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December 25, 2024

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GAO Critical of TSA Pipeline Security Efforts

By Rich Heidorn Jr.

The Transportation Security Administration’s oversight of natural gas pipeline security is hampered by staffing constraints and vague criteria for identifying critical facilities, the Government Accountability Office reported last week.

Pipeline security reviews conducted, fiscal year 2010 through July 2018 | GAO Analysis of Transportation Security Administration

TSA’s Pipeline Security Branch, which is responsible for more than 2.7 million miles of natural gas, oil and hazardous liquid pipelines, currently has only six full-time equivalent employees. Staffing has fluctuated from a high of 14 in fiscal year 2013 to only one in 2014. The agency, part of the Department of Homeland Security, also lacks a “strategic workforce plan” to identify the skills required of its employees, such as cybersecurity expertise.

GAO also found TSA has not updated its risk assessment methodology since 2014 to reflect current threats to pipelines and that its data sources and underlying assumptions on threats and vulnerabilities are not fully documented. Its risk assessment has not been peer reviewed since it was initiated in 2007, the report said.

Although TSA issued revised guidelines in March 2018 incorporating most of the National Institute of Standards and Technology’s “Framework for Improving Critical Infrastructure Cybersecurity,” it did not include all of the framework and lacks a formal process for revising the guidelines on a regular basis. “Without such a documented process, TSA cannot ensure that its guidelines reflect the latest known standards and best practices for physical security and cybersecurity, or address the dynamic security threat environment that pipelines face,” GAO said.

GOA
Map of hazardous liquid and natural gas transmission pipelines in the U.S., September 2018 | U.S. Department of Transportation

Critical Facilities

The guidelines also lack clear definitions to ensure that pipeline operators identify their critical facilities — one reason, auditors speculated, that one-third of the 100 largest pipeline systems have not identified any critical facilities.

TSA’s eight criteria lack “additional examples or clarification … to help operators determine criticality,” the report said.

GAO said pipeline operators told it that pipelines may interpret one TSA criterion, “cause mass casualties or significant health effect,” differently. “One of these operators that we interviewed stated that this criterion could be interpreted either as a specific number of people affected or a sufficient volume to overwhelm a local health department, which could vary depending on the locality. Another operator reported that because TSA’s criteria were not clear, they created their own criteria which helped the operator identify two additional critical facilities.”

GAO said one unnamed industry association it met with is working with TSA to develop supplementary guidance for its members to clarify the agency’s critical facility criteria. The American Gas Association (AGA), which represents more than 200 local distribution companies, confirmed it is the group mentioned.

TSA conducts security reviews of the largest 100 companies, but it hasn’t checked in the last five years whether its recommended improvements are being followed, leaving it unable to know whether its efforts are reducing risks, the report said.

Based on the company reviews, TSA may also review the security on a company’s critical facilities. Although the reviews are voluntary, TSA told auditors no company has ever rejected an inspection request.

The agency conducted 23 corporate reviews and about 60 facility reviews in fiscal year 2018 (through July 31). In 2014, when the safety unit had only one FTE, it conducted no corporate reviews and about 30 facility reviews.

U.S. natural gas and oil pipeline systems’ basic components and examples of vulnerabilities | GAO Analysis of Transportation Security Administration

Dispute on Mandatory Rules

At FERC’s open meeting Thursday, Chairman Neil Chatterjee said the GAO report “reiterated” concerns he and Commissioner Richard Glick expressed in a June op-ed calling for mandatory reliability standards for natural gas pipelines like those the commission and NERC enforce on the grid. “Despite having the authority to enforce mandatory cybersecurity standards, the TSA relies on voluntary ones,” they wrote.

Glick said TSA performs a valuable role in airport security but is ill-suited for overseeing pipeline security. “I continue to believe that Congress should … consider moving authority over gas pipeline cybersecurity to another agency such as the Department of Energy.”

Chatterjee said that although the GAO report identified gaps, he has been pleased by recent efforts by industry and DHS to improve pipeline security, including the creation of a risk assessment program that includes DHS, TSA, DOE and FERC.

In a press release, Don Santa, CEO of the Interstate Natural Gas Association of America (INGAA), also cited what he called his group’s “partnership” with TSA, DHS and DOE to conduct cybersecurity assessments of pipelines, saying, “This interagency approach will bring to bear the particular expertise of each agency, along with those of the industry itself.” INGAA says its 26 members represent most of the interstate natural gas transmission pipeline companies in the U.S. and Canada.

But he rejected the idea of mandatory standards. “In this environment of rapidly evolving cyber threats, it is important that we take an approach that enables flexibility and allows us to quickly adapt and update protocols,” he said. “Experience shows that mandatory standards are all too often outdated almost as soon as they are introduced. We need the flexibility and ability to build on our baseline practices to look forward towards addressing the threats of the future.”

AGA said in a statement that GAO’s criticism “is missing the mark.”

TSA officials “understand the industry and have a strong working relationship with natural gas utilities,” said AGA CEO Dave McCurdy, who called for expanding the agency’s budget and staff “so that they can come into our member companies and make the assessments themselves. In addition to our numerous voluntary programs in the cybersecurity arena, we believe that this is the best way to build upon the success of this public-private partnership.”

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GAO: No Consensus on GMD Risk to Grid

By Rich Heidorn Jr.

A Government Accountability Office report on geomagnetic disturbances released last week found a lack of consensus on how much of a risk they pose to the U.S. electric grid, in part because of limited modeling capabilities.

GMDs, which occur when the sun ejects charged particles that change Earth’s magnetic fields, can cause geomagnetically induced currents (GIC) that produce voltage instability and damage connected equipment.

Although such coronal mass ejections occur regularly, GAO said there have been only four GMDs worldwide since 1932 that significantly affected the grid with large-scale service disruptions or equipment damage. The only instances in the U.S. were GMDs in March and September 1989 that damaged four single-phase transformers at one power plant, with no loss in electric service.

GAO
Coronal mass ejection (CME) approaching Earth | GAO-19-98

‘Key Gaps’

“The magnitude of potential damages from a large GMD is not fully understood, in part because there have been few examples worldwide of GMDs that have caused equipment damage or large-scale blackouts,” GAO said. “Determining how GMDs will interact with and harm the electric grid is challenging because the magnitude of the ensuing GIC is influenced by several factors. The reaction of specific components of the electric grid to GIC and its secondary effects is also challenging to accurately model.”

GAO said there are “key gaps” in the understanding of variables that impact severity, such as data on local geoelectric fields. The U.S. Geological Survey has only 14 ground-based observatories measuring local magnetic fields.

“The relatively sparse coverage of magnetic observatories, particularly in the contiguous United States, limits the ability to monitor GMD in areas without magnetic observatories,” GAO said. “Even when the GMD is measured at nearby magnetic observatories, Earth resistivity required to calculate the geoelectric field … is often the dominant source of uncertainty in GIC calculations. … Earth resistivity varies by about a factor of 10,000 within a Midwest region otherwise described by a single, one-dimensional ground resistivity model.”

Because extreme GMDs are rare, researchers have attempted to extrapolate the impact of extreme events from available data on moderate events. But GAO said, “Researchers at Los Alamos National Laboratory found that the probability of extreme events is not accurately described by statistical models of historical records.”

Worst Case?

The worst-case scenarios from a solar-induced GMD — or an electromagnetic pulse produced by the detonation of a nuclear device 25 to 250 miles above Earth’s surface — sound like the stuff of disaster movies.

“A large GMD might have long-term, significant impacts on the nation’s electric grid,” GAO said. “Given the interdependency among infrastructure sectors, such a disruption to the electric grid could also result in potential cascading impacts on fuel distribution, transportation systems, food and water supplies, and communications and equipment for emergency services, as well as other communication systems that utilize electrical infrastructure.”

But the auditors said recent research suggests that the worst GMDs might have only limited impact. “The most persuasive studies we reviewed concluded that the most likely effects of a large GMD would be service interruptions that are neither long-term nor large-scale,” GAO said.

GAO
Coronal mass ejections cause geomagnetic disturbances that may interact with the electric power grid. | GAO-19-98

Two National Laboratory studies that evaluated the impact of an extreme GMD event on the Eastern and Western interconnections concluded “that the disconnection or loss of transformers experiencing high GIC would avoid equipment damage and maintain grid stability. … It is possible to use operating procedures or GIC-blocking technologies to protect transformers and grid stability.”

NERC cited operational procedures such as increasing operating reserve margins, modifying protective relay settings and removing vulnerable equipment from service.

A study by an unnamed electric power supplier “concluded that failures in generators or capacitors are unlikely during a 100-year storm,” GAO added.

NERC’s Geomagnetic Disturbance Task Force concluded that the most likely worst-case system impacts from a severe GMD event would be voltage instability and potential blackouts. But GAO noted that “blackouts that originate in the transmission grid in the absence of substantial equipment damage are generally restored within three days and often much sooner.”

FERC, NERC Actions

GAO’s findings on the limited data echo frustrations FERC and the Department of Energy have expressed.

In 2016, DOE said traditional power system planning models are flawed because they do not include substation grounding or transformer configuration details, which are essential to modeling GIC flows.

In November, FERC approved NERC’s revised GMD reliability standard, which broadens the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions (RM18-8, RM15-11-003). (See Revised NERC GMD Standard Approved.)

The standard seeks to create a benchmark for estimating the impact of a large GMD. But GAO said “conducting such estimates is challenging because the wide variety in transformers, including model, age and power capacity, could lead to significant variability in the effects [of] GIC on specific transformers.”

At FERC’s direction, NERC has joined with the Electric Power Research Institute to develop a research plan to improve the benchmark GMD event and Earth resistivity models.

Technological Fixes?

An October 2016 executive order by President Barack Obama directed DOE and the Department of Homeland Security to develop a plan to test and evaluate technology that could mitigate the effect of GMDs. The GAO report came in response to a request by the Senate Committee on Homeland Security and Governmental Affairs to examine the availability of such technologies and the challenges of using them.

DOE told the auditors that it completed a plan for a pilot program to test commercially available technology in April and has hired contractors to implement the plan.

The GAO researchers reported that three-phase transformers may be less vulnerable than single-phase units, but it said the larger, heavier three-phase units present shipping challenges.

GAO said series capacitors, used to improve the transfer capability of long transmission lines, can also block GIC. “However, care must be exercised in placing series capacitors in the electric power transmission system because blocking GIC in one section of the grid can affect GIC flow in other sections of the electric power transmission system. Therefore, it is necessary to evaluate the effect of series capacitors in sections of the electric power transmission system on other sections of the electric power transmission system before they are installed,” GAO said.

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PJM MRC Briefs: Dec. 20, 2018

By Rory D. Sweeney

PJM’s Markets and Reliability Committee held its final meeting of 2018 last Thursday at the Conference and Training Center in Valley Forge. | © RTO Insider

Board’s GreenHat Investigation

VALLEY FORGE, Pa. — PJM Board of Managers member Susan Riley asked RTO members for continued patience with the board’s ongoing investigation into the historically large default of GreenHat Energy’s financial transmission rights portfolio. (See PJM Board Investigating GreenHat’s Record FTR Default.)

Speaking via phone to attendees at the RTO’s Markets and Reliability Committee meeting Thursday, Riley said the Special Board Committee is progressing — having completed 30 interviews — but has little to offer yet publicly. It anticipates preparing a draft for board members to review in early January.

The final report, targeted for publication in early February, is intended to provide “a great deal of confidence” about what happened and ensuring it doesn’t happen again, Riley said.

“If it takes a little longer, I hope that you’ll bear with us,” she said. “Our goal here is to be comprehensive … complete and unbiased.”

FTR Mark-to-Auction Credit Requirements Endorsed

Members approved without discussion a proposal endorsed by the Market Implementation Committee to increase FTR credit requirements with the addition of a “mark-to-auction” provision. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)

The vote, taken by acclamation, included one objection.

Must-offer Exception Process Deferred

Members voted to defer consideration of a proposal endorsed by the MIC to revise the capacity market must-offer exception process. The changes would allow participants to specify multiple auctions when making exception requests. Resources that cannot be made Capacity Performance-capable by the start of the delivery year will be permitted to seek an exception. (See “Must-offer Exception Changes,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

Susan Bruce, representing the PJM Industrial Customer Coalition, requested deferring the vote until the April 29 MRC meeting and remanding the issue back to MIC to discuss resources wanting to move between capacity- and energy-only status. Despite the request, Bruce said the issue “feels like something to get wrapped up before [capacity market] auctions start.”

Asked to specify which member company made the deferral motion among those she represents, Bruce named industrial gas producer Praxair. Old Dominion Electric Cooperative, via Carl Johnson as the representative of the PJM Public Power Coalition, seconded the motion. It was approved in a sector-weighted vote with 3.74 in favor.

Asked by Marji Phillips of Direct Energy whether the Independent Market Monitor could address any withholding issues if the proposed rule passed, Monitor Joe Bowring responded that strong and clear rules are needed in order to be enforceable and that the Monitor would not be able to prevent the exercise of market power through withholding if the proposed rule were implemented.

FTR Forfeiture Rule Deferred

A second long debate, on a proposed change to the FTR forfeiture rule, ended in another vote deferral after some stakeholders expressed fear it could unintentionally create exploitable market loopholes.

The proposal, endorsed by the MIC, would revise the trigger for forfeiture of FTRs from virtual trades that create a penny’s worth of impact on the value of an FTR to those whose impact exceed 10%. (See “FTR Forfeiture Proposal Endorsed,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.) Bruce said certain physical suppliers have been very vocal about wishing to revise the trigger, but stakeholders haven’t heard from others about how “endemic” the issue is. Several financial-only traders responded.

“I think that there is a broader impact than just [on] companies like [proposal co-sponsors] Exelon and NextEra [Energy],” Appian Way Energy Partners’ Abram Klein said.

“We don’t think we’re striking the right balance today,” PJM’s Stu Bresler said in support of the proposal. As evidence of the revision’s necessity, proponents had provided an example of issues around taking positions at the RTO’s Western Hub.

“I think that the Western Hub is the most liquid location in the system,” Bresler said. “If there isn’t enough liquidity there, we should probably all pack our bags.”

The Monitor continued its longstanding defense of the current rule, including the so-called “penny test,” pointing out that the existing rule has a 10% test for the impact of a company’s portfolio on a constraint and that the penny test is simply a test for a positive impact on the value of an FTR. That test could reasonably have been zero, but a penny was implemented.

In response to assertions by Exelon and NextEra that the proposal would improve market efficiency, Bowring pointed out that “there is no evidence that the rule would improve the efficiency of the market. … The proposed rule would substantially weaken the FTR forfeiture rule and permit the exercise of market power.”

Exelon’s Jason Barker said such logic suggests it would also be more efficient to send people directly to jail when arrested, but that such a bypassing of due process ignores important nuances like intent and tenet of being “innocent until proven guilty.”

“We don’t have those things in our system because we have to judge the reasonableness of those actions,” Barker said. “[The penny test] is efficient, I’m sure, for Joe to monitor and for PJM to apply, but it’s not fair.”

“I didn’t quite get that, but it sounded pretty dramatic, pretty draconian. That’s not what we’re doing here,” Bowring said. He questioned why “10% is a good threshold for guilty but a penny is not?”

Gabel Associates’ Mike Borgatti, representing NextEra, motioned for deferral to the MRC’s Feb. 21 meeting to discuss a compromise of a 5% threshold for triggering forfeiture. The motion passed without objection or abstention.

PFR Task Force on Hiatus

Members agreed to a PJM proposal to put the Primary Frequency Response Senior Task Force on hiatus for one year to gather data and subsequently determine whether to reconvene. The hiatus was suggested after stakeholders in the task force failed to come to consensus on any proposals to require existing units to provide primary frequency response. (See PJM SHs Seek End to Frequency Response Debate.)

Many generators already provide the service such that there is no additional need for it in PJM, and those that don’t argue that being forced to install the necessary equipment would be a financial hardship that isn’t supported by reliability needs. PJM staff anticipate that outreach to unit owners will result in performance improvements over the next year and that NERC might issue enhanced standards.

The motion was endorsed by acclamation.

Transmission Replacement

Transmission owners remain at philosophical odds with load interests and merchant transmission operators about end-of-life (EOL) and replacement procedures for aging infrastructure.

American Municipal Power’s Ed Tatum and Lisa McAlister presented proposed revisions, developed in concert with ODEC to Manual 14B in a package that retains the position as the first option to receive a vote on the topic. The proposal would add language in section 1.5.4 of the manual to provide sufficient information to enable stakeholders to replicate transmission owners’ results on the need for proposed supplemental projects, as well as strike the word “useful” throughout in manual references to “end of useful life.”

“We don’t need folks replacing well-maintained assets simply because they are at the end of their depreciable life,” Tatum said.

PJM’s Aaron Berner, who presented the RTO’s alternative proposal endorsed by TOs, worried the slight wording difference could lead to reliability issues.

“Getting rid of ‘useful’ is going to leave us with ‘end of life.’ It means something failed,” he said.

The PJM proposal was moved for consideration by FirstEnergy and seconded by Public Service Electric and Gas.

LS Power’s Sharon Segner proposed a friendly amendment to either proposal that would limit the ability for supplemental projects — which are developed by TOs based on their own internal needs criteria — to supplant competitively bid projects accepted by PJM to address regional reliability violations or other criteria. She said LS is concerned about an apparent “blur” of the lines between such projects.

“We accept that some supplemental projects are needed. We accept that FERC has made the decisions that they have made,” Segner said. “But supplemental projects cannot be displacing regional projects.”

Stakeholders will vote on the issue at the Jan. 24 MRC meeting.

Resilience and Fuel Security

PJM’s Jonathon Monken presented an update on the RTO’s efforts to increase system resilience, noting several initiatives planned for 2019. Among them are an infrastructure interdependency analysis, a pilot to test distributed energy resources for resilience and identification of resilience attributes for fuel-secure generation resources.

PJM’s Dave Souder discusses the RTO’s fuel-security report and plans going forward. | © RTO Insider

The latter was the topic of a special session of the MRC that followed the normal committee meeting, in which PJM’s Dave Souder reviewed the fuel security report the RTO released earlier this week. (See Full PJM Study Makes Case for Fuel Security Payments.)

Responding to stakeholder questions, Souder acknowledged that the units included in the report’s retirement scenarios were just the least-profitable units rather than “underwater” facilities. He said scenario templates for each of the 324 analyzed scenarios are expected to be published in mid-January. Staff also plan to introduce a problem statement and issue charge on the issue for stakeholder consideration in the first quarter.

That would precipitate creating a senior task force to examine the topic with any potential market rule changes targeted to be filed with FERC in early 2020. A third phase of the initiative is occurring in parallel to consider further scenarios based on classified information about credible risks to fuel security that could impact the grid.

Manual Approvals

Stakeholders endorsed two manual revisions by acclamation:

  • Manual 14D: Generator Operational Requirements. Revisions developed to revise information input deadlines for the Resource Tracker application. (See “Resource Tracker,” PJM Operating Committee Briefs: Nov. 6, 2018.)
  • Manual 14E: Upgrade and Transmission Interconnection Requests. Revisions developed as part of a triennial cover-to-cover review. The revisions include changing the manual name to align it with the structure of Manuals 14A and 14G and explaining how to apply to the interconnection queue via Queue Point.
  • Clarifications of market participation rules for DERs in Manuals 11 and 14D and the Open Access Transmission Tariff. Among the changes are a consistent definition of on-site generators.
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Chatterjee Pressed on McNamee Resilience Recusal

By Michael Brooks

WASHINGTON — Bernard McNamee attended his first open meeting as a FERC commissioner on Thursday, where he was greeted by protests and questions of whether he would recuse himself from the agency’s dockets on grid resilience.

McNamee, who was sworn in Dec. 11, declined to vote on the commission’s consent agenda for the meeting, which did not feature any discussion items or presentations by staff. Instead, he simply marked himself as “present.”

“Some have asked me what’s going to be my agenda here at FERC. That always seems to be the first question I get asked by most people,” McNamee said in his opening remarks. “I can sum it up in one word: ‘listen.’”

FERC Commissioner Bernard McNamee gives his opening remarks at the commission’s open meeting Dec. 20, his first since being sworn in. | © RTO Insider

He said he is still interviewing potential staff and didn’t want to rush his decisions on issues. “I expect to fully participate in the commission’s proceedings and decisions soon, but for now, I just plan to listen.”

McNamee left the room almost immediately after the meeting ended, declining to answer a reporter’s question. It fell to Chairman Neil Chatterjee to address multiple calls for McNamee’s recusal from the resilience dockets. Those calls have come from Senate Democrats, environmental groups, the Harvard Law School’s Electricity Law Initiative and several protesters at Thursday’s meeting — though the last group did not say from what he should recuse himself. (See Enviros Seek McNamee Recusal in Resilience Dockets.)

Chatterjee said, “All I know is, on his very first day at the commission, [McNamee] went and received ethics training and sat down with our legal counsel here at the commission to discuss these matters, as we all did on our first days at the commission.” He repeatedly emphasized that the decision to recuse lies with individual commissioners, and that the chairman has no say in the matter. “I don’t have the capacity to deny another commissioner their vote or their ability to participate in a proceeding. That is between Commissioner McNamee and ethics” staff.

“And I have complete confidence in the lawyers in this building to ensure on all these fronts that whatever actions we take will be with an eye toward ensuring the maximum ability to withstand legal scrutiny,” Chatterjee said.

But Chatterjee also noted that upon his own arrival at FERC, there were also questions concerning his ability to be impartial given his previous job as energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), “and I probably wasn’t always helpful to dissuade those.” He said he felt that his record at FERC has proven he can make impartial decisions based on the record.

“So all I would ask is that he be given an opportunity to demonstrate that, like myself, [McNamee] will be an earnest public servant,” Chatterjee said. “And I think that based on my getting to know him and his remarks today, I truly feel he will be that earnest public servant.”

Chatterjee was referring to McNamee’s closing remarks at the meeting, after the commission had honored two retiring staff members.

McNamee said agency staff are “sometimes not given the due that they should be given. … Public service is a calling, and often people don’t respect it the way they should. You don’t get paid as much as you could in the private sector, but … you come each day to do what’s right for the country and give your best advice. And that’s something that’s very noble. Personally, I’m grateful for it, and I’m looking forward to working with all of you.”

Tension over LNG; No Update on McIntyre

Meanwhile, the partisan divide at the commission over natural gas facilities continued, as Chatterjee struck from the consent agenda a vote on Venture Global LNG’s application to build its Calcasieu Pass LNG export facility in southwestern Louisiana’s Cameron Parish (CP15-550).

In her opening remarks, Commissioner Cheryl LaFleur (D) said she was “disappointed we are not voting on the project today. Based on the record before us today, and my assessment of the legal requirements under the Natural Gas Act and the National Environmental Policy Act, I was prepared to cast a vote on the project. Without getting into internal deliberations, I think I made clear what I believe is required of us when considering whether to authorize this LNG project.”

Both LaFleur and fellow Democratic Commissioner Richard Glick have repeatedly disagreed with their Republican colleagues about the consideration of greenhouse gas emissions in gas infrastructure approvals. If the vote on Calcasieu Pass had been like previous votes, Chatterjee would have been outnumbered without McNamee and Commissioner Kevin McIntyre, who was again absent from the monthly meeting and has not voted on any items since stepping down from the chair in October because of what he called a “serious setback” in his battle with a brain tumor.

Chatterjee has previously poked fun at LaFleur at previous open meetings for her reversal on the issue, as she only recently began to vote against gas infrastructure over GHG concerns. (See FERC Says Farewell to Powelson.)

But speaking to reporters on Thursday, he was subtly critical of her.

“I appreciate my colleague’s concerns, but also, when she was chairman she had a reputation of being a strong supporter of LNG exports. The policy was fine then,” he said, before moving on.

Chatterjee declined to give an update on McIntyre’s status. The commissioners in their opening remarks wished him and his family well for the holidays. But unlike at earlier meetings, none of them offered hopes of him soon returning to work.

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NERC Offers Upbeat Long-term Assessment

By Rich Heidorn Jr.

NERC offered a mostly upbeat report on the long-term health of the nation’s grid Thursday, celebrating results from its first interconnection-wide frequency response studies while highlighting the need to model the increasing volume of distributed resources and supplement variable generation with ramping resources.

The 2018 Long-Term Reliability Assessment, NERC’s 10-year outlook for the North American bulk power system, found that frequency response will remain adequate through 2022 despite the loss of synchronous generators and the increase in inverter-based renewables.

“That gives us some confidence in the resource mix and also the ability to … see whether that performance is degrading out in the future — which is really important, so that if there are issues, you can put [in] policies or build new resources,” said John Moura, director of reliability assessment and system analysis, during a press briefing on the report.

| NERC

Moura noted that FERC Order 842, issued in February, requires all new resources seeking interconnections be able to provide frequency response, calling the requirement “really, really important for reliability.” (See FERC Finalizes Frequency Response Requirement.)

The report said dynamic stability analysis showed both the Eastern and Western interconnections’ generation “sufficiently supports frequency after simulated disturbances despite reductions in inertia” from the loss of synchronous generation. It said ERCOT has operational procedures to address risks from “degraded inertia.”

“My optimism is not only based on the current mechanisms in place but the ability of the industry to respond and adapt to the changes. And so, while today we don’t have really what I would call excellent frequency response modeling capability, we’ve got pretty good [capability]. We’re able to see it,” Moura said. “And I have confidence that we’ll be able to have that excellent frequency response model in by the time we really need it.”

Load & Reserves

The report predicts North America will see compound annual load growth of only 0.57% for summer and 0.59% for winter, with five areas — New York, New England, the Maritimes, Manitoba and the California-Mexico region (most of California and a northern sliver of Baja California) — expecting reductions in peak demand. The fastest growing regions are ERCOT and the Rocky Mountains region of the Western Electricity Coordinating Council, both projected to grow about 1.8% annually.

The report did identify concerns, noting that ERCOT’s anticipated reserve margins are below targets for the next five years, with MISO and Ontario foreseeing reserve shortfalls beginning in 2023. (See ERCOT Predicts Tight Reserve Margin for 2019.) But it said the shortfalls could be filled by accelerating construction of additional Tier 2 resources — those that have met milestones such as completing feasibility, system impact or facilities studies.

The report includes new probabilistic evaluations — loss-of-load studies that evaluate all hours of the year — which found the California-Mexico assessment area of WECC at risk of 2.3 loss-of-load hours in 2022, with an expected 152 MWh of unserved energy. “These are not significant numbers … but it’s a faint signal that tells us about risk that may not be occurring in the peak hour,” Moura said.

Following Florida, California

The more than 30 GW of new distributed solar PV expected by the end of 2023 impact system planning, forecasting and modeling needs. | NERC

The report projects 100 GW of new generation in the next decade, including about 41 GW of gas and 60 GW of solar. ERCOT and the California-Mexico region expect gas generation to contribute more than 60% of on-peak capacity, while Florida expects gas’ share to rise from 70% to 80%.

“When you do have this level of natural gas resources, you have to plan differently,” Moura said. “There are things that, for example, Florida does that other areas may need to do in the future, such as procuring more firm gas … or ensuring we have more dual-fuel capabilities.”

California is leading the way in addressing reliability risks from increasing solar, with CAISO’s three-hour ramping needs hitting a record 14,777 MW last March and expected to rise to 17,000 MW by 2022.

“As solar generation continues to increase in California and elsewhere across North America, system planners should ensure sufficient flexible ramping capacity, including large-scale energy storage,” the report said.

More than 30 GW of new distributed solar PV generation is expected by the end of 2023, with California expected to reach 18 GW of capacity, almost 40% of its projected peak. New Jersey, Massachusetts and New York are projected to each have 3.5 to 4 GW of distributed solar by 2023.

John Moura, NERC | © RTO Insider

“There’s more [distributed energy resources] coming online faster than we’ve really ever seen any type of resource coming on. … If that’s not represented in models, we’re going to be modeling the system completely inaccurately. And if we don’t have flexibility in our resources, we really won’t be able to meet the challenges of the daily demand curves,” Moura said.

“In areas that may not have a lot of DER, or only starting to get DER, it’s perhaps common for planning studies to negate them or net them out or mostly ignore them. However, as we get a larger penetration of DERs, it’s really important that their characteristics are modeled,” Moura said. “Engineers and planners need to prepare data specifications and data exchanges that are needed now so that we have a better understanding of what the system’s going to look like in the future.”

This fall, NERC created a new working group to guide its efforts: System Planning Impacts of DER (SPIDER).

Recommendations

Among the report’s recommendations was a call for NERC’s Reliability Assessment Subcommittee to lead development of common metrics to assess energy adequacy. “Additional analysis is needed to determine energy sufficiency, particularly during off-peak periods and where energy-limited resources are most prominent.”

Similarly, it urged NERC’s Planning Committee to develop a common framework for assessing fuel disruptions, saying “system planners should identify potential system vulnerabilities that could occur under extreme, but realistic, contingencies and under various future supply portfolios.” The assessments could be used to develop regulations or market mechanisms to promote fuel assurance.

“A common approach for what kind of contingencies to study would be very valuable to the industry,” Moura said.

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FERC Approves NextEra’s Gulf Power Acquisition

By Tom Kleckner

FERC on Thursday conditionally approved NextEra Energy’s acquisition of Florida utility Gulf Power as being “consistent with the public interest” (EC18-117).

Separately, the commission granted Gulf Power’s request to make limited market-based rate sales of capacity and energy during the transition ownership period (ER18-1952) and accepted the utility’s new, standalone tariff, effective upon the transaction’s closing (ER18-1953). The latter order also established hearing and settlement judge procedures addressing Gulf Power’s proposed base return on equity and protocols.

Gulf Power service truck | Gulf Power

Gulf Power, a subsidiary of Southern Co. in the Florida Panhandle, serves about 450,000 customers in eight counties. The utility owns or controls approximately 2,277 MW of generating capacity, a 2,700-mile transmission system and a 7,700-mile distribution system, and service over its transmission system is currently covered under Southern’s tariff.

NextEra announced in May it had reached an agreement with Southern to acquire Gulf Power, Florida City Gas and two gas-fired plants in Florida for almost $6.5 billion. NextEra completed acquisition of the gas plants in December.

Gulf Power will continue to operate in the Southern Company Pool and in Southern’s balancing authority area during the transition period, until it can operate on a standalone basis.

FERC said it found no adverse effect to generation markets in its analysis of Florida-based NextEra’s acquisition of Gulf Power. It said the applicants’ commitment to “indefinite rate de-pancaking” addressed any horizontal market power concerns that might arise, and it noted that Southern-affiliated generation would continue to compete in the Gulf Power balancing authority area, and vice versa.

The commission determined vertical competition would be unaffected as well, pointing to an unconcentrated upstream natural gas delivery market in the existing Southern balancing authority.

It also accepted the transaction’s proposed ratepayer protections, which included extending a rate cap period beyond five years, should the transition period take longer than five years, and charging grandfathered transmission customers the lower of Southern’s or the new Gulf Power rates during the transition.

In allowing Gulf Power to continue to make limited market-based rate sales of capacity and energy during the transition period, FERC also designated the utility as a Category 2 seller in the Southeast region and a Category 1 seller in the Northeast, Southwest, Northwest, SPP and Central regions.

The commission defines Category 1 sellers as wholesale power marketers and power producers that:

  • own or control 500 MW or less of generation in aggregate per region;
  • do not own, operate or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid (or have been granted waiver of the requirements of Order 888);
  • are not affiliated with anyone that owns, operates or controls transmission facilities in the same region as the seller’s generation assets;
  • that are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and
  • that do not raise other vertical market power issues.

Sellers that don’t fall into Category 1 are designated as Category 2 sellers and are required to file updated market power analyses.

FERC accepted Gulf Power’s proposed tariff, which included a 10.5% ROE, but ordered a public hearing on its justness and reasonableness. The commission held the hearing in abeyance to provide time for settlement judge procedures.

Commissioner Kevin McIntyre did not vote on the orders, while Commissioner Bernard McNamee, who was only sworn in Dec. 11, voted present on each one.

NextEra’s share price lost $2.27 at one point during another bloody day on Wall Street, before recovering to close up 16 cents, at $174.91/share, in after-hours trading.

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ISO-NE CSO Penalties Approved by FERC

By Michael Kuser

FERC on Thursday approved new ISO-NE penalties for market participants that fail to cover their capacity supply obligations (CSOs) when a new resource is delayed.

The commission’s Dec. 20 order agreed with the RTO “that the failure-to-cover charge rate mechanism establishes a just and reasonable penalty rate for capacity resources that do not cover their CSO in advance of a capacity commitment period and fail to demonstrate the ability to fulfill all or part of their CSO” (ER19-169).

The new Tariff provisions go into effect Dec. 24.

The rule changes are designed to shift the responsibility for covering CSOs to market participants, which ISO-NE says have the best information about project development schedules and potential delays. (See NEPOOL OKs Penalty for Delayed Capacity Resources.)

The changes stipulate that for delivery years before June 1, 2022, the monthly dollar/kilowatt-month failure-to-cover charge will be the higher of the capacity clearing price and the clearing price in any Annual Reconfiguration Auction (ARA) for that year. After that time, the charge will be based on the outcome of a second run of the third ARA, using the unproven CSO quantities as a demand bid. Market participants will still be compensated for their CSOs and continue to face Pay-for-Performance risk.

Two Protests Denied

Public Service Enterprise Group filed a protest seeking “staggered effective dates” to incorporate a three-month grace period beginning in June 2019, June 2020 and June 2021 for resources awarded CSOs in the Forward Capacity Auctions associated with those capacity commitment periods.

The general timeline for Forward Capacity Market events for a single capacity commitment period. The specific dates for 2019 can be found by clicking the image. | ISO-NE

The company argued that allowing the filing to take effect this month would impose new and unexpected risks and costs on resources that obtained CSOs under the existing rules, in particular its Bridgeport Harbor 5 plant scheduled to go into operation next June.

The commission disagreed “that the proposed effective date violates the filed rate doctrine and rule against retroactive ratemaking. … PSEG fails to quantify or detail the extent to which the risk profile for Bridgeport Harbor 5 is altered or otherwise to support its argument that any such change is unjust and unreasonable.”

Northeastern Massachusetts Consumer-Owned Systems (NEMACOS) also filed a protest expressing concern that load-serving entities may be paying arbitrage margins to suppliers that obtain a higher clearing price in the FCA and cover their capacity obligations in the reconfiguration auctions at a lower price.

The commission found the Tariff provisions that NEMACOS addresses in its protest are not at issue in the proceeding, but it noted that “under both the current Tariff and the proposed revisions, a resource that obtains a CSO in the FCA would have an opportunity to cover its CSO in a subsequent reconfiguration auction and potentially garner an arbitrage margin.”

“Because the failure-to-cover charge rate is designed to always be greater than or equal to the third Annual Reconfiguration Auction clearing price, the proposed revisions will offer no additional arbitrage incentives beyond those already available to resources under the current Tariff,” the commission said.

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BPA Stays on Track to Join Western EIM

By Hudson Sangree

The Bonneville Power Administration on Tuesday continued its series of discussions with stakeholders about joining CAISO’s Western Energy Imbalance Market, with a possible activation date in 2022.

Tuesday’s talks revolved around EIM settlements, with detailed presentations about invoices, charges and metering. The calculations may have appeared daunting but ultimately came down to familiar math, said Steve Kerns, BPA’s director of grid modernization.

“I want to make sure you don’t find this to be too scary,” Kerns told the dozens of stakeholders on the call and in BPA’s Rates Hearing Room in Portland, Ore. “There’s a lot of stuff going on here, but at the end of the day, it’s adding, subtracting [and] multiplying.”

Prior meetings that were part of BPA’s EIM stakeholder initiative have covered subjects such as market power, transmission and governance. Future meetings will deal with resource sufficiency and carbon obligations, with the next session scheduled for Jan. 16 in Portland.

BPA is targeting next September for issuing a final record of decision authorizing it to sign an implementation agreement with the EIM, which would allow the agency to begin spending on implementation projects without obligating it to join the market.

So far there has been little opposition among BPA stakeholders to joining the EIM, though details of the move are still being worked out. Joining would ease short-term trading of Pacific Northwest hydro power for solar energy from the desert Southwest and wind power from Rocky Mountain states.

BPA controls the Pacific Northwest’s largest hydroelectric resources — including the Grand Coulee, The Dalles and Chief Joseph dams on the Columbia River — and operates about 70% of the region’s transmission. Its balancing area covers most of Oregon, Washington, Idaho and western Montana, along with smaller portions of California, Nevada and Wyoming.

The Dalles Dam on the Columbia River is one of the major hydroelectric resources that the Bonneville Power Administration could bring to the Western Energy Imbalance Market. | © RTO Insider

If BPA signs an agreement with the EIM, it would bring a territory the size of France into CAISO’s real-time market. The EIM has been expanding rapidly, with entities joining or seeking to join from Canada to the Mexican border.

Idaho Power and Powerex began transacting in the market in April, bringing the number of members participating to eight. (See Idaho, Powerex Began Trading in Western EIM.) That expansion equipped the EIM to serve imbalances for about 55% of load in the Western Interconnection, according to the ISO.

NV Energy, Arizona Public Service, PacifiCorp, Puget Sound Energy and Portland General Electric are already participants.

The Energy Imbalance Market currently has seven participants in addition to CAISO. | CAISO

The Sacramento Municipal Utility District plans to begin participating in the EIM in April 2019. The Los Angeles Department of Water and Power, Arizona’s Salt River Project and Seattle City Light are scheduled to go live in April 2020. Public Service Company of New Mexico recently received state regulators’ permission to join the EIM by 2021. (See PNM Seeks to Join Energy Imbalance Market.)

In debates about establishing a Western RTO led by CAISO, the EIM often has been held up as a better alternative because, unlike an RTO, the market’s transmission-owning entities retain operational control over their assets, while member generators participate in the real-time market on a voluntary basis.

The EIM has conferred a half-billion dollars of benefits on participants since its founding five years ago, with $100 million realized in the third quarter of 2018 alone, CAISO officials said in October. (See Western EIM Reports Record Benefits.)

Moreover, the EIM’s board consists of members from multiple states, while CAISO’s board is appointed by California’s governor and confirmed by the State Senate. Industry leaders and officials from other Western states don’t want to cede control to California, and California politicians don’t want to give up authority over CAISO.

A series of CAISO regionalization measures that would have broadened its governance to include out-of-state representatives have failed in the State Legislature in recent years, largely because of this impasse. Proponents of a single RTO for the West say they will likely introduce another bill in January when California lawmakers reconvene for the start of another two-year session. (See Western RTO Proponents Vow to Keep Trying.)

In the meantime, CAISO officials and EIM participants have been pushing ahead to add day-ahead trading to the EIM’s current real-time-only market, bringing it closer to conferring many of the benefits of a regional RTO without the perceived drawbacks.

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NYISO Ordered to Revise DR Meter Rules

By Michael Kuser

NYISO must revise its rules governing the installation and reading of demand response meters for participants in its Installed Capacity (ICAP) market, FERC ruled Thursday (EL18-188).

The commission partly granted NRG Curtailment Solutions’ July complaint alleging the ISO’s Tariff provisions are unjust because they require curtailment service providers (CSPs) and responsible interface parties (RIPs) seeking to participate in the ICAP market to use the services of meter service providers (MSPs) or meter data service providers (MDSPs) certified by the New York Department of Public Service to install and read non-revenue grade interval meters.

The New York PSC told FERC that the future of competitive metering services is presently in question in New York.

The ruling denied NRG’s request for waiver of the rules, instead convening a paper hearing to determine replacement provisions.

The commission found the rules unduly discriminatory to the extent they require CSPs and RIPs that are not transmission owners to be certified by the DPS, which certifies only entities that also provide metering services for the state’s retail electric market.

“The result, even if not so intended, is that retail market participation is a prerequisite for demand response resource participation in NYISO’s wholesale market,” the commission said. “Indeed, in this proceeding, the New York [Public Service] Commission disavows the role ascribed to it through NYISO’s requirements and explicitly states that its certification program was designed to facilitate retail billing service, not for participation in wholesale markets or for measuring load reductions.”

FERC noted the PSC “has issued a notice proposing to eliminate the state MSP and MDSP programs and the certifications related to these programs.”

The PSC filed comments in favor of granting NRG the relief it sought, saying “the future of competitive metering services is presently in question in New York. Upon information and belief, there are no known utility customers today who avail themselves of competitive metering services, nor have there been for some time.”

NYISO answered NRG’s complaint Aug. 13 and filed a supplemental answer Oct. 22, saying it is examining its metering requirements as part of its broader DER Roadmap. But FERC found the current metering requirements “in need of immediate remedy.”

The commission established a paper hearing with initial briefs due within 45 days of the order and reply briefs due within 30 days thereafter. It ordered parties participating in the hearing to address the following issues:

What metering requirements could be implemented in NYISO, would not be unduly discriminatory and yet would effectively evaluate, measure and verify customer meter data?

How would such metering requirements address the verification of meter data and auditing of metering service providers?

How would such metering service eligibility criteria ensure that metering services are available to customers in all geographic areas of NYISO?

Would such metering requirements allow self-certification for DR providers in NYISO? If not, please explain why.

FERC said it expects to be able to render a decision within four months of receiving reply briefs, or by May 31, 2019.

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NERC Releases ‘Stress Test’ Analysis of Gen Retirements

By Michael Brooks

NERC on Tuesday warned that faster-than-expected coal and nuclear plant retirements could jeopardize reliability if grid operators are not prepared.

“If these retirements happen faster than the system can respond with replacement generation, including any necessary transmission facilities or replacement fuel infrastructure, significant reliability problems could occur,” NERC said in a special reliability assessment report. “Therefore, resource planners at the state and provincial level, as well as wholesale electricity market operators, should use their full suite of tools to manage the pace of retirements and ensure replacement infrastructure can be developed and placed in service.”

Projected retired capacity as a percent of total capacity in 2022, both currently confirmed and under NERC’s “stress test” scenario | NERC

Calling it a “stress test” of the bulk power system, the organization used data from the U.S. Energy Information Administration to identify generators set to retire through 2025 in 10 areas where coal-fired and nuclear generation make up a significant portion of the resource mix. It then analyzed the impacts of those generators retiring earlier, in 2022.

The analysis found four areas — SPP, SERC-East, WECC-RMRG and WECC-SRSG — in which currently planned generation resources would not be sufficient to make up for the accelerated retirements. NERC determined this by comparing projected planning reserve margins for 2022 under the scenario to projected peak load levels for the year. The organization used data from its 2017 Long-Term Reliability Assessment to determine projected reserve margins under currently confirmed retirements through 2022, to which it factored in the accelerated retirements. It also used the LTRA to determine the projected peak loads.

NERC analyzed the 10 regions where coal-fired and nuclear generation make up a significant portion of the resource mix. | NERC

‘Unlikely’ Scenario

Both the report and John Moura, NERC director of reliability assessment and system analysis, repeatedly emphasized that the analysis was not a prediction.

“I think it’s really important that stakeholders understand that this is a stress-case scenario,” Moura said in a conference call with reporters Tuesday morning. “We’re not necessarily making any recommendations or calls for any additional financial support beyond that which market operators think are required. We completely acknowledge that the scenario as tested is unlikely.”

He noted the organization also analyzes the impacts of geomagnetic disturbances and simultaneous, highly coordinated physical and cyberattacks on the grid. “These are things that we don’t believe will happen, but we think it’s instructive, when we break a system, to understand what are the potential mitigations and see how to get it working.”

“NERC’s stress-test scenario is not a prediction of future generation retirements nor does it evaluate how states, provinces or market operators are managing this transition,” the report says. “Instead, the scenario constitutes an extreme stress-test to allow for the analysis and understanding of potential future reliability risks that could arise from an unmanaged or poorly managed transition.”

Moura also noted that the report doesn’t criticize capacity markets or out-of-market subsidies. “We’re simply saying that these tools need to be monitored and tested in planning,” he said.

Under the “stress-test” scenario, SPP, SERC-East, WECC-RMRG and WECC-SRSG would not have enough new generation to make up for the accelerated retirements. PJM, MISO and ERCOT are just slightly above or equal to the reference levels. (SERC-East and WECC-RMRG’s margins are actually zero or in the negative.) | NERC

Fears of Politicization

NERC was criticized by some stakeholders, including FERC Commissioner Cheryl LaFleur, in early November, when it briefed its Members Representatives Committee on a draft of the report. They feared it would be politicized, and that the press and public would misunderstand it as a warning of things to come. (See LaFleur, Stakeholders Anxious over NERC Retirement Study.)

“Policymakers and regulators should not interpret this study as justifying interventions to artificially retain unprofitable power plants, as these actions deter the economic transition in the power generation fleet, undermine innovation and raise costs to America’s businesses and families,” Devin Hartman, CEO of the Electricity Consumers Resource Council, said in a statement Tuesday.

“As NERC itself states, the report looks at unlikely scenarios that go far beyond either announced or projected power plant retirements to determine at what point there might be some risk for reliability,” said Jeff Dennis, general counsel for regulatory affairs at Advanced Energy Economy. “The report does not provide evidence of any imminent threat to the reliability of the bulk power system. Nor does it suggest that competitive wholesale energy markets aren’t up to the job of ensuring reliability as the resource mix changes.”

The report “relies on too many extremes to be enlightening about real-world grid reliability,” the Natural Gas Supply Association said.

At FERC’s open meeting Dec. 20, LaFleur repeated her criticism, saying the report has a “fundamental flaw” in assuming baseload retirements beyond that currently anticipated but only counting new resource that have been announced. “So there’s an asymmetry in what’s coming out and what’s coming on,” she said. “It’s like saying, ‘What if I gave up 45% of my income and I kept my expenses the same. … You’d have a mismatch by definition.”

LaFleur said it was “noteworthy” that even under NERC’s extreme scenario “there’s not that many resource problems [that] pop up.”

“It’s a big deal … making sure we have enough resources in the future,” she concluded. “But I think we have to make sure that we rely on fact and not projections.”

NERC spokesman Marty Coyne declined to respond to LaFleur’s comments. “We don’t have anything further to say other than what’s in our media release,” he said.

Speaking to reporters after the open meeting, FERC Chairman Neil Chatterjee said he thought “NERC put a lot of work into it, and it was a thorough document. It is one data point amongst many, and I think as it pertains to our actions here at the commission and our resilience docket, my colleagues and I will analyze the myriad of data points that we have before us.”

Tuesday’s report did not include a detailed analysis of natural gas infrastructure; however, NERC said “additional midstream natural gas infrastructure could be required” to respond to early retirements.

In a November 2017 assessment, NERC had recommended industry consider the loss of key natural gas infrastructure in their planning studies under NERC reliability standard TPL-001-4. (See NERC: Natural Gas Dependence Alters Reliability Planning.)

Although NERC sees risks to increasing dependence on renewables and gas-fired generation, Tuesday’s report said that “successfully managed, the changing resource mix can provide … potential benefits to reliability and security of the BPS. Less reliance on large, centralized generation stations and greater use of dispersed networks comprised of smaller diversified generation resources can provide operating and planning flexibility. Additionally, some fuel assurance risks diminish with the changing resource mix. The effects of adverse weather on coal stockpiles or fossil fuel resupply infrastructure may be reduced when natural gas pipelines supply a greater proportion of the generating fleet. Attaining reliability enhancements associated with the changing resource mix is possible when the different challenges to fuel assurance and [essential reliability services] are addressed.”

Natural gas-fired generation’s contribution to the fuel mix in each region. | NERC

Recommendations

NERC included several suggestions to stakeholders, regulators and policymakers in the report, among them a recommendation to incorporate fuel assurance analyses in generator retirement assessments. This would mean factoring in fuel supply infrastructure, new infrastructure requirements for replacement resources, and firm vs. non-firm fuel delivery contracts.

It also recommended that regulators and policymakers consider ways to speed up approvals of infrastructure. “When a generator’s planned retirement is delayed to allow for completion of transmission system upgrades, expedited regulatory proceedings can help minimize the delay,” the report says. “Where more natural gas generation is needed, more natural gas pipeline capacity will likely also be needed.”

But Moura also noted that the report doesn’t make any specific recommendations for the four areas identified by the report as being at risk under the scenario. “We have a lot of confidence in how these areas plan their systems,” he said.