MISO now has a fifth wintertime waiver of its $1,000/MWh offer cap in hand after FERC approved the RTO’s request on Nov. 16 (ER19-27).
The commission allowed a waiver with conditions identical to the last four. (See FERC Grants MISO 4th Winter Offer Cap Waiver.) The waiver is effective from Dec. 1 through April 30, 2019.
Consumers Energy crews this year | Consumers Energy
“MISO’s experiences during the 2014 polar vortex, as well as the cold weather events of January 2018, demonstrate that fuel costs can increase to a level such that the current $1,000/MWh offer cap prevents resources from submitting incremental energy offers that reflect their marginal production costs. If similar weather and natural gas supply conditions materialize in the 2018/2019 winter, some resources could face the untenable position of being forced to offer electricity at levels below their actual cost,” FERC said.
Last winter, MISO experienced extreme cold in its North subregion starting Dec. 27, with frigid temperatures hitting the entire footprint Jan. 1 to 6. In all, MISO said the cold snap lasted longer than the 2014 polar vortex. Less than two weeks later, MISO South faced another cold snap. The event is the subject of a joint FERC/NERC investigation, which was announced in early fall. (See FERC, NERC to Probe January Outages in MISO South.)
While MISO said published gas index prices did not hit the $67/MMBtu experienced during the polar vortex, “there were a few resources during late December 2017 that offered within a dollar of the $1,000/MWh energy offer price cap due to high intraday prices for procuring non-firm gas.” The RTO said its ongoing coordination work with neighboring balancing authorities and a lower outage rate kept prices below 2014 levels.
However, MISO said its fourth waiver was helpful in that it granted generator operators peace of mind that they could have recovered costs that inched above $1,000/MWh.
MISO has until Oct. 1, 2020, to implement a $2,000/MWh hard cap for verified cost-based incremental energy offers. (See MISO Granted Longer Deadline for Offer Caps.) The RTO is all but certain to request another offer cap waiver for the 2019/20 winter.
Entergy Arkansas crews in winter | Entergy
“After implementing the reforms required by Order No. 831, MISO will no longer require temporary waivers because these reforms are intended to provide for a long-term solution to the issues associated with MISO’s offer cap,” the commission said.
In its request for this year’s waiver, MISO said it couldn’t yet tell whether 2014-style price spikes could occur during the 2018/19 winter months.
This year, MISO is using forecasts of a warmer-than-normal winter in much of its footprint, though the RTO says it’s prepping for a 40% possibility of entering emergency procedures at least once during the season. (See MISO Foresees Manageable 2018/19 Winter.)
PJM’s highly anticipated re-evaluation of its largest-ever congestion-reducing transmission project reiterated staff’s analysis that the project’s economic benefits to the region exceed its costs.
The $366.17 million project proposed by Transource Energy — the Independence Energy Connection — would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border. One line would run between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; the other would run between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | PJM
The RTO published its findings in a white paper released Thursday that showed a final benefit-cost ratio of 1.4, down slightly from the 1.42 staff reported at the September meeting of the Transmission Expansion Advisory Committee.
The slight decrease is attributable to a roughly $8 million increase in the project’s 15-year annual revenue requirement to $505.85 million. The benefit — measured in decreased load costs — held steady at $707.29 million. The actual estimated project costs increased from $366.17 million at the TEAC meeting to $372.2 million in the white paper.
The 1.4 ratio is still higher than the previous 1.32 evaluation from February and well above the RTO’s 1.25 threshold to consider projects. The current analysis shows that without the project, reliability violations will materialize as early as 2023 on three 115-kV lines in Adams County, Pa., the 500-kV Peach Bottom-Conastone line and the 500/230-kV transformer at Three Mile Island.
The project will also increase the ability to import power into the Baltimore Gas and Electric locational deliverability area.
Opposition
Residents of the region where the lines are planned attended the September TEAC meeting to register their objections, but staff pointed them toward the ongoing project proceedings being held in both states. (See PJM Redirects Residents’ Protests of Tx Project to States.)
The inclusion of newly identified reliability benefits has done little to sway the residents’ opposition, who believe it’s a ploy to avert the project’s potential failure at the state level.
“Faced with near certain failure, PJM is trying to reposition the IEC as a reliability project,” Pennsylvania resident Barron Shaw wrote in a recent blog post. “This is a desperate assertion made by an organization that has no credibility remaining. … Why would anyone believe PJM’s assertion that this project was suddenly all about reliability? The load forecast for the target market is flat, and every year the forecast is decreased. New high-voltage lines in York and Harford County have been constructed and are operating at less than 50% capacity. Recent and pending upgrades to move power across the grid in Maryland have drastically cut electrical congestion. The project is simply not needed.”
Shaw also accused PJM of fixing the ratio analysis and decried the millions of dollars taxpayers and ratepayers are already on the hook for, whether the project ever gets built or not.
“PJM allowed Transource to announce their new cost estimates one month after PJM announced their recalculated benefits for the project, in effect giving Transource the ability to provide the ‘right’ answer and save the project from cancellation,” he said. “This project is dead, and it is time that PJM admits it and moves on … before people begin to question why PJM is needed at all.”
HOUSTON — ERCOT set a pair of demand records last week, establishing new marks for wind energy generation and November monthly demand as temperatures dipped below freezing in much of the state.
The grid operator recorded 17.9 GW of wind generation on Nov. 12, accounting for more than 40% of the generation in its footprint. That broke the old record 17.5 GW set on Feb 19.
ERCOT, which manages the grid for about 90% of Texas, has more than 21 GW of installed wind generation. It has another 40 GW of wind energy in its interconnection queue.
It twice set monthly demand records for November, reaching 55.3 GW the evening of Nov. 13 and 56.3 GW the next morning. That broke the old 2014 mark by more than 5.4 GW.
“We’re busting through these records,” ERCOT CEO Bill Magness said during a Gulf Coast Power Association luncheon. “We continue to see load growth in Texas.”
ERCOT’s last capacity, demand and reserves (CDR) report indicated its load will grow from 71.7 GW in 2019 to almost 78 GW in 2023. The grid operator will release an updated CDR in December, but Magness said he expects the load projections to grow again.
Load projections in West Texas | ERCOT
Magness shared with his audience a slide of Culberson County in West Texas, where oil and gas exploration has driven demand through the roof. Eight studies have been conducted in the area since 2014, with a load increase each time.
“If you’re a planner, this will make your stomach hurt,” Magness said. “Every time we’ve done a forecast, it’s gone up dramatically.”
The demand record for November was the 10th the grid operator has set since January 2016. Only February and March have demand records that date back to 2015 or earlier.
MISO staff are seeking to advance the RTO’s full 2018 Transmission Expansion Plan despite stakeholder objections to two projects, board members heard last week.
Staff recommend moving ahead with all 442 projects currently spelled out in the $3.3 billion plan, but the Planning Advisory Committee endorsed only 439 of the proposals, Executive Director of System Planning Aubrey Johnson said during a Nov. 13 conference call of the Board of Directors’ System Planning Committee.
The two projects sparking concern at the PAC include the rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota and American Transmission Co.’s Straits of Mackinac project to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas. Stakeholders have complained the costs for the Wabaco-Rochester project will shift from generator interconnection customers to local load customers and have said that an alternate solution would better suit the Mackinaw area.
The third proposal not receiving endorsement has stirred less controversy: ITC Midwest’s capacitor bank project at the Walters 161/69-kV substation in southern Minnesota, which was only held from endorsement to allow MISO to update the project’s details. (See MISO PAC Puts MTEP 18 to Vote, Removes 3 Projects.)
The 10 voting sectors of MISO’s Advisory Committee eventually voted 5.25 in favor of the nearly complete MTEP 18, with 2.75 opposed and two abstentions. MISO’s sectors can divide their single vote based on differing opinions between organizations and companies within the same sector.
MISO is openly defying the strong objections of at least some stakeholders by recommending that the Wabaco-Rochester line and Straits of Mackinac circuit rebuild move ahead as planned.
Johnson said MISO staff are recommending the $11 million Wabaco-Rochester project despite stakeholder concerns over cost allocation and Xcel Energy’s request to defer the project in favor of a larger solution later. The RTO said the project improves market efficiency and has benefits “well in excess of costs” at 6.8:1. Johnson said staff have studied alternatives to the project, including proposals submitted by Xcel.
“The area is experiencing congestion currently, and there are no generator interconnection customers identified as responsible for upgrading this circuit,” MISO said.
MTEP 18 breakdown | MISO
MISO also continues to recommend ATC’s $105 million plan to replace its underwater circuit linking Michigan’s Upper and Lower peninsulas, which was damaged last year when the cables were struck by a passing vessel.
While stakeholders agree that ATC’s damaged cables should be replaced, some are divided on whether the cables should be installed on the bottom of the lake or in an underwater tunnel. Stakeholders have raised the possibility of an interim solution if the more complex tunnel option is needed. Some have also proposed alternative or joint ownership of the replaced cables.
Johnson said MISO believes the best course of action is ATC “expeditiously” replacing the cables, which solves the immediate planning issue. He also pointed out that ATC has the right to replace its own equipment under the terms of MISO’s Transmission Owner Agreement.
Johnson added that MISO “does not address regulatory requirements governing the manner of placement of the cables within the straits, as that is a state siting issue.” The siting on the Mackinac project has not been finalized with the Michigan Public Service Commission.
The uncontroversial $11 million Walters substation project was originally proposed as a line and transformer project but has evolved into a capacitor bank installment to improve voltages in the area. The PAC withheld approval so the alternate project could be updated into the MTEP 18 list. MISO said it has since updated the project details and isn’t aware of any outstanding stakeholder issues with the project. Johnson said the issue was resolved prior to the close of the PAC meeting in October.
Stakeholder Pushback
During the call, Director Phyllis Currie asked for stakeholder reaction to MISO’s decision to move ahead with the Wabaco-Rochester project, but none offered opinions during the open comment period. It was later discovered that technical difficulties prevented stakeholders from getting a line opened on the operator-assisted call. MISO held a special comment period by phone on Nov. 15, and CEO John Bear that same day apologized to stakeholders for the mishap during an Informational Forum.
During the make-up call, stakeholders repeated criticisms of the two proposed projects.
Representatives of Wolverine Power Supply Cooperative said the company submitted an alternative proposal to the Mackinac project and said MISO staff may have been too quick to dismiss it.
But ATC’s Brian Drumm said MISO evaluated the project and alternatives properly. He also pointed to ATC’s contractual right to perform upgrades on its own equipment.
Dairyland Power Cooperative’s Terry Torgerson said MISO’s estimated savings on the Wabaco-Rochester line are overstated.
Xcel Energy’s Carolyn Wetterlin said Xcel and MISO also “ended on a disagreement” this year concerning the Rochester-Wabaco line. She said the proposed line only shifts congestion into another area. Wetterlin asked that MISO delay the solution until MTEP 19.
The board will vote on whether to approve MTEP 18 in its entirety at its meeting on Dec. 6.
FERC last week granted MISO a one-time Tariff waiver allowing the RTO to designate certain Louisiana resources as commercially significant to voltage and local reliability (VLR) without first collecting and studying a year of data to back up the determination (ER18-2273).
Entergy Transmission | Entergy
MISO plans to allocate the majority of VLR commitment costs incurred in the Fancy Point load area on the Mississippi River to Entergy, which has the largest amount of load and stands to benefit most. Entergy said it did not oppose the waiver, which is effective for one year beginning Aug. 22, 2018.
The RTO’s Tariff requires it to conduct quarterly VLR issue studies using data from the previous 12 months before it can label VLR commitments “commercially significant.”
FERC said the waiver is “narrowly tailored” to allow MISO to make the designation while accumulating the 12 months of data necessary to conduct a study pursuant to its Tariff. It added that the move is “consistent with the principle of cost causation in that it is designed to allocate revenue sufficiency guarantee make-whole payments for VLR commitments to the load in the local balancing areas that benefit from the VLR commitments.”
MISO said that absent a waiver, it would be required to allocate VLR commitment costs to the local balancing area where the VLR-committed resource is located, instead of allocating costs on a load-share basis to the entities that benefit from commitments.
FERC found that MISO acted in good faith on the designation by working with affected parties to create an operating guide and convening a special meeting to discuss VLR issues.
The New York Public Service Commission on Thursday unanimously approved renewing Westchester County’s community choice aggregation (CCA) program, which since 2016 has pooled municipalities to purchase electricity and natural gas in bulk.
The New York PSC held its regular monthly session in Albany on Nov. 15, 2018.
The county’s Sustainable Westchester is the only active CCA in the state so far (Case 14-M-0564), though the PSC has approved three others. CCAs also provide consumers increased access to distributed energy resources and efficiency programs and products.
Diane Burman
Commissioner Diane Burman supported the order but asked Department of Public Service staff about low-income provisions in the programs.
Ted Kelly
Ted Kelly, DPS assistant counsel, said, “As with the other CCA programs, Sustainable Westchester can only serve low-income customers with the start of the new, renewed program if they offer and provide those customers with a guaranteed savings product, and they did discuss that in their master implementation plan and acknowledge that they were aware of and would comply with that requirement.”
Gregg Sayre
Commissioner Gregg Sayre said that CCAs are consistent with “increased customer choice and a market-based encouragement of new options for clean energy and distributed energy resources.”
Home EV Charging Tariff Nixed; Revisions Ordered
The PSC rejected tariff filings for residential electric vehicle charging from all the major investor-owned utilities in the state (Case No. 18-E-0206) and ordered them to file revisions that implement time-of-use (TOU) rates equal to the traditional residential customer charge.
“The incremental customer charge associated with TOU rates can deter EV customers from adopting the TOU tariff and can impact a customer’s decision as to whether to purchase an EV,” the commission said. “Minimizing such costs will lower barriers for customers to adopt TOU rates.”
John Rhodes
“We know electric vehicles are coming, and we know that it’s up to us to make sure that this coming call on the electric system is managed well,” PSC Chair John Rhodes said. “That in turn calls for good engineering, but also for good economics and, specifically, good rates.”
Mary Ann Sorrentino, acting DPS chief of electric rates and tariffs, testified that the relevant statute (PBS Section 66-o) was intended to provide incentives to buy EVs and encourage the adoption of grid-responsible charging times.
New York law requires utilities to file residential EV charging tariffs and to report periodically, but the commission’s Nov. 15 order defines the reporting as annual and directs Central Hudson Gas & Electric, New York State Electric & Gas, Rochester Gas and Electric, Consolidated Edison and Niagara Mohawk Power to file their annual report every Jan. 30, starting in 2019.
Mary Ann Sorrentino
“The tariffs addressing 66-o are essentially similar in that each of the electric utilities proposed a one-year price guarantee for residential customers with qualifying EVs that go on the residential time-of-use rate for their entire load,” Sorrentino said.
Under TOU rates, charges are lower during off-peak hours. The commission has already approved price guarantees for EV owners in Con Ed and Orange and Rockland Utilities service territories to reduce customers’ fear of trying a new rate, she said.
“The PSC has a broader proceeding underway to develop its approach to EVs comprehensively [Case 18-E-0138], but in the meantime, this is a smart, pragmatic adaptation of existing approaches that fits with our principles and makes sense,” Rhodes said.
The commission’s order on residential charging rates “complements the broader proceeding” on EV infrastructure and also the proceeding on the value of distributed energy resources (Case 15-E-0751), Sorrentino said.
Thursday’s order also addresses utilities with residential TOU rates that contain incremental meter charges as opposed to increased customer charges, such as National Grid and RG&E, directing that “residential customers with qualifying registered EVs that take service under residential TOU rates shall not be subject to the incremental charge.”
The commission in September approved Con Ed expanding its EV charging program, SmartCharge NY, to offer incentives to customers who charge medium- and heavy-duty EVs during off-peak hours. The commission’s order (Case 16-E-0060) said “it is critical to begin testing the efficacy of off-peak charging programs for the full gamut of EVs at a time when EV penetration is comparatively low.”
New York’s zero-emissions vehicle plan calls for creating statewide EV infrastructure to support 30,000 to 40,000 EV sales by the end of 2018 and 10,000 charging stations by 2021. The commission in September reported 26,470 EVs registered in New York.
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.
