Study: $25 Carbon Price Needed to Meet Goals

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.

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.

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.

“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.”

June 23, 2020

FERC Clarifies Western EIM Order

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 Chan g es.)

Western EIM order — 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.”

FERC didn’t buy the argument.

“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.

June 23, 2020

FERC Rules Against Anbaric in OSW Tx Order

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.

In its Nov. 18 Anbaric Seeks FERC Help on OSW Tx.)

Anbaric offshore wind — 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.

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 n o tice 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.”

June 23, 2020

FERC, RTOs Need to Set Hybrid Rules, Experts Say

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.”

FERC hybrid rules — Rob Gramlich, Grid Strategies | © *RTO Insider*

Grid Strategies President Rob Gramlich, who last year authored a pap e r for the ESA on the subject, says regulations have not kept up with technology and the markets. He thanked FE R C 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.

“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 ERCO T and CAI S O 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.”

June 22, 2020

FERC Seeks Comments on Cyber Investment Incentives

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.

Cyber Investment Incentives — | *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.

June 22, 2020

NEPOOL Reliability Committee Briefs: June 16, 2020

NEPOOL Reliability Committee Briefs: May 19, 2020.)

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.

“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.

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);
Bridgeport Fuel Cell Project (Avangrid/United Illuminating);
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.

June 22, 2020

Pandemic Pause Leaves MISO Under Budget

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.

MISO budget — MISO CFO Melissa Brown in 2018 | © *RTO Insider*

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.

June 22, 2020

PJM MRC/MC Briefs: June 18, 2020

Markets and Reliability Committee

Emerging Technologies Forum

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.

The measure was endorsed nearly unanimously at the MIC meeting. (See PJM 5-Minute Dispatch Proposal Endorsed.)

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 p eak m arket a ctivity (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.

Bridgid Cummings of PJM reviewed the revisions.

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.

June 22, 2020

SPP Briefs: Week Ending June 19, 2020

SPP is facing a two-month delay in gaining FERC approval of the Tariff for its Western Energy Imbalance Service (WEIS) market, staff said last week (ER20-1059, ER20-1060).

Regulatory Policy Manager Nicole Wagner told the Western Market Executive Committee (WMEC) on Friday that SPP, in responding in May to a deficiency letter from the commission, has asked for approval by July 21. The RTO had requested a May 21 approval date when it filed its proposed Tariff in February. (See “WEIS Tariff Approved, on to FERC,” SPP Board of Directors/MC Briefs: Jan. 28, 2020.)

The grid operator plans to launch its Western Interconnection energy imbalance market on Feb. 21, 2021.

FERC in April a ske d SPP for additional information in 14 categories, ranging from implementation and administrative costs to whether marketing employees will sit on the WMEC and how the RTO will ensure committee members do not “run afoul” of separation-of-function rules.

The RTO’s May response drew protests from a number of western utilities, led by Xcel Energy. The company sa id the WEIS Tariff could impair a joint dispatch agreement involving many of the entities. The company also said market flows may harm the Western Interconnection’s unscheduled flow mitigation plan and that SPP disregards the Northwest Power Pool’s activities.

Asked whether SPP would respond to the protests, Wagner said, “We have discussed the possibility of filing additional information with FERC.”

SPP’s WEIS market, with eight participants, is an alternative to CAISO’s Western Energy Imbalance Market. CAISO and PacifiCorp started the EIM in 2014 and have nine participants. They plan to add 10 more by 2022.

Staff said the WEIS implementation program’s various projects are all on schedule, now that it has taken delivery of the market engine that will make everything work. “That was big news for us and why we’re back on schedule,” said David Kelley, SPP’s director of seams and market design.

The program’s costs are trending at or less than 5% above budget. Market trials begin July 1 with connectivity testing. Structured and unstructured testing is scheduled for Aug. 3-Nov. 20.

Staff Close to Seams Agreement with AECI

SPP is working with Associated Electric Cooperative Inc. (AECI) to address remaining reliability concerns over a sidelined competitive interregional upgrade, staff told the Seams Steering Committee on Thursday.

The 105-mile Wolf Creek-Blackberry project in Kansas and Missouri, projected to cost $152 million, was approved by SPP’s Board of Directors last year and included in the 2020 Transmission Expansion Plan. The board suspended the project’s notification to construct (NTC) in April to give both grid operators an opportunity to hash out an agreement over costs and scope. The agreement must be approved by FERC before a request for proposals can be issued. (See “Directors Suspend Competitive Upgrade,” SPP Board/Members Committee Briefs: April 28, 2020.)

Cautioning members that he didn’t want to give a false sense that “we have fully crossed the finish line,” SPP Senior Operations Engineer Neil Robertson said additional analysis has indicated the 345-kV project would increase flows on some lower-voltage systems that would need to be mitigated.

“We’re working with AECI staff on those concerns. We have at least a tentative agreement for a mitigation plan,” Robertson said.

The AECI board of directors plans to take up the proposed agreement this week. SPP staff hope the RTO’s board will reconsider the NTC during its July meeting.

Robertson said staff are also trading possible needs solutions with MISO, SPP Staff Recommend 2020 Joint Study.)

“Hopefully, this will culminate in a set of projects that look like they have the possibility of meeting [criteria] thresholds by both organizations,” Robertson said.

The Seams Steering Committee will likely next meet as the Seams Advisory Committee. Its July meeting has been canceled, but the Markets and Operations Policy Committee plans to recommend a reorganized structure for its stakeholder groups to the board later that month.

The reorganization aligns the MOPC’s stakeholder groups with SPP’s primary functions and oversight responsibilities, allowing the committee to focus on policy-level work.

and renames the Seams Steering Committee as the Seams Advisory Committee. | *SPP*

“It’s just a name change,” System Planning Director Casey Cathey told the SSC, noting that the SAC will continue to participate in the RTO’s interregional planning stakeholder advisory committees with MISO and AECI.

Near Record $5.98M in M2M Settlements for SPP

SPP in April accrued a near record $5.98 million in market-to-market (M2M) settlements from MISO, staff said during the SSC videoconference. SPP has now piled up $82.32 million in M2M settlements since the two neighbors began the process in March 2015.

The process allows the RTOs to dispatch electricity on the most economical routes when congestion leads to constrained flowgates. Settlements have been in SPP’s favor for 46 of the 62 months.

Market-to-market settlements were again in SPP’s favor in April. | *SPP*

Two temporary SPP flowgates along the Kansas-Missouri border accounted for $2.81 million of the settlements. High winds and outages led to the constraints.

Temporary flowgates were binding for 890 hours, resulting in $3.87 million in settlements to SPP. Permanent flowgates were binding for 369 hours during April, resulting in another $2.11 million in settlements, again in SPP’s favor.

June 22, 2020

UPDATED: PG&E Sentenced; Bankruptcy Plan Approved

A federal judge approved Pacific Gas and Electric’s $60 billion Chapter 11 reorganization plan Saturday, two days after a state judge sentenced the company to $4 million in fines and costs, the maximum allowable, for starting the November 2018 Camp Fire that killed 84 people and destroyed the town of Paradise.

It was the state’s deadliest and most destructive wildland blaze and the worst of the catastrophes that led PG&E to seek bankruptcy protection in January 2019.

The approval of PG&E’s reorganization plan by U.S. Bankruptcy Court Judge Dennis Montali in San Francisco came after 17 months of negotiations between the utility, fire victims and other creditors, and Gov. Gavin Newsom. It allows the country’s largest electricity provider to resume its role as monopoly utility for most of Central and Northern California.

The utility will leave bankruptcy burdened with billions of dollars in debt and operating under the scrutiny of judges, elected officials and an angry public.

In Chico, Calif. on Thursday, Butte County Superior Court Judge Michael Deems said he couldn’t imprison a corporation, but he repeated the words of Federal Judge William Alsup, who oversees PG&E’s probation for felony convictions related to the San Bruno gas pipeline explosion that killed eight people in 2010.

“‘If there was ever a corporation that deserved to go to prison, it’s PG&E,'” Deems said, quoting Alsup. “This court is adopting that sentiment. If these crimes were attributed to an actual human person rather than a corporation, the anticipated sentence … would be 90 years to be served in state prison.”

PG&E pleaded guilty Tuesday to 84 counts of involuntary manslaughter and one felony count of unlawfully starting a fire as part of a sentencing agreement with the Butte County District Attorney’s Office.

‘Back to Business’

Fire victims who lost family members in the Camp Fire made statements to the court all day Wednesday and on Thursday morning.

Mike Hanko, a retired truck mechanic, broke down in sobs as he recalled the death of his brother, Dennis Hanko, in the Camp Fire and the devastating effects on their family. The brothers had lived together in Paradise, helping each other through hard times, until a month before the fire, Hanko said.

Hanko, speaking on behalf of himself and his three sisters, said it upset him that PG&E seemed to care more for profits than human lives.

“They just file for bankruptcy, pay fines, money to people they have harmed, and then it’s back to business,” Hanko said. “How can you put a price on a life?”

PG&E sentenced — | *USDA Forest Service/Tanner Hembree*

District Attorney Michael Ramsey read a statement by Tammie Hillis, whose father, T.K. Huff, died in the Camp Fire. Hillis said her father was able to make it to the edge of his property in his wheelchair, where he’d apparently tried to protect himself with a hose and water bucket.

Hillis said her family will never know if her father died quickly or suffered at length as the Camp Fire raced toward his home in the hamlet of Concow, which the fire destroyed shortly before it hit Paradise. His burned remains were identified through a DNA match.

“We are left to picture his last heart-wrenching moments on Earth,” she wrote. “Please explain to me why my father had to die this way … alone, afraid of what was coming down the hill. This was a flaming monster, destroying everything in its path. Our father died from the ultimate monster, PG&E. Their complacency year after year is pure evil. They knew and chose to do nothing, which makes them murderers.”

Ramsey released a report Tuesday, based on grand jury testimony, that detailed PG&E’s failure to maintain its aging transmission lines near Paradise. A C hook that cost 22 cents when it was made in 1919 broke after nearly 100 years of wear. That dropped a 115-kV line that arced on its steel tower, sending molten metal onto dry brush below, Ramsey said Thursday. (See PG&E Pleads Guilty to 84 Homicides and Ar s on.)

He said his office had been unable to show that any PG&E executives approved decisions over the course of decades that led to the fire, but he warned the utility it should know that future disasters could result in individual prosecutions.

“Now, as a result of the investigation and the prosecution and the distribution of the report to the executives of PG&E, those folks are now tasked with the knowledge of their company’s reckless behavior in failing to maintain their equipment,” Ramsey said. “They are on notice.”

He likened it to the procedure in California courts of warning repeat drunk drivers that they will be charged with second-degree murder if they kill someone while driving under the influence of drugs or alcohol.

PG&E Director Bill Smith, who will take over as acting chief executive when current CEO Bill Johnson retires at the end of June, represented PG&E at Thursday’s hearing. (Johnson had pleaded “guilty, Your Honor” 85 times on Tuesday.)

Smith promised, as PG&E executives have vowed numerous times since the utility filed for bankruptcy in January 2019, that it would change and that its equipment would never again cause a tragedy like the Camp Fire.

“Your Honor, we have come before this court [and the] Camp Fire victims … with humility and respect, ready to be held to account for this tragedy and committed to regaining the trust that we have broken,” Smith said.

Bankruptcy Approved

On Saturday, Bankruptcy Judge Montali signed an order approving PG&E’s reorganization plan, as he had said he would in a written order Wednesday and again on Friday, during a hearing to resolve remaining objections.

“These cases are among the most complex in U.S. bankruptcy history,” Montali wrote in his Wednesday order. “They involve difficult legal, financial, practical and personal issues. They were filed because of overwhelming damage claims following the devastating 2015-2018 Northern California wildfires, leaving thousands of victims who suffered from those wildfires owed billions of dollars, plus thousands more of traditional non-fire creditors of various types also owed billions of dollars.”

Like Deems, Montali said he felt he had little choice.

“If the court does not confirm the plan, the only option appears to be leaving the debtors where they have been for the last 17 months,” he wrote. “Leaving tens of thousands of fire survivors, contract parties, lenders, general creditors, allegedly defrauded investors, equity owners and countless others with no other options on the horizon is not an acceptable alternative.”

PG&E had met the requirements of the U.S. Bankruptcy Code by offering a plan that is financially feasible and will not leave the utility facing liquidation after it exits bankruptcy, Montali said. PG&E had also resolved major disputes with objecting parties, and it had won approval for its plan from the California Public Utilities Commission under Assembly Bill 1054, which establishes a wildfire insurance fund for the state’s investor-owned utilities. (See CPUC Approves PG&E Bankru p tcy Plan.)

The company reached negotiated settlements with creditor committees, agreeing to pay $13.5 billion to fire victims, $11 billion to insurance companies and hedge funds that hold third-party subrogation claims and $1 billion to local governments and agencies for wildfire expenses. PG&E plans to finance its bankruptcy with billions of dollars in stock and debt offerings, which it has already begun filing with the U.S. Securities and Exchange Commission.

On Monday, PG&E announced it had raised $8.9 billion in debt, including $3.5 billion for capital investments and $5.4 billion as its contribution to the AB 1054 wildfire fund. (The fund will be financed equally by ratepayers and utilities.) The company said it expects to close Tuesday on an additional $4.75 billion in debt.

Also on Monday, PG&E announced it plans to raise $5.23 billion from new equity offerings, including $4 billion in common stock. The sales are expected to close in mid-July, when the utility hopes to formally exit bankruptcy.