FERC has approved NERC’s request for a $3.8 million budget variance to support development of the ERO Secure Evidence Locker (SEL), part of the organization’s Align software project to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise (RR19-8).
NERC requested the variance on June 8, after receiving authorization from the Board of Trustees the previous month. (See “Align Expenditure Moves to FERC for Approval,” Align Tool Set for 2021 Rollout.) NERC’s filing did not provide a reason for the modification.
The organization will pursue a 60-month term for the loan rather than the normal 36 months because of current low interest rates. Annual debt servicing costs are expected to total $430,000 from 2021 to 2025 and will be incorporated in the Business Plan and Budgets for those years. NERC also estimates $570,000 in software, support and maintenance expenses for the ERO SEL in 2021 — based on licensing agreements with hardware and software vendors — with slight increases expected in future years.
Release schedule for Align and SEL as of March 23. NERC has said that Release 1 of the SEL may be delayed from Q4 2020 to Q1 2021 because of the COVID-19 pandemic. | NERC
SEL to Provide Secure Data Storage
Align grew out of the CMEP (Compliance Monitoring and Enforcement Program) Technology Project, begun by NERC in 2014. After NERC selected BWISE Information Security to develop the Align tool in 2018, the organization set its rollout date for September 2019. However, the project was delayed last summer because of concerns over the vendor’s sale to SAI Global, an Australia-based company whose investors include Baring Private Equity Asia, a Hong Kong-based private equity firm. (See NERC Investigating Chinese Tie to Software Vendor.) NERC CEO Jim Robb said earlier this year that the tool is now expected to be released in the first quarter of 2021.
NERC CEO Jim Robb | ERO Insider
The SEL was conceived as a way to provide secure storage where potentially sensitive information collected as evidence can be kept separate from work papers managed through the Align tool itself. Security features of the SEL and training of CMEP staff will prevent the improper access, use or transfer of evidence stored in the locker. NERC’s development plan includes an independent third-party security review of the SEL before launch; the organization expects to conduct annual reviews thereafter.
Several regional entities maintain their own digital lockers to store evidence associated with NERC’s Critical Infrastructure Protection reliability standards. NERC says the SEL, which will store “evidence associated with CMEP processes,” is not intended to replace these systems and that, in fact, REs are welcome to construct their own lockers for CMEP evidence as an additional security measure, though all such systems are expected to “meet certain functionality criteria.”
NERC originally planned to roll out the SEL in an update to Align, but development was accelerated at the request of registered entities last year after the tool’s first delay. As of the Align team’s most recent stakeholder update in March, it was targeting a fourth-quarter release for the SEL, though in its variance request, NERC said a delay to the first quarter of next year may be necessary “due to supply chain disruption caused by the COVID-19 health crisis.”
FERC last week denied a complaint by Amtrak challenging the transmission rates charged to the railroad company by PPL and seeking more than $12.5 million in refunds (EL19-78).
Exelon’s Constellation NewEnergy (CNE) supplies electricity to the Amtrak-owned Conestoga substation outside Lancaster, Pa., from or through the nearby Safe Harbor hydroelectric plant, which is directly connected to the substation. Amtrak alleged in its May 2019 complaint that it is being assessed “unreasonable” charges by PPL for network integration transmission service (NITS) because no PPL transmission facilities are used to deliver energy to it from Safe Harbor.
PPL, which formerly owned the substation, holds a “floating easement” there, allowing energy generated at Safe Harbor to be delivered to the transmission system to serve third parties. The power needed by the railroad flows through the substation to serve its rail system at Parkesburg and Royalton in Pennsylvania, and at Perryville, Md.
An Amtrak train stops at a station in Lancaster, Pa.
Amtrak complained that PPL’s NITS charges for energy delivered from Safe Harbor to Conestoga to serve Parkesburg and Royalton have “no basis in the physical configuration of the substation, operation or Amtrak’s consumption patterns.”
FERC found that PJM’s Tariff provisions applied appropriate NITS charges at the Conestoga substation because Amtrak indicated it receives most of its power from Safe Harbor, which is a network resource.
“Although Amtrak claims that PPL violated the PJM Tariff by calculating Amtrak’s Parkesburg and Royalton load based on an unfiled methodology, Amtrak’s fundamental argument is that Amtrak should not be charged for NITS for its load at Parkesburg and Royalton if the power Amtrak is supplied by its retail supplier does not flow across PPL’s transmission facilities,” the commission wrote, saying that the railroad is seeking transmission services “that are inconsistent with the PJM Tariff and commission policy.”
Map of Amtrak service at Conestoga | FERC
Amtrak also acknowledged that on “rare occasions” when Safe Harbor is unable to meet energy demands, power flows in through PPL’s Manor substation on PPL lines, across Safe Harbor’s frequency converter and into the Conestoga substation.
FERC responded that having a backup power source “is what it means to take and rely on network service” and that a transmission provider like PPL “plans and provides for firm transmission capacity sufficient to meet the customer’s current and projected peak loads.”
“Given these benefits, it is appropriate that Amtrak bears the costs associated with its reliance on the transmission system, as its retail supplier, CNE, is a network customer relying on a network resource,” the commission wrote.
New England needs a CO2 price of $25 to $35/ton by 2025, rising to $55 to $70 by 2030, to meet states’ carbon emissions goals, according to a report released Wednesday by the New England Power Generators Association (NEPGA).
The report, prepared by the Analysis Group, says carbon pricing is essential to preserving wholesale electric competition and ensuring the least-cost path to meeting the New England states’ 2050 goal of reducing economy-wide greenhouse gas emissions by almost 80% compared with 2015 emissions.
Projected CO2 emissions changes by sector under high electrification | Analysis Group
While other studies have focused on the 2050 end-state, said NEPGA President Dan Dolan, “this report provides a viable pathway to meet New England’s climate change responsibilities by producing needed investments in electricity supplies and enabling electrification in transportation and heating.”
A multisector carbon price is essential to the “deep and continuous investments” needed to electrify transportation and heating and build the power system infrastructure to support the transition, the report says. “Without a multisector approach, the financial signal for electrification in transportation or residential heating would be undermined because CO2 emissions have only been valued in the electricity sector,” it says.
Daily net load variability (January 2035) | Analysis Group
The study employed production cost modeling to determine the carbon prices needed in 2025, 2030 and 2035 to ensure “revenue sufficiency” for the resources required to meet GHG reductions without state or federal procurement mandates or subsidies.
Although the carbon prices calculated are lower than the estimated social cost of carbon, “they would allow for market competition to drive evolution of the region’s power system without state-mandated procurement of specific generation resources,” the study says. “The lower range of CO2 emission prices for 2025 recognizes that certain New England states have already made long-term contractual commitments that provide the financial support needed for various zero-emission resources to be brought into service or remain operational.”
The volume of zero-emission resources needed by 2030 and 2035 will increase the frequency of zero-price energy hours, putting downward pressure on prices and requiring a higher carbon price for them to remain viable without subsidies, it says.
The study assumed light-duty electric vehicle penetration of 25% in 2025, 60% in 2030 and 90% in 2035. Similarly, it assumed 25% of homes heating with oil, propane or natural gas would switch to electric by 2025, rising to 50% by 2030 and 75% in 2035.
Lower Household Prices?
Although a carbon price would increase wholesale power prices, it “would not drive up consumer costs materially if states choose to rebate carbon revenues,” the study says.
It projects that average residential household energy costs would actually decline by 2035 under electrification.
Without the transition, the study posits annual household energy costs will rise from less than $6,000 currently to almost $8,000 by 2035. Costs would be less than $7,000 with electrification and a carbon price, it said.
Electrification of the transportation sector would be the biggest source of GHG reductions. While residential heating electrification would produce only “modest contributions” to GHG cuts, it would turn ISO-NE from a summer- to a winter-peaking region by 2030.
Estimated average annual consumer energy costs for households that adopt electric vehicles and convert home heating system from fuel oil or natural gas to electric heat pumps | Analysis Group
The study also notes the increasing need for flexible electric sector resources to respond to increased hourly net load variability. More variable renewable resources and the addition of EV and heating loads would increase average hourly ramping requirements to more than 15,000 MW at times in winter, it says.
“Even assuming a significant quantity of technologically feasible energy storage resources, the availability of existing fossil fuel generators will be vital over at least the next one to two decades” for ISO-NE to manage the change in load shape and growth in daily ramping needs, it says.
Competitive markets with efficient carbon pricing could save consumers $100 million to $300 million ($2020) between 2026 and 2035 compared with reliance on utility-administered resource procurements.
A carbon price would allow technology-neutral competition; reduce reliance on out-of-market contracts that lock in long-term costs; ensure financing in the absence of long-term contracts; increase incentives for developing new supply-side and demand-side technologies; and encourage consumer use of demand management, the study says.
Historical and expected economy-wide greenhouse gas emissions by state | Analysis Group
“It is obvious that establishing enhanced carbon pricing in electric energy markets is not an easy path to take from political and regulatory perspectives,” it says. “Yet pursuing these objectives through state-mandated programs and procurements will almost certainly achieve the results imperfectly, and at costs in excess of what would result through efficient carbon pricing. …
“The absence of an effective carbon-pricing mechanism is a fundamental challenge to continued reliance on competitive markets,” it says, calling the Regional Greenhouse Gas Initiative insufficient. “Absent adoption of a carbon price in energy markets, the pace and magnitude of additions of out-of-market, procurement-based resources will likely undermine the continued relevance of wholesale markets in New England as a vehicle for resource development and investment. … Carbon pricing in energy markets is not an easy path to take, but it may be the only one that can preserve the operation of competition for the benefit of consumers.”
FERC denied CAISO’s request to reconsider its rejection of the ISO’s proposal to adopt a “net export limit” to help entities in the Western Energy Imbalance Market avoid unintended consequences of market power mitigation.
But the commission’s June 18 order denying rehearing clarified that its initial ruling did not imply that unmitigated bids would be effective in determining LMPs for serving load in an import-constrained balancing authority area (BAA) subject to local market power mitigation (ER19-2347).
The commission’s Sept. 19, 2019, order nixed the ISO’s proposal to introduce a net export limit that would have allowed EIM entities to limit the additional dispatch of resources when resources’ bids are reduced because of their BAAs becoming subject to bid mitigation. (See CAISO Goes 2 for 3 on EIM Hydro Rule Changes.)
Active and pending participants in the Western EIM | CAISO
As FERC explained in its order, “the optional feature would [have allowed] EIM entities to limit net transfers out of the mitigated BAA to the greater of: (1) the pre-mitigation transfer quantity, or (2) the base transfer quantity, plus, for both (1) and (2), the sum of the flexible ramping up awards in the market power mitigation run in excess of the BAA’s flexible ramping-up requirement.”
CAISO intended to enforce the rule in both the 15-minute and real-time markets to ensure that every interval limit was determined separately.
In rejecting the provision, FERC ruled that it was “inconsistent” with the EIM’s market power mitigation framework and “not an appropriately calibrated solution to the concerns CAISO identifies.”
“In particular, CAISO’s proposal could weaken CAISO’s market power mitigation process by allowing EIM entities to withhold generation through the submission of high supply bids and restricting EIM transfers out of their BAAs,” the commission wrote.
In seeking rehearing, CAISO argued that there was no evidence supporting FERC’s conclusion that the proposed net export limit would encourage EIM entities to withhold generation. In fact, CAISO said, the net export limit would encourage suppliers to offer greater levels of supply into the EIM because “it was designed to eliminate the existing incentive for an EIM entity, if it wishes to limit the amount of energy that its resources may have to sell at mitigated prices, to only offer the minimum amount of required supply.”
“We are concerned that CAISO’s proposed incentive for greater participation in the EIM is likely to produce outcomes that are not just and reasonable. Contrary to CAISO’s assertions, the direct effect of the proposed net export limit would be to allow EIM entities to limit the dispatch of their resources if they are mitigated in the market power mitigation run,” FERC wrote.
In its motion for clarification, CAISO faulted FERC for “failing to explain how the existing local market power mitigation system and the participation in the proposed net export limit feature can result in ‘unmitigated bids … determin[ing] the dispatch to serve load outside of the EIM entities’ BAAs.’”
FERC said that wasn’t the case.
“We acknowledge that all supply bids in an import-constrained BAA would continue to be subject to mitigation under CAISO’s proposal. However, the proposed net export limit would allow an EIM entity to cap its net transfers and the restriction on supply would affect dispatch in the exporting BAA and in other BAAs,” it said.
FERC denied a complaint filed by Anbaric Development Partners seeking an order for PJM to allow developers of offshore transmission “platforms” the ability to obtain injection rights.
In its decision filed June 18, the commission ruled that Anbaric failed to demonstrate that the PJM Tariff is “unjust and unreasonable” because of the RTO’s refusal to allow three proposed offshore transmission projects to receive transmission injection rights (EL20-10).
Anbaric and other transmission developers argued to PJM that having individual wind farms build separate radial lines to shore will be more expensive, more environmentally intrusive and less resilient than networked open access facilities that multiple wind farms could use.
Anbaric is focusing much of its efforts on areas off the coast of Massachusetts, which is seeking aggressively to develop offshore wind. | Bureau of Ocean Energy Management
“PJM’s interconnection analyses require a source and a sink and controllability in order to meet operational requirements, such as measuring congestion and assessing deliverability,” the commission wrote. “Rather than ‘picking winners and losers,’ these requirements enable PJM to ensure that its transmission system operates reliably and efficiently. Any merchant transmission facilities that meet these Tariff requirements may seek interconnection to the PJM system.”
PJM’s Tariff allows merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. In early 2019, stakeholders approved a problem statement that considered allowing merchant transmission developers to request injection rights for non-controllable AC transmission offshore, but after six special sessions, members opted to refrain from changes. (See “PJM Recommends Sunsetting Offshore Wind Special Sessions,” PJM PC/TEAC Briefs: Sept. 12, 2019.)
Anbaric — which helped build the 660-MW Neptune HVDC cable linking PJM to Long Island and the 660-MW Hudson project connecting Manhattan to the RTO — filed the FERC complaint after the stakeholder process failed. It is still planning a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, Anbaric Pushes Offshore Grid Plans.)
In March 2018, Anbaric submitted interconnection requests for two proposed AC transmission platform projects seeking 1,100 MW of injection rights, but PJM told the company it would need to partner with a generator to obtain the rights under current Tariff rules.
Anbaric envisions a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, NYISO and ISO-NE. | Anbaric Development Partners
Then in June 2018, Anbaric submitted an interconnection request for a proposed DC transmission platform project seeking a 1,200-MW injection into Public Service Electric and Gas’ transmission system in North Brunswick, N.J. After completing a feasibility study that assumed the injection, PJM informed Anbaric in November 2019 that it would only model the project without injection rights.
The company argued to FERC that there are no technical reasons for blocking transmission platform projects, citing transmission built to deliver onshore wind from Texas’ Competitive Renewable Energy Zones and California’s Tehachapi Pass. FERC dismissed the argument, saying PJM already has the “State Agreement Approach” in its Regional Transmission Expansion Plan (RTEP) process that can be used for transmission to offshore wind.
The commission last week issued a notice that it will hold a technical conference on Oct. 27 to discuss “whether existing commission transmission, interconnection and merchant transmission facility frameworks in RTOs/ISOs can accommodate anticipated growth in offshore wind generation in an efficient and effective manner that safeguards open access transmission principles and to consider possible changes or improvements to the current framework should they be needed to accommodate such growth.”
Commissioner Bernard McNamee issued a concurring statement in the Anbaric order saying the technical conference will allow FERC to hear from industry experts about the challenges and opportunities of developing offshore wind projects.
“A key element to gaining access to offshore wind is the construction of and access to transmission to bring wind-generated electricity onshore to the grid,” McNamee wrote in his statement. “As discussed in today’s order, there are a number of complicated issues involving open access, financing and jurisdiction that need to be confronted.”
First came the wind turbines, then solar panels. Battery storage followed, and now RTOs and ISOs are faced with integrating hybrid energy resources.
The main barrier to their integration? The RTOs and ISOs themselves.
“All of the markets are having conversations but in different stages and with different scopes,” said Jason Burwen, vice president of policy for the U.S. Energy Storage Association, during a recent online panel discussion facilitated by his organization. “We are starting to see how different markets are going to take this on.”
Grid Strategies President Rob Gramlich, who last year authored a paper for the ESA on the subject, says regulations have not kept up with technology and the markets. He thanked FERC for pursuing “some” reforms but noted the commission’s recent orders on storage (841) and interconnections (845) don’t address hybrid resources.
“It’s been just incredibly fast how much the market has changed,” he said during ESA’s June 11 discussion. “Hybrid doesn’t even appear in those rulemakings. That’s not the fault of FERC. It’s just that nobody raised it. The market has moved faster than policy.”
Hybrid resources are generally considered to be co-located pairings of two different technologies. Most of these resources consist of solar or wind installations paired with batteries, the “core technology driving hybridization,” Gramlich said. Batteries are highly scalable and modular, making them suitable for generation sites, integrating them into the wires’ infrastructure, or locating them with the customer.
Solar PV generation is the most common resource paired with batteries, but other configurations include wind-battery, gas-battery and hydro-battery. These resources’ ability to respond to economic signals differently than traditional generators has driven their recent growth.
According to the U.S. Energy Information Administration, some 4.6 GW of hybrid capacity is currently installed, with another 14.7 GW of capacity in the immediate development pipeline. More than 40 GW of hybrids entered generator interconnection queues last year, pushing the total hybrid capacity in RTO/ISO queues to 69 GW.
Hybrid costs are also coming down, further increasing their attractiveness. Gramlich said power-purchase agreement prices in the U.S. dropped from $40-70/MWh in 2017 to $20-30/MWh in 2018 and 2019, mostly due to falling technology costs and tax credits.
Hybrid resources are filling up interconnection queues. | Grid Strategies
“There are big opportunities for adding storage to existing generation. The main problem is the interconnection queues are very slow,” he said. “Everyone knows the interconnection queues are a constant challenge. If one can make a more efficient use of the interconnection service with an existing service or one that‘s made it through some stages of the queue, that’s an efficient way to go.”
“Order 841 opened the floodgates. Hybrids weren’t previously on the radar,” said Rhonda Peters, a principal with InterTran Energy Consulting. “All of a sudden, you had this ability to take variable generation and make it more dispatchable [with energy storage]. But having that ability didn’t mean it was actually possible because we didn’t have policies that allowed for it.”
The panel members all called for FERC and the RTOs and ISOs to get serious about hybrid resources. In his paper for ESA, Gramlich said some near-term changes can be made to improve integration of the resources by treating them as two separate units and harmonizing their participation models.
“However, for hybrid resources to deliver their full value, they may eventually need to be treated as fully integrated single machines, able to optimize what they provide and when they provide it,” he said, noting RTOs’ and ISOs’ current rules do not allow for this flexibility.
“We’re starting to see how different markets are starting to take this on,” Burwen said, indicating ERCOT and CAISO are taking the lead. “ERCOT plans to use an energy storage model for hybrids. That’s instructive of the direction we’re going. Participating as conventional generation might make more sense than [being paired with] existing resource types. It sets a market for where we think you’re going to make the best use of hybrids.”
FERC is seeking industry comments on a proposed incentive framework meant to encourage utilities to make cybersecurity investments above and beyond the requirements of NERC’s Critical Infrastructure Protection (CIP) standards (AD20-19).
Limitations in CIP Standards Recognized
In a white paper published Thursday, FERC described the proposed incentive framework as a complement to the current CIP standards, which the commission called an “effective technical baseline for cybersecurity practices.” A separate Notice of Inquiry, also issued Thursday, is seeking comments on potential gaps in the standards and suggestions on actions the commission can take to improve them. (See related story, FERC Starts Inquiry on CIP Standards.)
The new proposal is not directly connected to the NOI. Although the commission did recognize “certain limitations” in the existing CIP standards and suggested that voluntary actions by utilities as a result of the planned incentives “could be the basis of future” versions of the standards, FERC’s goal is to encourage utilities to pursue innovative — and voluntary — solutions that would protect their own transmission systems as well as the bulk electric system overall, while allowing the industry to:
be more agile in monitoring and responding to new cybersecurity threats;
identify and respond to a wider range of threats; and
create comprehensive solutions for addressing cybersecurity threats.
Such encouragement could take the form of either return on equity and non-ROE incentives, but the commission favored a mix of both approaches based on the type of investments being reported. ROE incentives would apply to specific incremental cybersecurity investments, while non-ROE measures could apply to construction work in progress, recovery of abandoned plant costs and accelerated depreciation, which would allow utilities to mitigate cash flow concerns caused by initiatives with a longer-term payoff.
Alternative Frameworks Proposed
FERC also sought input on how to identify the cybersecurity investments that merit its incentives, proposing two approaches that could be used independently or in combination. Both would reward utilities for going beyond the requirements of the CIP standards but would use a different basis for assessing their success.
| Shutterstock
The first proposed method would encourage entities to apply the current standards in areas where they are not currently relevant. Specifically, several CIP standards apply only to medium- and/or high-impact BES cyber systems, leaving many low-impact systems unaddressed — a distinction that has prompted criticism from security activists. (See NERC Pushes Back on New CIP Standard Challenge.) FERC would provide an ROE adder or other incentive for utilities that voluntarily apply CIP standards to BES cyber systems with a lower impact than those for which the standards were intended.
An advantage of this approach is that utilities and regulators would be working within a framework with which they are already familiar, making the criteria for approving an incentive clear. On the other hand, it would also leave registered entities with little reason to look beyond this framework. For that reason, the commission put forward another approach, under which incentives would be based on the National Institute of Standards and Technology’s (NIST) Cybersecurity Framework. This more open-ended approach would require more work from the commission to assess whether cybersecurity investments meet its goals but would allow greater flexibility and creativity on the part of utilities.
Further Questions
In the white paper, FERC emphasized that it is far from making a decision on the final shape of its incentive framework. To guide its decision-making, the commission is requesting comments on a number of questions, including:
whether the CIP standards or the NIST Framework, or both, should be considered as the basis for incentivizing cybersecurity investments;
how FERC can ensure that the incentive eligibility and applicant evaluation processes are clear and fair;
what guidance FERC can provide on structuring cybersecurity incentive applications;
which components of the NIST framework should be considered for an incentive, and how entities might demonstrate that their cybersecurity expenditures qualify under the framework; and
whether the commission should adopt a sunset date for incentivized cybersecurity investments in order to encourage utilities to keep up to date with a changing security environment.
Comments on the white paper are due within 60 days of its issuance, with reply comments due within 75 days.
To ensure that PDRs are not double counted as both a load-reduction and a supply resource in the FCA, the RTO “reconstitutes” PDR demand reductions — most of which is energy efficiency — into historical loads. The goal is to ensure the EE in the gross demand forecast approximates how much EE that will participate in the upcoming FCA.
Since 2010, the RTO has performed reconstitution using total EE measures installed, believing it to be roughly equal with the amount of capacity supply obligations (CSOs) obtained by EE resources cleared in the FCA. But the RTO says it now realizes that EE program administrators install and report EE measure quantities above the CSOs acquired in the FCA. The RTO has no way to differentiate which measures are installed to meet a CSO and which measures are not.
Under the revised methodology, the gross load forecast will be tied to EE’s participation in each FCA rather than all EE that is installed and reported to ISO-NE.
Illustration of gross load forecast adjustments | ISO-NE
“What we’ve seen is the CSOs for the [Annual] Reconfiguration Auctions are higher than the primary auctions, so we’re trying to correct things for the upcoming primary auction, and now we’re trying to adjust that gross load forecast accordingly to reflect the known differences in the amount of CSOs and PDR that clears in the Reconfiguration Auctions,” Black said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
The proposed methodology for adjusting the gross load forecast for the ARAs is based on the average difference between the two most recent reconfiguration auction CSOs and those of the FCAs for the corresponding capacity commitment periods.
The proposed changes would cut forecast 2020 50/50 gross summer peak demand by 652 MW, rising to 1,355 MW for the 2029 forecast. No changes will be made to the existing methodology utilized to reconstitute active demand resources.
Proposed PDR reconstitution methodology | ISO-NE
The change in load forecasting methodology is the first of three related initiatives the RTO introduced to NEPOOL technical committees so far this year. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments, and the third is intended to improve integration of the FERC Order 1000 solicitation process into the reliability delist bid review, starting with FCA 15.
The RTO will present the load forecasting methodology changes to the RC for an advisory vote in July. If the Participants Committee approves them in August, the RTO will file the Tariff changes with FERC with a requested effective date of Oct. 5.
Operating Changes for Storage
The committee recommended PC support for revisions to Operating Procedure 18 (OP-18) to enable DC-coupled facilities to participate in ISO-NE markets as separate assets.
ISO-NE Manager of Demand Resource Administration Doug Smith presented the proposal, which passed with opposition from two Publicly Owned Entity sector members and an abstention from one Transmission Owner. The proposed effective date is Aug. 6, 2020. (See “Metering for DC-coupled Assets,” NEPOOL Reliability Committee Briefs: May 19, 2020.)
Several market participants are installing electric storage and intermittent generation behind the same point of interconnection. Because some of those co-located facilities are DC-coupled — both the storage and intermittent components share one or more inverters — there is a need to address the metering of such assets.
Load Power Factor Correction
ISO-NE Manager of Real Time Studies Dean LaForest delivered an introductory presentation on improvements proposed for the tracking of the load power factor, the ratio of real power flowing to load versus apparent power in the circuit.
Under Operating Procedure 17 (OP-17), the RTO monitors load power factor by requiring participants to submit survey data for six discrete points in time over the 12-month survey period. But there are “no significant consequence[s]” for failing to meet load power factor standards, LaForest said.
Under the proposed change, the RTO would monitor performance using data from its supervisory control and data acquisition system, allowing it to track every hour of the year.
Poor load factor at high loads — in which reactive power is absorbed from the system — can require unit commitments to support post-contingent low voltage. Poor load power factor at light loads — with reactive power injected into the system — is more common and can require unit commitments to support pre- or post-contingent high voltage, LaForest said.
The RTO would use the more robust data to report on areas where poor performance hurts reliability or increases unit commitment costs.
Compliance with the load power standards for each area would be “consistent” with current operating procedure compliance practices, LaForest said.
Noncompliant entities would be allowed an opportunity to improve their performance; continued failures would result in actions under “existing compliance mechanisms,” he said. The RC will review redline changes to OP-17 in July, with a vote expected in September and PC action in October.
Committee Actions
The RC’s notice of actions included approval of several power purchase agreements.
The committee approved the New England Clean Energy Connect HVDC transmission project from Eversource Energy and Central Maine Power. Based on a voice vote, the motion passed with two Publicly Owned Entity members opposed and eight abstentions.
Also approved were the:
King Street Comprehensive Solar Cluster Project (New England Power);
ASO South Comprehensive Cluster Project (New England Power);
Wareham Cluster Solar and Battery Project (Eversource);
Versant Power Cluster Solar Project (Versant Power/Emera Maine);
Great River Hydro AVR Replacement and Digital Governor Retrofit Project (Great River Hydro);
Highland Avenue Dartmouth Cluster Solar and Battery Project (Eversource);
CMEEC New London Navy Fuel Cell Project (Connecticut Municipal Energy Electric Co.); and
Waterford Solar Project (Eversource).
The committee also recommended PC approval of revisions to Planning Procedure No. 5-1 to update the form for submitting PPAs, with a proposed effective date of Aug. 6. In response to an increase in PPAs and generator notification forms (GNFs) being processed monthly, the revised procedures require submittals 10 business days before the monthly RC meeting date.
The great pause brought on by the novel coronavirus pandemic could have one upshot for MISO: It will likely save millions of dollars this year.
The RTO is currently 3% — or $2.6 million — under budget in base operating expenses for 2020, primarily the result of a halt in employee travel and training initiatives and lower staffing levels because of a slowdown in new hires.
“COVID has introduced quite a bit of volatility in our financials,” CFO Melissa Brown told MISO’s Board of Directors during a virtual meeting Thursday.
Reductions in utility bills and building maintenance also contributed to the savings, as have delays in work being done by third-party contractors, a product of physical distancing measures, she said.
And while it was “challenging” to conduct remote interviews with prospective MISO employees while lockdowns were at their strictest, Brown said the RTO is now back to interviewing and onboarding.
“I think it’s the shock factor that occurred during the March-April time frame,” she said. “Most of delays, we’re already seeing reversals out, and we expect them to reverse completely by the end of the year.”
Still, MISO predicts to be about $7.3 million — or 2.7% — below its base operating budget by the end of 2020. Brown cautioned the board that MISO’s year-end prediction could change as the pandemic evolves. The RTO had a $264.7 million base operating budget planned for 2020.
“There are still quite a lot of unknowns in the back end of the year,” Brown said. “We expect to continue to have a lot of variability. It could go up or down, and we don’t claim to know the future.”
Other MISO budgets have suffered larger impacts from the pandemic.
Brown said MISO’s other operating expense budget is so far $6.8 million — or 18% — below what was budgeted for 2020, as fewer FERC assessment fees roll in and the third-party studies the RTO depends on for its own engineering studies are held up. By year-end, MISO expects other operating expenses to be down nearly $16 million. And project investments so far this year are down $1.4 million, or a little more than 9% below budget, she said, though MISO expects to be back on track in spending for those investments by the end of the year.
MISO also earned $3.9 million less than it projected to make in interest so far this year.
“What we’re seeing in interest is a marked reduction on interest income,” Brown said, adding that MISO expects to make about $10 million less than it originally anticipated in interest income by the end of 2020.
However, MISO still expects to have a $150.3 million year-end cash balance, slightly higher than the $148.7 million it planned for in its 2020 budget.
Stakeholders unanimously endorsed the charter for the new PJM Emerging Technologies Forum at Thursday’s Markets and Reliability Committee meeting.
Eric Hsia of PJM reviewed the charter, saying significant changes were made after some stakeholders expressed concerns with adding another subcommittee to the schedule. The subcommittee was instead changed to a forum with no formal decision-making role. (See “Emerging Technologies Subcommittee Proposed,” PJM MRC Briefs: April 30, 2020.)
Hsia said the forum is designed to keep stakeholders abreast of technology pilot programs PJM is seeking to implement and to facilitate discussions with technology providers. It will work to ensure transparency through a periodic review of the advanced technology pilot program, Hsia said, and continue fostering collaboration with technology providers and stakeholders.
The forum will not make selections of pilot projects and programs, Hsia said, with PJM maintaining management over the selection. Hsia said no official votes on issues will be made at the forum, but members will be able to conduct nonbinding votes and make recommendations that stop short of creating and voting on solution packages.
The group is currently targeted to meet monthly, with the first forum expected in August.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, expressed support for the forum and urged PJM staff to consider cost-benefit analyses in discussing projects. He said costs are one of the primary concerns of consumer advocates when discussing new initiatives.
Adrien Ford of Old Dominion Electric Cooperative said the changes made to the charter by PJM after stakeholder feedback have made it a stronger and more focused group.
Stakeholder Group Sunsets
Members unanimously endorsed sunsetting seven stakeholder groups that PJM staff said had achieved their original goals.
Dave Anders of PJM said stakeholder feedback resulted in modifications to the original list introduced at the May MRC meeting. (See “Task Force Sunset,” PJM MRC Briefs: May 28, 2020.)
Anders said the Modeling Generation Senior Task Force was struck from the sunset list. The task force met on June 10, Anders said, and members at the meeting expressed support for continuing to meet as needed to provide guidance and feedback.
The other suggested change based on feedback was to keep the Energy Price Formation Senior Task Force, Anders said. Although FERC last month approved PJM’s proposed energy price formation revisions, several members thought additional commission guidance could be received that will require more work related to the task force’s charter, he said.
FERC ordered PJM to submit a compliance filing in 45 days modifying the capacity market’s energy and ancillary services offset to reflect the additional revenues resources will receive under the new rules. (See FERC Approves PJM Reserve Market Overhaul.)
The groups being sunset are the:
Generator Offer Flexibility Senior Task Force, which last met November 2015;
Energy Market Uplift Senior Task Force, which last met March 2017;
Incremental Auction Senior Task Force, which last met January 2018;
Summer Only Demand Response Senior Task Force, which last met September 2018;
Primary Frequency Response Senior Task Force, which last met December 2018 (PJM provided a separate presentation on the work of the task force.);
Distributed Energy Resources Subcommittee (DERS), which last met in May; and
Intermittent Resources Subcommittee (IRS), which last met in March.
Erik Heinle, of the D.C. Office of the People’s Counsel, asked for clarification regarding the two subcommittees on the list, the DERS and IRS.
The MRC approved sunsetting seven stakeholder groups but agreed to retain the Modeling Generation Senior Task Force and Energy Price Formation Senior Task Force. | PJM
Anders said the intention is to form a new subcommittee, the Distributed Energy Resource and Inverter-based Resources Subcommittee (DIRS), combining the scope of work of the two groups. Anders said DIRS will report to the Market Implementation Committee, which is set to approve its charter at the July 8 meeting.
5-Minute Dispatch and Pricing
Debate continued on PJM’s proposal to improve coordination of its five-minute dispatch and pricing during a first read of the Operating Agreement and manual language changes.
Adam Keech of PJM presented the highlights of the package, which calls for “work streams”: short-term market changes to address pricing alignment; “enhancements and clarifications” to LMP verification; intermediate operational changes to implement more “regimented” real-time security-constrained economic dispatch (RT SCED) case approvals; and long-term operational changes to investigate changing SCED timing and consider previous dispatch instructions.
The RTO’s proposal will be voted on at the July MRC and Members Committee meetings. Pending FERC approval, implementation is tentatively slated for October.
Keech said PJM decided to break the process up into short-term, intermediate and long-term efforts based on how quickly they could be implemented.
PJM’s proposed short-term fixes would align the locational price calculator (LPC) to use the reference RT SCED case for the same target time. The LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. ET using the RT SCED solution for a 12 p.m. target time.
Much of the debate has centered on stakeholders’ desire to implement long-term dispatch changes along with the short-term and intermediate changes.
PJM’s “work streams” for improving coordination of its five-minute dispatch and pricing | PJM
Keech said PJM is dedicated to working with stakeholders on the long-term changes and determining if there are formulation changes needed for dispatch by doing side-by-side comparisons with the different dispatch methods used at MISO, SPP, CAISO and ERCOT. PJM is proposing holding the long-term discussion as a working issue at the MIC with reports provided to the Operating Committee, Keech said. Detailed discussions could start at the MIC by September.
Ford said she was glad PJM is committing to look at long-term solutions and suggested making the discussions a special session of the MIC because of the education needed to understand the concepts.
“September sounds as good a time as any to start so that we’re not waiting too long,” Ford said.
Paul Sotkiewicz of E-Cubed Policy Associates said PJM’s short-term proposal and the process moving forward on long-term issues are “eminently reasonable.” He said the point of stakeholder discussions are to get to a place where PJM is using the most up-to-date information possible, making dispatch and pricing more reflective of conditions.
Keech said PJM is looking forward to engaging with stakeholders on the discussions and solutions.
“I can assure you and the entire stakeholder community that we are committed to continuously getting better,” Keech said.
Members Committee
PMA Credit Requirements
Stakeholders unanimously endorsed Tariff revisions related to peak market activity (PMA) credit requirements to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS). The change was endorsed through acclamation, with one abstention.
In 2015, the Public Utilities Commission of Ohio moved NITS and other related charges to a non-bypassable rider that is the responsibility of the electric distribution company. The change means competitive retail electric suppliers serving load in Ohio are no longer allowed to collect NITS or any other transmission-related charges from end-use customers.
PJM requires load-serving entities to sign NITS agreements and post collateral based on their PMA and gives itself the ability to make changes to a participant’s PMA requirement when the RTO determines the PMA is not representative of expected activity. (See “‘Quick Fix’ on PMA Credit Requirements,” PJM MIC Briefs: April 15, 2020.)
Surety Bonds as Collateral
Members endorsed Tariff revisions to approve surety bonds as a form of collateral. The revisions passed with three objections and three abstentions in the consent agenda portion of the meeting.
The proposal allows the use of surety bonds as collateral for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
PJM said it will require the use of bond companies on the U.S. Treasury Department’s certified list and a minimum credit rating of A with S&P Global Ratings, Fitch Ratings and AM Best, or A2 with Moody’s Investors Service. PJM also will require one-day payment demand terms.
