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.
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 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.
