FERC on Thursday approved NERC’s revised geomagnetic disturbance 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).
NERC created Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) in response to FERC’s directives to improve how its initial GMD standard, approved in 2016, addressed the risks from “locally enhanced” events. (See FERC Pushes NERC Further on GMD Rules.)
GMD storm in Fairbanks, Alaska, April 2011 | NASA
Thursday’s order (Order 851) directed NERC to revise the standard further to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans. The commission also accepted NERC’s revised GMD research work plan.
‘Supplemental’ GMD Events
GMDs occur when the sun ejects charged particles that cause changes in Earth’s magnetic fields, potentially causing geomagnetically induced currents (GIC) that can cause voltage instability or collapse, damaging connected equipment.
NERC’s original standard required applicable entities — planning coordinators, transmission planners, transmission owners and generation owners connected at 200 kV or higher — to assess the vulnerability of their transmission systems to a “benchmark GMD event.” The benchmark was defined as a one-in-100-year event that would cause an 8-V/km “reference peak geoelectric field amplitude” at 60 degrees north geomagnetic latitude using Quebec’s ground conductivity.
Entities that fail to meet certain performance requirements based on the results of the benchmark assessment must implement corrective action plans.
Potential impacts of geomagnetic disturbances on the transmission system | PJM
The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. Going forward, entities will have to conduct vulnerability and thermal impact assessments on “supplemental” events.
NERC defined the supplemental GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability. The supplemental GMD event definition contains a higher, non-spatially averaged reference peak geoelectric field amplitude component than the benchmark event definition (12 V/km versus 8 V/km).
The new rule also requires the collection of GIC monitoring and magnetometer data and adds a one-year deadline for the completion of corrective action plans and two- and four-year deadlines for completing mitigation involving non-hardware and hardware, respectively.
Case-by-Case Review
NERC had proposed allowing entities to exceed deadlines for corrective actions when “situations beyond the control of the responsible entity [arise],” which FERC said was inconsistent with its prior directive that extensions be considered on a case-by-case basis.
“While we generally agree with the standard of review that NERC states it will use to assess the merits of extension requests, we conclude that such assessments should be made before any time extensions are permitted,” the commission said. “By requiring prior approval of extension requests, the modified reliability standard will limit the potential for unwarranted delays in implementing corrective action plans while also providing NERC with an advance and more holistic understanding of where, to whom and for how long extensions are granted.”
Additional Directives
FERC said NERC did not go far enough in the revised standard, which requires entities to assess supplemental GMD event vulnerabilities but not to implement corrective action plans to address them. NERC would have required entities only to make “an evaluation of possible actions to reduce the likelihood or mitigate the consequences and adverse impacts of the events if a supplemental GMD event is assessed to result in cascading.”
FERC disagreed with commenters who said requiring corrective action plans is premature. “We see no basis, technical or otherwise, for not requiring corrective action plans for assessed supplemental GMD event vulnerabilities,” the commission said.
The rule is effective 60 days after publication in the Federal Register.
The Organization of MISO States is now accepting applicants for a new executive director to replace Tanya Paslawski, who will depart the organization at the end of the year. (See OMS Executive Director to Exit.)
OMS office space in Des Moines | Terrus Real Estate
OMS said it is seeking a candidate with “extensive understanding of federal and state energy industry regulatory matters and experience leading teams with diverse perspectives.” The executive director takes direction from the board of directors to execute the group’s strategy on energy industry issues.
“We’re looking for someone who is driven, dynamic and skilled at achieving consensus outcomes. Experience with organization administration and boards of directors a plus,” Colleen Dougherty, OMS Office Manager, said in a press release.
Resumes will be accepted through Dec. 3 and should be emailed to Dougherty at colleen@misostates.org. OMS is headquartered in downtown Des Moines, Iowa.
OMS members recognized Paslawski’s four years of work at the group’s Nov. 13 meeting.
“You were the right person at the right time,” Michigan Public Service Commission Chair Sally Talberg told Paslawski, praising her “great skill and vision.” Talberg said Paslawski took over OMS when it was a startup in its teenage years and helped transform it into a serious organization. Paslawski thanked OMS members for the opportunity to serve them.
In 2019, OMS will continue its longstanding focus on policy around distributed energy resources. The organization is working with MISO to create stakeholder forums to discuss DER issues. Stakeholder workshops on DER should begin in early 2019, OMS Director of Member Services Marcus Hawkins said.
WASHINGTON — Senate Democrats on Thursday pressed President Trump’s FERC nominee to recuse himself from the commission’s ongoing proceeding on resilience because of his role in crafting a controversial Energy Department proposal.
Bernard McNamee, executive director of DOE’s Office of Policy, told the Senate Energy and Natural Resources Committee that he would “clearly” be unable to rule on the department’s already rebuffed Notice of Proposed Rulemaking for FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel. But he was less direct about whether he would rule on any other proceedings stemming from the NOPR.
McNamee worked on the NOPR as the department’s deputy general counsel for energy policy. After the commission unanimously rejected the NOPR in January and opened its own docket to explore how “resilience” is defined, McNamee left DOE to become the director of the Texas Public Policy Foundation’s Center for Tenth Amendment Action and Life: Powered initiatives, the latter described as a project to “reframe the national discussion” about fossil fuels. (See Trump Nominates DOE’s McNamee to FERC.) He returned to the department in his current role in June.
Sen. Catherine Cortez Masto (D-Nev.) asked McNamee whether he would recuse himself “from any issue related to the grid resiliency proposal.” McNamee responded, “I understand that the docket in which that proposal was offered has been closed, and I need to consult with ethics counsel about whether or not I could further participate in the issues. …
“The issue of resilience is constantly coming before FERC, and so I need to consult with ethics counsel to understand what I could or could not participate in,” he said.
Sen. Angus King, an independent from Maine who caucuses with the Democrats, picked up this line of questioning later in the hearing.
“I’m surprised you didn’t give a direct answer to Sen. Cortez Masto,” King said before quoting the section of the U.S. Code concerning recusals. “I don’t understand any argument where you would have to consult any counsel anywhere on Earth to understand that you have a conflict of interest when it comes to this issue of this so-called Grid Resiliency Pricing Rule, or any version thereof.” King asked again whether McNamee would recuse himself.
McNamee responded: “I believe that the statute that you read refers to a specific proceeding, and I would want to talk with counsel or ethics advisers…”
King interrupted him, noting the law says “‘expressed an opinion concerning the merits of the particular case in controversy.’ You have clearly expressed opinions on the merits of this issue repeatedly and in fact before this committee.”
McNamee said it would depend on what specific issue came before the commission and again said he would consult ethics advisers.
“I’m surprised and disappointed that you feel that you have to consult with counsel on something that’s so clear,” King replied.
After lambasting the NOPR, Sen. Ron Wyden (D-Ore.) said McNamee’s nomination wasn’t “like the fox guarding the chicken coop. This is like putting the fox inside the chicken coop.”
“I think that FERC has a tradition of making decisions, not based on whether they’re Republican or Democrat though they may be nominated as such, but making them based on working together and what’s the right thing to do, and my pledge to you is that I will work in that fashion,” McNamee responded.
“I believe you ought to recuse yourself, if you are [confirmed], on matters that deal with the specifics of what got such a resoundingly negative response earlier,” Wyden replied.
Most of the two-hour-plus hearing was not devoted to McNamee, as the committee also considered the nominations of Rita Baranwal and Raymond David Vela, Trump’s nominees to be DOE’s assistant secretary of nuclear energy and director of the National Park Service, respectively.
Committee Chair Lisa Murkowski (R-Alaska) said she plans to advance the nominees to the Senate floor shortly after Thanksgiving so they can be confirmed before the current Congress adjourns at the end of the year. If they are not voted on by then, Trump would need to resubmit them next year.
“I really don’t want to see all the good effort that this committee has put into advancing these nominees fall by the wayside,” she said, addressing committee members. “So I would ask that you all work with me to clear the nominations in [our] jurisdiction before the end of the year.”
McNamee told the committee that he understood the importance of FERC’s independent, apolitical status, and the difference between his work at DOE and the role of commissioner.
“If confirmed, I commit that I will be a fair, objective and impartial arbiter in the cases and issues that would confront me as a commissioner,” he said in his opening statement. “My decisions will be based on the law and the facts, not politics. And I don’t just say this because I’m trying to get your vote; it’s something I believe.”
King and Sen. Tina Smith (D-Minn.) quoted from an op-ed McNamee wrote for The Hill in April: “Some suggest that we can replace fossil fuels with renewable resources to meet our needs, but they never explain how.”
“As I am grappling with your ability to be a neutral arbiter of the facts and this very important role at FERC, can you just explain to me how you would do that given what appears to me to be a bias?” Smith asked.
McNamee pointed to his time as an energy lawyer with Virginia-based McGuireWoods, during which he said he helped get three utility-scale solar facilities built in the state. He also said he worked on Virginia’s and North Carolina’s renewable portfolio standards.
“So I understand the role that renewables can play in our electric mix,” he said. But “I think the primary thing for FERC is to make sure that they’re not picking and choosing what the resources should be but ensuring that the markets are able to function so that resources can compete and that the market decides what’s the right resource.”
But McNamee also dodged efforts by coal-state senators — Joe Manchin (D-W.Va.), John Barrasso (R-Wyo.) and John Hoeven (R-N.D.) — to get him to tout the importance of coal-fired plants to reliability.
He also distanced himself from Trump’s June 1 order to Energy Secretary Rick Perry to prevent further coal and nuclear plant closures under both Federal Power Act Section 202c and the Defense Production Act of 1950. (See Trump Orders Coal, Nuke Bailout, Citing National Security.) Asked by Sen. Martin Heinrich (D-N.M.) whether he believed that there was an urgent threat to the grid, McNamee said, “The secretary currently has not issued a 202c, and I have no reason to second-guess his determination about whether or not there is an emergency currently. And it does not appear at this point on a general, nationwide basis that there’s an emergency.”
“So that would be a ‘no’?” Heinrich asked.
“It’s only a ‘no’ in that I don’t have access to all the information the secretary does,” McNamee replied.
The status of Trump’s order with DOE is unknown; reports surfaced last month that the department has tabled it in the face of free-market conservative backlash. Its details are only known through a memo that was leaked in May. When asked about it by Heinrich, McNamee said he was not with the department when the memo was drafted. “My understanding is that it’s in the intergovernmental process. I’ve not been involved in that process for the past few months.”
Speaking to reporters after the hearing, Murkowski said she was satisfied with McNamee’s responses regarding the NOPR. “What I took away was that his role when he was at the Department of Energy was to take the secretary’s directive and to draft that policy. His role at the FERC would be different than that, and I would expect that he would respect those lanes.
“As far as the recusal issue goes, I think it is appropriate that he would consult with counsel. He stated clearly that that case he had worked on … has been closed down. So if it is a question as to that, then it seems to me you’ve got a recusal issue going on. But if it’s a question as to something else that spins off from it, is it something that would require a recusal? I think that’s where you get your lawyers in there, and you make clear one way or another. And he said he would follow that guidance, which is the appropriate course.”
FERC moved Thursday to apply its proposed new methodology for calculating transmission owners’ return on equity rates to dockets in MISO and the South.
The commission’s directives mirror its Oct. 16 order in a case involving the New England Transmission Owners (NETOs), in which it solicited briefs on its plan to consider other metrics in addition to the discounted cash flow (DCF) model it has relied on since the 1980s.
As in the Oct. 16 “briefing order,” the commission ordered parties in ROE litigation over MISO’s TOs to submit briefs in a paper hearing (EL14-12-003, EL15-45).
Separately, the commission also approved an order providing guidance on how the new methodology should be applied to seven pending ROE proceedings involving units of Entergy, American Electric Power, Southern Co. and others (EL17-41-001 et al.).
FERC has proposed giving equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)
FERC said the discounted cash flow methodology produced lower ROEs than the three other models for the four test periods at issue in the New England Transmission Owners’ proceeding. | FERC
Remand
The commission announced its new policy last month in response to the D.C. Circuit Court of Appeals’ April 2017 ruling vacating its 2014 order on the NETOs’ rates. The court said FERC failed to meet its burden of proof in declaring the NETOs’ existing rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
FERC said it would use three of the models — the DCF, CAPM and expected earnings — to establish a composite zone of reasonableness that will determine whether it accepts or dismisses ROE complaints. (The risk premium model results in a single number and cannot produce a range of rates.)
Zone of reasonableness quartiles | FERC
“Under this approach, we would dismiss an ROE complaint if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile unless that presumption is sufficiently rebutted,” the commission said.
When a complaint is warranted, FERC would base any subsequent rate on the average of the results from each of the four models.
The first of two complaints over the MISO TOs’ rates was filed for the period Nov. 12, 2013, through Feb. 11, 2015. Under the new formula, averaging the result of the risk premium analysis (10.36%) with the midpoints of the DCF (9.29%), the CAPM analysis (10.06%) and the expected earnings analysis (11.41%) results in a preliminary base ROE of 10.28%, with the incentive-based total ROE capped at 13.06%.
If the commission’s revised methodology calculation prevails, it said it will order refunds of amounts collected in excess of 10.28%.
The MISO TOs include units of Ameren, American Transmission Co., Entergy, Indianapolis Power & Light, MidAmerican Energy and ITC Holdings. A second challenge to their 12.38% rate was filed in February 2015, with complainants arguing the base ROE should be no higher than 8.67%.
FERC said parties in the case must submit briefs within 60 days on whether its proposed revisions should apply and, if so, how.
Guidance in Other Dockets
In addition, the commission told litigants in seven other ROE dockets they should address its proposed new methodology in their proceedings.
“We do not believe that allowing participants to address the briefing order’s proposed new methodology in their ongoing proceedings, and continuing those proceedings without abeyance on that basis, will result in wasted time and resources because we believe that continuing with settlement discussions or hearing procedures will move those proceedings closer to resolution,” the commission wrote.
“In addition, these ongoing proceedings involve issues of material fact that the commission determined would be more appropriately addressed in hearing and settlement judge procedures, and the briefing order’s proposed new base ROE methodology does not change that determination. While the issues of material fact to be addressed are expanded with the inclusion of the three additional financial models, the most effective procedures for addressing base ROE issues continue to be the ongoing hearing and settlement proceedings.”
FERC Chair Neil Chatterjee said he hoped the commission’s new policies will reduce delays and “pancaked” rate complaints. He noted that one of the pending complaints has been awaiting resolution for more than five years.
“This means that transmission owners still don’t know what they made in 2013, and consumers still face uncertainty about their bills,” he said.
FERC would no longer review mergers valued at less than $10 million under a Notice of Proposed Rulemaking (NOPR) approved Thursday (RM19-4). The NOPR would implement congressional direction under an amendment to Section 203 of the Federal Power Act.
“The commission interprets the amendment … as establishing a $10 million threshold, but not removing the commission’s jurisdiction to review transactions with a higher value that involve a public utility’s acquisition of facilities from non-public utilities if those facilities will be subject to the commission’s jurisdiction after the transaction is consummated,” FERC said.
| 123rf
The NOPR also would require mergers or consolidations by public utilities valued above $1 million to notify the commission of the transactions.
“Although the [smaller] transactions … are unlikely to present concerns under the commission’s public interest analysis and public utilities entering into these transactions are not required to secure an order of the commission … the information the commission proposes to require in the notification filing will allow the commission to collect information about the transaction should a question arise related to the underlying facilities and the commission’s oversight under the Federal Power Act,” FERC said.
“This may seem like just a simple legislative change, but its impact in relieving administrative burdens on regulated entities is significant,” said Chairman Neil Chatterjee.
Comments on the NOPR will be due 30 days after its publication in the Federal Register.
Transmission owners will be required to reduce their rates to reflect reduced corporate income taxes under a Notice of Proposed Rulemaking approved by FERC Thursday (RM19-5).
The NOPR is a response to the December 2017 Tax Cuts and Jobs Act, which cut maximum corporate income tax rates to 21% from 35%.
Senate Majority Leader Mitch McConnell, House Speaker Paul Ryan and Vice President Mike Pence celebrated the passage of the corporate tax cut with President Trump in November 2017. | The White House
It would require public utility transmission providers with rates under an Open Access Transmission Tariff, a transmission owner tariff or a rate schedule to modify the accumulated deferred income taxes (ADIT) incorporated in their rates. ADIT is used to account for timing differences between the computation of taxable income for reporting to the IRS and that used for regulatory accounting and ratemaking.
TOs with formula rates would be required to deduct excess ADIT from their rate bases and complete a new worksheet annually to track ADIT. Utilities with stated rates would be required to return any excess ADIT to customers.
In related actions, FERC also:
Issued a policy statement providing guidance on how other FERC-jurisdictional public utilities, natural gas pipelines and oil pipelines handle the accounting and ratemaking treatment of ADIT (PL19-2).
Approved Edison Electric Institute’s request for accounting guidance on recording a reclassification of any stranded tax effects from the law (AC18-59).
Acted on 46 of the Federal Power Act Section 206 show-cause investigations initiated in March, when the commission directed utilities whose transmission tariffs reference tax rates of 35% to reduce the rates to 21% or show why they did not need to do so.
Accepted three interstate natural gas pipeline rate reductions and one settlement in response to Order 849, which requires pipelines to provide a one-time report estimating their returns on equity before and after the new tax law and changes to the commission’s tax allowance policies. The rate reductions involved Millennium Pipeline Co. (RP19-65), North Baja Pipeline (RP19-71) and Vector Pipeline (RP19-60).
Commissioner Richard Glick said he was troubled by a clause in the settlement with Kern River Gas Transmission (RP19-55) that would undo its rate reduction if FERC initiates a rate proceeding in the future under Section 5 of the Natural Gas Act.
“In my opinion, Kern River in this settlement is essentially holding the commission hostage,” Glick said. “What I think this really highlights is the fact that the Natural Gas Act doesn’t have a refund provision like the Federal Power Act does. So, again, I want to call on Congress to add a refund provision to the Natural Gas Act which mirrors the refund provision in the Federal Power Act so that we can ensure that consumers are protected.”
Comments on the NOPR will be due 30 days after date of publication in the Federal Register.
FERC on Thursday approved NERC’s revised geomagnetic disturbance 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).
NERC created Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) in response to FERC’s directives to improve how its initial GMD standard, approved in 2016, addressed the risks from “locally enhanced” events. (See FERC Pushes NERC Further on GMD Rules.)
Thursday’s order (Order 851) directed NERC to revise the standard further to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans. The commission also accepted NERC’s revised GMD research work plan.
‘Supplemental’ GMD Events
GMDs occur when the sun ejects charged particles that cause changes in Earth’s magnetic fields, potentially causing geomagnetically induced currents (GIC) that can cause voltage instability or collapse, damaging connected equipment.
NERC’s original standard required applicable entities — planning coordinators, transmission planners, transmission owners and generation owners connected at 200 kV or higher — to assess the vulnerability of their transmission systems to a “benchmark GMD event.” The benchmark was defined as a one-in-100-year event that would cause an 8-V/km “reference peak geoelectric field amplitude” at 60 degrees north geomagnetic latitude using Quebec’s ground conductivity.
Entities that fail to meet certain performance requirements based on the results of the benchmark assessment must implement corrective action plans.
The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. Going forward, entities will have to conduct vulnerability and thermal impact assessments on “supplemental” events.
NERC defined the supplemental GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability. The supplemental GMD event definition contains a higher, non-spatially averaged reference peak geoelectric field amplitude component than the benchmark event definition (12 V/km versus 8 V/km).
The new rule also requires the collection of GIC monitoring and magnetometer data and adds a one-year deadline for the completion of corrective action plans and two- and four-year deadlines for completing mitigation involving non-hardware and hardware, respectively.
GMD storm in Fairbanks, Alaska, April 2011 | NASA
Case-by-Case Review
NERC had proposed allowing entities to exceed deadlines for corrective actions when “situations beyond the control of the responsible entity [arise],” which FERC said was inconsistent with its prior directive that extensions be considered on a case-by-case basis.
“While we generally agree with the standard of review that NERC states it will use to assess the merits of extension requests, we conclude that such assessments should be made before any time extensions are permitted,” the commission said. “By requiring prior approval of extension requests, the modified reliability standard will limit the potential for unwarranted delays in implementing corrective action plans while also providing NERC with an advance and more holistic understanding of where, to whom and for how long extensions are granted.”
Additional Directives
FERC said NERC did not go far enough in the revised standard, which requires entities to assess supplemental GMD event vulnerabilities but not to implement corrective action plans to address them. NERC would have required entities only to make “an evaluation of possible actions to reduce the likelihood or mitigate the consequences and adverse impacts of the events if a supplemental GMD event is assessed to result in cascading.”
FERC disagreed with commenters who said requiring corrective action plans is premature. “We see no basis, technical or otherwise, for not requiring corrective action plans for assessed supplemental GMD event vulnerabilities,” the commission said.
The rule is effective 60 days after publication in the Federal Register.
CAISO cleared a big hurdle in its nearly yearlong sprint to become the primary reliability coordinator (RC) in the Western Interconnection as FERC approved a set of Tariff revisions covering the ISO’s new services.
“Today we’ve got some good news from FERC in terms of our ability to move forward,” CAISO Regional Integration Director Phil Pettingill told a meeting of the ISO’s Board of Governors after the order was issued Wednesday.
Pettingill said the FERC order will allow the ISO to start signing binding agreements to provide RC services with two dozen entities across the Western Interconnection. About 72% of the region’s load is now poised to sign on with CAISO, compared with 12% for SPP. BC Hydro is proceeding with plans to stand up RC services for its own territory in British Columbia, representing about 7% of load in the area overseen by the Western Electricity Coordinating Council. (See CAISO RC Wins Most of the West.)
The Tariff revisons approved by FERC create a new section containing CAISO’s RC provisions while also providing a pro forma service agreement and designating a rate schedule to implement service charges (ER18-2366). The commission’s approval of the service agreement means CAISO can begin onboarding RC customers starting Thursday.
CAISO’s filing spelled out the functions applicable to an RC under NERC reliability standards, including providing outage coordination; performing operations planning analyses; conducting real-time assessments; monitoring and wide-area situational awareness; administering a system operating limit methodology; approving system restoration plans and facilitating system restoration drills; and issuing operating instructions to RC customers regarding their monitored facilities.
CAISO will also offer optional services such as hosted advanced network applications for a one-time charge of $35,000 to $70,000 (depending on the number of takers) and physical security reviews.
CAISO will shadow Peak Reliability as it readies to take over RC services in much of the West by the end of 2019. | CAISO
In approving CAISO’s RC provisions, FERC rejected protests by some market participants over the ISO’s proposal to assess volumetric service charges on generation-only balancing authorities.
The protesters, which include Avangrid, Calpine and Gridforce Energy Management, contended that the ISO’s charge, which will be based on annual net generation (NG) rather than net energy for load (NEL), deviates from commission precedent for allocating reliability-associated costs. They argue that an NG-based methodology is unjust and unreasonable because it double charges end users for energy produced in generation-only balancing areas. Peak Reliability currently charges such BAs based on NEL, which translates into minimum assessment rather than a volumetric charge.
“In effect, protesters argue that CAISO will assess a transaction that is sourced from a generation-only balancing authority reliability costs both for its exports from a generation-only balancing authority and its imports to a traditional balancing authority,” the commission noted.
The protesters further contended the NG methodology violates cost-causation principles because generation-only BAs require less RC service than BAs with load. They said CAISO had performed no analysis on the relative level of oversight costs for either type of BA.
But FERC sided with CAISO on the issue, saying neither the Federal Power Act nor commission precedent dictate a just and reasonable rate methodology for RC service. The commission also determined that CAISO’s proposed allocation methodology will not result in double-charging.
The commission also rejected the contention the ISO’s approach violates cost-causation principles, noting that none of the protesters argued that generation-only BAs do not require or benefit from RC services.
“Rather, protesters assert that CAISO has not justified charging them a rate that they assert will be significantly higher than the rate charged by Peak Reliability,” the commission wrote. “Moreover, protesters argue that the RC services required for generation-only balancing authorities are substantially less burdensome as compared to those of a traditional balancing authority with load. CAISO, however, specifically identifies core services that an RC provides and explains that traditional balancing authorities and generation-only balancing authorities all use the vast majority of these core services.”
While FERC’s decision is significant, CAISO’s RC effort is still subject to WECC and NERC certification next year. Still, CAISO is poised to lead the way in effort to fill the void being left by Peak.
Pettingill told Wednesday’s board meeting that the ISO had been holding roundtable meetings with SPP, the Alberta Electric System Operator, BC Hydro and Peak to coordinate the transition to a post-Peak West. When the question arose as to who will manage the Western system model, he said, roundtable participants decided it should be CAISO.
The ISO also intends to hold a series of public meetings to address concerns, either quarterly or “as many as needed,” he said.
FERC has accepted CAISO’s revised proposal to protect electricity ratepayers from funding shortfalls in the ISO’s congestion revenue rights market.
CRR holders will be paid for their entitlements “only to the extent the CAISO collects sufficient revenue through day-ahead market congestion revenues and other sources to fund those entitlements,” the commission said in its Nov. 9 decision (ER19-26).
“We agree with CAISO that the proposal reasonably distributes the burden resulting from congestion revenue insufficiency and will help improve the revenue insufficiency and auction revenue shortfall,” FERC said. “Rather than relying solely on LSEs to make whole CRR holders in the event those obligations are revenue insufficient, CAISO’s proposal distributes the burden to all CRR holders.”
CAISO filed its proposed revisions Oct. 1 after FERC rejected an earlier plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges. In rejecting the earlier plan, the commission objected to how the ISO would treat counterflow and prevailing-flow CRRs differently (ER18-2034). (See CAISO Modifies CRR Plan, Seeks Quick Approval.)
The ISO acknowledged that its revised proposal relies on “essentially the same methodology” found in its prior proposal, with one “important” modification: a provision to net CRRs with both prevailing-flow and counterflow CRRs within a holder’s portfolio before scaling the payment to that holder.
CAISO said the trend of CRR revenue insufficiency has persisted into this year despite a recent uptick in congestion rents because of unusually high flow patterns. | CAISO
CAISO also noted in its revised filing that CRR revenue shortfalls have continued into this year, and it urged the commission to quickly approve the revised plan to relieve ratepayers from paying costs for fully funding CRRs in 2019. The ISO’s Department of Market Monitoring has estimated that the shortfalls — which are allocated based on power consumption — cost California ratepayers about $100 million a year.
In ruling for CAISO, the commission rejected protests by the Western Power Trading Forum, which argued that the ISO’s stakeholder process on the revisions had been rushed and that they did not fully address FERC’s concerns on symmetry.
The commission also found that CAISO’s plan would curtail a commonly used strategy to exploit market loopholes.
“CAISO’s constraint-specific approach … discourages strategies that attempt to exploit differences between the CRR model and the day-ahead market,” it said. “Under CAISO’s current CRR process, congestion revenue insufficiency and the auction revenue shortfall can be driven by market participants purchasing CRRs over constraints that appear to be nonbinding in the CRR auction but are actually binding in the day-ahead market.
“According to CAISO’s analysis, this practice has been a driver of both revenue insufficiency and the auction revenue shortfall. Under CAISO’s proposal here, if there is a substantial difference between the CRR model and the day-ahead market such that the payments due to CRR holders vastly outstrip the available congestion revenues, then payments to CRRs will be scaled, making the strategy potentially less viable.”
FERC clarified Tuesday that rehearing requests on its April 19 order revising its pro forma large generator interconnection procedures did not affect transmission operators’ compliance obligations spelled out in the order (RM17-8-002).
The order required transmission providers to submit compliance filings adopting the rule’s requirements as revisions to their large generator interconnection procedures (LGIP) and large generator interconnection agreements (LGIA) within 90 days of the publication.
Blue Canyon wind farm | EDP Renewables
On June 18, however, the commission issued a procedural order giving itself more time to consider about 20 rehearing requests on the rulemaking. On Oct. 3, the Office of the Secretary issued a notice granting a motion by the Edison Electric Institute to delay the compliance filings until 90 days after the commission rules on rehearing.
The American Wind Energy Association challenged the secretary’s notice, arguing that extending the deadline for compliance filings was a departure from commission precedent that rehearing requests do not stay commission orders. AWEA said the extension notice effectively stays Order 845 “indefinitely until a rehearing request is issued.”
But the commission said the extension notice “does not change or stay Order No. 845’s effective date, but simply extends the date that compliance filings are due.”
Order 845 adopted all but four of 14 potential rule changes in the commission’s December 2016 Notice of Proposed Rulemaking revising the pro forma LGIP and LGIA. The rulemaking, which was prompted by AWEA’s complaint over backlogs in interconnection queues, applies to generators larger than 20 MW.
