Page 1032 – RTO Insider

November 24, 2019

Storage Plans Clear FERC with Conditions

By Hudson Sangree

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.”

FERC Storage Plans — 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.

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.)

RTOs and ISOs filed proposed tariff revisions in December 2018. Together, the filings by CAISO, ISO-NE, MISO, RTOs/ISOs File FERC Order 841 Compliance Plans.)

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.”

November 24, 2019

FERC OKs NYPA Incentives for AC Project

By Rich Heidorn Jr.

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).

In April, NYISO Board Selects 2 AC Public Policy Tx Projects.)

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 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.)

November 24, 2019

FERC Orders Ameren Accounting Changes

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.

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.

— Rich Heidorn Jr.

November 24, 2019January 26, 2025

Overheard at ReliabilityFirst’s Annual Meeting 2019

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?”

NERC Trustee Bob Clarke | © ERO Insider

“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.”

ReliabilityFirst CEO Tim Gallagher | © ERO Insider

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, ReliabilityFirst | © ERO Insider

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.

Ray Palmieri, ReliabilityFirst | © ERO Insider

“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.”

Patrick Cass, ReliabilityFirst | © ERO Insider

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.

Larry Bugh, ReliabilityFirst | © ERO Insider

“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.

Joe Trentacosta, SMECO | © ERO Insider

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.

Brenton Greene, ReliabilityFirst | © ERO Insider

“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.

RF board and members held their annual meeting in D.C. | © ERO Insider

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.

— Rich Heidorn Jr.

November 22, 2019

Parties near Agreement on El Paso Electric Purchase

By Tom Kleckner

The Texas Public Utility Commission’s scheduled hearing on a $4.3 billion private equity bid for El Paso Electric has been postponed until January to allow time for the parties to reach a unanimous settlement (49849).

EPE and its private equity suitors filed the continuance request on behalf of commission staff and the proceeding’s intervenors. They said the applicants, commission staff, and “most of the intervenors” had reached an agreement in principle on the major terms and hope to resolve all issues in the next few weeks.

“The remaining parties believe additional time for further discussions is merited rather than proceeding to a hearing at this time,” the applicants said.

El Paso Electric — Intervenors line up before the judge during a prehearing conference Nov. 20.

Administrative Law Judge Hunter Burkhalter granted the request Wednesday. He directed the parties to file a non-unanimous settlement by Dec. 17 and invited them to provide detailed status reports during the PUC’s Dec. 13 open meeting.

Burkhalter rescheduled the commission’s hearing for Jan. 7-8. It had originally been set for Nov. 20-22.

J.P. Morgan Investment Management’s Infrastructure Investments Fund US Holding 2 and Sun Jupiter Holdings, a limited liability company formed to enter into the merger agreement, announced their proposed purchase of EPE in June.

The parties have proposed a purchase price that is a 17% premium to EPE’s closing price before the merger’s announcement. The private equity firms have said the management team will remain in El Paso and no jobs will be transferred outside of Texas. They have sweetened the deal by offering a $21 million credit to current EPE customers and creating a $100 million community economic sustainability fund.

The deal has been opposed by the Texas Office of Public Utility Counsel, which says the proposal does not provide sufficient tangible, quantifiable benefits to EPE’s customers and does not adequately protect them from “the additional risks created by the post-closing corporate structure and governance.”

The utility’s industrial customers have also raised concerns over the utility’s governance and financial risks. Other intervenors include PUC staff and the city of El Paso, who both say most of the regulatory commitments don’t impact customer rates or promise any benefits beyond the status quo.

November 22, 2019

MISO Committee Revisits ‘Other’ Sector Spin-off

By Amanda Durish Cook

Environmental advocates are stepping up calls for MISO to split up its Environmental and Other Stakeholder Groups sector to provide them with a more singular voice — and the idea may be getting some traction.

Sector members continue to press MISO’s Steering Committee to expand the number of sectors in the Advisory Committee, affording dedicated space for green advocates in RTO activities.

“In the long run, if you don’t offer a new way for folks to join MISO … there are always going to be problems,” John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project, said during a Steering Committee conference call Thursday.

Advisory Committee members in September indicated they weren’t yet ready to embrace the idea of creating an 11th sector to accommodate hard-to-pin-down members. At the time, the Power Marketers and Brokers sector offered to take on the “Other” contingent temporarily to see if it was a harmonious fit. (See Scant Support for 11th MISO Sector.)

But the Steering Committee is now suggesting that the Advisory Committee re-examine the issue.

Moore this week sent an email urging Steering Committee members and MISO staff to revive the issue. He wrote that “regardless of the intentions for creating this sector at the inception of MISO, a sector composed of entities in addition to ‘environmental’ is problematic at best and creates governance challenges within our sector.”

“For that reason, we encourage MISO to develop a solution that allows members to participate in the stakeholder process and governance in ways that do not render our sector dysfunctional,” Moore wrote citing two instances of entities joining the sector that were not “aligned” with its mission.

“In one instance, it was several gas pipeline development companies, and in another case, it was several competitive transmission developers,” he wrote.

Moore said those two instances “substantially disrupted our ability to operate as a cohesive sector.” He also wrote that he fears that prospective MISO member the Lignite Energy Council (LEC) may end up in the sector because the organization “does not fit neatly into any sector because it is so diverse in its membership.”

“MISO needs a durable solution that can allow for meaningful participation in the stakeholder process for entities like the LEC, who wish to become members, without forcing them into sectors with fundamentally different interests,” Moore wrote.

During the conference call, Moore suggested MISO at least create a “holding” space for new members that may have a difficult time deciding where they fit in.

“We don’t want our sector to become a repository for just anyone that doesn’t have a home,” Moore said.

“I’m very sensitive to the concerns of the Environmental sector, but where do we draw the line on creating new sectors? … I’m struggling myself on coming up with an answer to that,” WEC Energy Group’s Chris Plante said.

Plante said his Municipals, Cooperatives and Transmission Dependent Utilities sector also contains groups that don’t always agree with each other.

But some Steering Committee members said MISO cannot expect to persist with the same 10 sectors given the increasingly mercurial nature of the energy industry.

“The world is changing, and the industry is changing,” Manitoba Hydro’s Audrey Penner said, citing Bill Gates’ secretive Heliogen solar startup that has created solar arrays capable of generating heat above 1,000 degrees Celsius with the help of artificial intelligence. She said it was an example of the “new players entering our industry.”

“To the extent that we need to create new sectors, that’s going to be pressed upon us whether we like it or not. We’re not in a static industry,” Penner reminded fellow members.

Penner argued that MISO could create as many as three new sectors, for example, and said members “could still feel comfortable and make their voices heard.”

Steering Committee Chair Tia Elliott said the topic would be passed to the Advisory Committee in time for its Dec. 11 meeting as part of MISO Board Week in Indianapolis.

Remove Affiliation Obligation?

Steering Committee leaders on the same call also discussed eliminating the requirement that entities must join a sector in order to become MISO members.

Current rules dictate that organizations seeking MISO membership must declare affiliation to one of the 10 sectors in order to gain entry. Sectors are used for member voting purposes in the Planning Advisory Committee and Advisory Committee.

The Steering Committee ultimately agreed to hold off on making draft changes to MISO’s Stakeholder Governance Guide until further discussion. Any revisions to the governance guide must go before the Advisory Committee before they are adopted.

Moore said dropping the requirement might be a positive step, freeing elusive and prospective members from trying to narrow down their purpose.

“I think it’s definitely a sticking point,” he said.

November 22, 2019

IMM Cites Smooth Summer, Outage Issues in MISO South

MISO’s Independent Market Monitor found no major concerns with performance in MISO South over the summer and early fall, but it still wants the RTO to get a handle on short-notice and unreported generation outages in the region.

Potomac Economics’ Robert Sinclair delivered a MISO South operations report at the Entergy Regional State Committee’s annual meeting Wednesday. The report showed South prices for late summer and fall were significantly lower than in 2017 and 2018, holding to about $25/MWh, while natural gas prices hovered around $2.50/MMBtu.

“During the year, you see prices have been declining, and that’s the result of declining natural gas prices,” Sinclair said. Monitor staff also reported higher prices in the MISO portions of Texas in recent months because of transmission outages.

But Sinclair said the Monitor is keeping tabs on short-notice outages and extensions of planned generation outages, along with unreported outages and derates, which continue to be prevalent in South.

“A significant portion of resources continue to be unreported and short-notice,” Sinclair said.

MISO Director of Operations and External Affairs Liaison Tag Short said the RTO called a maximum generation warning in South in early June because of both high load and forced generation outages.

Short said South’s 32.2-GW summer peak occurring Aug. 12 came in lower than the 32.7-GW all-time peak on Aug. 10, 2015.

Sinclair also told Entergy executives that the regional dispatch transfer limit continues to provide South members with cost savings and the benefit of integration. He said the transfer limit bound much more frequently in the South-to-Midwest region August through October. MISO’s agreement to use SPP transmission to facilitate transfers stipulates a 2,500-MW South-to-Midwest limit and a 3,000-MW Midwest-to-South limit.

— Amanda Durish Cook

November 22, 2019

CAISO Tx Planners Look at Reliability, Capacity Reqs

By Hudson Sangree

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, assess ing 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.

November 22, 2019

RF Enforcement: ‘Getting Harder to Process Violations’

By Rich Heidorn Jr.

WASHINGTON — Processing NERC violations is getting more difficult — at least in ReliabilityFirst, says the regional entity’s enforcement chief.

ReliabilityFirst enforcement of NERC violations — Kristen Senk, ReliabilityFirst | © *ERO Insider*

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.

“That’s good news,” Senk said. “We want to see mostly self-reports.”

ReliabilityFirst enforcement — 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.”

November 22, 2019

FERC Refocusing Cybersecurity Efforts

By Rich Heidorn Jr.

FERC announced Thursday it was rethinking its cybersecurity strategy by reorganizing two departments and directing its efforts at five “focus areas.”

FERC Cybersecurity — 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.

“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.”

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.”