FERC on Thursday issued a flurry of orders delegating authority and waiving requirements in response to the COVID-19 coronavirus pandemic.
The commission issued:
A policy statement saying it will “expeditiously review and act on requests for relief” to ensure the business continuity of regulated entities’ energy infrastructure (PL20-5).
An order delegating authority to the director of the Office of Energy Market Regulation (OEMR), or the director’s designee, “to take action on uncontested requests for waiver of certain regulatory obligations to address needs resulting from steps entities have taken to meet the emergency conditions” (AD20-13). The delegation will be effective until June 1.
An order delegating authority to the director of the Office of Energy Policy and Innovation, or the director’s designee, to act on requests for extension of filing deadlines or waivers of the requirements of FERC Form 552 (Annual Report of Natural Gas Transactions) and FERC-730 (Report of Transmission Investment Activity). This authority was previously delegated to the director of the Office of Enforcement (RM20-13).
An order extending until Oct. 20 the deadlines for RTOs and ISOs to post monthly reports that would have been due between April and September on uplift and operator-initiated commitments (RM17-2). (See FERC Orders RTOs to Shine Light on Uplift Data.)
An order granting a blanket waiver through Sept. 1 of requirements to hold meetings in-person and obtain notarized documents in any tariff, rate schedule, service agreement or contract subject to the commission’s jurisdiction under the Federal Power Act, the Natural Gas Act or the Interstate Commerce Act (EL20-37). NYISO had requested relief from the notary requirements on March 27 (ER20-1419).
FERC has already granted PJM’s request for a waiver of generator interconnection-related deadlines (ER20-1392).
The commission said its delegation to OEMR will allow more efficient action on uncontested waiver requests. “The need for efficient processing and action is particularly important given the emergency conditions related to COVID-19, as entities may need to seek waiver of various requirements with which they are unable to comply due to the extraordinary circumstances,” the commission said.
It said the waiver “does not permit violations of the filed rate doctrine and the rule against retroactive ratemaking, even in uncontested cases. If such questions arise, they will be considered by the commission.”
The policy statement noted that the entities subject to FERC regulation “have had to take unprecedented actions in response to the emergency conditions, including directing staff to work remotely for an extended period, which may disrupt, complicate or otherwise change their normal course of business operations.”
“We will give our highest priority to processing filings made for the purpose of assuring the business continuity of regulated entities’ energy infrastructure during this extraordinary time,” the commission continued. “We view the reliability and security of our nation’s vital energy infrastructure as critical to meeting the energy requirements essential to the American people.”
FERC on Wednesday reaffirmed its conclusion that bidding results in ISO-NE’s 2013/14 Winter Reliability Program were just and reasonable despite the fact that the largest participants may have had market power (ER13-2266-004).
ISO-NE’s program offered compensation to demand response and generators able to burn oil to prevent New England from falling short of power in the winter because of the retirement of coal-fired units and tight natural gas supplies.
Wednesday’s order was prompted by a D.C. Circuit Court of Appeals ruling in December 2015 that said the commission had failed to justify its approval of the auction results. Although ISO-NE estimated the program would cost no more than $43 million for up to 2.4 million MWh of energy, the RTO filed for approval of bids totaling 1.95 million MWh at a cost of $75 million.
The court said that in approving the auction results, FERC failed to address how much of the program’s cost was attributable to profit and risk mark-up or to explain the economic forces that it believed restrained participants from submitting excessive bids.
The court was acting on an appeal by TransCanada Power Marketing, which contended ISO-NE’s pay-as-bid auction resulted in excessive costs because resources were incented to raise their bid prices knowing they would probably be accepted.
In response to the D.C. Circuit’s remand, FERC directed ISO-NE to query bidders on the process they used to formulate their offers. It also ordered the RTO and its Independent Market Monitor to opine on the reasonableness of the bids based on that information. (See ISO-NE Ordered to Justify Cost of Winter Reliability Program.)
The IMM found that each participant had market power because there was insufficient supply to meet the RTO’s 2.4 million MWh procurement target and that the program did not include a mechanism for mitigating their leverage. It said market participants were aware of their market power because the first auction failed to attract sufficient supply to meet the target.
About 70% of the supply offered into the auction came from only four participants, a concentration that the IMM said allowed them to submit bids above a competitive level.
After the remand by the D.C. Circuit, the IMM calculated that the supply curve would intersect with the assumed procurement level of 1.95 million MWh — the amount procured in the second auction — at a marginal cost of $15.08/MWh-month.
ISO-NE and its Independent Market Monitor calculated different expected marginal bids for the Winter Reliability Program because the RTO assumed procurement of 2.25 million MWh and the IMM assumed the purchase of only 1.95 million MWh. | FERC
The Monitor boosted that price to $18.85/MWh-month — a 25% risk premium reflecting participants’ limited information regarding the auction’s supply and demand curves and uncertainties over how the RTO would value resources in what was the first year of the program.
The IMM estimated the auction resulted in potential cost overages of $6.6 million, compared to what the program would have cost if all bids were at or below $18.85/MWh-month. The IMM concluded that 75% of the supply offered was competitive, but the remaining 25% “included sufficiently high markups to raise concerns that participants submitting bids for this supply may have exercised market power.”
“Market design issues, lack of information, uncertainty and measurement accuracy issues … prevent us from concluding, with certainty, the extent to which participants exercised market power or the impact it had on program cost,” the Monitor said.
ISO-NE conducted a similar analysis but assumed a supply curve of 2.25 million MWh, which it said would result in a clearing price of $24.86/MWh-month, or $31.08/MWh-month including the 25% adder.
It concluded there was no evidence that market power was exercised because there were no bids above $31.08/MWh-month. Using $24.86/MWh-month, it estimated $1.72 million in potential cost overages.
“We find that although the IMM found that the auction was not structurally competitive, ISO-NE nevertheless demonstrated that the Winter Reliability Program prices were just and reasonable because there were factors that sufficiently restrained parties’ ability to exercise market power,” FERC said. “These factors included the facts that, ahead of the auction, participants lacked information about ISO-NE’s chosen level of procurement, the costs and strategy of their competitors, and how ISO-NE would value the non-cost reliability factors that it would consider in addition to price when selecting bids.”
FERC compared the $75 million cost of the program to ISO-NE’s estimate in 2013 that the value of lost load “could reach into billions of dollars for a region the size of New England.” The RTO had cited estimates of the costs of the 2003 Northeast blackout, which ranged from $4 billion to $10 billion ($2003).
For a “competitive benchmark,” FERC looked at what costs would have been had the RTO used a single-price clearing auction — which incents bidding based on individual resource’s marginal cost — rather than pay-as-bid, in which participants seek to bid just below their estimate of the clearing price.
If resources bid based on marginal costs, FERC said the auction would have cleared at $15.08/MWh-month for a total of $88 million — above the actual total of $75 million ($12.82/MWh-month).
TransCanada protested the auction results, saying that ISO-NE’s “reliability need … created an essentially inelastic vertical demand that suppliers were aware of.”
FERC disagreed, saying that while the RTO said it would purchase “up to” 2.4 million MWh of winter reliability service, it ultimately purchased only 1.95 million MWh. “Contrary to TransCanada’s view, structural market power alone (i.e., a structurally uncompetitive market) does not necessarily result in unjust and unreasonable rates,” the commission said.
FERC also disputed the IMM’s conclusion that the 70% market share held by the four largest participants — the result of a C4 concentration test — was evidence that the auction was uncompetitive.
The commission said its preferred concentration test, the Herfindahl-Hirschman Index (HHI) — which sums the squares of the market shares of each market participant — resulted in an HHI of 1,462, “indicating a moderately concentrated, but not a highly concentrated, market.”
Even assuming there was structural market power, “there is no conclusive evidence that participants knew they had structural market power; therefore, participants would have bid competitively,” FERC said. “This is particularly likely given that the Winter Reliability Program presented a new product market with no prior auctions, making it more difficult to determine which other oil-fired generators would choose to participate and then what quantity of service each would bid (to cover their respective costs and include profits sufficient to warrant their participation in the auction).”
FERC on Wednesday resolved a dispute over overlapping congestion charges on the MISO–SPP seam when it accepted a settlement between Southwestern Electric Power Co. (SWEPCO) and the city of Prescott, Ark.
The settlement outlines a new rate schedule and documentation that the utility must provide the city for a power supply agreement (ER20-869).
Prescott filed its complaint against SWEPCO, an American Electric Power subsidiary, and MISO last April, but the issue behind the complaint can be traced to the 2013 integration of Entergy into the RTO. The city opposed Entergy’s integration because it would be moved into MISO and served by a pseudo-tie from SPP member SWEPCO under a power supply agreement. SWEPCO proposed eight years ago to build a new transmission line to buffer the city from excessive charges from MISO, but it was never built.
Prescott’s 2019 complaint claims that the failure of MISO and SWEPCO to guard it from congestion have pinned the city with about $770,000 per year in duplicate congestion charges and unreasonable transmission rates. SWEPCO neither hedged the city’s transmission congestion risks nor protected it from rate pancaking, abandoning duties under the power supply agreement, Prescott contended.
City of Prescott, Ark., water tower | Waymarking
The situation also spurred SWEPCO to file a separate complaint alleging MISO violated its joint operating agreement with SPP regarding congestion charge assessments for loads that are pseudo-tied out of MISO and into SPP. The utility said the charges resulted in a $963,974 overpayment to MISO for one four-month period in 2016. A FERC investigation into MISO and SPP’s potentially overlapping congestion charges is ongoing. (See FERC Sets Briefings on MISO, SPP Congestion Fees.)
Under the settlement agreement approved Wednesday, SWEPCO must file updated depreciation rates as formula rate inputs to FERC whenever the Louisiana Public Service Commission, Arkansas Public Service Commission or the Public Utility Commission of Texas approve changes to the utility’s state depreciation rates that would affect Prescott’s rates. If four years pass without an update, SWEPCO must make a FERC filing to update its depreciation rates.
The settlement also holds SWEPCO to providing Prescott with an annual populated formula rate, “including detailed work papers and other relevant supporting documentation, and to responding to Prescott’s requests for additional data related to the formula rate calculations.”
Finally, SWEPCO must also detail all RTO transmission charges and MISO market charges in its monthly invoices to Prescott.
FERC trial staff said the settlement agreement “reflects thoughtful and reasoned negotiations undertaken by all participants in good faith.”
MISO is gradually improving its ability to forecast the more sedate load profiles that have emerged in the face of widespread community measures to halt the COVID-19 pandemic, stakeholders learned Thursday.
The RTO is experiencing lower loads that no longer follow a sharp uptick in demand in the morning or evening, Director of Central Region Operations Ron Arness told stakeholders during a Reliability Subcommittee conference call Thursday.
“We have seen significant shifts in the morning and evening peaks. For instance, the morning peak has shifted from the usual 8 a.m. and 9 a.m. to about 11 a.m. or noon and then it’s not dropping off — and it’s staying steady until it dissipates in the evening,” Arness said. “It’s a more gradual increase. We’re seeing more steady peaks across the day, [and] we’ve not seen that evening bump-up in peak.”
MISO officials initially compared evolving load profiles to weekend usage patterns, but RTO staff now find that a slew of business closures have contributed to lower load than even typical weekend days. (See MISO Loads Down as Region Faces COVID-19 Threat.)
“There have been a lot more closures going on, in restaurants as well as industry. So, it’s not an exact weekend profile, but it’s close,” Arness said. “It’s down slightly — it’s still going down.”
MISO has experienced load forecasting errors for both on- and off-peak periods, Arness said, but he added that forecasters since March 23 have begun more aggressively predicting load shapes based on recent demand tracking and are each day manually inserting them into existing models.
Arness said that while MISO’s load was significantly down in March compared with a year earlier, most of the decline can be attributed to higher temperatures. Peak loads decreased 18% from 2019 and were down 13% from the March five-year average. March’s peak usually breaks just above 90 GW, but last month topped out at 79 GW.
COVID-19 early impacts on MISO load shapes | MISO
“We believe most of that is due to the temperature,” Arness said.
MISO said the few weeks of load forecast errors have not impacted reliable operations.
“These are unprecedented times, and we’re starting to hone [in on] it and get a little better,” Arness said.
Varying Emergency Responses in Footprint
Arness also said the sheer size of MISO’s footprint means that its uncharted load forecasting doesn’t fit neatly into a new model. He pointed out that states in MISO South have not yet clamped down on gatherings or population movement in the stricter ways that Michigan or Illinois have through industry shutdowns and travel restrictions.
“That’s why we’re still seeing some continued changes in our numbers,” he said.
The Energy and Policy Institute reports that 22 state commissions — including seven in the MISO footprint — have so far ordered utilities to suspend disconnections as the pandemic wears on.
Wisconsin in particular has moved proactively to gauge the economic impact of stay-at-home measures on ratepayers and utilities. The state’s Public Service Commission has opened two new dockets: one to ensure customers can continue to access service, and the other to investigate the costs utilities are incurring under the public health emergency orders. Gov. Tony Evers suspended some of the PSC’s administrative rules so public utilities can waive late fees, halt disconnections, connect residents more quickly and without cash deposits, and offer deferred payment agreements for commercial, farm and industrial customers in addition to residential customers. Utilities are beginning to warn of deferred maintenance and financial impacts. (See AEP Warns of ‘Adverse’ Effects from Coronavirus.)
Northern Indiana Public Service Co.’s Bill SeDoris said his company is checking temperatures of employees before they’re allowed into company offices. He also said NIPSCO has brought in trailers to park on-site as temporary offices for customer service representatives.
“We’re giving them more space so they’re not on top of each other,” SeDoris said.
What Lies Ahead
MISO headed into April with the manual, day-by-day load forecasting in place.
“April is a time when we have big variety in temperatures. But generally, the load is lower,” Arness said.
MISO also plans to hold a summer readiness workshop April 28. It’s not yet clear how the pandemic will affect summer operations.
MISO March load comparison | MISO
Arness emphasized that MISO needs ample warning from generators that foresee a need for conservative operations or outage rescheduling. He said MISO continued to observe an uptick in outage deferments over the past week. The RTO last month noted increased deferment of maintenance outages as utility work crews were scaled back as social distancing took hold.
“The plea here — I can’t say this often enough — is that you document the request. We’re really imploring the generation owners and operators to please keep MISO updated in terms of your plans. Please document them in writing,” Arness urged market participants, adding that the RTO needs all relevant information on changes in outage plans to navigate outage scheduling.
Jim Dauphinais, an attorney with the Coalition of Midwest Transmission Customers, asked how MISO was dealing with load-modifying resources (LMRs) that aren’t available with no personnel on-hand to lower load. He also wondered if some LMRs could even be considered deployed because they’re already shuttered because of shelter-in-place orders.
“There might be no demand reduction that would come from a MISO call since load is already reduced,” Dauphinais said, adding that the RTO should examine how LMRs in limbo could impact an emergency declaration.
Rob Benbow, MISO’s executive director of energy operations, asked all LMR owners to update their availability in the MISO Communication System. He said MISO would examine how LMRs that are temporarily unavailable or considered already deployed could impact resource adequacy.
Customized Energy Solutions’ Ted Kuhn asked if MISO is contemplating how it will best manage a return to normalcy once social distancing mandates are lifted and load picks up.
“There’s a good argument that load is going to return, but the question is will it return to those historical levels that we experienced a year ago. That’s a good question, and we’re studying it,” Arness said.
MISO will hold another Reliability Subcommittee meeting April 29, in which COVID-19 impacts will again be discussed.
“Be safe, take care of yourselves and your families,” SeDoris said before ending the call.
NERC says it is confident the electric industry is “taking aggressive steps to confront” the COVID-19 pandemic, based on responses to its recent Level 2 alert.
The alert was sent on March 10 and advised registered entities to maintain situational awareness, reinforce good personal hygiene practices, and review and update business continuity plans. (See Coronavirus, Cybersecurity Top WECC Board Discussion.) It directed recipients to inform NERC by March 20 whether their organizations:
have a written response plan that covers pandemic emergencies;
have reviewed staffing requirements and resources for critical roles in a potential pandemic emergency in North America;
anticipate being able to offer mutual aid to other industry participants involved in a pandemic emergency;
have reviewed supply chains for potential disruption of critical goods and services by a pandemic emergency; and
expect to encounter any specific additional risks to reliable and secure operations in a potential pandemic emergency.
According to a press release, risks identified by respondents include staffing and material shortages, along with delays to major construction and maintenance projects that could create constraints over the summer. The “vast majority” of registered entities reported that they either have a written response plan or are in the process of developing one, while a “large majority” have reviewed supply chain needs.
More than half said they would support mutual aid requests — which NERC CEO Jim Robb called “a key consideration” during the spring and summer storm season — and the majority said they have reviewed staffing requirements.
NERC said reliability coordinators have “generally” activated their backup control centers, isolated key workers and are maintaining deep-cleaning routines, along with participating in weekly situational awareness calls with NERC. Utilities also remain engaged with the Electricity Information Sharing and Analysis Center, which recently detailed its own COVID-19 operations summary.
Along with ordering the Level 2 alert, NERC has activated its Business Continuity Plan and shifted its upcoming meetings to conference calls or video conferences in light of safety restrictions from global health authorities and travel restrictions by many stakeholders. The organization confirmed last month that an employee in its Atlanta office had tested positive for the COVID-19 virus, though the individual had not visited the office since March 10. (See NERC Employee Tests Positive for Coronavirus.)
NERC will provide its report on industry readiness to FERC as an informational filing. The organization is also working on a comprehensive assessment of potential reliability risks and considerations from the pandemic, scheduled for release in April, that will draw on lessons learned from utilities around the world.
FERC has ruled that two merchant transmission operators in New Jersey are still liable for some cost allocations under PJM’s Regional Transmission Expansion Plan (RTEP) despite converting from firm to non-firm service after the cancellation of the “Con Ed-PSEG wheel” in 2017 (ER18-680).
In its ruling on Wednesday, FERC said despite the conversion from firm to non-firm transmission withdrawal rights (TWRs) that would limit exposure to future RTEP costs, Linden and HTP were still liable for RTEP costs previously allocated while still under their firm TWR status.
Linden VFT and Hudson Transmission Partners (HTP) own merchant transmission facilities that carried power into New York City as part of the former Con Ed-PSEG wheel, in which 1,000 MW were exported from upstate New York to PJM through Public Service Electric and Gas facilities in northern New Jersey, and then exported to the city. Consolidated Edison and PSE&G canceled the agreement in April 2017, prompting HTP and Linden to convert their firm TWRs to non-firm TWRs.
The commission had previously found that merchant transmission facilities with firm TWRs are “like loads in that they remove energy from PJM, thus requiring PJM to study deliverability of energy from the PJM system to the point of interconnection.”
PJM interpreted the December 2017 orders as directing that all allocations to Hudson and Linden cease as of Jan. 1, 2018, and proposed to pro-rate the allocations to the remaining zones. But the commission said Tuesday that the companies should only be relieved from ongoing cost allocations in Schedule 12-Appendix A, which PJM redetermines annually based on the level of firm transmission withdrawal rights. It said the companies remain liable for costs of lower-voltage facilities that use the pre-Order No. 1000 violation-based distribution factor (DFAX) method and economic projects that are allocated on the load energy payment method, which is also fixed at the time the projects are included in the RTEP.
Linden VFT’s interior | Energy Initiatives Group
“Our finding here accords with the commission’s prior holding that the merchant transmission facilities remain responsible for targeted market efficiency projects, because these calculations were not based on the level of firm transmission withdrawal, but on the basis of congestion savings,” FERC said. “The merchant transmission facilities continue to benefit from these savings regardless of whether they hold firm transmission withdrawal rights. For these reasons, we reject PJM’s proposal to reassign cost responsibility from Hudson and Linden for the economic projects identified in PJM’s compliance filing.”
FERC ordered PJM to submit a filing within 60 days correcting the allocations.
The New Jersey Board of Public Utilities had protested PJM’s filing, arguing that eliminating the RTEP allocation to HTP and Linden would “result in unduly burdensome costs on PJM customers, particularly in northern New Jersey, at a preference to New York load” and was “particularly egregious in light of the benefits retained by New York load regardless of the character of Hudson’s and Linden’s transmission rights.”
FERC ruled that the BPU’s arguments were “beyond the scope of a challenge to a compliance filing” and that they should instead be raised in a rehearing request, not a protest to the compliance filing implementing that order.
Last month, the BPU appealed FERC’s rulings on Linden and HTP’s TWRs, and the reassignment of Con Ed’s cost responsibility assignments for RTEP projects including the Bergen-Linden Corridor project, to the D.C. Circuit Court of Appeals.
Rehearing Denied
In a related ruling Tuesday, the commission rejected rehearing of its March 2018 ruling accepting PJM’s annual cost responsibility assignments for regional transmission facilities and lower-voltage facilities included in the RTEP for 2018 (ER18-579-002).
PJM transmission owners American Electric Power, Dayton Power and Light, Dominion Energy, Exelon, FirstEnergy, PPL and PSE&G challenged PJM’s decision that Linden and HTP should not have a cost assignment for Schedule 12-Appendix A projects for 2018.
“PJM transmission owners advance no argument on rehearing to explain why merchant transmission facilities must be responsible for cost allocation assignments for a year in which they hold no firm transmission withdrawal rights,” the commission said.
The commission also dismissed as moot Dominion’s rehearing request over PJM’s initial assignment of 100% of the costs of the Loudoun-Brambleton 500-kV and 230-kV lines (project b2372) to the Dominion zone.
FERC noted that PJM responded to Dominion’s original protest by conceding the utility was correct and that the project should be allocated as a regional facility needed for reliability, with 50% of costs allocated via the load-ratio share and 50% using the solution-based DFAX. PJM filed a modified allocation assigning two-thirds of the costs to the Dominion zone and one third to the APS zone, which FERC accepted in August 2018 (ER18-2028).
James Danly was sworn in as a FERC commissioner Tuesday, officially beginning a term to end in 2023 and giving Republicans a 3-1 advantage on the commission.
Danly, who had been serving as general counsel for the commission since September 2017, was sworn in by 6th U.S. Circuit Court of Appeals Judge Danny J. Boggs, for whom he once served as law clerk.
“I’m so glad to have James join my colleagues and me as a commissioner, particularly as FERC is dealing with many pressing issues related to the COVID-19 pandemic in addition to continuing the important work of the agency,” FERC Chairman Neil Chatterjee said. “The commission and the American people will benefit from Commissioner Danly’s viewpoint on the many issues that we now have before us.”
Judge Danny J. Boggs swears in former FERC General Counsel James Danly as a commissioner as his wife, Frankie, looks on. | FERC Chair Neil Chatterjee
“Welcome to FERC Commissioner James Danly! I look forward to working with him in his new capacity,” tweeted Commissioner Richard Glick, the lone Democrat.
“Congratulations to James Danly on being sworn in as a commissioner at FERC,” Commissioner Bernard McNamee tweeted. “He has been a valued adviser while general counsel and will be a great colleague on the commission.”
The U.S. Senate confirmed Danly’s nomination to the commission March 12. (See Senate Confirms Danly to FERC.) He fills a seat left open by the death of Commissioner Kevin McIntyre in January 2019. McNamee, whose term ends June 30, has said he would stay on until a replacement for his seat is confirmed or the end of the year.
To replace Danly — at least temporarily — Chatterjee named Deputy General Counsel David Morenoff as acting general counsel.
“David is a consummate professional and outstanding lawyer,” Danly said. “I have relied on his wise counsel since the beginning of my tenure at FERC. I appreciate his willingness to accept this role and am confident that he will provide much-needed continuity during these difficult times.”
FERC on Tuesday gave its blessing to the merger of Columbia Grid and Northern Tier Transmission Group to form NorthernGrid, a vast transmission planning region stretching across eight Western states (ER20-882, et al.).
The commission approved the latest revisions to the transmission tariffs filed by NorthernGrid’s seven members: PacifiCorp, NorthWestern Energy, Avista, Puget Sound Energy, Idaho Power, MATL and Portland General Electric.
All the “filing parties’ proposed tariff revisions are hereby accepted, effective April 1, 2020,” FERC wrote.
In late December, FERC had sent the latest round of proposed tariff changes back to the parties, agreeing with independent transmission developer LS Power that the utilities failed to meet Order 1000’s requirement to show the new transmission planning region would do better than the status quo. (See FERC: NorthernGrid Merger Needs More Work.)
The proposed NorthernGrid regional planning organization would consolidate the areas covered by ColumbiaGrid and Northern Tier Transmission Group. | ColumbiaGrid
FERC also said more information was needed to show the tariff revisions complied with Order 1000’s principles of openness and coordination in transmission planning.
A major sticking point raised by LS Power was that the tariff changes, as drafted, would have required developers to submit proposed projects before the regional planning process identified transmission needs.
FERC agreed. “We find that this structure deprives developers and stakeholders of a sufficient opportunity to propose solutions in response to needs identified through the regional transmission planning process,” the commission wrote, rejecting the proposal without prejudice and inviting the parties to refile after correcting deficiencies.
The parties filed their proposed revisions to their respective Open Access Transmission Tariffs on Jan. 28.
Among the changes, the parties “added a new 60-day window after posting [a regional transmission needs] draft study scope for stakeholders to submit additional data,” FERC said. The change “provides a meaningful opportunity for transmission developers to submit project proposals after enrolled party needs have been identified.”
LS Power again protested, saying the 60-day window failed to address the concerns it raised, and with which FERC agreed, before.
Puget Sound Energy, which operates the Wild Horse wind project in Washington State, is one of seven members seeking to form the NorthernGrid transmission planning region. | PSE
FERC rejected the argument, saying developers would have opportunities to propose projects in accord with Order 1000.
“We … find that the proposed regional transmission planning process complies with Order No. 1000’s requirement to conduct a regional analysis to identify whether there are more efficient or cost-effective transmission solutions to regional transmission needs,” FERC wrote.
That includes “an affirmative obligation to analyze whether such transmission solutions exist regardless of whether potential transmission solutions have been proposed by transmission developers or stakeholders,” it said.
FERC on Monday clarified that non-transmission owning members of SPP are still subject to a $50,000 deposit for if they withdraw from the RTO, rejecting environmental organizations’ complaint that the deposit constitutes a barrier to membership (EL19-11).
The organizations — Advanced Power Alliance (APA), Clean Grid Alliance, Climate + Energy Project, Natural Resources Defense Council, Sierra Club, Southern Renewable Energy Association, Sustainable FERC Project and Western Resource Advocates — filed a request for clarification in early February following FERC’s rejection of SPP’s request for rehearing of the commission’s decision to end the RTO’s exit fee for non-transmission owners. They objected to what they called the commission’s “reinstatement” of the $50,000 deposit in its December order. (See FERC Denies Rehearing of SPP Exit Fee Decision.)
FERC reminded the groups that it had ruled that non-TOs “should only be exempt from paying a share of SPP’s long-term financial obligations, rather than all existing obligations associated with membership withdrawal.” The deposit represents the costs SPP would incur to process a member’s withdrawal from the RTO, while the fee represents the sum of the withdrawing member’s share of SPP’s outstanding long-term financial obligations and its obligations at the time of withdrawal, including any unpaid dues or assessments.
The commission also rejected their arguments that the deposit requirement represents a barrier to membership and is unjust and unreasonable. FERC also said the groups missed the 30-day deadline following a commission decision to file a request for rehearing and ruled their motion as a late-filed request.
APA and the American Wind Energy Association filed the initial successful complaint that resulted in FERC last April ordering SPP to end charging an exit fee for members that are not TOs or load-serving entities. (See FERC Tells SPP to End Exit Fee for Non-TOs.) SPP had estimated the fee could amount to as much as $630,000 for entities without load.
In December, FERC rejected a rehearing request by SPP and its LSEs, along with the RTO’s proposal to lower the exit fee to $100,000. It ordered the grid operator to submit another proposal “that adequately explains” why the exit fee for non-TOs is just and reasonable and “not a barrier to membership … and not excessive as a means of ensuring stability in membership and members’ financial commitment.”
MISO is stepping up efforts to understand how its markets will function with the possible participation of heavy concentrations of distributed energy resources.
The RTO is researching how to manage DER aggregators in its market, DER Program Director Kristin Swenson said during a joint workshop between MISO and the Organization of MISO States (OMS) on Tuesday.
The workshop was held over telephone — rather than in person — because of the COVID-19 pandemic.
“I’m leading a virtual MISO stakeholder workshop upstairs while my wife leads a virtual yoga class downstairs. A lot of ‘virtuality’ these days,” MISO Managing Assistant General Counsel Michael Kessler remarked as he began his presentation.
Swenson said the MISO market platform’s computational abilities cannot handle the addition of several thousand small, distributed resources. She also noted that broad DER aggregation across multiple nodes is difficult to manage from an operations standpoint. The RTO may be unable to handle some issues if it doesn’t precisely know the physical location of some aggregated resources, she said.
“You may not be able to solve the transmission or reliability issues without visibility from an aggregator,” Swensen explained. “That’s what we call the DER balance problem.”
Hoosier Energy Power Network Solar Power Plant in Bloomington, Ind. | Inovateus-Solar
MISO last held a DER workshop in February, in which it focused on transmission planning challenges as the distribution system takes on more generating resources. (See MISO Mapping Out DER Challenges, Benefits.)
Energy storage may assist in the balancing act. FERC Order 841 mandated RTOs facilitate participation for storage resources over 100 kW located on distribution systems. In response, MISO created a contract in its Tariff to coordinate with distribution utilities that host storage resources.
But a legal challenge to Order 841 is currently pending before the D.C. Circuit Court of Appeals. Opponents of the order, which include the National Association of Regulatory Utility Commissioners and traditional utilities, are suing to block FERC’s ability to mandate DER participation in wholesale markets and seeking an opt-out mechanism for states.
“We’re still waiting to see what the states’ authority will be and what FERC’s jurisdiction will be over storage resources located on the distribution system participating in wholesale markets,” Kessler said.
In addition, FERC’s 2016 Notice of Proposed Rulemaking on the participation of DER aggregation in wholesale markets is still outstanding.
Working Through the Tension
Swenson said MISO’s work with OMS on DERs began in preparation for a federal rulemaking on DER participation.
OMS Executive Director Marcus Hawkins said the increasingly blurred lines between state and federal jurisdiction “has created tension.” He said a DER participation model must respect the “primarily vertically integrated nature of the MISO footprint.”
“Whatever the eventual market model is, it should reflect that fact,” Hawkins said.
Hawkins said a significant number of aggregators selling at the wholesale level could disrupt state-jurisdictional resource adequacy planning.
“There’s just a lot of coordination required when a DER wants to participate in the wholesale market,” Hawkins said, adding that OMS wants to avoid double-counting when a resource on the distribution system participates at both the wholesale and retail levels. However, he said MISO, utilities and states should not all rush to invest in technology that’s ultimately “redundant” in order to gain visibility into DER operations.
“We’ve been fighting against wasteful technology to do that,” Hawkins said.
Swenson said MISO will survey members in mid-April on how they currently communicate with DERs, what investments they have made to improve communications and what approaches they would recommended.
“We’re trying to get a good impression of where folks are in communicating with DERs as MISO prepares to communicate with more resources. Where should MISO be focusing?” Swenson said.
Swenson stressed that the new survey is separate from the annual OMS survey on DER totals in MISO.
Independent Market Monitor staffer Michael Chiasson said the monitoring of DERs isn’t a concern for now. DERs and demand response “typically lack the size and concentration needed to have significant market power,” he said.
However, Chiasson noted, DERs could help lessen the market power wielded by large, traditional generators in load pockets constrained by transmission limitations.
“It’s a good structural thing to have more market participants,” Chiasson said.
Chiasson said if the Monitor eventually discovers that DERs could exercise market power, it could propose to FERC under Federal Power Act Section 205 to adjust the application of market mitigation.
“A lot of market rules evolved that way,” Chiasson said.
