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April 3, 2025

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.

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.

Texas PUC Briefs: Dec. 22, 2018

By Tom Kleckner

Commission Approves Revised 345-kV CenterPoint Project

The Public Utility Commission of Texas last week preliminarily approved a certificate of convenience and necessity for CenterPoint Energy’s proposed 345-kV project in the industrial Freeport area south of Houston, but not before quibbling over the wide range of cost estimates (Docket 48629).

CenterPoint provided ERCOT a revised estimate of $481 million to $695 million for a new 345-kV double-circuit transmission line over its preferred route connecting two substations and upgrading an existing 345-kV double circuit line. The grid operator filed a revised study with the PUC on Dec. 14 that still recommends CenterPoint’s preferred route.

“The range of cost estimates is still not terribly satisfying,” Commissioner Arthur D’Andrea said. “It’s no one’s fault but the ambiguity and uncertainty of doing these [studies].”

“Unsatisfying is an understatement for me,” PUC Chair DeAnn Walker said, “especially when the low end — the $481 million — depends on using state land that I’m not sure is even an option.”

In September, the commission had asked ERCOT to take a second look at the project in the face of rising costs.

ERCOT reviewed five options in its original study and 10 in the second. Its Board of Directors approved the project, which was estimated at $202 million, in December 2017. (See “Board Approves $246.7M Freeport Transmission Project,” ERCOT Board of Directors/Annual Meeting Briefs.)

PUC Slashes NRG’s Nuke Decommission Costs

The commission approved a 65.2% reduction in the decommissioning costs for NRG South Texas’ share of the South Texas Project (STP) nuclear plant (Docket 48447).

With the order, NRG’s annual funding amounts will drop from $758,791 to $264,351.

The PUC “substantially reduced” the annual funding requirement in its last review in 2013, assuming a 20-year license extension for STP’s twin units from the original 2027 and 2028 expirations. The Nuclear Regulatory Commission approved the extensions last year.

NRG’s share of the decommissioning fund was $691.8 million at the end of 2017. The plant faces total decommissioning and dismantling costs of an estimated $2.5 billion.

The company owns a 44% share of STP. The plant’s other two owners are the city of San Antonio (40%) and the city of Austin (16%).

The nuclear plant’s two units have a combined capacity of almost 2.6 GW. They have been online since the late 1980s.

Hearing Schedule Set for Sempra-Oncor-Sharyland Deal

The commission will hold hearings April 10-12 on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services (Docket 48929).

Staff filed a procedural schedule following a Dec. 18 prehearing conference.

In October, the parties announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)

The transactions would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in central, north and west Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest. The real estate investment trust (REIT) structure that holds Sharyland and Sharyland T&D would be terminated.

InfraREIT and Sharyland are both owned by Hunt Consolidated, which failed in a 2016 attempt to acquire Oncor.

SPP, ERCOT Set New Wind Generation Marks

By Tom Kleckner

For the last two years, SPP and ERCOT have been saying, “Anything you can do, I can do better” in their friendly competition to see which can produce more wind energy or a greater share of its production.

Texas wind farm | Target

Both grid operators set new records for wind generation this month, with SPP producing a new wind peak of 16.4 GW at 7:40 a.m. on Dec. 20, six days after ERCOT topped out at a record 19.2 GW on Dec. 14.

SPP’s previous record of 15.7 GW was set in December 2017. ERCOT, which established its latest record just seven minutes into the new day, eclipsed the old mark of 17.9 GW, set Nov. 12, by almost 7%.

KCP&L’s Slate Creek Wind Project | KCP&L

ERCOT may produce more wind energy — it has 22 GW of installed wind capacity, while SPP recently passed the 20 GW level — but SPP relies on wind for more of its capacity. On April 30, it served 63.96% of its load with wind energy, and it is making plans for wind-penetration levels of 70%.

SPP became the first North American grid operator to top the 50% wind penetration level in February 2017.

ERCOT’s high for wind penetration is 54.22%, set in October 2017. Wind penetration was only 51.53% at the time of its latest wind peak.

CORRECTED: FERC Acts on Transcos’ Revised Tax Calculations

By Rich Heidorn Jr.

FERC ordered more than a dozen transmission owners to correct how they calculate accumulated deferred income tax (ADIT) balances.

FERC on Thursday approved tariff filings by transmission owners in two dockets to correct how they calculate accumulated deferred income tax balances while ordering more than a dozen others to make additional compliance filings.

The commission approved tariff revisions for Ameren Illinois, Ameren Transmission Company of Illinois and Northern States Power (EL18-155, et al.); and Public Service Company of Colorado and Southwestern Public Service (ER18-2319, et al.).

It ordered additional compliance filings by ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas & Electric (EL18-138, et al.); International Transmission Co., ITC Midwest and Michigan Electric Transmission Co. (EL18-159, et al.); American Transmission Co. (EL18-157); TransCanyon DCR (EL18-165); Virginia Electric and Power Co. (EL18-167); GridLiance West Transco (EL18-158); and Southern California Edison (EL18-164).

The companies’ filings came after the commission ordered Section 206 proceedings, finding that their use of the “two-step” averaging methodology used to calculate ADIT balances in the projected test year calculations or annual true-up calculations for formula transmission rates may no longer be just and reasonable.

The commission had previously permitted TOs to use a two-step averaging methodology to calculate ADIT balances based on the understanding that the methodology was necessary to comply with IRS rules. But after guidance that IRS provided in an April 2017 private letter ruling, the commission said it now believes the two-step method could lead to overstated rate bases and unreasonably higher rates.

Earlier this year, the commission issued a series of orders to ensure ratepayers benefit from the savings energy companies received through the Tax Cuts and Jobs Act, which reduced the maximum corporate income tax rate to 21% from 35%. (See FERC Orders Pipelines to Pass Through Tax Savings.)

[Editor’s Note: An earlier version of this article incorrectly stated that FERC had approved all of the TOs’ compliance filings.]

FERC Denies Oakland Complaint Against PG&E

By Hudson Sangree

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.”

FERC Proposes Market Screen Exemptions

By Michael Brooks

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.

FERC issued the Notice of Proposed Rulemaking at its monthly open meeting on Dec. 20. | © RTO Insider

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, SPP Tweak Interregional Criteria

By Amanda Durish Cook

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.

A MISO-SPP JOA meeting last year | © RTO Insider

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.

MOPC Gets New Leadership for 2019

By Tom Kleckner

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.

Holly Carias listens to a discussion during a 2018 MOPC meeting. | © RTO Insider

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.

Denise Buffington | © RTO Insider

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.

SPP FERC Briefs: FCAs, NPPD Complaint, Refunds

By Tom Kleckner

FERC Approves SPP’s Streamlined FCA Process

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.

The MMU’s 2017 analysis reduced the FCA list to one, effective April 2018. (See SPP’s FCA List Pared to One Area.)

NPPD Complaint Against Tri-State Denied

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 OKs Mich. Wind GIA, Leaves Open Funding Issue

By Amanda Durish Cook

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.