Page 1154 – RTO Insider

January 2, 2020

MISO to Continue Adapting to Resource Shift in 2020

By Amanda Durish Cook

CARMEL, Ind. — MISO spent much of 2019 preparing for a massive shift to renewable resources — and 2020 will herald much the same, RTO executives say.

“The next leg of fleet evolution is going to take us to a much different place,” MISO CEO John Bear said at the beginning of 2019.

Bear said the foreseeable future would be characterized by what MISO dubs the “3Ds”: demarginalization, decentralization and digitization.

MISO 2020 — MISO CEO John Bear at Board Week in December | © *RTO Insider*

The three trends represent significant growth in renewables and natural gas generation; a shift in power production away from large centralized plants to distributed generation; and an Internet of Things to help consumers control their energy consumption, he said.

By 2030, MISO predicts, wind and solar will take a 36% share of its generation, with coal representing just 22%, compared with 76% in 2005.

The RTO in March will publish its second Forward Report, which explores changing industry trends and their impact on the footprint.

“We continue to expect a steady stream of renewable generation entering the queue,” MISO Executive Director of Resource Planning Patrick Brown told RTO board members in December.

“We’ve got a big year ahead of us,” Bear said last month at MISO’s final Board Week of 2019.

Bear said the RTO will continue studying renewable integration in the footprint, contemplate changes to its capacity resource accreditation, explore more tactics to minimize the impact of increasing generation outages, firm up new transmission planning futures and evaluate dynamic transmission line ratings.

MISO President Clair Moeller foresees “a lot of knowledge transfer” over the next five years to train a younger workforce.

“MISO has enjoyed a lot of baby boomer expertise,” Moeller said during last month’s Board Week.

MISO also envisions its control room operators will one day use Alexa-type voice command technology — what it tentatively calls “Electra” — to monitor and mitigate transmission congestion.

Looming industry transformation has created a sense of urgency in the stakeholder community.

“We’re facing rapid change in the industry, and our current stakeholder cadence isn’t going to cut it,” Transmission-Dependent Utilities sector representative Kevin Van Oirschot said during the Advisory Committee’s meeting in June. He argued for quicker development of policies for distributed energy resources and storage devices.

SATA, DER and Solar: New Kids on the Block

MISO wrapped up the year by submitting to Despite Pushback, MISO Pursuing TO-only SATA.) It said its plan will avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.

Director of Planning Jeff Webb predicted that MISO will soon begin addressing SATA’s participation in the energy market.

“It’s something we need to address early in the year, I think, because folks are interested and dual-use storage is going to be complicated,” Webb said at the Planning Advisory Committee’s October meeting.

“In the spirit of marginalism, we’re addressing this one step at a time,” Principal Adviser of Market Design Mike Robinson told attendees at the Market Subcommittee’s meeting Oct. 10.

MISO also held seven workshops in 2019 to prepare for widespread DERs in its footprint and markets.

“We don’t have the answers yet, but we want the situational awareness in place,” Executive Director of Market Strategy and Design Scott Wright said during the last Board Week, adding that MISO is now focusing on what new communication protocols it may need to introduce to foster greater DER participation. (See MISO Explores Changes to Accommodate DER.) Even without a DER participation ruling from FERC, MISO has nevertheless reserved space for a participation model in its new market platform.

Bear also pointed out that MISO contains a few gigawatts of “legacy DERs,” which have for years existed outside the markets.

“How do we bring all that together and still operate the system is pretty complicated,” Bear said. “It’s a lot of snowflakes to bring together.”

Meanwhile, MISO has more than two years before it must roll out a participation model for electric storage resources. (See Storage Plans Clear FERC with Conditions.) The RTO must still address a handful of compliance requirements in its model, including crafting metering and accounting rules for distributed storage resources, the potential qualification of storage as fast-start resources and exemption of those resources from transmission charges when providing down-ramp capability.

MISO is also seeking to make solar resources dispatchable using rules nearly identical to those that brought wind resources under dispatch in 2011. (See “Solar Dispatch Imminent,” MISO Market Subcommittee Briefs: Dec. 3, 2019.) Solar could register under the dispatchable intermittent resources category as early as the first half of this year. The RTO currently has 314 MW of registered solar capacity.

“We expect solar to grow 10 to 20 times. It’s small now; we’d like to get ahead of it,” Wright said.

Facelift for MTEP Futures

MISO has committed to using more aggressive renewable generation projections in its annual transmission planning by 2021.

The effort will include development of three new 15-year future scenarios — Announced Plans, Accelerated Fleet Change and Advanced Electrification — that account for utilities’ decarbonization plans, the push toward renewable generation and increasing electrification in the footprint. (See Stakeholders Debate MISO Planning Futures.)

“Certainly, the drive in demand appears to be there,” MISO Director Nancy Lange observed.

Director Phyllis Currie urged the RTO to carefully balance increasing energy efficiency with electrification, the “savior” of the industry.

Vice President of System Planning Jennifer Curran said stakeholders have not yet reached “widespread agreement” on the futures retooling, noting that some think the proposed futures are too aggressive and others think the renewable predictions don’t go far enough.

Moeller said the 40% renewable penetration scenario outlined in the futures reflects MISO’s regional characteristics, with a nearly 80% penetration in the northwestern portion of the footprint and about 10 to 15% across MISO South.

The RTO hopes to finalize the new future scenarios in June or July. Directors asked executives to ensure it meets its self-imposed deadline.

MISO predicts it will have adequate resources in 2020 to meet a 9% planning reserve margin requirement above forecasted peak load but is bracing for the possibility of a winter emergency in January. (See MISO Taking Pains to Prepare for Moderate Winter.)

Last year roared in like a lion, as an extreme late-January cold snap prompted the largest deployment of load-modifying resources since MISO rolled out its current annual capacity auction design in 2013. The RTO exceeded the 3,000-MW contractual limit on the regional directional transfer limit to provide replacement for MISO South generation outages and derates. That region saw another emergency event May 16 in the face of outages and derates coupled with unseasonable heat. (See Emergencies Prompt MISO to Re-examine LMR Protocols.)

The January event prompted MISO to solicit stakeholder ideas on how to get additional capacity to address the North-South constraint, producing nine potential transmission projects. (See MISO Studying Projects to Cut North-South Tx Reliance.)

Cost Allocation Decision Made

MISO and PJM last year agreed to construct their first interregional market efficiency project, the $21.6 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in northwestern Indiana. (See MISO, SPP Empty-handed After 3rd Project Study.)

MISO has emerged with a nearly complete cost allocation plan for its market efficiency projects (MEPs) despite stakeholder complaints the proposal ignores the wider benefits of sub-230-kV transmission lines.

After months of back-and-forth, MISO recently landed on a proposal that lowers the MEP threshold from 345 kV to 230 kV and eliminates the 20% postage stamp allocation. The plan also adds new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP contract path.

MISO’s new plan also eliminates the regional benefit-to-cost test on local economic projects between 100 and 230 kV, now proposing to perform only a local test on those projects.

Still, stakeholders said the cost-causation issues that prompted FERC’s June rejection of the first cost allocation plan remain, with some saying MISO is essentially ignoring an entire class of transmission projects that could be beneficial on a regional basis. (See MISO Makes U-turn on Cost Allocation Policy.)

“This is not ‘beneficiaries pay,’” Michigan Public Service Commission staffer Bonnie Janssen said of the new plan at a cost allocation meeting in early December.

“If we thought this was going to fail, we wouldn’t file it. We have a level of confidence this will work for us,” MISO Senior Manager of System Planning Jarred Miland responded. “We’re not justifying the projects regionally; we’re justifying them locally.”

“I certainly wouldn’t characterize this as a consensus proposal,” WEC Energy Group’s Chris Plante told RTO officials at the same meeting.

MISO plans to file the proposal in January and has included a provision to revisit the effectiveness of the cost allocation method in three years.

FERC Upholds 2015 Capacity Auction

MISO also closed the book on a four-year dispute after FERC in July cleared the 2015/16 Planning Resource Auction results, finding no market manipulation on the part of Dynegy (now Vistra Energy). (See FERC Clears MISO 2015/16 Auction Results.) The commission said it would take no further action to investigate allegations of market manipulation in the auction, which resulted in a $150/MW-day clearing price in Southern Illinois’ Zone 4.

January 1, 2020

ERCOT Market Adjusting to ‘The New Normal’

By Tom Kleckner

Most ERCOT market participants have come to grips with the fact that “9-ish percent” reserve margins are likely “the new normal” in Texas’ energy-only market, as former FERC Chairman Pat Wood III recently said.

In 2019, for the second summer in a row, the state’s grid withstood extreme heat and loss of wind power during some of the hottest days to meet multiple demand peaks exceeding the previous year. Despite beginning both summers with single-digit reserve margins, ERCOT resorted to emergency actions just twice.

“The reliability of our markets has been the story of the last quarter-century in our state,” said Wood, also a past Texas Public Utility Commission chairman. (See “Wood Reflects on Electric Industry’s Past — and Future,” Texas Reliability Entity Briefs: Dec. 11, 2019.)

“What we’ve built here is something everybody should be proud of,” attorney Katie Coleman, representing the Texas Industrial Energy Consumers trade group, said during a PUC workshop on ERCOT’s summer performance. (See “ERCOT MPs: Market Worked as Designed in Summer,” Magness, Walker to Explain ERCOT Reliability to NERC.)

ERCOT — Former FERC Chair Pat Wood III (left) and NRG CEO Mauricio Gutierrez at GCPA’s fall conference in 2017 | © *RTO Insider*

Real-time prices did hit the $9,000/MWh systemwide offer cap several times, mostly because Texas wind generation hits a lull during the early-afternoon hours.

“But [that’s] how an energy-only market is supposed to work and part of [its] success,” Texas Competitive Power Advocates’ Michele Gregg Richmond said.

“You do live closer to the edge than what I’m used to, but you do a fantastic job of managing it,” NERC Trustee Ken DeFontes said during the Texas Reliability Entity’s December board meeting.

ERCOT, which has a 13.75% planning reserve margin, projects its reserves will climb to 10.6% next year and 18.2% in 2021, before shrinking to 12.9% in 2024. (See ERCOT’s Reserve Margin Climbs to 10.6% in 2020.)

Renewables will provide the majority of the incoming reserves with solar (64.7 GW) and wind (32.3 GW) accounting for almost 88% of the more than 110 GW of capacity under study in ERCOT’s generation interconnection queue.

With not a single megawatt of coal capacity in the queue, wind is expected to surpass coal’s share of the fuel mix in 2020. Coal accounted for 20.43% of ERCOT’s energy production through November 2019, with wind right behind at 19.76%. The Norwegian research firm Rystad Energy has predicted that Texas wind farms will generate about 87 TWh of electricity this year, compared to 84.4 TWh from coal.

Wood said during the Texas RE’s annual meeting that the state is the country’s largest carbon-emitter, “but this power system is much cleaner than it used to be.” He said the shift to cleaner-burning fuels has only just begun.

“That’s going to happen in the country. I know President Trump doesn’t like it, but that’s inevitable,” Wood said.

With more than 27 GW of installed wind capacity, Texas has more wind than any other state in the nation (including 22.4 GW in ERCOT). Solar capacity is coming at an even faster rate, with the 3 GW of capacity at the end of 2019 expected to double to more than 6.2 GW in 2020. ERCOT expects to have more than 11 GW of solar capacity on hand by 2022.

Battery storage, with its falling costs and improving technology, is fueling much of that increase. There is about 1 GW of storage on the system right now, but another 7.2 GW is under study.

Recognizing the need to be prepared for the wave of storage resources, ERCOT last year suggested creating a B attery E nergy S torage T ask F orce to develop policy recommendations related to the resources’ integration into the grid. The group will consider operational and market design policies that can be implemented in the short term and rules that can be implemented on a longer timeline. (See “TAC Approves BESTF Leaders, Scope,” ERCOT Technical Advisory Committee Briefs: Oct. 23, 2019.)

Another task force has developed real-time co-optimization’s key principles, which will go before the Board of Directors in February for final approval. Staff and stakeholders will then draft the revision requests and other documents necessary for the implementation of the market tool, which procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

Staff are also developing rules and requirements for distributed generation. ERCOT has limited interconnections of new distributed generation projects in the meantime.

January 1, 2020February 13, 2025

FERC’s ‘Rifts’ Only Widened in 2019

By Michael Brooks

For years, it seemed like the most exciting thing to happen at a FERC open meeting was a creative interruption by environmental activists protesting the commission’s approvals of natural gas infrastructure.

But while that certainly continued in 2019, center stage is occupied by the “Glick-McNamee Show”: the label Commissioner Bernard McNamee, now in his second year, has given to the monthly debate he and Commissioner Richard Glick have through their opening statements over Glick’s dissents at the meetings.

FERC Chairman Neil Chatterjee (left) and Commissioner Richard Glick chat before the start of the commission’s open meeting in September. | © RTO Insider

The FERC that unanimously rejected the Department of Energy’s proposed Grid Resiliency Pricing Rule nearly two years ago is mostly gone. The commission began 2019 in mourning when Commissioner and former Chairman Kevin McIntyre died Jan. 2. Less than a month later, Commissioner Cheryl LaFleur announced she would retire; she left at the end of August, having served nine years on the commission, and joined ISO-NE’s Board of Directors.

Prior to her departure, LaFleur gave a keynote speech at the Energy Bar Association’s annual meeting in May, in which she said that “the polarization of Washington, D.C., and societal rifts on big issues have sort of spread to 888 First St., especially the profound societal disagreement about climate change.”

Those rifts only widened at FERC after she left and, absent any major surprises, will stay in place for 2020.

Sabal Trail

Most of the tension between the remaining commissioners — Glick and Republicans McNamee and Chairman Neil Chatterjee — stems from the D.C. Circuit Court of Appeals’ August 2017 ruling in Sierra Club v. FERC (the “Sabal Trail” case), in which the court remanded the commission’s environmental impact statement on the Southeast Market Pipelines Project. The court ordered FERC to estimate the project’s impact on greenhouse gas emissions or explain more fully why it could not do so.

In May 2018, FERC chose to do the latter, arguing that it does not have sufficient information to determine the source of the gas being transported over pipelines, nor its end use. It declared that it would no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” (See FERC Narrows GHG Review for Gas Pipelines.)

| FERC

In his dissents, and in public, Glick argues that this means “the commission is essentially ignoring” the court’s determination when it approves natural gas pipelines and LNG export terminals.

During her remaining time with the commission, LaFleur voted for certain pipelines after considering their emissions but also partially dissented on those projects, noting the rest of the majority did not take emissions into account.

Until February, Chatterjee was pulling certain gas items from the commission’s agenda to avoid them being voted down or nullified by a tie vote. That month, however, LaFleur joined the Republicans in approving the Calcasieu Pass LNG export project in Louisiana. While she criticized her Republican colleagues for their “failure to disclose and discuss cumulative potential direct GHG emissions associated” with Calcasieu Pass, LaFleur included in her concurring statement a table estimating those impacts.

FERC in 2019 approved 11 LNG export facilities worth about 20 Bcfd of liquefaction capacity and 19 natural gas pipeline projects.

“I’m trying to keep our disagreements about the way we conduct our environmental reviews from forcing me to dissent every single time, even if I have to supplement the climate analysis myself,” LaFleur told the EBA.

“I expect that the courts will ultimately require the commission to do more climate analysis,” she added.

Stalled Proceedings

The tension over the emissions dispute appeared to spill into other, less controversial proceedings. LaFleur told the EBA that “even some less prominent orders that have nothing apparently to do with climate have gotten stalled because individual commissioners are too dug in on something to agree on language. And this has happened far more frequently than in the past.”

At his monthly press conferences, Chatterjee continually faced questions about the status of the commission’s inquiry into grid resilience (AD18-7), PJM’s proposal to extend its minimum offer price rule (MOPR) (EL16-49), the commission’s consideration of revising its implementation of the Public Utility Regulatory Policies Act of 1978 (AD16-16) and its review of its 1999 policy statement on certifying new interstate natural gas pipeline facilities (PL18-1).

FERC Commissioner Richard Glick (center) holds a press conference, with legal adviser Matthew Christiansen and Technical Adviser Pamela Quinlan, after the commission’s ruling on PJM’s MOPR in December. | © RTO Insider

FERC issued a NOPR on its PURPA regulations in September and extended PJM’s MOPR to all new state-subsidized resources in December. Glick dissented on both dockets, which had languished at the commission for more than a year. FERC has yet to act on the resilience and gas dockets, both of which were opened in 2017 under McIntyre.

In October, Glick complained that he had not been allowed to suggest changes to staff’s annual Winter Energy Market Assessment before its presentation at that month’s open meeting. Glick cited the report’s statement that “Coal and oil-fired generation continue to play an important role in maintaining electric reliability during the winter, especially in the Northeast, where winter demand for natural gas can exceed pipelines’ capacity.” He noted that coal makes up 2% or less of installed capacity in New York and New England.

After the next open meeting in November, Glick stayed to watch Chatterjee’s monthly press conference. He also held his own press conference after the MOPR ruling in December calling it “definitely the wrong thing.”

Looking Ahead

The D.C. Circuit rejected two challenges to FERC’s gas infrastructure approvals in 2019 but mostly on procedural grounds.

In May, it ruled that New York-based environmental nonprofit Otsego 2000 lacked standing to challenge FERC’s decision to approve Dominion Energy Transmission’s New Market Project — the same decision in which the commission narrowed its review of GHG emissions. Otsego 2000 not only had argued that FERC was required to include an evaluation of upstream and downstream emissions in its environmental review of the project, but that the commission improperly announced its new policy without notice and an opportunity for public comment.

In June, the court rejected a similar complaint by Concerned Citizens for a Safe Environment over FERC’s approval of a new natural gas compression facility in Davidson County, Tenn., by Tennessee Gas Pipeline. But it did so on far narrower grounds.

“We are troubled … by the commission’s attempt to justify its decision to discount downstream impacts based on its lack of information about the destination and end use of the gas in question,” the court said. “It should go without saying that [the National Environmental Policy Act] also requires the commission to at least attempt to obtain the information necessary to fulfill its statutory responsibilities. …

“Despite our misgivings regarding the commission’s decidedly less-than-dogged efforts to obtain the information it says it would need to determine that downstream greenhouse gas emissions qualify as a reasonably foreseeable indirect effect of the project, Concerned Citizens failed to raise this record-development issue in the proceedings before the commission. We therefore lack jurisdiction to decide whether the commission acted arbitrarily or capriciously and violated NEPA by failing to further develop the record in this case.”

The court seemed to open a path for a new challenge to one of the commission’s approvals. But as of the end of the year, none on the “record-development issue” have been filed with the courts.

Status of each seat on the commission. Terms end on June 30 each year. *Danly has been nominated and advanced out of committee but not confirmed by the full Senate. **Democrats have suggested a replacement for LaFleur, but President Trump has not nominated anyone. | © RTO Insider

It’s also unknown when the commission’s makeup will change.

While the Senate Energy and Natural Resources Committee advanced both the nominations of General Counsel James Danly to the commission and Dan Brouillette to succeed Rick Perry as energy secretary on Nov. 19, the Senate confirmed Brouillette mere weeks later, suggesting FERC was not high on Senate Majority Leader Mitch McConnell’s to-do list. Danly’s nomination could be further held up into the year as the Senate holds a trial on the impeachment of President Trump.

Danly was nominated Sept. 30 to finish McIntyre’s term, which would end June 30, 2023. Trump angered Democrats when he declined to nominate a replacement for LaFleur. It has been widely reported that Democrats have put forward Allison Clements, clean energy markets program director for the Energy Foundation, as their choice. It’s fairly safe to say that Trump will be disinclined to acquiesce to their request as he goes through the impeachment process and runs for re-election.

McNamee’s term expires June 30, but by law he is allowed to serve past that date until the end of the year if he is not reappointed and a replacement is not confirmed. If McNamee stays on into 2021, the presidential election could determine whether Chatterjee not only remains chairman but also a commissioner past June 30 of that year.

The 2020 election cycle also diminishes the odds of any major energy legislation being enacted. Corey Schrodt, legislative director for Rep. Francis Rooney (R-Fla.), told the Solar Energy Industries Association at a meeting in December that “I’ve been on the Hill long enough to know that we have from now to maybe until March to really do anything.”

On Dec. 20, Trump signed two spending packages for fiscal year 2020, which began Oct. 1, totaling $1.4 trillion. The bills narrowly averted a government shutdown but did not include extending tax credits to solar and electric vehicles. Wind developers, however, can now qualify for the production tax credit through 2020. The bills also increased funding for FERC, the Department of Energy and EPA.

December 23, 2019

PJM Fuel Security OK for Now, Stakeholders Decide

By Christen Smith

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee agreed to sunset the Fuel Security Senior Task Force on Thursday after determining the RTO seems prepared enough, for now, for any potential reliability threats.

Except, some utilities argued, PJM stakeholders should do more than the “minimum” required to protect against fuel supply issues — especially when generators can signal a deactivation in as little as 90 days ahead of time.

The MRC approved the task force’s issue charge in March to investigate what market responses to conditions could lead to fuel insecurity and assessing whether the current market construct is sufficient to cure the problem. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)

PJM Fuel Security — Fuel security analysis scope | *PJM*

PJM Director of Energy Market Operations Tim Horger said Thursday that stakeholders could decide either to maintain the status quo with periodic reviews of the RTO’s fuel security or pursue more aggressive paths to implement market, operational and planning changes. A nonbinding poll of 204 stakeholders determined that 74% agreed nothing more needed to be done.

Exelon, FirstEnergy and Dominion Energy were not among those in favor.

“These retirements can cause a significant shift on installed reserve margins,” said Sharon Midgley, Exelon’s director of wholesale market development. “Generation owners have a line of sight into how resources are doing from an economic standpoint that PJM does not have.”

Midgley added that resilience-based events cannot be averted by market-based solutions developed after the fact, so it would be prudent to initiate a discussion on potential criteria or solutions in 2020, so planning could occur in advance of any issue.

Paul Sotkiewicz, president of E-Cubed Policy Associates and PJM’s former chief economist, said because of the three-year forward structure of the capacity market, the average retirement notice falls somewhere between 30 and 33 months. He said that PJM’s analysis — which included 324 different scenarios — shows “there’s no urgent or imminent problem.”

Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, pointed to yearly reports from Monitoring Analytics, PJM’s Independent Market Monitor, that provide a high-level view of generator economics in the RTO.

“I think the Market Monitor does an excellent job of highlighting generation at risk in its annual State of the Market Report,” he said. “While it may be done at a rough level based on types of assumptions that need to be made, I think it does give a pretty good indication of where the economics are regarding retirement.”

The utilities disagreed, arguing that the Monitor does not take into account risks associated with plant operations and presumes that PJM’s short-run capacity market outcomes are sufficient to benchmark the prudence of continued investments in long-lived assets.

Jim Davis, an electric policy market consultant for Dominion, said the average retirement notice doesn’t tell the full story of PJM’s changing resource portfolio.

“Even though the average is three years in advance, that could be accelerated in the future given the advancement of renewables,” he said. “From our experience, pipelines are being constrained more frequently [than before].”

Susan Bruce, of the PJM Industrial Customer Coalition, said that perhaps the idea of just monitoring the situation, as part of the status quo path, “might not be the right phraseology.”

“It has a more passive approach than many from the outside looking in might expect,” she said, mentioning that some continued reporting to stakeholders might help ease concerns.

The MRC approved the status quo path in a sector-weighted vote of 4.5 to 0.5. A motion from the D.C. Office of the People’s Counsel to sunset the task force was endorsed by acclamation, with objections from Exelon, Dominion and FirstEnergy.

December 23, 2019

FERC Denies Rehearing of SPP Exit Fee Decision

By Tom Kleckner

FERC last week rejected a request by SPP and its load-serving entities to rehear its April order that eliminated the RTO’s membership exit fee for non-transmission owners (EL19-11).

The commission also rejected SPP’s alternative proposal to lower the fee to $100,000. Rejecting the proposal without prejudice, FERC 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.” (See SPP Proposes to Drop Exit Fee to $100K.)

“Any future exit fee proposal should ensure that [non-TOs] pay a smaller exit fee than transmission owners, regardless of whether the [non-TO] is also [an LSE], and that non-transmission-owning load-serving entities pay an exit fee similar to that paid by other [non-TOs],” the commission wrote.

In affirming its previous decision, FERC denied contentions by the RTO and its LSEs that it erred in finding that the exit fee is so high that it presents a barrier to membership to non-TOs and results in cost shifts among SPP’s members. (See FERC Tells SPP to End Exit Fee for Non-TOs.)

SPP Exit Fee — Western U.S. transmission lines | *Southwire*

The commission said exempting non-TOs from the exit fee does not unfairly shift costs to remaining SPP members because non-TOs “have less of an impact on the system when they exit than transmission owners do and SPP can still recover these costs through administrative fees.”

The commission determined in April that the exit fee “was not needed to maintain SPP’s financial solvency or to avoid cost shifts and was excessive as a means for ensuring the stability of SPP’s membership and members’ financial commitment.” FERC did agree “some level of exit fee” is necessary for non-TOs.

The proceeding stems from a complaint last year by the American Wind Energy Association and the Advanced Power Alliance, which have long argued against the exit fee. The fee is defined as the sum of the withdrawing member’s obligations at the time of withdrawal, including any unpaid dues or assessments, and the member’s share of SPP’s outstanding long-term financial obligations. SPP estimates the fee for an entity without load is $631,915 — nearly twice the estimated $327,191 fee when FERC approved it in 2006.

The decision was a welcome bit of good news for AWEA and APA. Amy Farrell, AWEA’s senior vice president of government and public affairs, said the order partially offset FERC’s ruling favoring existing generation in the FERC Extends PJM MOPR to State Subsidies.)

“The only glimmer of light … was FERC’s reaffirmation requiring [SPP] to eliminate the membership exit fee, allowing for a more inclusive stakeholder process that will lead to better outcomes for consumers,” Farrell said in a statement.

December 23, 2019

FERC Rejects Rehearing in PJM Cost Allocation Saga

By Michael Brooks

FERC on Thursday denied requests for rehearing and clarification of its acceptance of a settlement between PJM and its transmission owners over the cost allocation of major legacy transmission projects, the latest development in a nearly 13-year dispute that has reached the 7th U.S. Circuit Court of Appeals (EL05-121, ER18-2102).

In May 2018, the commission approved an agreement over how PJM would allocate the costs of transmission projects above 500 kV approved between April 19, 2007 — when FERC found the RTO’s existing violation-based distribution factor (DFAX) method unjust and directed a new load-ratio share method — and Feb. 1, 2013, when FERC approved PJM’s new hybrid method, combining both the DFAX and load-ratio methods. (See “Response to FERC’s Cost Allocation Order,” PJM Market Implementation Committee Briefs: Ju ne 6 , 2018.)

The commission approved the settlement under the second so-called “Trailblazer approach,” referring to the precedent set by a 1999 case involving Trailblazer Pipeline Co. Under the second Trailblazer approach, FERC may “approve a contested settlement as a package on the grounds that the overall result of the settlement is just and reasonable. The commission does not need to render a merits decision on whether each element of a settlement package is just and reasonable, so long as the overall package falls within a broad ambit of various rates which may be just and reasonable.”

Linden VFT challenged FERC’s approval under the approach, arguing that the commission needed “a detailed and independent cost-benefit analysis.”

“The commission largely bases its findings on the contested settlement’s general adoption of the cost allocation methodology currently contained in the PJM Tariff,” Linden said in its request for rehearing. “The settling parties did not present, and the commission did not base its decision on, any detailed or quantitative analysis comparing costs and benefits of any of the projects.”

The merchant transmission developer also said the commission’s order contained “oversimplified and fallacious data analyses” and “determinations contrary to circuit court and FERC precedent.”

“Any one of these flaws alone would constitute reversible error and would make the order unable to withstand an appeal,” Linden warned. “That would mean that this proceeding, which officially began over 13 years ago, would continue following yet another remand without the certainty of cost allocation that the settling parties and the commission have expressed the desire to obtain.”

Neptune Regional Transmission System and the Long Island Power Authority also alleged factual inaccuracies in their own requests for rehearing. Linden, along with Hudson Transmission Partners and the New York Power Authority, also requested clarification that they would not be subject to any of the current recovery charges or transmission enhancement charge adjustments provided for by the settlement.

The 7th Circuit twice remanded FERC’s approval of the load-ratio share method before PJM abandoned it in favor of the hybrid method. The Illinois Commerce Commission, which had filed the original complaint with the 7th Circuit on behalf of Commonwealth Edison, was among the parties to the settlement. (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.)

“We continue to find that the commission’s reliance on the Order No. 1000 hybrid cost allocation method is consistent with the court’s decision, and that the settlement’s application of the Order No. 1000 hybrid cost allocation method achieves an overall just and reasonable result,” FERC said in denying rehearing. “While the court did discuss using a cost-benefit analysis, it did not require exact quantification of costs and benefits but rather required that the benefits be ‘roughly commensurate’ with costs.”

Regarding the requests for clarification, FERC noted that Linden, Hudson and NYPA based their argument that they should not be subject to any charges under the settlement on the fact that the commission did not approve it until May 31, 2018, when they had already converted their firm transmission withdrawal rights to non-firm transmission withdrawal rights effective Jan. 1, 2018. “In fact, Hudson and Linden sought to convert their firm transmission withdrawal rights to non-firm transmission withdrawal rights because they were subject to transmission enhancement charges,” it said.

“Cost responsibility under this provision does not depend on the date on which the commission approves the settlement or the date on which the transmission owners begin collection of these charges,” FERC said. “Because clarification parties held firm transmission withdrawal rights from the period from Jan. 1, 2016, to Jan. 1, 2018, we find that they are responsible for paying for the current recovery charges for that period.”

December 23, 2019

FERC Partially Accepts NYISO Storage Compliance

By Michael Kuser

FERC last week partially accepted NYISO’s plan to comply with a mandate that RTOs and ISOs develop rules to provide energy storage resources (ESRs) full access to their wholesale markets.

Order 841, issued last year, requires that grid operators recognize the unique physical and operational characteristics of ESRs in designing market participation rules.

NYISO proposed a model that allows ESRs to either blend into a higher aggregation with other storage resources and demand response, or to come together as one, virtual, larger resource. (See Overheard at GTM’s Energy Storage Summit 2019.)

The commission on Thursday found that “NYISO has demonstrated that all [ESRs], including those located on the distribution system or behind the meter, will be eligible to provide all capacity, energy and ancillary services that they are technically capable of providing” (ER19-467).

However, the order also faulted NYISO’s filing for a lack of details on its “metering methodology and accounting practices for [ESRs] located behind a customer meter,” directing the ISO to alter its Tariff to include a basic description of such.

FERC noted its earlier determination that defers further action on the Order 841 compliance directive to allow participation in wholesale and retail markets until the commission takes action on the merits of NYISO’s November responses about ESR energy bids in the day-ahead markets, and its definition of “an obligation outside the ISO-administered markets” (ER19-2276).

The commission did, however, agree with the Energy Storage Association that it is not reasonable to allow NYISO to adopt an open-ended effective date of no earlier than May 1, 2020, saying the proposal “inappropriately creates uncertainty for existing and prospective market participants,” and ordered an effective date of no later than that date.

Separate Concurrence

In a separate concurrence, Commissioner Bernard McNamee reiterated a point he’s made in other storage-related orders, saying FERC “should have, at the very least, provided states the opportunity to opt-out of the participation model created by the storage orders.”

McNamee, not a member of the commission at the time Order 841 was issued, said he concurred in part and dissented in part with Order 841-A, which — among other things — affirmed that states cannot prevent ESRs from participating in wholesale markets.

“To the extent the commission’s storage orders exercised authority over the distribution system and behind-the-meter … the majority has exceeded the commission’s jurisdictional authority by depriving the states of the ability to determine whether distribution-level ESRs may use distribution facilities so as to access the wholesale markets,” he said.

December 23, 2019

NYISO ESCO Ruling Was Right, FERC Says

By Hudson Sangree

FERC said Thursday it won’t reconsider NYISO’s decision to deny membership to the successor to a bankrupt energy service company (ESCO) (EL19-39-001).

Light Power & Gas of NY (LPGNY) had sought rehearing of FERC’s June order upholding NYISO’s decision to exclude it from joining until its bankrupt predecessor, North Energy Power, paid its outstanding debts to the ISO. (See FERC Upholds NYISO Treatment of ESCO as Successor.)

NYISO expelled North Energy in October after the company filed for bankruptcy and its unpaid obligations exceeded its collateral.

A screenshot of the bankrupt North Energy Power’s website | *North Energy Power*

LPGNY filed its application to join NYISO one week after North Energy’s membership was terminated. The two companies had the same principal personnel and had served or sought to serve the same customers in the same service territory, FERC noted.

In a conversation with a NYISO manager, one of the principals had “expressed a desire to get his customers back,” FERC said.

LPGNY argued NYISO had found incorrectly that it was North Energy’s successor and liable for its debts.

FERC disagreed. The commission looked to its own precedents after finding NYISO’s transmission tariff was “silent with respect to the question of whether two different limited liability companies with close ties can be treated as the same transmission customer,” it said.

“The commission found that the close overlap of LPGNY and North Energy presented circumstances in which NYISO’s treatment of LPGNY and North Energy as one transmission customer was reasonable,” FERC wrote.

In its rehearing request, LPGNY argued that the “starting point for tariff interpretation is determining whether the relevant tariff language is ambiguous, and that the commission never made a finding of ambiguity,” FERC said. “LPGNY contends that under [two prior FERC decisions] … the commission must declare tariff language ambiguous prior to relying on extrinsic evidence.”

FERC decided, however, that the silence of the NYISO tariff on whether closely related companies can be treated as the same transmission customer “is adequate to permit the commission to rely, as it did in the complaint order, on commission precedent and extrinsic evidence, in discerning the meaning” of the relevant section of NYISO tariff.

December 23, 2019

FERC Lets Original PJM Stability Method Stand

By Michael Brooks

FERC on Thursday backtracked on several Tariff provisions it directed PJM to include in its implementation of a new cost allocation method for transmission projects that address stability issues (EL15-95-005, ER19-1501).

The commission granted rehearing of its Feb. 28 order accepting PJM’s stability deviation method for the limited purpose of removing the provisions from the compliance filing the RTO submitted in April. It directed PJM to refile its Tariff revisions without the provisions, leaving the new method as originally proposed.

The stability deviation method identifies the loads that would be most impacted by a stability disturbance — and thus benefit most from transmission projects that address stability-related issues — by measuring the voltage angular deviations during a simulated worst-case fault. Load buses with a deviation of less than 25% of the highest deviation would be excluded from the cost allocation. (See FERC: Stability Deviation Method Best for Artificial Island.)

from the plants led to the creation of the stability deviation method. | *BHI Energy*

In its original proposal, however, PJM identified a possible flaw in this plan: Once in service, the new transmission facility could address all stability issues, making it impossible to measure any angular deviations in a simulation. Several transmission owners also noted that the 25% threshold meant that under certain conditions, some deviations would be excluded from the cost allocation.

FERC directed PJM to include language to take the new facility out of the analysis if it resulted in deviations too small to measure when running the simulation. It also directed language that would allow PJM to adjust the 25% threshold as necessary.

In its April compliance filing, however, PJM said it had done further analysis and determined “that removing the stability upgrade would cause the model to go unstable and, therefore, fail to provide any meaningful information upon which to base the cost allocation.” Meanwhile, TOs American Electric Power, Dominion Energy, Duke Energy, FirstEnergy and PPL complained that the discretionary threshold provision would allow the RTO “to unilaterally determine the rate design under the PJM Tariff to recover the costs of a stability project based solely on PJM’s own discretion and with no approval or participation by” TOs.

To address both concerns, PJM asked FERC to delete the two provisions for now and give it some time to develop more Tariff revisions. FERC agreed.

“Accounting for these changed perspectives, we grant rehearing and remove both the deviation measurement provision and the discretionary threshold provision,” the commission said. It gave the RTO 30 days to refile its original proposal.

December 23, 2019

FERC Seeks More Testing on Spectrum Protections

FERC last week urged the Federal Communications Commission to conduct additional testing to ensure automated frequency coordination (AFC) will protect utilities’ use of the 6 GHz spectrum band, which the FCC is considering opening to unlicensed users.

In a letter to FCC Chair Ajit Pai, the commission noted the concerns of electric utilities, which use the spectrum (5,925 to 7,125 MHz) for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wireline networks are not available.

The issue was the subject of a panel during FERC’s annual technical conference on reliability in June. (See Utilities Warn of Encroachment on Communications Band.)

FERC Spectrum Protections — Microwave relay dish

In proposing the use of the spectrum by unlicensed users, FCC cited estimates that North American mobile traffic, including unlicensed Wi-Fi devices, grew 44% in 2016 and is projected to grow nearly 35% annually through 2021. AFC would use a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area.

“We ask that you consider the implications for electric reliability and closely review the rulemaking comments that discuss the potential impacts of the proposal on electric reliability,” the commissioners wrote. “Should the proposed rule be adopted, we strongly urge you to consider requests from electric utilities and state regulators for additional testing of the AFC system prior to implementation. We understand the complexity of assessing the cross-dependencies between areas of critical infrastructure and would be pleased to offer technical assistance through FERC staff if it would be helpful.”

— Rich Heidorn Jr.