RTOs, TOs Defend Competition Exemptions

By Michael Kuser, Christen Smith and Rich Heidorn Jr.

Transmission owners this week defended PJM’s, ISO-NE’s and SPP’s designations of “immediate-need” reliability projects while state officials complained the grid operators are frustrating FERC Order 1000’s intent to open transmission construction to competition.

More than a dozen stakeholders and groups filed comments on the RTOs’ responses to FERC’s Oct. 17 orders opening investigations under Federal Power Act Section 206 into their use of Order 1000’s immediate-need exemption. The exemption allows the RTOs to assign projects to incumbent TOs. FERC said it was “concerned that the responding RTOs may be implementing the exemption in a manner that is inconsistent with or more expansive than what the commission directed, and therefore may be unjust and unreasonable.” (See FERC to Probe Order 1000 Competition Exemptions.)

The TOs agreed with ISO-NE (EL19-90), PJM (EL19-91) and SPP (EL19-92), which insisted in their Dec. 27 filings that they were following Order 1000 and that no changes to their transmission planning practices were warranted.

Exception ‘Swallowed’ the Rule

But state officials disagreed, with several New England state agencies saying, “the exception has swallowed the rule.”

“The three-year, immediate-need deadline is a fiction that has not been respected in theory or in practice in New England,” the Connecticut and Massachusetts attorneys general, Connecticut’s Department of Energy and Environmental Protection and Office of Consumer Counsel, and the Maine Office of Public Advocate said in a joint comment.

FERC should order ISO-NE to amend its Tariff and revise or eliminate the time-sensitive-needs exemption to encourage competition, they said.

The New Jersey Board of Public Utilities argued that PJM applies the exemptions too broadly, resulting in “increased transmission rates from projects not subject to competitive pressures.”

Ending the Federal ROFR

Order 1000 required RTOs to eliminate from their tariffs a federal right of first refusal for incumbent transmission developers for facilities selected for cost allocation in a regional transmission plan.

In allowing PJM, ISO-NE and SPP to create the exemptions, FERC set out five criteria, including that a project is needed in three years or less to solve reliability criteria violations. It also required the RTOs to post information about the exemptions to ensure transparency. (CAISO, MISO and NYISO did not seek such exemptions.)

The commission said “it is unclear how each responding RTO determines whether an immediate-need reliability project is needed in three years or less,” noting that PJM designated 19 immediate-need reliability projects between 2017 and 2018 with need-by dates prior to or in the year they were designated. In other cases, FERC found, the projects were projected to be in service after the need-by date.

The commission also faulted the RTOs for a lack of transparency, saying it was difficult to locate where they identify and post explanations of reliability violations and system conditions with time-sensitive needs.

It suggested potential changes, such as shortening the three-year rule for projects deemed immediate-need, approving exemptions based on the in-service date versus the need-by date, increasing transparency into how the RTO determines a competitive process is unfeasible and requiring more frequent project re-evaluations.

SPP: Small Share of Projects Exempted

FERC noted that SPP designated an immediate-need reliability project in December 2018 that is needed by June 1, 2020 but has an expected in-service date of June 30, 2023.

SPP said the five projects it designated as short-term reliability projects (STRPs) represented only 3.5% of 144 total reliability upgrades between 2015 and 2018.

Of the five, one was canceled, and two others designated in July 2016 and December 2018 have not yet been energized. Two projects designated in June 2015 were completed in June and November 2018.

The RTO said the process for designating STRPs “is working as intended” and that changes contemplated by FERC “would have very little impact on increasing the number of projects subject to competition and could increase reliability risks incurred due to delays in construction caused by implementing the competitive bidding process.”

American Electric Power defended both SPP and PJM in its filings, saying immediate-need reliability projects “are a necessary component of reliability” that allow RTOs to adapt to “retirement of conventional generation, the rapid addition of variable resources and the addition of block load, such as data centers and shale gas facilities.”

PJM Late to ID Needs?

In its critique of PJM, FERC had questioned the RTO’s approval of the Flint Run 500/138-kV substation upgrade as an immediate need, saying the size of the project — intended to serve load growth in the Marcellus Shale region in West Virginia — “raises questions about why PJM did not identify this need earlier.”

PJM’s 137-page response clarified that the number of immediate-need projects approved between 2015 and 2018 totaled 63, slightly more than a quarter of the 241 transmission proposals exempted from competition in that time frame.

The RTO said it arrived at the smaller number after sorting out projects that claimed other competitive exemptions, including the lower voltage threshold, thermal reliability violations solved with substation upgrades and Form 715 projects. It also argued that the relative size of the population it serves contributes to the number of immediate-need projects in its Regional Transmission Expansion Plan (RTEP) as compared to SPP and ISO-NE.

FERC questioned PJM’s approval of the Flint Run 500/138-kV substation project as an “immediate need” reliability project, saying the size of the project, to serve load growth in the Marcellus Shale region, “raises questions about why PJM did not identify this need earlier.” | PJM

FERC’s proposed changes, PJM said, ignore the unpredictable nature of the siting and eminent domain processes and would require RTO staff to “prognosticate” about complex government processes for which they lack expertise. Its existing practice of posting information about immediate-need projects online three days before the monthly Transmission Expansion Advisory Committee meeting gives stakeholders a chance to review and ask questions about the proposals, eliminating the need for greater transparency, PJM said. Further, mandated re-evaluations for projects that fail to meet a projected in-service date “would be highly disruptive and lead to further delays.”

“Thus, it is necessary that PJM continue to have the authority given the relevant facts and circumstances to direct transmission owners to resolve an immediate-need reliability issue when identified and that those entities designated responsibility to construct the project will have reasonable assurance of recovery if they proceed with the project as approved,” the RTO said.

TOs: No Changes Needed

In separate filings, Exelon, Old Dominion Electric Cooperative and AEP said that PJM’s response demonstrates effective implementation of the immediate-need exemption and supported no further policy changes.

“Exelon agrees with PJM that the additional conditions and restrictions on the use of the immediate-need reliability project exemption that the commission introduced in the show-cause order would either undermine the effectiveness of the immediate-need reliability project exemption or fail to meaningfully increase opportunities for nonincumbent transmission development,” Exelon wrote.

The New Jersey BPU took aim at PJM’s argument that its immediate-need projects were “artificially inflated,” noting that the subset still accounts for 13% of all baseline upgrades in the RTEP.

After the last of PJM’s competitive exemptions went into effect in 2017, more than $3 billion in transmission projects were planned “without the benefit of competition,” the BPU said. The issue hits close to home for New Jersey regulators, who have charged that more than a third of PJM’s transmission expansion has occurred within their state, increasing transmission rates 124% since 2013 for “certain customers.”

“Taken together, these facts undercut PJM’s use of other exemptions as support for the justness and reasonableness of its existing rules,” the BPU said. “To the contrary, the substantial portion of noncompetitive PJM transmission investment, particularly in New Jersey, confirms the commission’s concerns about the expanding scope of transmission exemptions.”

Because PJM has demonstrated the operational capability to maintain a reliable transmission system when construction on such projects extends beyond three years, competitive transmission developer LS Power said, the commission should eliminate the blanket immediate-need exemption and require the RTO to seek FERC approval of exemptions on a case-by-case.

LS Power said the total value of transmission additions classified as immediate-need exceeds $4.5 billion over the last six years — far beyond what the commission envisioned when it approved the “limited” exemption.

“The commission must require PJM to fully explain why this staggering amount of transmission spending in PJM is in immediate-need reliability exemption projects and why PJM’s planning process is insufficient to prevent this level of immediate-need reliability projects,” LS Power said. “Significant reform is warranted.”

American Municipal Power said PJM’s process for approving RTEP projects is flawed because incumbent TOs hold all the relevant information and don’t provide it to the RTO on a “timely basis.”

“The commission should direct PJM to improve the RTEP process to ensure that it has timely information from processes that feed into the PJM planning process to avoid immediate-need reliability projects resulting from changes in topology, facility rating methodologies or other modifications controlled by the PJM transmission owners,” AMP said.

ISO-NE’s Lack of Annual Tx Planning

FERC also was critical of ISO-NE, saying that because the RTO does not conduct an annual transmission planning process, and instead relies upon needs assessment studies, “it appears that all reliability needs in ISO-NE may be classified as immediate-need reliability projects.”

ISO-NE and New England TOs Avangrid, Eversource and National Grid stood alone in defending the RTO’s use of immediate-need exemptions, with most stakeholders urging FERC to curtail or abolish the exemption.

The RTO said it has 31 reliability projects for which the need-by date is earlier than the projected in-service date, all resulting from either its Boston 2028 or its Southeast Massachusetts/Rhode Island 2026 needs assessments.

“The solutions are addressing the time-sensitive needs described in the two assessments,” the RTO said. “ISO-NE believes that the exception is working as intended in the New England area and that no changes are necessary at this time.”

After the RTO in December issued its first competitive transmission solicitation — to address reliability concerns over the planned retirement of the Mystic Generating Station near Boston — it told the commission it “intends to conduct a ‘lessons learned’ process, during which time ISO-NE will revisit its processes to determine if overall improvements can be made.” (See ISO-NE Issues First Competitive Tx RFP.)

| © RTO Insider

The New England Power Pool urged the commission to restrict the use of such exemptions “as much as possible, consistent with ensuring that reliability needs are met in a timely way.”

NEPOOL said it continues to support the immediate-need exemption for transmission facilities that are needed within three years of the identification of a reliability need. However, it “should be the exception and not the rule,” the organization said.

The New England state agencies said the “fiction” of the three-year immediate-need deadline is demonstrated by the data. Of 30 completed and ongoing immediate-need projects, they said, 24 (80%) were not completed within three years; 15 (50%) are expected to take at least five years; and 20 (67%) had need-by-dates predating the assessment study that identified the need. Another four had need-by-dates in the same year as the need was identified.

The New England States Committee on Electricity (NESCOE) said it is concerned that ISO-NE’s practices could cause all reliability needs to be met outside of the competitive process.

“Given the unique circumstances and system conditions giving rise to the identified need, the Boston [request for proposals] does not appear to signal a fundamental shift away from ISO-NE’s use of the exemption,” NESCOE said.

The limited competition in New England raises obvious questions about whether consumers are paying more than necessary for transmission, it said, noting that revenue requirements are forecast to increase from $2.1 billion in 2018 to $2.7 billion in 2023, a jump of more than 25%.

“Even before these increases take effect, an ISO-NE analysis shows that most residential retail electric customers in New England paid transmission costs representing 11 to 18% of their total retail rates,” NESCOE said. “If needs were classified as time-sensitive years ago but ISO-NE has not yet selected projects to meet those needs, it raises questions regarding whether the appropriate criteria is being used to assess the time-sensitivity of those needs.”

The Connecticut Public Utilities Regulatory Authority said, “Any competition is superior to no competition,” and that the RTO “appears to prefer not using the competitive process to address transmission needs and to being unable to identify any transmission need that is more than three years away.”

The PURA suggested limiting the percentage of transmission need projects that can have a noncompetitive solution, based on either the number of projects or on the dollar expense.

The agency “believes that 25% is the appropriate limit to place on the amount of dollars that can be spent on noncompetitive solutions. This percentage level ensures that the majority of dollars spent on transmission need solutions benefit from competitive forces, yet should be amply sufficient to handle those few occasions when reliability concerns arise and cannot be mitigated.”

To Proceed or not to Proceed

The immediate-need exemption has given incumbent TOs in New England exclusive rights to construct nearly all new transmission in the region, and they are at the same time “failing almost universally to complete or, in some cases, even commence projects on or before the need-by date,” Massachusetts Municipal Wholesale Electric Co. and New Hampshire Electric Cooperative said.

The immediate-need exemption is “out of step with its intended purpose and should be eliminated,” they said, suggesting a more streamlined competitive solicitation process.

ISO-NE asserts that in-service dates are based on realistic appraisals by the affected TOs of how long it is likely to take for the preferred solution. “But that does not advance the ball; it merely describes the problem,” the public systems said. “If the TO cannot build the project within the [RTO’s] need-by timeframe, then the project should be put out for bid.”

The public systems proposed a competitive solicitation process they said could be completed in less than half the time of the RTO’s method, “or just 279 days, compared to the 630-day time frame ISO-NE has established for the Boston 2028 RFP.”

Avangrid tried to parry the thrust of the commission, asserting that “a litigated proceeding based on a misunderstanding of need-by dates versus in-service dates does not signal to the industry that the commission intends on maintaining the reasonable balance struck between eliminating barriers to new entry and ensuring participating transmission owners are able to address immediate reliability needs on the New England transmission system without unnecessary delay.”

The company suggested giving up “a one-sided view of post-Order No. 1000 transmission planning measures” in favor of a technical conference as “the most transparent and balanced manner to manage this discussion.”

Eversource Energy said, “The benefits of adjusting the three-year exemption … to increase competition are minimal.”

ISO-NE independently determines what reliability needs to put out for competitive solicitation, and stakeholders can challenge its use of the three-year exemption, the company said.

There would be “little benefit to creating more process” for the kinds of projects that are needed within three years, which typically involve upgrades to TOs’ existing assets or on their rights of way, which FERC explicitly reserved for the public utility transmission provider, Eversource said.

“Near-term reliability should not be compromised for such little, if any, benefit. There is ample evidence for the record of the significant time needed to conduct competitive solicitations,” Eversource said.

National Grid reported nine of 13 immediate-need projects identified through the SEMA-RI report as “progressing satisfactorily against their key milestones,” with the remaining four “less advanced due to factors outside of National Grid’s control.”

January 28, 2020

NJ Unveils Plan for 100% Clean Energy by 2050

By Rich Heidorn Jr.

New Jersey Gov. Phil Murphy on Monday released an updated Energy Master Plan outlining how the state will meet its goal of 100% “clean energy” and an 80% reduction in statewide greenhouse gas from 2006 levels by 2050.

New Jersey clean energy — Gov. Phil Murphy announced New Jersey’s revised Energy Master Plan Monday, which sets a goal of 100% clean energy by 2050. | *Phil Murphy*

“New Jersey faces an imminent threat from climate change, from rising seas that threaten our coastline to high asthma rates in some of our most vulnerable communities due to fossil fuel pollution,” Murphy said in a stat e ment. “Successfully implementing the strategies outlined in the Energy Master Plan will drastically reduce New Jersey’s demand for fossil fuels, reduce our carbon emissions [and] greatly improve local air quality.”

Murphy also issued an executive order directing the Department of Environmental Protection to issue regulations to reduce emissions and adapt to climate change. The Protecting Against Climate Threats (PACT) regulations, due within two years, will require a monitoring-and-reporting program to identify all significant sources of GHG emissions and integrate climate change considerations, such as sea level rise, into the department’s land use permitting and other regulatory programs.

Murphy said the regulations will result in better planning and more resilient communities by avoiding construction in flood-prone areas, re-establishing wetlands, revegetating riparian areas and encouraging green infrastructure. “With this executive action, New Jersey is the first state in the nation to pursue such a comprehensive and aggressive suite of climate change regulations,” Murphy said.

The master plan, which was last updated in 2015, calls for:

reducing energy consumption and emissions from transportation by encouraging electric vehicle adoption, electrifying transportation systems and using technology to reduce emissions and miles traveled.
accelerating deployment of renewable energy and distributed energy resources with offshore wind, community solar, a new solar incentive program, solar thermal and energy storage. It includes low-cost financing for DERs.
improving energy efficiency and conservation and reducing peak demand through new financing mechanisms and stronger building and energy codes and appliance standards. It will implement the state Clean Energy Act, which requires electric and gas utilities to reduce consumption by at least 2% and 0.75%, respectively.
reducing energy consumption and emissions from buildings through decarbonization and electrification of new and existing buildings, the expansion of incentives to encourage net-zero-carbon homes and developing EV-ready and demand response-ready building codes.
the creation of integrated distribution plans, investments in grid technology and a reduced reliance on natural gas.
prioritizing clean transportation options in “underserved” communities and supporting the establishment of community energy plans.
expanding New Jersey’s 52,000 clean energy jobs by making research and development investments to create services and products that can be exported to other regions.

The plan was embraced by numerous environmental groups, although some were disappointed that the definition of carbon-neutral “clean energy” includes nuclear power and natural gas plants that offset their emissions. New Jersey’s three remaining nuclear plants are set to receive subsidies of $300 million annually for the next three years.

At the New Jersey Board of Public Utilities’ meeting Wednesday, President Joseph Fiordaliso praised the governor’s plan but lamented that the state’s carbon-reduction efforts could become much more expensive as a result of PJM MOPR Rehearing Requests Pour into FERC.)

January 28, 2020

FERC SPP Briefs

FERC last week partially accepted SPP’s compliance filing to Orders 845 and 845-A, directing the RTO to submit a further changes (ER19-1954).

The commission found SPP complied with six of the 10 revisions it was directed to make to its pro forma large generator interconnection agreement (LGIA) and pro forma large generator interconnection procedures, but only partially complied with the other four.

It gave the RTO 60 days to submit compliance filings related to identification and definition of contingent facilities; provisional and surplus interconnection service; and material modifications and incorporation of advanced technologies.

FERC found that SPP’s method for determining contingent facilities — unbuilt interconnection facilities and network upgrades upon which the interconnection request is dependent — lacked the “requisite” transparency to ensure it will be applied on a nondiscriminatory basis. The commission directed the RTO to specify the thresholds or criteria it will use in its technical screens or analysis.

The commission said SPP’s revision to allow interconnection customers to request provisional service only if its requested in-service date precedes the study’s projected completion did not comply with Order 845. It ordered SPP to remove the limitation in its compliance filing.

SPP’s new three-stage generator interconnection study process | *SPP*

FERC also found that the RTO failed to support its proposed “independent entity variation” from the Order 845 requirement to identify any additional necessary interconnection facilities and network upgrades in surplus interconnection service study results. SPP had proposed to identify only necessary interconnection facilities — and not network upgrades — in those studies. The commission also rebuffed a proposal to hold the original customer, instead of the surplus customer, responsible for any study costs beyond the original deposit to be unjust and unreasonable. The commission ordered further compliance filings for both revisions.

Finally, FERC said that because SPP’s proposed “permissible technological advancement” definition and change procedure was silent on whether SPP will explain to the customer why a proposed technological advancement is a material modification, it required the RTO provide an explanation if it cannot accommodate a proposed technological advancement without triggering the material modification provisions.

FERC issued Orders 845 and 845-A in 2018 and 2019, respectively, to increase the transparency and speed of generator interconnection processes. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

The commission last year approved SPP’s three-stage study process, meant to improve its interconnection procedures. (See FERC OKs New SPP Interconnection Process.)

Commission Rejects Springfield’s Rehearing Request

The commission last week denied City Utilities of Springfield’s (Mo.) request to rehear a 2019 order rejecting the utility’s complaint against SPP over how the RTO administers transmission cost allocations (EL19-62).

Springfield had appealed FERC’s August decision that SPP’s administration of regional cost allocation reviews (RCARs) was not unjust and unreasonable. The utility filed a complaint under Federal Power Act Section 206 alleging that SPP’s highway/byway cost allocation methodology has produced unintended consequences in its pricing zone that violated the cost-causation principle and the “roughly commensurate” standard. (See FERC Denies Springfield Utilities’ Complaint vs. SPP.)

SPP’s transmission pricing zones | *SPP*

The order also clarified that FERC’s denial “should not be construed as eliminating SPP’s obligations” under the Tariff.

Springfield contended that the commission erred in its initial finding by not finding that the Tariff language provides for retroactive adjustments to allocated costs if “analysis show[s] an imbalanced cost allocation in one or more [transmission] zones.” The utility said “reallocation of … costs … is well within [FERC’s] remedial authority” and argued that the Tariff does “prescribe a methodology for changing cost allocations based on the outcome of the RCAR studies.”

FERC disagreed that the language “unambiguously” provides for retroactive adjustments. It said the language is ambiguous because a recommendation to change allocated costs “could refer to a prospective adjustment for future allocations.”

The utility’s transmission zone in southwestern Missouri is the only one where the benefit-cost ratio does not meet SPP’s minimum threshold, Springfield said in its original complaint.

The commission said it did not dispute that the first two RCAR analyses revealed “an imbalanced cost allocation to Springfield’s zone, and we do not minimize or discount the significance of this imbalance.” However, it also said the “unintended consequence” of a cost imbalance “does not compel the conclusion that SPP’s administration … is unjust, unreasonable, or unduly discriminatory or preferential.”

FERC said SPP’s Tariff provides avenues to address alleged imbalanced cost allocations. It suggested Springfield request the grid operator’s Regional State Committee, composed of state regulators, to provide recommendations to adjust or change the allocated costs.

Changes for Sponsored Upgrade Security Costs

FERC on Jan. 14 issued an order accepting SPP’s Tariff revisions to reduce the risk of incurring unnecessary financial security expense related to certain transmission upgrades (ER19-2669).

The Tariff changes, effective Oct. 20, 2019, apply to sponsored upgrades outside of SPP’s transmission planning processes and that are proposed by entities that will assume the cost of the new facilities. The changes also apply to system upgrades needed to fulfill eligible customers’ requests for long-term transmission service.

Under the revision, no payment security will be required when the project sponsor and TO are the same entity. The security requirements will also be waived when the TO building an upgrade to meet a service request notifies SPP it has already received sufficient payment security from the customer.

— Tom Kleckner

January 28, 2020

PJM MRC/MC Briefs: Jan. 23, 2020

Markets and Reliability Committee

Soak Time Rule Change Deferred Until May

The PJM MRC Briefs: Dec. 19, 2019.)

Stakeholders disputed some of the analysis that PJM used to set soak time operating reserve credit rules and also raised concerns with the way the concept was being woven into energy offers.

The PJM Markets and Reliability Committee convened Jan. 23 at the Conference and Training Center in Valley Forge, Pa.

It’s the second time the MRC has deferred voting on the issue, after requesting a one-month delay in December. The committee instead endorsed two other recommendations from the Modeling Generation Senior Task Force that can be implemented in the near term while PJM focuses on completion of its next generation energy market (nGEM).

The Tariff and Operating Agreement revisions, which were also approved by the Members Committee, will increase the number of segments on the energy offer curve (effective in 2020) and introduce hourly differentiated segmented ramp rates (late 2020).

The task force, assembled in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.

Primary Frequency Response Task Force Hiatus Extended

The committee agreed to keep the Primary Frequency Response Task Force on hiatus through the first half of 2020.

Primary frequency response (PFR) is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.

The task force wrapped up its action last year and promised to update the Operating Committee on a quarterly basis of PJM’s performance. During the most recent update in October, PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-MHz deadband, frequency stays outside the +/- 40-MHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 MHz.

No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.

The task force will continue to update the OC on a quarterly basis of PFR results across the RTO.

Credit Risk Tariff Revisions on Hold

PJM Chief Risk Officer Nigeria Poole Bloczynski told the MRC that Tariff revisions that would update the RTO’s market participant risk profiles and expand updated credit rules to apply to all markets — not just the financial transmission rights market that was the subject of GreenHat Energy’s massive default — are on hold temporarily as stakeholders continuing reviewing the proposed language.

“We’ve made significant progress, but we also acknowledge that we are moving a little fast,” she said. “Feedback internally has suggested we take our time to get this right.”

PJM hired Bloczynski in July after an independent probe of the GreenHat default found the RTO’s executive team lacked credit expertise. She said last month she’s hiring four additional staff in her department, including a manager of credit risk and trading risk, and challenging current employees to automate as many processes as possible.

In the meantime, Bloczynski encouraged leaders of PJM member companies to attend meetings of the Financial Risk Mitigation Senior Task Force, from which many of the Tariff changes originate.

On Friday, the ISO/RTO Council asked FERC to reject financial traders’ request for a rulemaking to update and standardize RTO credit policies nationwide, saying it would upset stakeholder proceedings on the issue. (See related story, RTO Council Balks at Credit Rulemaking.)

Later, the Members Committee approved revisions to the OA endorsed by the task force and MRC to hold five long-term FTR auctions a year, instead of three, to increase visibility into portfolio conditions so that more collateral can be collected if necessary. The revisions also would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter. (See “FTR Credit Rules Endorsed,” PJM MRC Briefs: Dec. 19, 2019.) There were three objections to the vote, including from the Consumer Advocates of the PJM States and the PJM Industrial Customer Coalition.

Members Committee

PJM Annual Meeting Scheduled in Chicago

PJM will host its annual meeting at the Drake Hotel in Chicago on May 4-6. Registration for the event opens on Feb. 5 and will close April 29.

Member companies, voting proxies, state and federal employees, and event sponsors can attend free of charge. Otherwise, attendees must pay a $400 guest fee for media, spouses, children and others that covers all meals and one leisure activity.

Manual Revisions, Tariff Changes Endorsed

The MRC endorsed revisions to Manual 38: Operations Planning that included updates from the periodic cover-to-cover review and updated procedures.

The Members Committee endorsed:

revisions to the OA to changing the competitive transmission proposal fee structure. PJM will charge a $5,000 nonrefundable fee to all developers who submit competitive proposals. Itemized study costs will be added as necessary. RTO officials said the current tiered approach doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “Competitive Transmission Proposal Fee,” PJM MRC Briefs: Dec. 19, 2019.)
revisions to the Tariff and OA to align them with PJM’s actual implementation of market-based parameter-limited schedules. (See “Parameter-limited Scheduling Fix,” PJM MRC Briefs: Dec. 19, 2019.)
revisions to the OA clarifying the requirements for sharing forecasted unit commitment data to transmission owners for reliability studies, to ensure consistency with NERC standards and PJM manuals.
revisions that clarify that market sellers can only change the format of maintenance adders ($/MMBtu, $/MWh or $/start) during the annual review period for energy offer components. (See “Manual 15 Clarifications on VOM Costs,” PJM MRC/MC Briefs: Dec. 5, 2019.)

– Christen Smith

January 28, 2020March 12, 2025

RTO Council Balks at Credit Rulemaking

By Rich Heidorn Jr.

The ISO/RTO Council asked FERC on Friday to reject financial traders’ request for a rulemaking to update RTO credit policies, saying it would upset stakeholder proceedings on the issue.

The Energy Trading Institute asked the commission on Dec. 16 to schedule a technical conference by March 30 and convene a rulemaking to update FERC Order 741, its 2010 rulemaking on credit and risk management in the RTO/ISO markets (AD20-6).

Order 741 shortened settlement periods in the energy and ancillary services markets, reducing default exposure. ETI said the order— which also banned or limited unsecured credit and provided guidance on the use of netting and demanding additional collateral — was “appropriate at the time.”

GreenHat Concerns

“However, given the recent GreenHat default and the evolution of these markets over the last decade since the issuance of Order No. 741, ETI strongly believes that the commission and industry should engage in a dialogue to ensure that credit and risk management practices and procedures in the ISOs and RTOs are robust, do not create unnecessary barriers to entry or compliance burdens, and ensure that organized markets are secure in order to meet the commission’s goals of open access, competition and transparency.”

The group, whose members include Vitol, SESCO Enterprises and Appian Way Energy Partners, said FERC should insist that new policies are uniform across all markets. Allowing each grid operator to set its own minimum participation and risk policy requirements has created “a significant compliance burden” for market participants and resulted in a mix of policies that “are not effective in reducing exposure and detecting default risk,” ETI said.

“There should be one set of standards, one set of disclosures and one set of certificates for entities to comply with the commission’s rules,” ETI said.

IRC: Don’t Rush RTOs

The IRC, which includes the six FERC-jurisdictional RTOs/ISOs, did not challenge any of ETI’s criticisms in its filing Friday. Instead, it said FERC should allow the grid operators and their stakeholders to address their credit and risk management issues individually before considering a conference or rulemaking.

“At a minimum, these RTOs and ISOs should have time to gain experience with those rules before the commission facilitates a dialogue of best practices, schedules a technical conference and/or commences any rulemaking proceeding to examine further enhancements to credit policies and practices in organized electricity markets.”

IRC said a rulemaking would “upend those individual stakeholder processes and the timely submittal of reforms by individual RTOs and ISOs.” It proposed an alternative approach that it said acknowledges ETI’s concerns without becoming an impediment to stakeholder processes and filings before the commission.

“From a timing perspective, the IRC believes that the issues raised by ETI are best addressed once experience is gained with those individual RTO and ISO reforms. The IRC’s proposed approach is consistent with the commission’s prior determination that: ‘In matters of administrative regulation, a month of experience may be worth a year of hearings.’”

IRC said the commission has already approved revisions to the credit policies of ISO-NE (ER18-2293), MISO (ER20-73) and PJM (ER18-2090, ER19-945) since 2018.

NYISO Management Committee Briefs: Oct. 30, 2019.)

MISO’s stakeholders have been working for seven months on a filing that was submitted to FERC on Monday (ER20-877). (See MISO Looks Beyond FTRs for Market Protections.)

“MISO’s filings are intended to improve the baseline by implementing well-considered measures,” the RTO said in a statement Monday.

PJM has also been working for seven months and hopes to submit its proposed credit and risk management rule changes by the end of March. (See “Credit Risk Tariff Revisions on Hold,” PJM MRC/MC Briefs: Jan. 23, 2020.)

SPP’s Credit Practices Working Group, which has been working for nine months, is reviewing draft proposals on capitalization requirements and other matters and expects the group to vote on the proposed changes by the end of the first quarter.

“The commission should not schedule a nationwide technical conference at this time. Instead, it should proceed to address filings that are before it or that RTOs/ISOs plan to submit in the near future,” IRC said.

Improvements Needed

ETI said improvements are needed in credit risk management, counterparty risk management and ISO/RTO internal risk management infrastructure and expertise. It says each of the RTOs should hire a chief risk officer who reports to its board — as PJM did following the GreenHat debacle. (See PJM Names Chief Risk Officer.)

The group said MISO, SPP and ISO-NE “have inapposite submission credit requirements, on the one hand requiring submission credit as much as 10 times the anticipated exposure and, on the other, far lower hold credit requirements for cleared positions that under-collateralize the actual exposure of the position.”

Despite FERC regulations prohibiting unsecured credit in financial transmission rights markets, the group says, MISO allows market participants to hold positions for which they have not posted collateral.

MISO returns hold credit to counterflow FTR holders at the beginning of every month even though the market participant holds the counterflow position open for the entire month, the group said. “MISO’s assumption is that the counterflow FTR’s value will remain in-the-money. However, this is not always the case. Put simply, the market participant then gets to hold those positions for free.”

ETI also criticized SPP, saying it gives transmission congestion rights holders “a credit for historically strong performing paths. By not establishing a basic credit requirement for any position, SPP allows for large portfolios (i.e., exposure) that require no collateral.”

“SPP’s FERC-approved credit and risk management practices are fair, reasonable and configured according to the specific design of our market and market participants,” RTO spokesman Derek Wingfield said in response to ETI’s criticism. “Because our Integrated Marketplace operates differently than other ISO/RTOs’ markets — our region is vertically integrated and we lack a capacity market, for example — it would not make sense that we would have the same credit requirements as our peers operating in other parts of the country.”

ETI said the technical conference should include representatives from exchanges, futures commission merchants and commercial entities with experience managing commodity risk. It wants FERC to follow the conference with a Notice of Proposed Rulemaking that will lead to adoption of industry best practices such as mark-to-auction tools to track changes in exposure and requiring variation margin as the value of a position changes.

Only PJM has implemented mark-to-auction valuation, a standard practice in other commodity markets, including commission-jurisdictional bilateral markets, ETI said.

The group likened the need for uniformity in minimum credit requirements to NERC’s national reliability standards. “Some foundational rules spanning all ISOs and RTOs are inherently necessary for credit models to function well.”

ETI suggested the minimum net worth requirement should be $1 million, which it said is “high enough to signal the risk of participating in the markets but not so high as to unnecessarily discourage entry or negatively impact liquidity.”

It criticized SPP’s proposal to require a market participant to have $20 million in capitalization regardless of a market participant’s activity — meaning the money cannot be used in another ISO/RTO market — as arbitrary and an unnecessary barrier to entry.

Markets ‘not Standardized’

IRC challenged ETI’s premise that the rules should be standardized, saying “the underlying markets to which the credit policies apply are not standardized. While an evaluation of areas of credit policy that lend themselves to standardization is appropriate, assuming standardization at the outset is not appropriate.”

“If the commission is inclined to facilitate a dialogue to identify whether specific credit policies should be made applicable on a uniform basis, the IRC requests that the commission allow the individual RTOs and ISOs to finalize their stakeholder discussions, submit their proposed tariff revisions to the commission and implement these changes first. This would allow each region and stakeholders to gain experience with those rules and begin to examine best practices that might be applicable across RTO/ISO markets. At that point, the commission could facilitate a more informal dialogue as a potential next step without necessarily scheduling a formal technical conference or commencing any rulemaking proceedings.”

January 28, 2020

CCA Summit Explores Storage Options

By Hudson Sangree

SACRAMENTO, Calif. — The California Energy Commission is funding pilot programs for energy storage systems that go well beyond lithium-ion batteries, the audience at the Community Choice Energy Summit heard Friday.

The state accounts for 77% of planned large-scale storage nationwide, David Erne, a supervisor with the commission, told the audience.

The Community Choice Energy Summit took place at the Doubletree Hotel in Sacramento on Jan. 23-24. | © *RTO Insider*

He described the effort to develop utility-scale storage systems that don’t rely on lithium-ion batteries. Among the most sought-after systems are those with a minimum rating of 400 kW that could provide electricity for more than 10 hours at a time.

“We struggle with having a diversity of technology available,” Erne said.

Driven partly by the multiday outages caused by wildfires and public safety power shutoffs, the commission is seeking longer-duration storage that overcomes the run-time limits of lithium-ion batteries.

The commission is looking at technology that includes flywheel energy storage systems, flow batteries and non-lithium-ion Znyth batteries developed by Eos Energy Storage.

Proposals for some types of storage, primarily to deal with grid outages, are due at the end of February. The same solicitation includes smaller-scale storage systems to support Native American and low-income communities as well as lithium-ion batteries for residential construction.

A solicitation for projects to study the most useful locations and run times for longer-duration storage systems will be coming out soon, Erne said.

“We’re grappling with where [it will] provide the most value and what duration will provide the most value,” he said. “That one is not currently on the street, but it will be released imminently.”

Much of the research is funded by the commission’s Electric Program Investment Charge (EPIC) program, which provides approximately $130 million per year for research in science and technology to meet the state’s renewable energy and greenhouse gas reduction goals. (See EPIC Interest Growing Rapidly in California.)

The program is funded by a charge on ratepayer bills and administered by the commission and the state’s three big investor-owned utilities, Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.

Erne said a related effort by the commission is resolving problems and costly delays connecting storage to the grid. It is working with the California Public Utilities Commission on rulemaking to ease interconnection rules and speed the process, “which I know is a significant problem for everyone who wants to put new technologies on the grid,” he said.

“It has become very challenging both from a time perspective but also from a cost perspective,” because developers find it hard to anticipate what a metered interconnection might ultimately cost, Erne said.

January 28, 2020

Entergy Must Rework Pension Formula, FERC says

By Amanda Durish Cook

Entergy must provide a clearer rationale before it will be allowed to include a line item for pension costs in its rate base, FERC ruled Thursday.

Relying on a 10-year-old order involving Southern Co., the commission ruled that Entergy is allowed to include prepaid and accrued employee pension costs in its rate base but must still justify and more clearly account for those costs before doing so (ER15-1436).

In a filing updating its formula rate in 2015, Entergy proposed to include prepaid and accrued pension costs for pension plans at its Gulf States Louisiana, Arkansas, Louisiana, Mississippi, New Orleans and Texas operating companies. Prepaid pension costs represent company contributions that exceed pension expenses “to meet the requirements of pension funding laws and rules,” while accrued pension costs are payments collected from ratepayers “in excess of what the utility has contributed to its pension plans,” which must be credited back to customers.

FERC sent Entergy’s transmission rate to settlement procedures in 2016, and a partial settlement left unresolved whether the operating companies could include the pension line item in their base rates. An administrative law judge in 2018 decided that Entergy hadn’t properly justified prepaid costs in the rate base because it did not show a net benefit to ratepayers or a “correlation between its prepaid pension costs and a reduction in transmission rates.”

But FERC last week rejected the ALJ’s reasoning while still disallowing the pension line item, saying Entergy’s accounting wasn’t properly justified — but not because the pension costs didn’t show customer benefit.

The commission said prepaid pension costs in rate bases are reasonable when the “pension expense recovered from ratepayers is less than its contributions to fund pension costs.” Likewise, it said accrued pension costs are also permissible.

“Entergy is not required to provide a policy statement or other documents describing how it exercises its pension funding discretion,” the commission said.

However, FERC found that “Entergy’s proposed formula for its qualified pension plans includes components that Entergy has not fully explained and that are not clearly appropriate to include in the calculation of prepaid and accrued pension costs for inclusion in rate base,” the commission said.

Entergy had proposed a formula that included using a funded status minus unrecognized gains and losses. But FERC said the company should calculate cumulative differences between its pension contributions and expenses each year.

The commission said Entergy failed to explain what constitutes “unrecognized gains and losses” and describe why it thought its proposed calculation would yield the “same result as calculating cumulative employer contributions and cumulative pension expense.”

“Without additional explanation, we are unable to evaluate whether unrecognized gains/losses are an appropriate component to include in the calculation of prepaid pension costs to be included in rate base,” the commission said.

It also pointed out that “employee contributions to a pension trust are not shareholder-financed funds that the utility has paid out of pocket.”

“Consequently, it would not be just and reasonable for Entergy to include amounts that employees contribute to pension plans in rate base and earn a return on such amounts,” FERC said.

Another Shot

While FERC ordered removal of the pension line item, it also urged Entergy to refile the line item formula when it could “adequately demonstrate” its proposal.

“If the commission approves the inclusion of that line item, Entergy would then be required under the MISO formula rate protocols to provide specific prepaid pension cost amounts in its annual formula rate informational updates,” FERC wrote. “Interested parties would be able to challenge the prudency of such amounts at that time. … Therefore, we find that Entergy does not need to quantify or support specific prepaid pension costs in this proceeding to establish a line item in its formula rate.”

Finally, the commission said Entergy also needed to explain why its rate included prepaid and accrued pension costs even for its non-qualified plans. Non-qualified pension plans are often used as an additional retirement savings for executives and are not governed by the Employee Retirement Income Security Act.

“There is insufficient evidence and explanation in the record to find that Entergy’s proposed inclusion of prepaid and accrued pension costs for its non-qualified pension plans in rate base is just and reasonable,” the commission concluded.

January 28, 2020

FERC Upholds Orders on PJM Tx Withdrawal Rights

By Michael Brooks

FERC on Thursday rejected requests for rehearing of its order directing PJM to allow two merchant transmission operators to convert some of their firm transmission withdrawal rights (TWRs) to non-firm.

The New Jersey Board of Public Utilities and Public Service Electric and Gas had challenged the commission’s December 2017 finding that the RTO and PSE&G’s interconnection service agreements (ISAs) with Hudson Transmission Partners (HTP) (EL17-84) and Linden VFT (EL17-90) were unjust because they did not permit the conversions. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)

The transmission companies own facilities that carried power into New York City as part of the “Con Ed-PSEG wheel,” in which 1,000 MW were exported from upstate New York to PJM through PSE&G’s facilities in northern New Jersey, and then exported to the city. Consolidated Edison and PSE&G canceled the agreement in April 2017. HTP and Linden had sought the conversions to relieve themselves of cost allocations under PJM’s Regional Transmission Expansion Plan.

PJM Transmission Withdrawal Rights — Linden VFT’s exterior | *Joseph Jingoli & Son*

PSE&G argued that FERC erred in applying the just-and-reasonable standard of the Federal Power Act to the ISAs, rather than the public-interest standard of the Mobile-Sierra doctrine, which presumes the rates established through a negotiated contract are just and reasonable unless they’re found to harm the public interest. The commission had found the ISAs’ terms to be generally applicable to all PJM participants — and thus excluded from Mobile-Sierra — but the utility said the TWRs and provisions in the ISAs were unique, not pro forma.

In rejecting PSE&G’s argument, FERC pointed to the fact that Section 232.3 of PJM’s Tariff governs the conditions under which a transmission interconnection customer receives firm and non-firm TWRs. “Because PJM determined the TWRs available to HTP [and Linden] following [studies] conducted under terms and conditions that are generally applicable (even though the results of that study were specific to [the companies]), we regard those terms as generally applicable and therefore subject to the ‘just and reasonable’ standard, rather than the Mobile-Sierra presumption,” the commission said.

PSE&G also argued that the commission erred in finding no operational or reliability rationale preventing it from directing that PJM convert the TWRs and that it ignored the utility’s affidavit that raised concerns about the operational, reliability and LMP impacts from the conversions, rather relying on “one sentence written by an attorney in a PJM pleading, unsupported by any independent evidence or expert testimony.”

“We disagree with these PSEG arguments,” FERC said. It “reasonably relied on statements from PJM that reducing [the] TWRs from firm to non-firm presented no operational or reliability risks to PJM’s system.” The commission also noted that the utility’s affidavit relied on NYISO’s 2016 Reliability Needs Assessment, which made no reference to the TWRs in question.

The New Jersey BPU argued that FERC failed to consider whether the conversions would result in preferential rates to NYISO customers. But the commission said that argument was outside the scope of the proceeding, as Schedule 12 of the PJM Tariff calculates merchant transmission facilities’ cost responsibilities for RTEP projects based on their firm TWRs.

January 28, 2020

ISO-NE Planning Advisory Committee Briefs: Jan. 23, 2020

ISO-NE is incorporating stakeholder comments and questions from December’s Planning Advisory Committee meeting as it works to complete its 2019 Economic Study in stages this year, the PAC heard last week.

The New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast submitted requests at the April 2019 PAC meeting for additional studies, which Patrick Boughan, ISO-NE senior engineer for system planning, said the RTO hopes to complete and publish in June and July.

“At previous PAC meetings, stakeholders requested us to evaluate other offshore wind interconnection points, but we’re only going to evaluate the interconnection points we previously presented,” Boughan said. “I think that we’ve provided a variety of interconnection points here at different points throughout the system, in Boston, off of the cape and off of Connecticut.”

“At what point does the addition of offshore wind start to cause large onshore transmission upgrade costs?” asked Theodore Paradise, Anbaric’s senior vice president for transmission strategy.

He said the region has spent about $14 billion on transmission upgrades (ISO-NE has cited $10.6 billion since 2002), creating a robust transmission system. “So, for example, west of Millstone [Nuclear Power Station in Connecticut], which is not being used in the study, has a lot of great injection points that can take 1,200 MW or more into uncongested parts of the system.

“There’s a lot of transmission there that we’ve invested in that we could see some real benefits [from] if we chose a couple of interconnection points, even just along the Connecticut shore,” Paradise said.

ISO-NE Director of Market Development Carissa Sedlacek told Paradise that the RTO has “taken on a lot of work” in agreeing to do three economic studies.

“I think we should focus on getting the NESCOE study done and move onto the Anbaric and RENEW [studies],” Sedlacek said. “Based on the scope of work that we decided in August, we’re going to be in a good position in another two months that we’re going to be ready to request additional economic studies, so that maybe part of the 2020 Economic Study could look at those interconnection points.”

In response to another stakeholder query, Boughan said the behind-the-meter PV category in the economic studies includes resources that do not participate in the wholesale markets but are reflected in the capacity, energy, loads and transmission (CELT) load forecast. The utility-scale PV category includes resources that have cleared in the Forward Capacity Market, are settlement-only generators or otherwise participate in the wholesale markets, he said.

CO2 Emissions down, Environmental Sensitivity up

Last year saw CO2 emissions from coal and oil generation drop more than 50% compared with the previous two years, while those from gas-fired generation fell 10%, Patricio Silva, the RTO’s lead analyst, told the PAC.

The RTO’s Environmental Advisory Group assists the PAC and the Reliability and Power Supply Planning committees in evaluating the impact of environmental rules on the regional power system.

Thursday’s update included regional system trends; regional generation and emission trends; the estimated impact of carbon pricing on regional energy costs; performance statistics from the Regional Greenhouse Gas Initiative; a timeline for the region’s Transportation Climate Initiative; and a snapshot of Massachusetts’ Global Warming Solutions Act and its CO2 cap on power plants, Silva said.

While retirements within New England obviously impact the system, closures in the greater Northeast and beyond also have indirect effects that may affect the RGGI compliance costs of generators in the region, he said.

“Likewise, changes in unit availability and interconnections over time could also indirectly affect the environmental performance of the system as we’re seeing more impacts from carbon compliance costs and as other costs decline … such as nitrogen oxide allowance and sulphur dioxide allowance costs that decline in both price and significance,” Silva said.

With the May 2019 retirement of the 680-MW Pilgrim nuclear plant in Massachusetts, the 2014 retirement of the 620-MW Vermont Yankee plant and an equivalent amount of coal-fired generation retired in that period, “the system is now sensitive, more than ever from an environmental performance standpoint, to changes in the weather and economic conditions,” he said.

– Michael Kuser

January 28, 2020

SPP Names Nickell COO, Adds Board Member

SANTA FE, N.M. — S P P Chairman Larry Altenbaumer told stakeholders Tuesday that the Board of Directors has elected Lanny Nickell as its chief operating officer.

Altenbaumer said the board approved Nickell’s appointment on Jan. 26.

SPP Nickell — COO Lanny Nickell explains transmission issue to SPP stakeholders. | © *RTO Insider*

Nickell, one of several internal candidates for the CEO position filled by Barbara Sugg, replaces Carl Monroe, who announced his retirement last year after 22 years with SPP. (See SPP COO Monroe to Retire in Early 2 0 20.)

“I couldn’t be more excited about the opportunities I’ve been blessed to have, both by working in and on the SPP organization the last 22 years and to work with Barbara in our new roles as we move this fantastic organization forward,” Nickell told RTO Insider.

“I know with Barbara’s leadership our staff and stakeholders are going to do great things. I’m excited to be working more closely with our stakeholders to bring new and creative ideas to life,” he said.

“I have a tremendous amount of respect for Lanny and appreciate the expertise and strategic viewpoint he brings to the team,” CEO-elect Sugg said in a statem e n t. “His commitment to SPP and our culture will serve him well in this critical role as we look forward.”

Altenbaumer noted boards rarely get to fill both the CEO and COO positions at the same time. “It is even rarer for a board to have the luxury of the opportunity to select an individual of Lanny’s caliber to become its new COO,” he said.

Nickell, promoted last year to senior vice president of engineering, joined SPP in 1997 and has more than 27 years of experience in the electric utility industry. He directed the development of SPP’s Regional Transmission Expansion Plans; delivered the RTO’s generator interconnection, transmission and financial congestion hedging services; administered regional resource adequacy policies; and ensured reliability and market operations engineering support.

Nickell came to SPP from Public Service Company of Oklahoma and Central and South West Services, now American Electric Power. He has a bachelor’s degree in electrical engineering from the University of Tulsa and is a graduate of Harvard Business School’s Advanced Management Program.

SPP members also elected Bronwen Bastone, who has a background in financial services and human resources, to the Board of Directors.

In announcing Bastone’s approval, Altenbaumer promised “she will more than live up to the hype we have spread about her.”

Bastone has nearly 20 years of HR and human capital strategy experience, spending more than half of that time in financial services. Her deep HR background was one of the selling points to the search committee.

She replaces Phyllis Bernard, who left the board last year after 16 years as a director.

Bastone is a partner at investment bank Exos F inancial. She previously held roles at Brookfield Asset Management, Cushman and Wakefield and Knight Capital Group. Bastone has an MBA from the University of Technology Sydney.

“The challenges facing SPP and the RTO industry as a whole will continue to become more complex, and the need for a more agile, digital and strategic workforce becomes critical to its success,” Bastone said in a state m ent. “My focus will be working with the SPP board and management to ensure that we continue to attract, engage and strengthen the skills of the workforce to tackle each of the challenges facing SPP in a more innovative and proactive manner.”