rolled over and we didn’t get the violations until 2019. And then we had a few entities that had multiple registrations, so when we audit them, the number would tend to go up.”
Three-quarters of the violations were for CIP, up from 72% last year. Like the ERO, about half the violations were in CIP-007 (patching) and CIP-010 (change management and baselining).
Senk said RF also is seeing an increase in CIP-004 violations. “Those really started increasing with the changeover to CIP version 5. CIP-004 violations are access management: So, some entities are revoking access too late. There’s a pretty strict timeline around those [requirements]. Also, not having the proper authorizations before granting access,” she said. “A lot of entities have kind of manual processes around this access management and they’re learning that those just aren’t sustainable for version 5.”
FERC announced Thursday it was rethinking its cybersecurity strategy by reorganizing two departments and directing its efforts at five “focus areas.”
FERC is directing its cybersecurity efforts at five “focus areas.” | FERC
The changes resulted from Chairman Neil Chatterjee’s directive that the Office of Electric Reliability (OER), the Office of Energy Infrastructure Security (OEIS) and the Office of Energy Projects (OEP) identify ways they can combine their cybersecurity efforts.
As a result of that review, OEP is creating a unit within the Division of Dam Safety and Inspections staffed by physical and cybersecurity specialists.
In addition, OER will reorganize based on functions effective Sunday, with the Division of Reliability Standards and Security and the Division of Compliance realigned into the Division of Operations and Planning Standards and the Division of Cybersecurity.
FERC also identified five subject areas that will guide FERC staff efforts:
Supply Chain/Insider Threat/Third-Party Authorized Access: Ways an attacker can bypass perimeter security controls.
Industry access to timely information on threats and vulnerabilities: A recognition that many entities have limited threat intelligence capabilities and access to information on threats.
Cloud/Managed Security Service Providers: A recognition that delegating trusted third parties to perform common services can have security benefits while also calling for more research to determine if the most critical systems, such as those used for real-time operations, could be moved to the cloud.
Adequacy of security controls: Although low-impact bulk electric system cyber systems (BCS) make up the majority of BES cyber assets, they are generally not subject to mandatory security controls. The simultaneous loss or degradation of a large number of these systems could have a significant impact. Many commission jurisdictional hydroelectric facilities and natural gas pipelines are not subject to mandatory cybersecurity controls.
Internal network monitoring and detection: Internal monitoring of protected networks is not required by NERC critical infrastructure protection (CIP) standards; a failure to conduct monitoring can allow attackers to move laterally within “trust zones.”
Staff identified the focus areas based on a review of public and nonpublic threat reports, significant cybersecurity events impacting industrial infrastructure and CIP standards.
“Staff will continue to monitor entities’ supply chain security implementation and use of trusted connections,” staffers said in a presentation at the commission’s open meeting Thursday. “Additionally, staff will monitor entities’ adoption of new technologies and services to address cyber infrastructure implementation [including] virtualization of systems and use of cloud-computing services. Staff will continue to gather information and work with regulated entities on these issues as well as potential modifications to the CIP standards, such as the security controls for low-impact BES cyber systems.”
Staff noted that OEIS offers voluntary network architecture assessments of electric, hydroelectric, natural gas and LNG facilities, working with other federal agencies such as the Department of Homeland Security, the Transportation Security Administration and the Coast Guard.
Hydro Security, Internal Monitoring
FERC said the additional security capabilities for OEP will build on the Security Program for Hydropower Projects, created in response to the Sept. 11, 2001, terrorist attacks and revised three times since.
David Capka, FERC Office of Energy Projects
“The program’s been enhanced over the years,” David Capka, director of the dam safety division, explained in response to a question from the chairman after the presentation. “However, when cybersecurity became part of the program, within OEP we had to rely heavily on experts outside our office. So, we relied on OEIS and OER to help us. And it quickly became clear that we needed in-house … expertise.”
Barry Kuehnle, FERC Office of Electric Reliability
Capka said the changes will have two benefits. “I think we’re going to have a much more robust security program with the expertise we’ve been able to bring on board. [And] we’re allowing our dam safety engineers to focus on dam safety now.”
OER’s Barry Kuehnle responded to a question from Commissioner Bernard McNamee about the need for internal network monitoring to prevent hackers from being able to make undetected lateral movement within a “trust zone.”
“If someone were to gain access [within a safety perimeter] — suppose they come in with a supply chain attack where you purchase a piece of equipment with a back door in it — you put that into the network, now it’s an authenticated piece of equipment … that potentially may end up … communicating with other equipment within that network,” Kuehnle said. “If you’re … looking for anomalies … you can catch that quicker and you’re able to address any type of security concerns.”
