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.)
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.
ERCOT’s projected resource capacity through 2024 | ERCOT
“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 Battery Energy Storage Task Force 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.
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.
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 joinedISO-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 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.
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.
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Thursday endorsed the first round of credit policy revisions to come out of a task force formed in the wake of GreenHat Energy’s default on its 890 million MWh financial transmission rights portfolio.
PJM said the recommendations, initially presented at the October MRC meeting, will improve its credit risk policies after the Financial Risk Mitigation Senior Task Force delegated a more holistic FTR market review and possible design changes to a separate Market Implementation Committee task force. (See “FTR Market Rule Changes,” PJM MRC Briefs: Oct. 31, 2019.)
One proposed change includes hosting five long-term FTR auctions a year, instead of three, in order to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary. A second would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter.
Stakeholders had voiced concerns about the auction restructuring crossing into market design territory, but they ultimately agreed to move forward with the option of revising the changes during the forthcoming MIC review. (See “FTR Vote Deferred,” PJM MRC/MC Briefs: Dec. 5, 2019.)
“I assure that no changes we are making here preclude us from making additional changes when we do the full FTR review,” said interim CEO Susan Riley, who had urged stakeholders to endorse the revisions as a “really big win.”
Competitive Transmission Proposal Fee
Stakeholders endorsed PJM’s new fee structure for its evaluation of competitive transmission proposals.
The new framework PJM wants to use will involve charging a $5,000 nonrefundable flat fee to all developers who submit competitive proposals. Itemized study costs will be added as necessary. Mark Sims, PJM’s manager of infrastructure coordination, said the intent is to bill projects that incur the extra expense. (See “PJM Unveils Flat Fee Cost-containment Plan” in PJM PC/TEAC Briefs: Aug. 8, 2019.)
Sims previously told the Planning Committee that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: June 13, 2019.)
Real-time Values
Stakeholders endorsed PJM’s issue charge that would address concerns over the misuse of real-time values (RTVs) in parameter-limited scheduling (PLS). (See “Real-time Values, Parameter-limited Schedules,” PJM MRC Briefs: Dec. 5, 2019.)
PJM said that some capacity generators use RTVs to override unit-specific parameters for inappropriate reasons, causing unnecessary confusion during dispatch.
The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources couldn’t meet their unit-specific parameter limits or approved exceptions. Generators opt to use RTVs and forfeit operating reserve credits and make-whole payments as a result.
Except, some generators consistently use RTVs to increase notification time on PLS “to reflect the decision not to staff the resource during hours they project the resource will not be economic,” PJM said. The operational impacts mean that resources called in real time based on their schedules cannot perform as expected.
The RTO will commence a special session of the MIC in 2020 to study the problem and recommend solutions.
Parameter-limited Scheduling Fix
The MRC endorsed revisions to the Operating Agreement and Tariff that align it with PJM’s actual implementation of PLS.
The revisions correct language errors introduced with the implementation of Capacity Performance that caused the RTO’s practice regarding PLS to contradict its own rules and conflict with other governing documents, PJM told the MIC and MRC earlier this month. The Monitor said, however, that PJM should simply follow the language set out in the Tariff instead of revising the document to fit its current practice. (See “Parameter-limited Schedules, PJM MIC Briefs: Dec. 11, 2019.)
Stakeholders approved PJM’s revisions in a sector-weighted vote of 4.67 to 0.33.
Modeling Generation Senior Task Force Recommendations
The MRC partially endorsed recommendations from the Modeling Generation Senior Task Force that can be implemented in the near term while PJM focuses on completion of its next generation energy market (nGEM).
The MGSTF, assembled in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.
The endorsed recommendations include:
adding additional segments to the energy offer curve beyond the 10 currently available to increase resource configuration modeling capabilities; and
providing market participants with the ability to submit hourly differentiated segmented ramp rates for resources in both the day-ahead and real-time markets.
A third recommendation to implement “soak time” modeling of resources was deferred until next month at the request of stakeholders who were concerned about the time and energy it would require. “Soak time” refers to the minimum number of hours a unit must run, in real-time operations, from the generator breaker closure until the time the unit is dispatchable.
FTR Market Update
PJM Chief Risk Officer Nigeria Poole Bloczynski told the MRC that the RTO should do more to assess market participant risk profiles and enhance its collateral practices across all markets — not just FTRs.
“I think it’s best practices to evaluate risk profiles for all participants,” she said. “This is phase 1 of what I think should be a prudent practice of looking at our policies every year or every other year to make sure our policy isn’t static while the market continues to change.”
PJM hired Bloczynski in July after an independent probe of the GreenHat default found the RTO’s executive team lacked credit expertise. She said Thursday she’s hiring four additional staff in her department, including a manager of credit risk and trading risk, and challenging current employees to automate as many processes as possible.
As far as expanding the application of credit risk management beyond the FTR market, PJM will bring corresponding Tariff and OA changes to the MRC for a final vote in January.
Manual 14D: Generator Operational Requirements, adding guidance associated with distributed energy resource ride-through.
Manual 27: Open Access Transmission Tariff Accounting, addressing the implementation of the annual calculation of the border rate and the impact on firm point-to-point transmission service charges.
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.)
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.
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.)
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.
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: June 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.”
PJM’s high-voltage transmission | PJM
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.”
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).
Storage resources’ potential services | NYISO
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.
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.
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.
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.
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.”
