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.”

January 26, 2020

PJM Members Resist TO Critical Infrastructure Filing

By Christen Smith

PJM members endorsed a resolution Thursday that objects to a Tariff attachment pending before FERC that would create a new confidential process to mitigate critical infrastructure on NERC’s CIP-014-2 list.

The unusual step came less than a week after a group of transmission owners submitted the proposal to the commission following several tense conversations dating back to August that left other sectors wary of its vague details.

LS Power, author of the resolution, argues that incumbent TOs don’t get exclusive rights to handling critical infrastructure on the list. Because the projects could carry significant regional implications, the company believes PJM should plan their mitigation — a point other stakeholders echoed during the Members Committee meeting on Thursday. (See PJM TO Filing Stirs Up Transparency Concerns.)

PJM Critical Infrastructure Filing — The Members Committee on Jan. 23 debates a resolution from LS Power opposing a Tariff filing that would mitigate critical infrastructure projects.

“We feel strongly that PJM should have stepped up and taken this issue under its wing as a reliability issue,” said Carl Johnson of the PJM Public Power Coalition. “It would have saved us a lot of trouble.”

The resolution alleges that the filing also conflicts with the Operating Agreement because mitigating these critical assets — which count as a subset of supplemental projects — must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)

The TOs also point out that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without consent from other sectors.

In an effort to quell rising concerns, TOs collected questions from other stakeholders and hosted a webinar in November to answer some of them publicly. The two-hour meeting, however, left many issues unresolved. Seemingly frustrated by the unfolding process, the Planning Committee endorsed an issue charge in December to consider whether PJM must develop governing document language to deal with the mitigation of existing and future critical infrastructure on the list. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)

Top-secret Cost

PJM has refused to take sides in the debate, despite protests from stakeholders that mitigating the facilities presents risks to reliability that the RTO should handle. It’s a decision staff now question, Vice President of Planning Ken Seiler said. (See PJM Remains Neutral in CIP-014 Debate.)

“I agree, we could have done things differently,” he said, noting that a rough estimate of the cost to remove these assets from the list would total much less than $1 billion.

When stakeholders pressed for a more accurate cost estimate — key information many said may make them more comfortable with the Tariff filing — Seiler declined.

“We’ve looked at what the potential solutions would be and most of them are fairly simple,” he said. “Line rerouting, substation reconfiguration, very minor things that would keep the cost at a reduced rate for everybody … we are nowhere near into the billions of dollars on this.”

Sharon Segner, vice president of LS Power, said that although Seiler’s feedback was “encouraging,” there’s nothing in the Tariff proposal that caps costs.

“What would encourage my company even more would be for PJM to be in charge of these top-secret projects,” she said. “If PJM were to be in charge, then this language would go in the OA and not the Tariff. If it’s in the Tariff, at the end of the day, the TOs are in charge. There’s nothing in this language that provides cost containment. There’s a finite number of projects, but there is no restriction on cost.”

PJM Board of Managers member Susan Riley — who last month encouraged TOs and PJM to tally a cost for projects on the list — pushed back against sentiments that the RTO should have greater authority over the process.

“We’ve agreed to have an oversight role,” she said. “TOs have ultimate authority. I know the costs have been moving around, but they are moving down. We are reasonably confident that it won’t be more than $1 billion and won’t be more than 20 projects. We are committed in a very public way. Whether or not there wasn’t enough discussion, that’s up to you. I think there was.”

The MC endorsed the resolution in a sector-weighted vote of 3.83 to 1.17. Segner said LS Power intends to submit the resolution as part of its protest against the TO proposal. Comments on the filing are due within 21 days, Segner said, hence the timing of the vote.

January 26, 2020

FERC Stalls PJM Fast-start Compliance Filing

By Christen Smith

FERC said Thursday it will hold PJM’s fast-start pricing compliance filing in abeyance until July 31 in order to give the RTO enough time to resolve pricing and dispatch misalignment issues currently under review by stakeholders (ER19-2722).

In April, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable. (See FERC Orders Fast-start Rules for NYISO, PJM.) PJM submitted a compliance filing in July that the Independent Market Monitor, state commissions and consumer advocates argued didn’t provide clear evidence that it would implement fast-start pricing correctly.

Specifically, the groups said that PJM uses different market intervals to calculate prices and dispatch instructions, suggesting that resources’ compensation doesn’t correspond to their dispatch instructions.

PJM Fast-start Filing — PJM control room | *PJM*

As part of its April order, FERC directed PJM to alter its real-time energy market clearing process to consider fast-start resources “in a way that is consistent with minimizing production costs.” The process requires PJM to first execute a cost-minimizing dispatch run, followed “by a pricing run where integer relaxation for fast-start resources allows them to set price.” The use of integer relaxation is intended to pinpoint a unit’s commitment costs in the pricing run and allow for their recovery through a market process rather than administrative methods.

“However, PJM may not be able to implement these separate dispatch and pricing runs in a way that is just and reasonable without first resolving the pricing and dispatch misalignment problem,” FERC said Thursday. “If fast-start resources dispatched in a given market interval could be compensated with a price from a different market interval, prices may not accurately reflect the marginal cost of serving load.

“Moreover, implementing fast-start pricing as directed … could exacerbate the pricing and dispatch misalignment issue because the lost opportunity cost payments … may be calculated based on inaccurate prices and, therefore, may not correctly compensate opportunity costs.”

FERC said implementing fast-start pricing now could also render lost opportunity cost payments ineffective “because they may not provide correct incentives to follow dispatch.”

PJM’s stakeholder process to fix the issue remains ongoing, with plans to conclude the effort by May.