Page 1097 – RTO Insider

October 8, 2020

FERC: NY DR Program Not Exempt from Offer Floor Rule

FERC ruled Wednesday that New York’s Commercial System Distribution Load Relief Programs (CSRP) are not entitled to an exemption from NYISO’s buyer side mitigation (BSM) because they were designed in part to offset transmission investment (EL16-92-001, et al.).

The ruling by FERC Chair Neil Chatterjee and Commissioner James Danly, both Republicans, sparked a dissent from Democratic Commissioner Richard Glick, who said it was the latest example of the commission’s campaign against state clean energy efforts.

The dispute resulted from a paper hearing initiated by the commission in February, when it narrowed the resources exempt from NYISO’s BSM rules in southeastern New York. Granting a rehearing request by the Independent Power Producers of New York, that ruling partly reversed the commission’s 2017 decision granting a blanket exemption from the rules for special-case resources (SCRs), a type of demand response. (See FERC Narrows NYISO Mitigation Exemptions.)

The commission said the blanket exemption ignored the fact that certain payments made to SCRs outside NYISO’s capacity market could provide the resources with the ability to suppress capacity market prices below competitive levels.

The commission said that SCRs’ offer floors should include only the incremental costs of providing wholesale-level capacity services and that “payments from retail-level demand response programs designed to address distribution-level reliability needs” should be excluded from the calculation of SCRs’ offer floors.

The February order initiated a proceeding to evaluate retail-level DR programs individually to determine whether their payments should be excluded.

Wednesday’s ruling concluded that CSRP should be subject to BSM but that payments received under the Distribution Load Relief Programs (DLRP) qualify for exclusion from the calculation of offer floors.

New York demand response — FERC said New York’s Distribution Load Relief Programs (left) are exempt from buyer-side mitigation rules but that Commercial System Distribution Load Relief Programs (right) are not. | *Con Edison*

Under Con Edison’s DLRP, customers receive notification two hours before a DLRP event, which is called to address an isolated need. In contrast, the utility’s customers receive notification at least 21 hours before a CSRP event, which is called in response to system-wide peak demand.

“The record in this proceeding demonstrates that the purpose of the DLRPs under consideration is to maintain distribution-level reliability by reducing distribution system demands in response to contingencies and other emergencies,” the commission said.

“We find, however, that the CSRPs under consideration are not designed to address and do not address solely distribution-level reliability needs, and therefore payments received under those programs must be included in the calculation of SCR offer floors in NYISO. … Both Con Edison and Orange and Rockland state that the CSRPs under consideration provide network load relief to the system during peak hours to address system-wide needs under peak load operating conditions.”

The commission said its case-by-case review of DR programs ensures a balance between the need to protect NYISO’s capacity markets while avoiding inappropriate barriers to DR’s participation in the market.

Glick disagreed, saying the order “once again perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix.”

“Buyer-side market power rules — often referred to as minimum offer price rules or MOPRs — that were once intended only as a means of preventing the exercise of market power have evolved into a scheme for propping up prices, freezing in place the current resource mix, and blocking states’ exercise of their authority over resource decision making,” Glick wrote.

Glick said the majority made “arbitrary distinctions” between different types of retail-level demand response programs.

“The record before us suggests that both DLRPs and CSRPs are retail-level programs directed at distribution system issues. They do so by having retail customers curtail their consumption in order to reduce the stress on particular elements of the distribution system,” he said. “That solves a very different issue than NYISO’s SCR program, which addresses peak demand on and the reliability of the bulk power system by, among other things, calling on demand response to maintain adequate operating reserves. To see that, one need look no further than the fact that the dispatch of DLRPs and CSRPs rarely overlaps NYISO’s SCR dispatch.”

October 8, 2020

9th Circuit Vacates FERC Orders in PG&E PPA Dispute

The 9th U.S. Circuit Court of Appeals on Wednesday vacated two FERC orders that last year threatened to force a jurisdictional standoff with the federal judge overseeing Pacific Gas and Electric’s bankruptcy. The court also vacated an order by the bankruptcy court but declined to resolve the issues at the heart of the dispute.

The conflict goes back to the onset of PG&E’s Chapter 11 proceeding, in January 2019, when FERC issued two declaratory orders saying it shared authority with the U.S. Bankruptcy Court over any of the $42 billion in power purchase agreements that PG&E might seek to modify in bankruptcy (EL19-35, EL19-36). (See FERC Claims Authority over PG&E Contracts in Bankruptcy.)

As part of its bankruptcy filing, PG&E had asked bankruptcy Judge Dennis Montali to issue an injunction confirming his court’s exclusive jurisdiction over the utility’s rights to alter or reject PPAs and other FERC-related agreements.

The issue arose after NextEra and Exelon petitioned FERC for declaratory orders against PG&E because of concern that PG&E would try to get out of high-cost contracts it had signed with owners of solar, wind and other renewable electricity sources.

PG&E PPA Dispute — PG&E headquarters in San Francisco | © *RTO Insider*

FERC acknowledged that the law over conflicts between the Federal Power Act and the Bankruptcy Code was unclear. The commission staked out a compromise position asserting that the commission and courts held “concurrent jurisdiction” over PPAs in cases such as PG&E’s.

Montali initially took a cautious approach to the jurisdiction issue, asking FERC’s and PG&E’s attorneys to reconcile their differences over the matter. But once that effort failed, the judge issued a declaratory judgement stating that FERC had no authority over the contracts and that PG&E did not need commission approval to reject any of them. (See ‘FERC Must be Stopped,’ PG&E Bankruptcy Judge Says.)

The dispute became a moot point in the Chapter 11 proceeding when PG&E chose to honor all PPAs with its suppliers.

Clearing the Path

The 9th Circuit’s r u ling addressed two petitions: one from PG&E to review FERC’s declaratory orders and another from FERC to review Montali’s declaratory judgement.

“The orders all involved the same question: whether a Chapter 11 debtor can cease performing under its wholesale power contracts with the approval of the bankruptcy court, or whether FERC’s consent is also needed,” the three-judge panel wrote.

“We need not — and cannot — reach the merits of this dispute, because the cases became moot when the bankruptcy court confirmed a reorganization plan requiring PG&E to assume, rather than reject, the contracts at issue,” the court found.

The one remaining question: How to treat the “unreviewed” orders?

The judges moved to vacate all three, applying the rule set forth in Munsingwear v. United States, which holds that “[w]hen a case becomes moot on appeal, the ‘established practice’ is to reverse or vacate the decision below with a direction to dismiss.” That decision “clears the path” for any future relitigating of the issues, preserving the rights of all parties involved while prejudicing none of them “by a decision which … was only preliminary.”

The judges noted that all parties involved in PG&E v. FERC agreed the court should vacate the bankruptcy court’s declaratory judgement. However, FERC and the power suppliers protested giving similar treatment to the commission’s orders, asking that they remain in place.

“FERC and the intervenors point out that PG&E proposed assuming the power contracts in the reorganization plan ultimately confirmed by the bankruptcy court. They argue that PG&E’s involvement in this process renders vacatur inappropriate,” the judges noted.

But the court disagreed, saying the circumstances justified vacatur even though PG&E had a hand in mooting its own petition in the matter.

“Importantly, the company did not intend to circumvent our review of FERC’s orders. … Rather, PG&E twice moved for expedited consideration of these cases so that we could resolve them prior to resolution of the bankruptcy proceedings,” the 9th Circuit found. “The company also urged us to hear the cases over FERC’s related ripeness arguments.”

The court went on to point out that PG&E’s actions to moot Montali’s order were in part attributable to “coercion” by the state of California, which required the utility to reach a bankruptcy plan by June 20 in order to become eligible to draw on the state’s $21 billion wildfire liability fund.

The court also found that vacating FERC’s unreviewed orders would prevent the orders from having an adverse impact on PG&E or any other utility in the future.

“At the heart of these cases lies a dispute concerning FERC’s powers over contract performance, including a question of what constitutes a rate change under the filed-rate doctrine and Federal Power Act,” the court wrote. “These issues could well arise outside of bankruptcy. While the orders are declaratory, and we cannot say with certainty how they might affect PG&E or others, we think the better course is to eliminate that concern.”

The court held that its decision did not express any opinion on the merits of the dispute and should not harm FERC, “as it can easily re-assert its position in future proceedings.”

October 6, 2020

ATC Shifts to MISO Allocation Model for Tx Upgrades

After years of using its own generator interconnection cost allocation method, American Transmission Co. will transition to MISO’s after FERC on Monday gave the company its approval.

ATC’s revision will apply to the 2020 cycle of generators interconnecting to its system, or any interconnection request submitted on or after April 29, 2019 (ER20-2619).

MISO currently allocates 90% of necessary transmission upgrades above 345 kV to the generator and 10% to load on a systemwide basis. Costs for upgrades rated below 345 kV are 100% assigned to the generator.

In 2006, MISO adopted a reimbursement approach where 50% of a generator’s network upgrade costs would be repaid to the interconnection customer through credits against transmission service charges, if the customer could prove its generator had been designated as a network resource or held at least a one-year contract to supply capacity or energy. That process was only in effect for three years.

ATC opted not to use the MISO approach. The transmission utility instead used a 100% reimbursement policy for interconnecting generators that could prove they were fulfilling network needs. ATC also never adopted MISO’s 10% postage-stamp allocation for network upgrades 345 kV and above, which replaced the 50% reimbursement procedure in MISO’s Tariff in 2009.

With the commission’s approval, ATC will use the 10% postage-stamp allocation provision and phase out its 100% reimbursement policy. The utility said most MISO transmission owners already use the RTO’s cost allocation approach and that the transition would bring more homogeneity with the RTO’s interconnection procedures. ATC also said its revaluation of cost allocation was prompted by FERC’s recent decision reinstating TOs’ option to self-fund network upgrades. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

Clean Grid Alliance, the American Wind Energy Association and the Solar Council argued against ATC’s proposal, contending the April 2019 effective date violates rules against retroactive ratemaking. They argued that interconnection customers have already entered the MISO queue’s 2020 cycle “with the reasonable expectation that the current cost allocation rules would apply.” The parties pointed out that 45 projects planning to interconnect to ATC entered the 2020 queue cycle and reminded FERC that it previously supported “stability and predictability” in grid operators’ queues.

But FERC said an interconnection customer’s generator interconnection agreement, signed upon completion of MISO interconnection queue studies, should be considered the Rubicon for projects in the queue. ATC’s proposal does not affect existing executed or unexecuted GIAs, the commission said, “because prospective generators in MISO’s 2020 queue cycle are not scheduled to execute GIAs until July 2022, nearly two years in the future.”

October 6, 2020

FERC Denies Complaints vs. Tri-State G&T

FERC on Friday rejected Gladstone New Energy’s complaint that Tri-State Generation and Transmission’s generator interconnection procedures caused the renewable developer to lose its queue position and be assigned network upgrade costs by an “inappropriate” restudy (EL19-97).

The proceeding stemmed from Gladstone’s 2017 interconnection request for a 78-MW wind facility in New Mexico. Tri-State’s final system impact study in 2018 pinned the costs for interconnection facilities and network upgrades at $31.7 million, requiring Gladstone to provide a $7.9 million security deposit.

In April 2018, Gladstone asked Tri-State that its interconnection request be placed into deferral over concerns with the study’s report. The project remained in deferral until September 2019, when Tri-State approved Gladstone’s request to proceed out of deferral. In November, under Gladstone’s protest, Tri-State conducted a system impact restudy. Tri-State filed a facilities study agreement in March, and FERC accepted it, with Gladstone again protesting.

Tri-State complaints — Colfax County, N.M., is home to Gladstone New Energy’s proposed wind facility. | *Lands of America*

FERC rejected Gladstone’s argument that Tri-State “improperly” restudied the project, saying the restudy and the inclusion of a higher-queued project in its allocated costs were just and reasonable.

Gladstone argued that Tri-State’s interconnection procedures were outdated and did not conform with FERC’s large generator interconnection procedures (LGIP). But the commission said events prior to Sept. 3, 2019, were outside of its jurisdiction. Tri-State only became FERC jurisdictional on that date. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.)

The commission also noted that it accepted Tri-State’s proposed LGIP in March, finding them consistent with the pre-jurisdictional procedures that provide projects exiting deferral to be subject to restudy, unless Tri-State deems such analysis unnecessary. FERC said that Gladstone was aware that, as it entered deferral, a restudy was possible once it exited.

October 5, 2020January 24, 2024

Chatterjee, Danly Clash over ‘Regulatory Flexibility’

A seemingly mundane request for a waiver of an SPP Tariff requirement last week prompted a rare philosophical dispute between FERC’s two Republican members (ER20-966).

At issue was a request by Montana-Dakota Utilities for a one-time waiver of a one-year notice requirement for rolling over its network integration transmission service (NITS).

Under SPP’s Tariff, an existing firm transmission customer with a contract of at least five years has the right to continue taking service from a transmission provider when its contract expires, rolls over or is renewed. But the RTO’s rules stipulate that the customer must notify the provider that it is exercising its reservation priority no later than one year before the end of its existing contract.

In May 2016, FERC approved a partial settlement among Montana-Dakota, SPP, the Western Area Power Administration and Basin Electric Power Cooperative that memorialized an agreement among the parties to resolve seams issues related to the integration of WAPA and Basin into the RTO.

One of the issues the partial settlement was intended to resolve was the provision of network customer transmission credits to Montana-Dakota according to section 30.9 of SPP’s Tariff. The settlement also described the terms and conditions of the NITS agreement (NITSA) signed by Montana-Dakota and SPP. The RTO filed the NITSA on July 27, 2016, retroactively effective Oct. 1, 2015, and to expire five years later.

On Oct. 19, 2019, Montana-Dakota submitted revisions to the NITSA to include additional facilities eligible for the section 30.9 credits. While that revised NITSA was still pending before FERC, the utility was notified by SPP on Jan. 28, 2020, that its original NITS was set to expire on Sept. 30. Montana-Dakota said it contacted SPP the next day to express its wish to roll over the NITS. Because the service was set to expire Oct. 1, Montana-Dakota had been required to notify SPP on Oct. 1, 2019, but the utility said SPP had been on notice of the utility’s intent to do so throughout negotiations for the revised NITSA.

Montana-Dakota contended that it met the four criteria laid out by FERC for granting Tariff waivers: that it acted in good faith; that the waiver is limited in scope; that it solves a “concrete problem”; and that it does not harm third parties.

The utility said it incorrectly assumed that the NITSA was effective as long as the partial settlement remained in effect and that it was unaware SPP’s Tariff required it to provide notification of its intent to roll over. It said the waiver would protect it from substantial network upgrade costs that it and its customers would incur in obtaining new NITS.

Both WAPA and Basin said they supported the waiver; SPP said it did not oppose the request.

In a brief finding, Chairman Neil Chatterjee and Democratic Commissioner Richard Glick voted to grant the waiver, agreeing that Montana-Dakota’s request met FERC’s four requirements. “Montana-Dakota’s failure to comply with the current one-year notice requirement appears to have been inadvertent, and Montana-Dakota states that it notified SPP the day after it was informed that it missed the deadline, providing SPP with notice approximately eight months prior to expiration of its NITSA,” they said.

No Authority

More substantial than the order itself was the dissent issued by Commissioner James Danly, along with a concurrence from Chatterjee that firmly faulted Danly’s legal reasoning.

In his dissent, Danly argued that the commission lacks the authority to grant such a request. “Even if we were to put that infirmity aside, Montana-Dakota’s request fails our four-factor test,” he added.

FERC Commissioner James Danly at his confirmation hearing in November 2019 | © RTO Insider

Danly wove a complicated legal argument that left open the question what latitude — if any — that FERC has in approving waiver requests. He argued that the filed rate doctrine and FERC’s rule against retroactive ratemaking restrict the commission’s ability to grant retroactive waivers. He noted that while those doctrines were developed in cases regarding utility rates, the logic of the doctrines “applies equally” to non-rate tariff cases.

“Because a waiver request is in essence a request that the commission permit a one-time change to a tariff provision, the commission is legally barred by the filed rate doctrine and the rule against retroactive ratemaking from granting a retroactive waiver request unless one of two judicially recognized exceptions applies: (1) the parties had notice that the tariff provision could be waived retroactively; or (2) the tariff provision is embodied in a private contract between the parties, who have agreed in that contract to make the agreed-upon rate effective prior to filing that contract with the commission. Neither of these exceptions apply here,” Danly said.

He said that while the commission “may enjoy some latitude to interpret this precedent,” it must “at least acknowledge that its authority to grant such a waiver is at issue and then identify the source of its legal authority to approve the request.” FERC had failed to meet that standard in the Montana-Dakota docket, he argued.

But even if FERC had the authority to grant the waiver, Danly said Montana-Dakota failed the four-factor test because the utility asserted that the waiver would maintain the status quo through its ability to continue to take NITS to serve its load and maintain the long-term benefits of the partial settlement for the utility and SPP members.

“But the fact that granting the waiver preserves the status quo is exactly why the waiver harms third parties,” Danly argued.

“Preserving the status quo for Montana-Dakota when application of SPP’s tariff would cause it to lose its rollover rights will cause entities that have submitted requests for service to incur substantial network upgrade costs to obtain service to which they would otherwise be entitled absent the waiver, or else be denied service,” Danly said. “The record does not inform us as to the number of requests that would be affected by granting this waiver. Nevertheless, even in the absence of that evidence, we know, based on Montana-Dakota’s own submission, that the request must run afoul of the no-harm-to-third-parties factor.”

Danly said he recognized that denying the request could have “serious consequences” for Montana-Dakota in the form of network upgrade costs passed on to its customers, which “would only have been exacerbated” by FERC’s “inexcusable” eight-month delay in acting on the request, preventing the utility from meeting SPP’s May deadline for participating in the transmission open season.

“Though Montana-Dakota and its customers may be due sympathy, to ignore the consequences of the waiver to other utilities is to take a one-sided view of the equities,” Danly said.

‘Regulatory Inflexibility’

“The dissent, at its core, argues for an approach to waiver requests that requires flawless adherence to all administrative tariff deadlines and denies the commission a modicum of regulatory flexibility to address ministerial or inadvertent errors on a case by-case basis,” Chatterjee countered in his concurrence. “Such an approach ignores the business realities facing public utilities. And it harms consumers. Recent challenges posed by the COVID-19 pandemic have underscored the value of regulatory flexibility when circumstances warrant.”

FERC Chairman Neil Chatterjee | © RTO Insider

Chatterjee noted that Danly acknowledged the potential harm to Montana-Dakota customers and said that neither the Federal Power Act nor the filed rate doctrine require such an outcome for an “inadvertently” missed administrative deadline where there is no evidence of harm to third parties.

“The dissent does not sufficiently grapple with the record evidence here that granting the instant waiver not only will avoid harm to customers of Montana-Dakota, but also will avoid harm to specific third parties,” Chatterjee wrote.

The chairman cited WAPA’s comments that failure to grant the waiver could jeopardize the partial settlement, which preventing pancaked rates for WAPA’s Upper Great Plains Region, Basin Electric members and other load-serving entities in the Upper Missouri Zone.

Danly shot back regarding Chatterjee’s criticism of the dissent’s “regulatory inflexibility.”

“It is the law that denies us that regulatory flexibility, inadvertency and circumstance-specific challenges notwithstanding,” Danly said. “To deny a waiver under circumstances such as these might appear inflexible. But the doctrines that constrain us make no allowance for such considerations.”

October 5, 2020

Laura Pricing Has MISO Stakeholders Scratching Heads

A briefing by MISO staff last week on the record uplift in the RTO’s energy market caused by Hurricane Laura left stakeholders with more questions than answers.

During a joint meeting of the MISO Markets and Reliability subcommittees, staff recounted the events of Aug. 27, when the Category 4 hurricane made landfall in Louisiana, just east of the state’s border with Texas, damaging about 120 transmission lines and leaving about 730,000 customers in the area without power. (See MISO Keeps Advisories in Effect a Week After Laura.)

The storm caused a unique situation that resulted in nearly $90 million in uplift payments, a record high for the RTO. Though Laura itself barely touched MISO’s Texas footprint — with little rain, wind or even cloud cover, according to the RTO — the hurricane sliced across the West of the Atchafalaya Basin (WOTAB) load pocket, which straddles the Louisiana-Texas border. This created a new load pocket in Texas within WOTAB, which staff variously referred to as the “western load pocket” and the “Hurricane Laura load pocket subarea.”

MISO Hurricane Laura — Hurricane Laura damaged scores of transmission lines as it roared through Louisiana just east of the state’s border with Texas, creating a new load pocket in MISO’s Texas footprint. | *MISO*

Only three high-voltage transmission lines were available to serve load in the new pocket because of the storm, and the largest, rated at 500-kV, eventually tripped. This led MISO to direct Entergy to shed about 573 MW of load in the pocket, centered around The Woodlands, about 30 miles north of Houston.

MISO’s Tariff requires emergency pricing for load-shedding events, with each node in the affected area set at the value of lost load (VoLL), $3,500/MWh. But according to staff, the RTO’s pricing software does not allow for an area as small as the new load pocket to be automatically priced at VoLL, requiring staff to spend more than 1,000 hours over two weeks manually entering the prices after-the-fact.

Staff said they were confident that MISO followed the Tariff appropriately, and stakeholders did not dispute that. They did question, however, the rationale for pricing what were presumably “dead buses” in the load-shed area.

Stakeholders also expressed confusion over the different labels for the load pocket, the timeline of events and the map provided by staff. They asked that MISO provide clarifications and a more detailed map that included the nodes that were affected and the three remaining transmission lines.

MISO said it would provide such clarifications at the subcommittees’ meetings next month, and that staff will be prepared to discuss lessons learned and potential policy changes.

October 5, 2020

NEPOOL Participants Committee Briefs: Oct. 1, 2020

ISO-NE will ask FERC to exempt energy efficiency resources from capacity performance payments, although the proposal failed to win an endorsement from the New England Power Pool Participants Committee on Thursday.

The proposal received a 58% sector-weighted vote of the PC, short of the 60% endorsement threshold, with unanimous dissent from the End User sector and all 49 Publicly Owned Entity members abstaining from the vote. The Generation, Transmission, Supplier and Alternative Resource sectors supported the change. Last month, the NEPOOL Markets Committee also failed to endorse the proposal along similar voting lines. (See NEPOOL Stakeholders Split over PfP for EE.)

However, the Participants Committee did endorse a related measure to revise the Financial Assurance Policy to exclude EE capacity supply obligations from the calculation of capacity financial assurance requirements. The motion passed with a 79% vote in favor.

The RTO says capacity performance bonuses should be limited to those resources whose performance could be at risk during a capacity shortage. The change is a recognition that EE resources permanently reduce energy consumption and have no real-time performance measures, officials said.

Other Actions

In other action, the committee approved:

Revisions to Operating Procedures 17 and 21. The changes to OP-17 spell out in more detail the ranges of acceptable load power factors for sections of the New England Control Area and the responsibilities of ISO-NE, transmission owners and transmission customers. The revisions to OP-21 incorporate the annual generator winter readiness survey process and the yearly natural gas critical infrastructure survey, intended to ensure the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.
Hydro-Québec interconnection capability credits and installed capacity requirement values for Forward Capacity Auction 15. The HQICC is 883 MW for each month of the 2024/25 capacity commitment period (June through May). The ICR is 34,153 MW, with a net ICR of 33,270 MW.
The 2021 operating and capital budgets for ISO-NE and the budget for the New England States Committee on Electricity (NESCOE). The RTO’s proposed operating budget is $178.6 million, a 2.5% increase from 2020, excluding FERC Order 1000 funding and before depreciation. Its full-time headcount remains unchanged at 587. The RTO’s capital budget is unchanged from 2020 at $28 million. NESCOE’s $2.4 million budget for next year is below the $2.5 million projected in its five-year pro forma budget.

In executive session, the committee also:

approved an extension and amendment to the Generation Information System Administration Agreement between NEPOOL and APX; and
approved the hiring of former National Grid executive Peter Flynn as a project administrator for the Future Grid Study and Rutgers University professor Frank Felder as a consultant on the “Transition to the Future Grid.”

Pathways Process Continues

Felder and Kathleen Spees of The Brattle Group each made presentations on “Potential Pathways to the Future Grid,” with Spees exploring the “Integrated Clean Capacity Market” and Felder the “Focus on Forward Clean Energy Market and Carbon Pricing.”

Spees said any useful path forward for New England will have to meet both resource adequacy needs and state policies supporting emission-free generation. She said that the Integrated Clean Capacity Market would be a three-year forward market that attracts the optimal resource mix for reliability and state policy goals. By co-optimizing procurement of unbundled capacity and unbundled clean energy attribute credits, it would be a “fit-for-purpose market for achieving the 80 to 100% clean electricity future,” she said.

Felder told the committee that the goal of his project is to achieve “a common understanding” that defines potential future pathways and the variations and tradeoffs among them.

He said while co-optimizing the Forward Clean Energy Market (FCEM) and Forward Capacity Market (FCM) would “in theory … maximize the social surplus of meeting states’ clean energy objectives and regions’ resource adequacy requirements … it is not clear if [it] can be implemented in practice.”

Without co-optimization, resources offering into the FCEM will have to estimate their expected revenues in the FCM, and if those estimates are incorrect, inefficient outcomes may result.

Felder added that to achieve significant carbon reductions, the emission cap for the Regional Greenhouse Gas Initiative must be “substantially reduced so that prices of emission allowances are close to the” social cost of carbon. Low and non-emitting carbon resources offering into the FCM have larger margins and recover more of their fixed costs in the energy market, enabling them to be more competitive.

CEO, COO Reports

ISO-NE CEO Gordon van Welie briefed the PC on the Board of Directors’ direction to management to prioritize the evaluation of “net carbon pricing” and an FCEM, which he discussed at FERC’s Sept. 30 technical conference on carbon pricing. (See related story, FERC Urged to Embrace Carbon Pricing.)

NEPOOL — ISO-NE CEO Gordon van Welie | © *RTO Insider*

In prepared remarks to the FERC conference, van Welie said the primary tool for New England states “to effect rapid decarbonization has been to sponsor clean energy resources outside of the wholesale markets, which make the owners of these resources largely indifferent to market prices.” He added that the RTO “has long advocated for carbon pricing as a solution that allows markets to efficiently price emissions without harming price formation.”

Van Welie said the RTO recognizes “that any solution requires a coordinated effort with state and federal policymakers and our stakeholders. Many policymakers are concerned that carbon pricing will lead to cost increases in the wholesale markets. We believe that those increases will be significantly offset by reductions in state programs. Furthermore, we can implement a ‘net carbon pricing’ methodology whereby the emissions fees on resources are automatically rebated to wholesale buyers through our wholesale settlements systems, thereby minimizing the cost impact.”

In his committee report, ISO-NE Chief Operating Officer Vamsi Chadalavada said that the energy market value was $158 million in September, a nearly 50% drop from August and down $53 million from September 2019.

Chadalavada added that development of the 2021 Regional System Plan will start in the first quarter. He said improvements to streamline the plan are underway and include a webpage for economic studies and enhanced environmental and emissions information.

According to Chadalavada, FCA 15 values will be filed with FERC no later than Nov. 10, and 2021 annual reconfiguration auction values will be filed by Dec. 1.

Draft of ISO-NE 2021 Annual Work Plan Discussed

Chadalavada also presented a draft of ISO-NE’s 2021 Annual Work Plan for “innovating for the changing grid; adjusting to impacts of recent events; advancing operational improvements; and managing risks.”

In addition to the Future Grid project, the RTO’s major initiatives will include elements of the Energy Security Initiative, transmission planning for an evolving grid and evaluating the impact of shifting net peak loads.

The RTO also will be reviewing lessons learned from its first competitive transmission solicitation; working on improvements to operational and long-term planning forecasts, including the impact of the COVID-19 pandemic; and moving the financial transmission rights market to a clearinghouse.

Chadalavada also cited upcoming upgrades to the nGEM day-ahead market clearing software and capital projects to protect against increased hacking attempts.

October 5, 2020January 25, 2024

FERC Approves GIAs, Rejects OG&E Challenge

FERC last week accepted two previously rejected unexecuted generator interconnection agreements between SPP, Oklahoma Gas & Electric (OG&E) and a pair of wind farms (ER20-2544, ER20 –2545).

The two wind facilities, Frontier Windpower II and Chilocco Wind Farm, were part of SPP’s 2016 definitive interconnection system impact study (DISIS). Staff performed five restudies following the initial DISIS as projects dropped out of the GI queue or interconnection points were re-designated.

The fourth restudy identified Wolf Creek-Emporia as a shared network upgrade needed to accommodate the cluster’s interconnection requests. However, the ensuing restudy indicated the upgrade was no longer needed following the Board of Directors’ 2019 approval of the Wolf Creek-Blackberry competitive transmission project.

The latter project is now waiting on FERC approval to proceed. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)

SPP revised the original GIAs to remove the Emporia upgrade. It said it filed the unexecuted agreements because OG&E disagreed with the proposed cost allocations, which did not allocate any Blackberry project costs to the wind facilities.

FERC rejected the GIA filings in April, saying their cost allocations were unjust and unreasonable because they were based on the Emporia upgrade. In approving the revised GIAs on Sept. 28, it noted they no longer contain the Emporia upgrade and include the Blackberry project as a contingent facility.

The commission reiterated its position that SPP did not violate its Tariff in performing the fifth restudy, pointing out that 13 higher or equal priority queued interconnection customers had dropped out. FERC disagreed with OG&E’s argument that SPP violated the commission’s interconnection-related pricing policy and cost-causation principles by proposing not to assign Blackberry’s costs to the DISIS group.

“SPP’s proposed cost allocation for the Blackberry project is consistent with the [Tariff’s] requirements for cost allocation,” the commission said.

FERC last week also responded to OG&E’s request to rehear the April order on Frontier II, which was automatically rejected when the commission did not respond within 30 days. The commission provided additional discussion but came to the same conclusion (ER19-2747).

OG&E had argued that FERC “failed to support with substantial evidence” its finding that SPP was allowed to undertake the fifth restudy when some of the projects were withdrawn. The commission declined to address the complaints.

The utility also contended that FERC erred by agreeing with an earlier mistaken SPP statement that a planning assessment justified the fifth restudy, arguing that the assessment contained improper assumptions that cause it to ignore the Frontier project’s impact. The commission reminded OG&E that it found the fifth restudy was not flawed, and it said the utility failed to provide evidence supporting its allegations that SPP never provided “specific assumptions” including in the planning assessment.

Frontier II, at 350 MW, is the largest wind project in Duke Energy Renewables’ fleet. It will be paired with the 200-MW Frontier I, which has been operational since 2016.

October 5, 2020

PacifiCorp Faces Class Action over Wildfire Response

Three Northwest law firms last week filed a class action suit against PacifiCorp alleging the utility failed to de-energize power lines that contributed to a set of devastating blazes ignited in Oregon during the Labor Day weekend.

The development highlights the pressures Western utilities increasingly confront as wildfire dangers grow in length and scope, impacting areas previously not prone to the kind of fast-moving conflagrations that have plagued California in recent years.

It also illustrates the tightrope utilities must walk when deciding whether to invoke public safety power shutoffs (PSPS), the policy of pre-emptively shutting down lines to prevent sparking fires in high-risk areas.

The lawsuit, filed with the Multnomah County Circuit Court on Thursday, contends that Portland-based Pacific Power and its parent company PacifiCorp ignored warnings of hot, dry winds coupled with “extremely critical fire conditions” on Sept. 7, leaving lines energized in high-risk fire areas even as other Oregon utilities proactively cut power to avoid igniting trees and brush in the state’s extensive and towering forests.

An unusual wind storm with easterly winds swept the state Labor Day evening, toppling a number of those lines, sparking fires that rapidly swept through the Clackamas, Santiam, McKenzie and Umpqua canyons, as well as other parts of Oregon, the complaint contends.

“Defendants’ energized power lines ignited massive, deadly and destructive fires that raced down the canyons, igniting and destroying homes, businesses and schools,” the complaint says. “These fires burned over hundreds of thousands of acres, destroyed thousands of structures, killed people and upended countless lives.”

PacifiCorp wildfire response — Ruins of the Lyons, Ore., home of the lead plaintiffs in the class action suit filed against Pacific Power and PacifiCorp | *Jeanyne James/Robin Colbert*

As evidence of Pacific Power’s culpability, the lawsuit cites a Northwest Incident Management Team (NIMT) report on Sept. 10 stating that downed lines on Sept. 7 sparked at least 13 fires along a nearly 30-mile stretch of the Santiam Canyon from the town of Detroit west to Mehama. The following day, the ferocious, wind-driven Beachie Creek Fire overran Detroit from the east and ultimately grew to more than 190,000 acres after merging with a separate blaze originally dubbed the Santiam Fire.

The lead plaintiffs in the suit, Jeanyne James and Robin Colbert, lived in the Santiam-area town of Lyons. The couple lost their home, four cars, a garage full of collectibles and tools, and nearly all their personal belongings, according to the suit, which seeks to represent other residents who suffered similar losses.

The complaint cites statements from an NIMT commander, who recounted during an early September press conference that a fire team stationed at the Old Gates School in Gates, east of Lyons, witnessed power lines fall near the school around 9:45 p.m. on Labor Day, sparking a fire that burned down the incident command post. Firefighters and other witnesses saw downed lines ignite fires in other parts of Gates, the complaint notes.

Pacific Power “could have de-energized their power lines during the critical and extremely critical fire conditions, at little to no cost to defendants, and thereby fully eliminate the risk of fire caused by power lines,” the complaint says.

Instead, the utility acknowledged that the Santiam area was not in its PSPS area and only de-energized lines at the request of local emergency agencies, the suit said.

PacifiCorp said it does not comment on pending litigation.

‘No Small Matter’

The filing of the class action Thursday coincided with a special meeting of the Oregon Public Utility Commission on utility responses to the Labor Day wind storm and subsequent fires. Testimony illustrated the complications utilities face when deciding whether to call for shutoffs in high-risk areas. It also demonstrated the differences between the responses of the state’s two big investor-owned utilities, Pacific Power and Portland General Electric.

Pacific Power CEO Stefan Bird said the utility introduced PSPS in its planning in 2018 “as a last resort in extreme weather conditions in specific high fire-risk areas of our service territory.”

“We understand it’s no small matter to consider turning the power off for an entire community, and that such an action needs to take in consideration the risks that imposes to critical emergency services that rely on power, such as hospitals, 911 communications, water supply and vulnerable customers that rely on power to meet their medical requirements,” Bird told commissioners.

David Lucas, Pacific Power’s vice president of operations, said conditions on the utility’s system “did not meet protocols” for using PSPS in its high fire-risk areas. However, a map on Pacific Power’s website shows the Santiam Canyon is not even located near any of the utility’s PSPS zones.

“Similar to our colleagues at PGE,” Lucas said, “we did de-energize lines at the request of local emergency agencies to allow firefighters to do their job safely and to assist in removing debris to unblock roadways.” He said utility staff took those actions in the Medford area, about 235 miles south of the Santiam Canyon.

“We know public safety power shutoffs are often a focus when the public hears about utility wildfire mitigation; however, this is only one tool in a utility’s toolbox,” Lucas said. “And as we’ve learned through extensive local community engagement, public safety power shutoff events must be properly planned and coordinated so that a loss of power does not have unintended consequences of actually increasing public safety risk.”

Unlike Pacific Power, PGE did pre-emptively de-energize lines on Labor Day in anticipation of the wind storm, shutting power to about 5,000 customers near Mount Hood in what was the first PSPS event to affect Oregon residents. (See High Fire Danger Prompts First Oregon PSPS Event.)

During the PUC call, PGE Vice President Larry Bekkedahl said the utility was under a “heightened level of alert” in the week before the weather event, prompting it to contact customers and community leaders to plan for a potential PSPS, including relocating “medically fragile” residents.

“This was not a decision we took lightly, as we recognized the hardships that the loss of power presents to many customers,” Bekkedahl said. “On [Labor Day] evening, I made the decision to de-energize in the highest-risk section of our service area” near Mount Hood. PGE subsequently de-energized lines in eight other areas, including towns threatened by both the Beachie Creek and Riverside fires, which at one point threatened to merge.

While the lawsuit does not mention PGE’s actions, it does note that the Eugene Water & Electric Board (EWEB), which serves a territory about 70 miles south of the Santiam area, pre-emptively de-energized lines during the storm.

The complaint noted that EWEB spokesman Joe Harwood told The Register –Guard on Sept. 9 that “I know people weren’t happy, but the idea was not to be the cause of a fire.”

October 5, 2020March 6, 2026

Overheard at NECA 2020 Fuels Conference

The Northeast Energy and Commerce Association’s Fuels Conference on Wednesday tackled the subject of natural gas bans by local governments, questioning whether they are necessary for the “transition to a clean energy future or major government overreach with unintended consequences.”

Judy Chang, undersecretary of energy in the Massachusetts Executive Office of Energy and Environmental Affairs, said that the transition away from natural gas “is not going to be easy,” noting that gas demand has increased amid decarbonization efforts and that it is used for both heat and electricity.

“New England has very cold winters, and approximately 50% of our households heat with natural gas, and that number has been increasing,” Chang said. “In addition, we are at the end of long pipelines.”

Regulatory Assistance Project principal Richard Cowart concurred, saying, “Phasing out natural gas is probably the most challenging climate policy topic” he has encountered in nearly 30 years of working to decarbonize the power sector.

“I just think [natural] gas is going to be harder,” Cowart said. “The automobile fleet is easier than converting buildings away from fossil fuels, but climate science tells us it has to be done.”

Cowart said gas utilities need new business models and a regulatory transformation as well. “I went through electric industry restructuring, and this is starting to feel a lot like that.”

Clockwise from top left: Tamara Small, NAIOP Massachusetts; Paul Hibbard, Analysis Group; Albert Wynn, Greenberg Traurig; Judy Chang, Massachusetts Executive Office of Energy and Environmental Affairs; Richard Cowart, Regulatory Assistance Project | NECA

Cutting away quickly from fossil fuels like natural gas is not possible, according to Cowart. “Cold turkey is not on the menu,” he said. “We can only exit traditional fossil gas and oil as quickly as we can add renewable electricity, perhaps some clean gases, heat pumps and building renovations.”

Tamara Small, CEO of NAIOP Massachusetts, which represents companies involved in commercial real estate, said that her organization recognizes the effects of climate change, and its 1,700 members embrace projects designed to reduce carbon emissions. Small said any transition away from fossil fuel needs to be done in a “phased approach,” especially in new construction.

“Banning the use of natural gas for new construction means that residents will be paying for electric stoves and other electric appliances that drive up individual utility costs and may burden residents who cannot afford large increases,” Small said. “Energy efficiency needs to go hand in hand with electrification, but there is still a cost impact.”

Paul Hibbard, principal at Analysis Group, said he has not seen “careful economic analysis or assessment of what is the pathway” to reaching net-zero carbon emissions by 2050.

“The most difficult part of decarbonization is putting a pin on the board about when we need to be all-electric in buildings. [It] will be important to provide that runway … to get carbon reductions going much sooner,” Hibbard said.

Tepper Talks About Mass. DPU Petition

Nearly two years after a series of explosions and fires in natural gas lines just outside of Boston in September 2018, the Massachusetts Attorney General’s Office filed a petition with the Department of Public Utilities to investigate the future of the industry as the state “transitions away from fossil fuels and toward a clean, renewable energy future by 2050.”

Rebecca Tepper, the chief of the office’s Energy and Telecommunications Division, said during a keynote speech that “numerous audits and reports” showed how vulnerable the “whole state gas system is.”

“If we sit back and do not plan for how to manage this transition, we will repeat the mistakes of the past, and vulnerable communities will be the ones who suffer,” she said.

Shaela Collins of Columbia Gas (left), and Rebecca Tepper, Massachusetts Office of the Attorney General | NECA

The first phase of the investigation, Tepper said, should require gas companies to submit detailed economic analyses and business plans that project the state’s future gas demand, including potential revenues, expenses and investments, and input from stakeholders on necessary regulatory, policy and legislative changes. The second phase should focus on developing and carrying out the changes required in a way that protects the state’s gas consumers.

“It’s critical that we start planning this now, and that we include all stakeholders in our process,” Tepper said. “I feel like we are at a crossroad. It’s not unlike where we were in restructuring, and we need to work together as a stakeholder community to figure this out.

“We’re not alone in Massachusetts thinking about this,” she said. The petition points to similar actions in New York, where an investigation was opened in March to ensure more useful and comprehensive planning for natural gas usage and investments, and California, which started a proceeding this year to examine the safety and reliability of its natural gas infrastructure, while the state focuses on achieving its long-term decarbonization goals.

“This transition is happening; it’s happening faster than even we thought it would, so neither the status quo nor kicking the problem down the road is going to work,” Tepper said. “This is the time. Not five years or 10 years from now.”

Renewable Natural Gas Opportunities

Judith Judson, Ameresco’s vice president of distributed energy systems, said that the Northeast has a chance to be an early leader in renewable natural gas.

Judson said that Ameresco had discussions with utilities in the Northeast on adding RNG from landfills, waste-water treatment plants or large waste-producing farms to their supply portfolios.

Clockwise from top left: Rick Sullivan, Economic Development Council of Western Massachusetts; Judith Judson, Ameresco; Zach Chapin, Dominion Energy; and Edson Ng, G4 Insights | NECA

“In terms of carbon emissions, it’s considered carbon neutral,” Judson said. “There are a growing number of studies that [RNG] is cost-effective relative to other decarbonization options for heating.”

RNG can be delivered through existing infrastructure without any further capital investment, she said, and it is a baseload, dispatchable renewable fuel source to support resilience objectives.

Judson said that an “economy-wide perspective” is needed to meet carbon goals in a “cost-effective way,” and RNG should be a part.

Looming Mystic Closure Reduces Flexibility

Jake Anderson, head of gas and power fundamentals analysis at Macquarie Energy, said during his keynote that the announced retirement of Exelon’s Mystic Units 8 and 9 “reduces flexibility” for New England gas markets.

Jake Anderson of Macquarie Energy (left) and Jonathan Carroll, Énergir | NECA

Asked if there will be renewed interest in gas storage development from independent or pipeline-affiliated companies, given the gap in storage capacity and production volume, Anderson said, “it’s a tough environment for building storage because the costs haven’t necessarily come down all that much.”

Regardless of the economics, Anderson added, if gas demand grows and LNG terminals need storage, “we’re going to see at some point a resurgence of storage building; it’s just a question of when and how quickly.”