FERC denied a complaint Thursday by the city of Oakland against Pacific Gas and Electric for charging retail instead of wholesale power and transmission rates at the Port of Oakland, which maintains an extensive distribution network. The city claimed PG&E violated the Federal Power Act by charging the higher rates and failing to file a wholesale service agreement with FERC (EL18-197).
The city, acting through the port, asked for a refund of the difference between the retail rates PG&E charged and the wholesale rates the city argued it should have paid for electricity it had received through its Cuthbertson substation between 1997 and 2017, when it signed a wholesale agreement with the utility. The city said that since 1997, it had resold virtually all the electricity it received from PG&E to metered electricity end-use customers, and that PG&E should have been aware of the situation and charged wholesale rates.
FERC rejected a complaint by the city of Oakland regarding rates PG&E charged the city’s port.
FERC rejected the city’s argument and request for relief, saying it hadn’t provided evidence, such as invoices, of its resale of electricity to end users. Moreover, the city never specifically asked PG&E to change its rates from retail to wholesale at the substation, and the utility did not have an obligation to do so on its own, the commission said.
“We do not believe that Port has substantiated its general claim that PG&E violated Section 205c of the FPA by failing to file a wholesale transmission and power sale agreement for the Cuthbertson substation,” the commission said. “Port’s statements to the contrary are speculative, not supported by the record evidence, and insufficient to meet its FPA Sections 206 and 306 burdens.”
The commission added that “even if we were to find that PG&E violated FPA Section 205c as alleged by Port, we would not direct refunds here. As noted above, Port had ample opportunity over roughly two decades to clarify the nature of the service it took from PG&E and failed to do so. We therefore do not think requiring refunds from PG&E would be appropriate.”
WASHINGTON — FERC on Thursday proposed to exempt market participants in ISO-NE, MISO, NYISO and PJM from its indicative horizontal market power screens (RM19-2).
Under the Notice of Proposed Rulemaking issued at the commission’s monthly open meeting, entities in the four regions would no longer be required to submit the pivotal supplier and wholesale market share screens to qualify for market-based rate authority.
“We believe that this proposal would reduce the filing burden on market-based rate sellers in RTO/ISO markets without compromising the commission’s ability to prevent the potential exercise of market power in RTO/ISO markets,” the commission said.
The new rule would presume that the grid operators’ commission-approved monitoring and mitigation rules provide adequate protection against market power abuse.
“The existence of market power mitigation in an organized market generally results in a market where prices are transparent, which disciplines forward and bilateral markets by revealing a benchmark price, keeping offers competitive,” FERC said.
CAISO and SPP are excluded from the NOPR because they do not have centralized capacity markets, FERC said. Bilateral capacity sales in these markets are overseen by state regulators, not by the grid operators’ market monitoring units.
“We recognize that there is state regulatory oversight of the capacity costs and/or prices incurred in CAISO and SPP,” FERC said. “However, we do not believe that it is appropriate to exempt sellers from filing the indicative screens … in markets that lack commission-approved monitoring and mitigation programs. Capacity markets are distinct from energy markets … so monitoring and mitigation of energy prices in day-ahead and real-time markets does not ensure that capacity prices will be just and reasonable.”
Both screens were created in 2007 by FERC’s Order 697, which simplified the commission’s analysis for determining whether a market participant qualifies for MBRA into a two-part test examining the participant’s horizontal and vertical market power.
The pivotal supplier screen tests whether peak demand in the participant’s balancing authority area can be met without the participant’s supply. The market share screen ensures a participant’s share of the total capacity of the market is 20% or less.
All market-based rate sellers would still be required to file vertical market power analyses.
“The commission has long relied on RTO market monitoring and mitigation to address any market power concerns,” FERC Chairman Neil Chatterjee said Thursday. “So, limiting these submissions is a common-sense change that will reduce regulatory burdens without diminishing protections for ratepayers.”
“I support the general gist of the proposal,” Commissioner Richard Glick said. “If we are imposing unnecessary burdens on jurisdictional utilities, we should eliminate them.” But he also said he was looking forward to reviewing the comments “to consider whether there are additional measures the commission or regions could adopt to offer added protections against market power.”
Comments on the NOPR are due 45 days after its publication in the Federal Register.
MISO and SPP plan to file a slightly revised version of proposed changes to their joint operating agreement aimed at making a first interregional project between the two more attainable.
Targeted for the first quarter of 2019, the RTOs’ filing will still eliminate the $5 million cost threshold for the projects, add avoided costs and adjusted production cost benefits to project evaluation, mandate coordinated system plan studies, and remove the joint modeling requirement in favor of individual RTO regional analyses. (See MISO, SPP to Ease Interregional Project Criteria.)
But with recent changes, the proposal will now require that a coordinated system plan (CSP) — the joint study used to identify interregional transmission needs — take place once every two years instead of the originally proposed three years.
MISO and SPP also restored the JOA’s original opt-in instead of an opt-out approach for the CSP study agreement. The RTOs had proposed that the two would have to agree not to perform a study in order to skip a CSP, but now they will actually have to agree to initiate a CSP before undertaking one.
“I think SPP and MISO’s intent is still to do a study annually,” SPP’s Adam Bell said during a Dec. 20 conference call held by the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).
But multiple stakeholders pointed out that the CSP study process is historically an 18-month process and doesn’t fit well into the annual time frame. However, RTO staff said the studies, now evaluated regionally, will probably take less time to complete.
Entergy’s Jennifer Amerkhail said her company opposed the study frequency minimum. She reminded the RTOs of their “fiduciary responsibility” to not expend resources on CSP studies that aren’t ultimately necessary.
JPC Review
The RTOs have also added to the proposal both a study model review and project review by the Joint Planning Committee (JPC), an interregional group comprising representatives from both RTOs. The JPC will also vote on a project’s proposed interregional cost allocation.
Some stakeholders questioned the need for a JPC review and vote, saying the RTOs may be introducing another interregional project hurdle.
Bell said the JPC review isn’t for “leverage” purposes but to ensure that projects “have more certainty” before they are decided on by the RTOs’ boards of directors. He said it’s best for the JPC to meet and ensure all project expectations can be realized.
“It’s so we’re not operating blindly,” Bell said. “It’s not to second-guess assumptions or cost allocations.”
Stakeholders questioned what the impact of a JPC vote would be, asking whether the vote was a recommendation or binding vote, which could lead to re-evaluation of projects and delay before projects are put to either board.
Officials said the RTOs’ already-approved regional processes will be used by the JPC to evaluate the projects.
“There would be no reason for the JPC to deviate from the regional process and the study findings,” Bell said.
LS Power’s Pat Hayes asked for the RTOs to develop criteria to guide the JPC in its votes on projects.
But RTO officials reiterated that their regional processes will guide JPC decisions, with some noting the committee already reviews project candidates under the current interregional process.
Negative APC Consideration
SPP and MISO also agreed to evaluate adjusted production costs and avoided costs for all potential interregional projects regardless of whether the projects are driven by economics, reliability or public policy.
The two also said they have “tentatively” agreed to include negative adjusted production cost values to evaluate reliability and public policy projects.
However, Bell said the RTOs will craft language that would still allow for otherwise beneficial projects that happen to have negative adjusted production costs. Bell said MISO and SPP legal teams are still deciding whether to include the caveat in the JOA.
Adam McKinnie, chief economist with the Missouri Public Service Commission, asked if projects with negative values must be pursued through special FERC filings to find a different cost allocation methodology. Bell said that would probably be the case.
SPP’s Markets and Operations Policy Committee will begin 2019 with new faces in all its leadership positions following the Board of Directors’ approval of NextEra Energy Resources’ Holly Carias as chair and Evergy’s Denise Buffington as vice chair.
SPP Vice President of Engineering Lanny Nickell, who will become the committee’s staff secretary, made the announcement late Friday in an email to stakeholders.
“I’m confident they will do a fabulous job leading the group,” said Nickell, who is replacing SPP COO Carl Monroe on the committee. Monroe served as secretary for 18 years.
Carias, a senior director in regulatory affairs for NextEra who became heavily involved with the MOPC during 2018, has been a vocal proponent for renewable resources.
Buffington, director of federal regulatory affairs for Evergy companies Kansas City Power & Light and Westar, has focused on SPP’s budget and transmission zonal placement issues. The board and MOPC in 2017 both rejected her attempts to address cost shifts caused by the RTO’s zonal placement decisions. (See SPP Board Rejects Changes to Tx Zonal-Placement Rules.)
Carias and Buffington replace Nebraska Public Power District’s Paul Malone and independent consultant Jason Atwood. Malone cycled off the committee in December, while Atwood left the Northeast Texas Electric Cooperative in November to start his own business.
FERC last week approved SPP’s plan to streamline the process by which it designates frequently constrained areas (FCAs), effective Dec. 22 (ER19-166).
The commission had directed SPP to seek approval of any new, removed or modified FCAs when the RTO submitted Tariff revisions in 2012 to implement its Integrated Marketplace. SPP and its Market Monitoring Unit worked with stakeholders to develop the designation process for areas with high levels of congestion and a dominant or pivotal supplier.
The commission agreed with SPP’s argument that the designation process may result in a significant lag between the MMU’s annual evaluation of FCAs and when they are updated in the Tariff. It said SPP’s proposal allows the RTO and MMU to address market power concerns in a timely fashion.
“We find that this delay could result in the inappropriate application of mitigation measures during the lag period or, conversely, the lack of application of mitigation measures when appropriate, potentially allowing market participants to exercise market power,” FERC said.
SPP’s Tariff requires the MMU to re-evaluate FCAs at least annually.
The MMU said it strongly supported SPP’s proposed revisions, noting that under the previous process, it could take up to six months to update the FCA list following its report. With the change, the Monitor’s updates and associated analysis will be publicly available at least 14 days before any updates take effect. Affected market participants can raise any concerns with the MMU.
SPP stakeholders approved the Tariff revision during July’s Board of Directors and Markets and Operations Policy Committee meetings.
Tri-State G&T transmission upgrade project in Colorado | Tri-State G&T
The commission denied Nebraska Public Power District’s complaint against fellow SPP member Tri-State Generation and Transmission Association that certain costs in the latter’s annual transmission revenue requirement (ATRR) and its failure to credit certain revenues are unjust and unreasonable (EL18-194).
NPPD alleged that Tri-State unfairly included in its ATRR the costs of two grandfathered agreements (GFAs) and its facilities not physically connected to SPP’s system. It also said Tri-State excluded point-to-point revenue from the credits applicable to revenue requirements for network service. The utility asked the commission to remove all costs related to the two GFAs and the facilities from Tri-State’s ATRR and SPP’s rates for NPPD’s transmission zone, and to include point-to-point revenue as a credit to the cooperative’s revenue requirement.
The complaint stems from Tri-State’s placement in NPPD’s transmission zone when the cooperative wholesale power supplier joined SPP in 2015 as part of the Integrated System. NPPD protested at the time but reached a settlement with Tri-State and SPP in 2017.
FERC ruled the disputed cost components were covered in the settlement agreement, saying that NPPD had failed to demonstrate that without its proposed modifications, the settlement “seriously harms the public interest.”
SPS Gets Partial Approval to Issue Refunds
El Paso Natural Gas’ iconic “Blue Flame” headquarters in El Paso | Texas Historical Commission
FERC granted one of Southwestern Public Service’s three waiver requests related to the issuance of customer refunds, but it rejected a second and dismissed a third as unnecessary (ER18-2377).
The Xcel Energy subsidiary requested the waivers in September, saying it had received a $12 million refund from El Paso Natural Gas (EPNG), which provides fuel to SPS and third-party-owned gas-fired plants on its system. The utility said each wholesale requirements customer has a power supply agreement that contains a fuel cost adjustment clause, through which SPS recovers fuel transportation costs.
The commission accepted SPS’ request for a waiver of section 35.14 of FERC’s regulations, which limits the fuel cost adjustment clause to the recovery of current fuel costs. That clears the way for the utility to issue about $3 million in refunds to eight of its current and former wholesale customers.
FERC rejected the utility’s request for a waiver of section 35.19a of its regulations and its methodology for computing interest on refunds. SPS requested the waiver to avoid paying interest for the period between its receipt of the refunds from EPNG and the distribution of refunds to SPS’ wholesale customers.
The commission said the utility’s arguments were insufficient to explain why it should be exempt from paying interest.
Finally, FERC dismissed SPS’ request for a waiver from the utility’s fuel cost adjustment protocols as unnecessary, saying they don’t conflict with providing EPNG refunds to wholesale requirements customers.
FERC last week accepted a revised generator interconnection agreement (GIA) between MISO and a Michigan wind farm, avoiding complex analysis from the fallout of a vacatur of the commission’s previous orders covering transmission owners’ ability to fund network upgrades.
The Dec. 20 order allows Invenergy’s 150-MW, 60-turbine Crescent Wind Farm near the Michigan-Ohio border to interconnect to the MISO system under a revised agreement that eliminates TO Michigan Electric Transmission Co.’s (METC) “unilateral right to elect to provide initial funding for network upgrades” (ER18-2340). The new GIA allows METC to provide initial funding for network upgrades “only upon mutual agreement with the interconnection customer.”
Crescent Wind Farm interconnection site map | MISO
In approving the GIA, FERC focused on the requested effective date, not the issues still in flux around agreements executed between mid-2015 to mid-2018, after the D.C. Circuit Court of Appeals early this year vacated FERC orders dealing with TOs’ rights to fund upgrades.
MISO in July submitted a pre-emptive Section 205 filing to retain the option to allow new generators to self-fund interconnection transmission upgrades. (See MISO Files Revised Upgrade Funding Provisions.) FERC dismissed that filing as moot after deciding TO initial funding should be included in MISO’s pro forma GIA only prospectively as of Aug. 31, 2018. It instituted a briefing schedule to determine how to address GIAs, facility construction agreements and multiparty facility construction agreements that were entered into between June 24, 2015, and Aug. 31, 2018.
FERC said because MISO and Crescent Wind filed for an Aug. 15, 2018, agreement effective date, MISO’s previous pro forma GIA should be followed, which allows TOs to provide initial funding for network upgrades “only upon the mutual agreement of the interconnection customer.”
“We find the amended agreement to be just and reasonable because such language was not included in MISO’s pro forma GIA as of the effective date of the amended agreement,” FERC said.
METC had requested FERC reject the amended agreement, arguing that MISO’s removal of the funding language is premature because the commission is still working through whether to include language allowing the initial TO funding of network upgrades for all GIAs executed between June 24, 2015, and Aug. 31, 2018. METC also pointed out that the agreement does not contain any network upgrades that would be subject to TO initial funding. FERC did not address the argument.
The Crescent Wind GIA is also exempt from FERC Order 842 primary frequency response requirements because MISO requested an exemption for all projects having reached at least the second decision point in its interconnection queue before May 15, 2018.
FERC last week voted 2-1 to approve ISO-NE’s cost-of-service agreement with Exelon for its Mystic Generating Station Units 8 and 9, including payments to the company’s Distrigas LNG facility. It also ordered a paper hearing on the issue of return on equity for the plants.
FERC Chairman Neil Chatterjee and Commissioner Cheryl LaFleur approved the order — issued after the commission’s open meeting Thursday — with Commissioner Richard Glick dissenting (ER18-1639). The agreement becomes effective June 1, 2022.
The RTO sought the agreement after Exelon said in March that it would retire the 2,274-MW plant when its capacity supply obligations expire on May 31, 2022 (ER18-1509).
The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. But the commission found the information Exelon provided to support those figures insufficient and ordered the company to submit a compliance filing within 60 days of the order.
In the most recent order, the commission directed Mystic to adopt Exelon’s capital structure for ratemaking purposes, include an amortization of excess deferred income taxes and amend the agreement to state that it will recover 91% of the costs of Distrigas as Mystic fuel costs, determining that other New England beneficiaries of the LNG terminal should bear some of its operational costs.
Glick’s Dissent
In his dissent, Glick argued the commission “cannot and should not use its authority over wholesale sales of electricity to bail out an LNG import facility. … The commission concludes that it can use the [Federal Power Act] to bail out an LNG import facility simply because that LNG import facility has an undefined and unexplained ‘extremely close relationship’ to the Mystic facility.”
The commission is attempting to regulate the costs incurred and sales made by a non-jurisdictional facility, he said.
“A more reasonable construction of the commission’s jurisdiction would be to limit its reach to the entities that can or actually do participate directly in the wholesale market for electricity,” he said.
“The jurisdictional puzzle in which the commission now finds itself only reinforces the fundamental mistake that the commission made in rushing to seize control of the debate over fuel security in New England and dictate a particular outcome. That outcome, ‘individual, ad hoc contracts with particular resources whose retirement might, under the most conservative assumptions, create a fuel security concern,’ is no way to address a region’s long-term fuel security,” Glick said, quoting from his previous dissent in the commission’s July tentative acceptance of the agreement.
FERC on Dec. 3 approved ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security (ER18-2364). (See ISO-NE Fuel Security Measures Approved.) The RTO’s Tariff had previously only allowed cost-of-service agreements to respond to local transmission security issues, with the interim proposal developed in response to FERC’s July denial of a request for waiver to allow for the Mystic agreement. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
New Mexico regulators on Thursday gave Public Service Company of New Mexico (PNM) permission to join the Western Energy Imbalance Market, clearing the way for the state’s largest electric utility to begin participating in the interstate real-time market in April 2021.
The Public Regulation Commission voted 5-0 to allow the move by PNM, which declared its intent to join the EIM in August. (See PNM Seeks to Join Energy Imbalance Market.)
The New Mexico Wind Energy Center is among the resources that PNM could bring to the Western Energy Imbalance Market. | PNM
CAISO, which administers the EIM, welcomed PNM in a news release, saying the utility’s participation would increase the EIM’s efficiency in trading resources across the West. New Mexico is fast becoming one of the West’s largest producers of wind power, and California has a legal mandate to gather an increasing share of its electricity from renewable resources.
PNM generates about 2,580 MW of electricity, including 800 MW from low- or zero-carbon resources, CAISO said.
“The diversity and location of PNM’s resources, along with the transmission connectivity to the rest of the EIM footprint will provide significant benefits to their customers,” CAISO said in its statement.
The EIM has generated a half-billion dollars in benefits for its members since its founding in November 2014, including $100 million in the third quarter of 2018 alone, CAISO has said.
The EIM’s current members include Arizona Public Service, Idaho Power, NV Energy, Portland General Electric, Puget Sound Energy and Powerex. The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District and several other entities are scheduled to join between 2019 and 2021.
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.
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.”
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.
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.
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.
