Page 1034 – RTO Insider

October 8, 2020

CAISO Says Constrained Tx Contributed to Blackouts

A report on the causes of California’s August blackouts details for the first time the role that convergence bidding played in masking tight supply and contends that constrained transmission prevented much needed imports from reaching the state.

The 107-page report to Gov. Gavin Newsom by CAISO, the California Public Utilities Commission and the state Energy Commission blames previously discussed causes, including extreme heat induced by climate change and inadequate resource planning. And it expands on the allegation, mentioned in passing at recent CAISO meetings, that load-serving entities failed to anticipate their needs when scheduling in the day-ahead market.

“We have identified several factors that, in combination, led to the need for the CAISO to direct utilities in the CAISO footprint to trigger rotating outages,” the organizations wrote. “There was no single root cause of the outages, but rather, a series of factors that all contributed to the emergency.”

The rolling blackouts were the first to sweep the state since the energy crisis of 2000-2001. Over two days, about 812,600 households — representing about 2.4 million people — lost power.

Outmoded RA Planning

In an expected finding, CAISO said the state was unprepared to meet the extreme Western heat wave of Aug. 14-19 and that resource planning now must assume there will be similar events caused by climate change.

During the mid-August “heat storm,” California experienced four out of the five hottest August days since the ISO and the CEC began tracking such data in 1985, the report said. The organizations use an average daily temperature composite to predict electricity consumption across the CAISO region.

“Current resource adequacy planning standards are based on a one-in-two peak weather demand plus a 15% [planning reserve margin] to account for changing conditions,” the report said.

CAISO blackouts — The 2020 heat storm was a one-in-35-year event, the California Energy Commission said. | *CEC*

But the August heat wave was a one-in-35-year event “not anticipated in the planning and resource procurement time frame, which is necessarily an iterative, multiyear process.” The state needs more supply resources, including battery storage for wind and solar, and must use new planning criteria for long-term projections, it said.

The rolling blackouts were made worse by transmission constraints and other causes, but “it is unlikely that current RA planning levels would have avoided rotating outages” under the same conditions, even without those contributing factors, it said.

Constrained Supply

Import bids in the day-ahead market were 40 to 50% (2,600 to 3,400 MW) higher during the August energy emergency than typical RA requirements from imports in August, but the output couldn’t get where it need to go, the organizations said.

“Despite this robust level of import bids, transmission constraints ultimately limited the amount of physical transfer capability into the CAISO footprint,” the report said.

A major transmission line in the Pacific Northwest upstream from CAISO was on forced outage because of weather conditions, and the California Oregon Intertie (COI) was derated, the report said.

“The derate reduced the CAISO’s transfer capability by approximately 650 MW and caused congestion on usual import transmission paths across both COI and Nevada-Oregon Border,” it said. “In other words, more imports were available than could be physically delivered, and the total import level was less than the amount the CAISO typically receives.”

Under-scheduling

CAISO said LSE scheduling coordinators “collectively under-scheduled their demand for energy by 3,386 MW and 3,434 MW below the actual peak demand for Aug. 14 and 15, respectively.”

During the net peak — the hours after solar goes offline but demand remains high on hot days — LSEs under-scheduled demand by 1,792 MW for Aug. 14 and 3,219 MW for Aug. 15, the ISO reported. The blackouts on those days occurred in the net-peak hours.

“The under-scheduling of load by scheduling coordinators had the detrimental effect of not setting up the energy market appropriately to reflect the actual need on the system and subsequently signaling that more exports were ultimately supportable from internal resources,” the report said.

CAISO said its own peak forecasts were 825 MW below actual demand for Aug. 14 and 559 MW above actual demand for Aug. 15. Its forecasts for the net demand peak times were 511 MW and 632 MW above actual demand.

But during the mid-August events, “it was difficult to pinpoint these contributing causes because processes that normally help set up the market masked the under-scheduling,” the report said.

One of the processes was convergence bidding, a financial hedge that some observers believed could have been used to game the market.

“As the name suggests, convergence bidding is intended to allow bidders to converge or moderate prices between the day-ahead and real-time markets,” the report said. “Under normal conditions, when there is sufficient supply, convergence bidding plays an important role in aligning loads and resources for the next day. However, during Aug. 14 and 15, under-scheduling of load and convergence bidding clearing net supply signaled that more exports were supportable.”

“Once this interplay was identified on Aug. 16 after observing the results for trade day Aug. 17, convergence bidding was temporarily suspended for Aug. 18 trade date through the Aug. 21 trade date,” it said.

During those days, when conditions remained much the same as Aug. 14-15, further blackouts were averted.

RUC Flaw

The report also delved into complications stemming from a flaw in CAISO’s residual unit commitment (RUC) process. The ISO runs the RUC after the day-ahead Integrated Forward Market (IFM) process to avoid real-time supply shortages in rare cases when LSEs under-schedule demand.

The report notes that inputs into the RUC process differ from the outputs of the IFM in three ways:

Load cleared in the IFM is replaced by CAISO’s own day-ahead forecast, which does not include exports.
Wind and solar schedules cleared in the IFM are replaced by CASO’s wind and solar forecasts.
Virtual supply and demand that cleared in the IFM’s convergence bidding market are removed.

The RUC itself consists of two passes: a scheduling run intended to address any unresolved market constraints based on “an intricate but prescribed set of relative priorities” for relaxing the constraint or curtailing schedules; and a pricing run to produce prices that align with both the $1,000/MWh bid cap and the scheduling run.

To ensure that schedules produced by the IFM are physically feasible, the RUC process enforces a power balance constraint to ensure that forecast load can be met in real time.

In 2014, CAISO implemented the Pricing Inconsistency Market Enhancement (PIME) to address inconsistencies between schedules and prices. PIME redirected both the IFM and the RUC to use pricing run results as the source of both prices and schedules.

“Through these RUC constraints, the CAISO determines what portion of the day-ahead schedules are physically feasible and which portion that market participants should tag when the E-Tag is submitted in the day-ahead,” the report said.

After the Aug. 14 and 15 blackout events, CAISO determined that rather than reducing the volume of infeasible exports scheduled in the IFM, the RUC pricing run instead relaxed the power balance constraint, compromising the ISO’s ability to meet actual load. But the ISO found that the RUC’s scheduling run (no longer used to set final schedules) would have relaxed the IFM’s scheduled exports before relaxing the power balance constraint.

As a result, CAISO said it stopped using the PIME functionality in its RUC process beginning Sept. 5, allowing it to use scheduling run results for RUC schedules rather than pricing run results.

October 8, 2020

FERC Approves SPP-AECI Competitive Project

FERC on Wednesday approved a cost-and-usage agreement between SPP and Associated Electric Cooperative Inc. (AECI) that could result in the RTO’s first competitive project under Order 1000 (ER20-2707, ER20-2708).

The letter order accepted the terms and conditions governing the construction, ownership, operation and cost for the installation of 345-kV terminal equipment at AECI’s existing Blackberry substation, the endpoint for SPP’s 109-mile, 345-kV Wolf Creek-Blackberry transmission project. It also accepts Tariff revisions to include the substation’s construction costs in each SPP transmission owner’s respective annual transmission revenue requirement.

“We were glad to see that outcome,” Neil Robertson, SPP’s interregional relations senior engineer, said in breaking the news Wednesday morning to the Seams Steering Committee.

The Wolf Creek-Blackberry project is expected to cost $152 million. SPP members will fund the line according to load-ratio share. The RTO’s Board of Directors last month lifted a suspension on the project and authorized the Oversight Committee to create an industry expert panel (IEP) to evaluate responses to a request for proposals, which staff have since issued. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)

SPP awarded its first competitive project in 2016 to Mid-Kansas Electric, but the project was later canceled because load projections dropped over time. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

A third competitive project has already been evaluated by an IEP and will be brought before the board for its consideration in October.

October 8, 2020

FERC Report Outlines CIP Compliance Recommendations

In its latest round of Critical Infrastructure Protection (CIP) audits, FERC noted registered entities have made significant progress in meeting or exceeding the reliability standards’ mandatory requirements.

However, the commission still noted several “potential compliance infractions” and other areas for improvement.

FERC’s “Lessons Learned from Commission-Led CIP Reliability Audits” report is based on audits carried out during the federal government’s 2020 fiscal year, which began on Oct. 1, 2019, and ended Sept. 30. The number of audits performed, which also involved staff from regional entities and NERC, was not disclosed in the report; the audited entities’ identities were also kept confidential.

FERC has been conducting CIP audits since FY 2016. Audit fieldwork includes data requests, webinars and teleconferences, and site visits to registered entities’ facilities. During site visits, audit staff interview utilities’ subject matter experts, along with employees and managers responsible for performing tasks within the audit scope; observe operating practices in real time; and examine entities’ “regulatory and corporate compliance culture.”

Recommendations up from Previous Report

This year’s report produced 12 lessons learned, intended to “help responsible entities improve their compliance with the CIP reliability standards and their overall cybersecurity posture.” The commission’s first report covered FY16 and FY17, and included 21 recommendations; the number of lessons learned dropped to 10 in the FY18 report and seven last year. (See FERC: Room for Improvement on CIP Compliance.)

Despite the rise in recommendations, FERC’s report emphasized that “most of the … processes and procedures adopted by the registered entities met the mandatory requirements” of the CIP standards. As a result, the lessons learned reflect “practices that could improve security but are not required by the [standards],” in addition to mandatory fixes to bring entities back in line with requirements.

The suggested improvements covered the following standards:

CIP-002-5.1a — Bulk electric system cyber system categorization
CIP-004-6 — Personnel and training
CIP-006-6 — Physical security of BES cyber systems
CIP-007-6 — Systems security management
CIP-009-6 — Recovery plans for BES cyber systems
CIP-010-2 — Configuration change management and vulnerability assessments
CIP-011-2 — Information protection

For CIP-002-5.1a, staff observed that some entities did not properly identify BES cyber assets; for example, in some cases, cyber assets such as switches and protocol converters were recorded as communication equipment. This is incorrect, as such equipment “may pose an impact … within 15 minutes of their misuse.”

Auditors also found some instances in which substation BES cyber systems that should have been considered medium-impact were instead recorded by utilities as low-impact because staff “did not properly consider” the effect that all the relevant equipment might have when operated collectively.

CIP Compliance Recommendations — | *FERC*

Recommendations for CIP-004-6 include ensuring that electronic access to BES cyber system information is properly authorized and revoked, following auditors’ discoveries that several entities had not followed their procedures consistently. In some cases, access was granted verbally without filing the necessary documentation, while in others, the access of terminated employees was not deactivated by the end of the calendar day following their departure.

Improvements for physical security — covered by CIP-006-6 — include dedicated visitor logs at each physical access point, locking BES cyber systems’ server racks where possible and periodic inspections of physical security perimeters to ensure there are no unidentified physical access points. Consistent practices are also endorsed in the recommendations for CIP-007-6, which include periodic review of security patch management processes, as well as consolidating and centralizing password change procedures.

Under CIP-009-6, auditors noted that some entities “failed to update their backup and recover procedures in a timely manner,” for instance by failing to establish a new process following a critical event in violation of the standard’s requirement. Entities were also found to have neglected to “report any information to remediate and mitigate vulnerabilities identified in vulnerability assessments,” as mandated in CIP-010-2.

Finally, staff noted that several entities could not “demonstrate that they properly disposed of” substation devices removed from services as required by their asset reuse and disposal policies, and that others relied entirely on security controls provided by third-party vendors without verifying their sufficiency. Both issues could constitute a violation of information protection requirements in CIP-011-2.

In several places, staff also recommended that entities “consider the guidance” of the National Institute of Standards and Technology’s Security and Privacy Controls for Federal Information Systems and Organizations report. While implementing these recommendations would not contribute to compliance, they would enhance the culture of security among utility staff, they said.

October 8, 2020

Tri-State Increases Members’ Self-supply Options

Colorado cooperative Tri-State Generation and Transmission Association said Wednesday it will cut its rates by 8% by the end of 2023 and give members additional flexibility to provide their own power, addressing two of its members’ most frequent complaints.

CEO Duane Highley acknowledged during a press conference that members had asked for more leeway in self-supply options to increase their use of renewable energy, calling the actions a “green energy dividend.”

“It’s been lots of work, but the cooperatives have come together cooperatively to find ways to make this work for everyone,” Highley said, apparently unaware of his play on words. “We’ve all agreed this is a fair way to share costs.”

Highley was backed by two member representatives, Poudre Valley Rural Electric Association CEO Jeff Wadsworth and Southeast Colorado Power Association CEO Jack Johnston, and former Colorado Gov. Bill Ritter, director of the Center for the New Energy Economy.

Ritter lauded Tri-State for its Responsible Energy Plan, which the co-op unveiled in January with similar fanfare. The plan’s components include 50% renewable consumption by 2024, reduced emissions by closing coal plants in Colorado and New Mexico, and additional self-supply and local renewable energy flexibility for members. (See Tr i -State to Retire 2 Coal Plants, Mine.)

“This was not an easy result to get to. None of this is easy,” Ritter said. “They’re living up to the commitments they made in the Responsible Energy Plan. We’re going to make a commitment to lower rates for the next few years. That is something I think we should all applaud.”

The announcement followed a meeting at which Tri-State’s Board of Directors approved the rate cut and the Contract Committee’s process to implement partial requirements contracts with its utility members.

“You typically don’t hear about electric utilities lowering rates, so we’re grateful to Tri State and board for this big lift,” Wadsworth said.

Tri-State Generation and Transmission Association — Tri-State’s members cover much of the Rocky Mountains. | *Tri-State Generation and Transmission*

Beginning with an “open season” nominating period in early 2021, utility members can transition to the new contracts by expressing their interest in shares of the 300-MW of system-wide self-supply capacity allocation. The open season capacity accounts for 10% of Tri-State’s system peak demand.

Members can self-supply up to 50% of their load requirements, subject to availability in the open season. This expands on the current 5% self-supply provision and a new communi t y solar provision.

The 5% cap has frustrated Tri-State’s 42 utility members, some of whom are involved in regulatory litigation to leave the co-op. (See Tri-State, Delta Officially Part Wa y s.)

Tri-State has recently added three non-utility members, making it FE R C-jurisdictional. The commission in March found Tri-State to be under its jurisdiction, a ruling it affirmed in August. (See FERC Affirms its Jurisdictio n over Tri-State G&T.)

FERC Rejects Interconnection, GIA Procedures

As the press conference proceeded online, FERC issued an order rejecting Tri-State’s proposed Tariff revisions modifying its generator interconnection procedures and generator interconnection agreements (GIAs) without prejudice to a submitted revised proposal (E R 20-2593).

Tri-State said it intends to refile a revised proposal.

FERC in March accepted Tri-State’s Tariff revisions establishing the jurisdictional rates and terms and conditions for transmission service over its Western Interconnection facilities, but set the matter for hearing and settlement judge procedures to determine their justness and reasonableness. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 1 6, 2020.)

Tri-State proposed to reform its interconnection queue by transitioning from the pro forma sequential first-come, first-served study approach to a first-ready, first-served cluster study. The cooperative said the change was consistent with or superior to its pro forma large and small generator interconnection procedures (LGIP/SGIP) and the large and small GIAs.

The revisions would have established an informational interconnection study process — to assist customers make business decisions about their generation facilities before entering the queue — and a definitive interconnection study process. Tri-State said interconnection customers must demonstrate site control and meet increasingly stringent readiness milestones as they advance through the interconnection phases.

FERC found that Tri-State did not demonstrate several revisions to be consistent with or superior to the pro forma LGIP: 1) its proposal to allocate network upgrade costs based on a distribution factor analysis; 2) the requirement for interconnection customers to select energy or network resource interconnection service (ERIS/NRIS) before beginning one of the study process’ phases; and 3) the requirement for interconnection customers entering a transitional process to demonstrate readiness within 10 days of the revised LGIP’s effective date.

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, 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, 2020February 12, 2025

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.”