Page 961 – RTO Insider

March 16, 2021

PJM MIC Briefs: March 10, 2021

PJM stakeholders endorsed an issue charge regarding the allocation of capacity transfer rights (CTRs) after delaying the vote last month when stakeholders raised questions about the initiative’s scope and potential impact.

The vote on the issue charge, originally advanced by Buckeye Power, was endorsed with 79% support at last week’s Market Implementation Committee meeting.

Kevin Zemanek, director of system operations for Buckeye Power, reviewed the problem statement and issue charge, saying current rules are exposing his cooperative to price separation. Zemanek said the issue charge was changed after stakeholder feedback received last month at the MIC. (See “RPM Capacity Transfer Rights,” PJM MIC Briefs: Feb. 10, 2021.)

“We think we’ve modified our issue charge to account for all the comments we’ve received,” Zemanek said.

capacity transfer rights — PJM Monitor Joe Bowring | © *RTO Insider*

Under the Reliability Pricing Model (RPM), Zemanek said, CTRs return to load-serving entities capacity market congestion revenues occurring when there’s a difference between the prices paid by load and market revenue received by cleared resources. CTRs permit LSEs with load inside a constrained locational delivery area (LDA) to receive a credit for the import of capacity from a lower-priced region.

Zemanek said PJM does not have a way to allocate CTRs to an LSE that will correspond to the network load identified in the RTO’s network integration transmission service agreement. Instead, Zemanek said, PJM allocates CTRs pro rata to each LSE serving load in the LDA or zone based on the LSE’s share of the zonal unforced capacity obligation.

Although an LSE may have resources that are deliverable to load inside the constrained LDA, current rules do not allocate an equivalent number of megawatts, Zemanek said.

The key work activities presented by Buckeye included education on the current capacity market rules regarding how CTRs are allocated to LSEs in a constrained LDA. It also sought to explore potential enhancements to the allocation of CTRs to recognize designated historic network resources and network load identified in a network integration transmission service agreement (NITSA), without changing the total amount of available CTRs or the incremental capacity transfer right (ICTR) allocation.

Zemanek said Buckeye is looking for two months of education followed by discussion and exploration of enhancements to CTR allocation rules, with an objective for PJM to make a Section 205 FERC filing by the end of the year.

Independent Market Monitor Joe Bowring said the revised issue charge seemed to be “moving in exactly the wrong direction” from the one presented in February. Bowring said he objected to the added language “without changing the total amount of available CTRs or the ICTR allocation” in the second key work activity.

“It’s clearly only considering only one option and recognizing that it’s a zero-sum game,” Bowring said. “If the allocation changes, some people will be helped and some people will be hurt.”

Gary Greiner, director of market policy for Public Service Enterprise Group, said he agreed with Bowring’s objection to the issue charge language. Greiner said he thinks the second key work activity “presupposes” that stakeholders want to recognize the designated historic network resources and load identified in the NITSA.

Greiner suggested adding a work activity to determine whether the historic resources should be accounted for in the determination of CTR allocations.

“I think it needs to retreat back some in its words and context,” Greiner said.

Stakeholders also suggested adding ICTR allocation to an out-of-scope section in the issue charge.

The changes were made in a revised issue charge and endorsed by members.

PJM said education on the issue should begin at the April MIC meeting.

5-Minute Dispatch Plan Endorsed

Stakeholders unanimously endorsed a proposal by PJM and the Monitor on the long-term five-minute dispatch evaluation under consideration for several months.

Aaron Baizman, senior engineer for PJM, reviewed the solution proposal matrix for the long-term five-minute dispatch and pricing issue worked on in MIC special session meetings. The endorsement vote on the PJM/IMM proposal was delayed last month. (See “Long-term Five-minute Dispatch,” PJM MIC Briefs: Feb. 10, 2021.)

PJM’s tentative timing design for five-minute dispatch | *PJM*

Stakeholders approved the short-term proposal to resolve five-minute dispatch and pricing at the Markets and Reliability Committee meeting in July. PJM said it expects to continue evaluating long-term solutions late into this year, with a quantitative analysis of the pros and cons of different approaches. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)

Baizman said highlights of the long-term package include creating new real-time security-constrained economic dispatch (RT SCED) instructions utilizing previous ones. PJM dispatchers will also be provided flexibility for exceptions for case-by-case approval caused by unanticipated conditions or application issues.

PJM is also discontinuing use of degree of generator performance (DGP), a software logic used to determine how well a unit is following the dispatch signal. Baizman said DGP is being replaced with a less complex and more efficient software program.

Baizman said the current long-term timeline calls for software development until April, testing from May to June, parallel operations and evaluation from July to September, and a pilot evaluation and implementation by Nov. 1.

A first read of the proposed tariff language is scheduled for the March 24 MRC meeting.

Capital Recovery Factor Endorsed

An issue charge aimed at updating the value of capital recovery factors (CRFs) was unanimously endorsed by members.

Jeff Bastian, PJM senior consultant of market operations, provided an overview of the problem statement and issue charge designed to regularly update the value of CRFs based on current federal tax rates. CRFs are a component of the net avoidable cost rate (ACR) of a resource, which determines its market seller offer cap or minimum offer price rule (MOPR) floor price, depending on which is applicable.

The issue has been under review since the IMM notified PJM in a Dec. 4 letter that the CRF values, which were originally set in 2007, do not reflect the current 2017 reduction in federal corporate tax rates. (See “Capital Recovery Factors Discussion,” PJM MIC Briefs: Feb. 10, 2021.)

The Monitor said the tables should have been updated in 2018 and must be changed before the next capacity market auction, for the 2022/23 delivery year, takes place in May. PJM said it was concerned that seeking an earlier effective date would further delay the auction, which was originally scheduled for 2019. (See PJM Sets BRA for May 2021.)

PJM proposed that after the upcoming auction, the table of CRF values be posted on the PJM website no later than 150 days before the beginning of the offer period of each auction. Bastian said the values would reflect federal income tax laws in effect for the relevant delivery year at the time of the determination.

Erik Heinle of the D.C. Office of the People’s Counsel thanked PJM for its work to correct the CRF table and ensure it be updated along with tax laws in the future.

“Hopefully we can move forward on this,” Heinle said.

Reactive Supply Compensation

Jim Davis, regulatory and market policy strategic adviser for Dominion Energy, provided a first read of a problem statement and issue charge to address compensation for reactive supply and voltage control service.

Davis said Dominion has looked at the growing number of projects in the interconnection queue and determined that the proliferation of renewable resources on the system are going to create issues.

“We think that the timing is right for this, and we need to address this going forward,” Davis said.

Davis said reactive power is a “critical component” for operating the alternating current electricity system and controlling system voltage for reliable operation of transmission. He said reactive power allows for transmission of real power across transmission lines.

The transmission lines dissipate reactive power more quickly than real power, Davis said, resulting in a condition where reactive power cannot be efficiently transferred over long distances. Because of this, PJM needs localized resources to provide reactive power.

Transmission customers pay for reactive power as an ancillary service under Schedule 2 of the tariff, Davis said, and the charges collected from customers are paid to resources in the zone where the customers and resources are located. Under the tariff, generation owners must submit a Section 205 filing to FERC to seek compensation.

Davis said the existing rate mechanism is “time-consuming and onerous” for generation owners, developers and transmission customers. He said it exposes generators, developers and customers to significant litigation costs in either defending or contesting the requested rates.

To solve the problem, Dominion has proposed several key work activities, including providing education on topics such as the existing reactive rate filing process, a review of the inputs for the determination of reactive revenues and an examination of the reactive rate recovery mechanism in other RTOs/ISOs, including ISO-NE.

Davis said the issue charge also requests the discussion of improvements to the reactive power cost recovery process and examination of alternative reactive power cost recovery mechanisms.

Carl Johnson of the PJM Public Power Coalition said now is an important time for stakeholders to examine issues related to reactive power, calling the issue a “black box” and difficult for people to understand.

Johnson questioned Davis about an out-of-scope issue denoted in the issue charge that bars discussion of any existing FERC-approved reactive service revenue requirements. Johnson said he wanted to hear PJM’s opinion at the next MIC meeting whether the reactive service rates on file in the RTO are considered contractual.

Questions about whether black start unit arrangements constitute contracts nearly derailed stakeholder discussions on the issue last year. (See Vote on PJM Black Start Compensation Deferred.)

Davis said the problem statement and issue charge seek to create rules “prospectively” and not affect existing FERC-approved decisions.

The committee will be asked to approve the issue charge at the April MIC meeting.

New Load Behind-the-meter

Bastian provided a first read of the problem statement and issue charge addressing new load locating behind the meter of an existing generation resource. Bastian said PJM has received inquiries from several generation owners seeking direction on the RTO’s rules related to locating new load behind the meter of an existing generator’s point of interconnection.

The proposed arrangements envision the new load, including facilities such as data centers, being directly served by an existing generation resource that has capability exceeding the new load amount.

Bastian said the tariff contains several provisions that address generation added behind the meter with the existing load of a network service customer, but there is no existing tariff or PJM manual provisions addressing a scenario where new load is added behind the meter of an existing generation resource.

PJM is proposing key work activities in the issue charge, including education on the existing tariff and manual provisions around locating new BTM generation with the existing load of a network service customer.

Bastian said PJM also wants to assess whether the existing provisions can be equally applied to a case where new load is proposed to be added behind the meter of an existing generation resource for two different proposed arrangements: new load to be served from the system when the generation is not operating, and new load solely served by the generation but never from the system.

Several stakeholders questioned what would constitute a “new load.” Bastian said PJM would work to “better articulate” what the issue charge is seeking to address at next month’s MIC meeting.

Manual 11 Revisions

Stakeholders unanimously endorsed minor manual updates as part of the biennial cover-to-cover review.

Nikki Militello, PJM senior engineer of real-time market operations, reviewed updates to Manual 11: Energy & Ancillary Service Market Operations. Militello said the updates included providing additional clarification of existing processes, removing outdated rules and terminology and correcting spelling and grammar mistakes. The updates will be voted on at the March 29 MRC meeting.

March 16, 2021

Haaland Confirmed as Interior Secretary

The Senate confirmed Rep. Deb Haaland (D-N.M.) as secretary of the Interior Monday night, making her the first Native American to become a cabinet member.

Haaland was confirmed on a near-party line vote of 51-40. Among Republicans, only Sens. Lindsey Graham (S.C.), Susan Collins (Maine), Lisa Murkowski (Alaska) and Dan Stevens (Alaska) voted in support.

The vote followed an introduction by Sen. Ben Ray Luján (D-N.M.).

“As a Pueblo woman and 35th generation New Mexican, Deb Haaland has a long overdue perspective to contribute to the Department of the Interior’s mission of protecting our natural resources and public lands and honoring America’s trust responsibilities to tribal nations,” he said.

Sen. Tom Carper (D-Del.) also gave a brief endorsement before the vote, praising Haaland’s humility, “good heart and good mind.

“She will provide the leadership that is needed at the Department of the Interior after the years that we’ve been through,” he added.

Haaland had attracted criticism from Republican senators from oil and gas producing states because of her statements opposing fracking and drilling on federal lands and her support of the Green New Deal. But no Republicans spoke in opposition before the floor vote Monday. (See Senate Panel Advances Haaland.)

Senate Majority Leader Chuck Schumer (D-N.Y.) called Haaland’s confirmation “a huge step forward,” saying it “creates a government that more embodies the full richness and diversity of this country.”

March 16, 2021January 27, 2024

ACORE: Storage and Tax Incentives Key to Infrastructure

A panel of industry stakeholders concluded the American Council on Renewable Energy’s 2021 Policy Forum with a discussion on infrastructure and the policies that might shape the future grid.

ACORE COO Bill Parsons introduced the panel, noting that the discussion couldn’t have come at a better time with the recent passage of the America Rescue Plan.

“America’s infrastructure is critically in need of updating,” Parsons said.

Moderator Larry Eisenstat, partner at Crowell & Moring, said that the purpose of any federal infrastructure plan should be to repower the economy and achieve clean energy targets.

Vice President of Berkshire Hathaway Energy Christina Hayes started off the conversation by saying the biggest inhibitor of infrastructure projects and the adoption of new technologies is often the associated costs. Mitigating “sticker shock” with tax incentives will be key, she said.

Scott Hennessey, vice president of federal policy at Brookfield Renewable, agreed that tax credits will be vital to building out new generation, but he also emphasized the importance of preserving and investing in existing non-emitting resources, specifically hydropower. With a focus on wind and solar generation to meet future energy needs, Hennessey feels that hydropower isn’t being valued as a renewable resource like its counterparts.

Christina Hayes, Berkshire Hathaway Energy | ACORE

“If we are always focused on new generation … we take two steps forward only to take a step back,” he said.

Eisenstat noted that critics of federal clean energy tax credits have said that the renewables industry has matured to a point where incentives are no longer necessary and that new generation buildout would continue with or without them. Hennessey disagreed.

“If what we want is more generation capacity [and] to preserve the good generation capacity we have, that takes investment, and right now, to say, ‘Go off and hit these lofty goals by the administration without the policy support’ seems very difficult,” he said.

Susan Nickey, executive vice president at Hannon Armstrong, responded that her company would like to see policy that attracts private capital. Reaching a net-zero economy is going to take “trillions” of dollars, she said, and a balance between federal tax incentives and private sector investment is going to be necessary to build out the needed infrastructure.

Dominion Energy’s William Murray agreed that the federal government should play a part in modernizing and expanding the grid.

“Federal government has played a transformative role for more than a century in moving new technology forward, and there’s an opportunity … across infrastructure, certainly, and energy to do that,” Murray said.

Building Storage

Eisenstat asked the panel what could be done at the federal level to start seeing the widespread adoption of storage resources necessary to keep a potentially all-renewables grid reliable.

Murray said that current storage technology is not going to be sufficient to get to net zero. He said he would like to see the federal government invest in research and development to maximize storage resources.

Nickey said that investors feel differently. She said that while they’re comfortable with storage technology and interested in new developments, they’re still skeptical that they’ll see a return on their investment.

Incentivizing storage as a transmission asset may be the key to widespread adoption, Hayes said. “Leveling the playing field through the tax credit play with storage would really be helpful.”

March 16, 2021

Texas Senate Passes Bill to Reprice ERCOT Feb. Sales

The Texas Senate on Monday passed a bill that would require repricing of $4.2 billion in wholesale market transactions that ERCOT’s Independent Market Monitor identified as “billing errors” associated with the winter storm that gripped the state last month.

If passed by the House of Representatives and signed by Gov. Greg Abbott, Senate Bill 2142 would direct the state’s Public Utility Commission to reprice market transactions for Feb. 18-19, when ERCOT kept $9,000/MWh scarcity pricing in place after the grid had been stabilized following the storm.

Authored by Sen. Bryan Hughes (R), the bill says the PUC has “all necessary authority” to order ERCOT to correct wholesale power and ancillary services sold between 11:55 p.m. Feb. 17 and 9 a.m. Feb. 19. It places a March 20 deadline on the commission to do so and does not offer details on how to correct the prices.

During testimony before the Senate’s Jurisprudence Committee March 11, PUC Chair Arthur D’Andrea said that he lacked the authority to retroactively change the prices, and he questioned the Monitor’s contention of a billing error. He said repricing the market would lead to additional bankruptcies and other unforeseen circumstances. (See Abbott Rejects Call to Fire D’Andrea.)

Texas ERCOT sales — Texas Lt. Gov. Dan Patrick guides debate over legislation that would reprice the ERCOT market. | *Texas Senate*

D’Andrea, the only commissioner left after the other two resigned, declined to comment on the bill.

“When it comes to any pending legislation, out of deference to the Legislature and its ongoing process, the chairman’s commentary will be limited to his statements in legislative hearings, our open meetings and associated memoranda,” spokesperson Andrew Barlow said in a statement Monday.

The bill will likely be opposed by power producers, who benefited from the $47 billion in market transactions during the storm and its aftermath. ERCOT’s normal annual market transactions amount to about $10 billion.

The full Senate wasn’t scheduled to be in session Monday, and the bill had not been filed when the morning began. However, SB 2142 was read on the Senate floor and then heard by the Jurisprudence Committee, which conducted nearly six hours of hearings last week on the issue. The bill passed out of committee by a 3-1 vote, with only Sen. Brandon Creighton (R) opposing.

The legislation cleared the Senate by a 27-3 margin.

Lt. Gov. Dan Patrick, who dressed down D’Andrea in front of the Jurisprudence Committee last week, thanked senators for “this extraordinary day.”

“The Senate has acted. We now ask the governor to join us,” Patrick said. “Hopefully, the House will take up [this bill] and pass the legislation necessary.”

Abbott last week added the repricing issue as emergency legislation for consideration. He told Patrick Friday that the legislature is the only body that can “authorize the solution you want.”

March 16, 2021

NYISO Prepares Hybrid Storage Aggregation Model

NYISO on Thursday kicked off an effort to create a market participation model that would allow an energy storage resource (ESR) and one or more generators to be located at a single point of interconnection, share the same point identifier (PTID) and act as a single resource.

The project is slated for completion by year-end.

Market rules that the ISO filed with NYISO OKs Changes on Hybrid, Fast Start Resources, TCCs.)

“The HSR participation model will only apply to aggregations located at a single physical location and may not allow for swapping aggregations,” said Christina Duong, market design specialist for distributed resource integration, who presented the initiative at the Installed Capacity/Market Issues Working Group. “The DER model only allows resources up to 20-MW injection capability, but the HSR model will accommodate resources of all sizes.”

The distributed energy resources participation model provides market rules for DERs to participate in NYISO’s energy, ancillary services and ICAP markets. The ISO’s market design is complete, with the FERC Order 2222 filing due in July. The DER model permits aggregation of resources across multiple locations, and an individual resource may leave or join aggregations at the start of a calendar month.

NYISO hybrid storage — Because the peak operating times for wind and solar systems occur at different times of the day and year, hybrid storage systems are more likely to produce power when needed. | *DOE*

State initiatives such as renewable energy credit procurements incent developers to couple storage with intermittent renewable assets, which benefits the grid by reducing the output volatility and improving the availability of intermittent resources.

NYISO believes a new HSR market participation model will improve grid flexibility and resilience by enabling new resource types to provide their full capabilities, Duong said.

Evolving Grid Services

One stakeholder asked if the ISO is trying to build off the three existing participation models, or do something new.

“We do want to make this a different model rather than just expanding and making ESR 2.0 or CSR 2.0, so this is going to be a separate and distinct model,” Duong said.

Another stakeholder asked about combining two distinct resources into one PTID, and whether the ISO will be able to discern performance of the individual resources, for example a solar farm and a battery.

“That brings up some concerns we have been having internally during preliminary discussions of how much do we need to know and how much telemetry do we need in order to see for each of the components within this aggregated model, so those are steps and concerns that we’re trying to walk through,” Duong said.

Speaking about a related study on grid services from renewable generators, Michael DeSocio, NYISO senior manager of market design, said that in the immediate future, “maybe we can offer up ways that these resources can provide existing services [operating reserves, regulation, voltage support service and black start service], and as we develop new services, this will inform how these resources could provide those services.”

The ISO focuses on the attributes necessary to provide the service, and any resource capable of meeting those attributes is eligible to provide the service, DeSocio said.

“We’re focused here on discussing what are the capabilities that renewables can provide with regard to their ability to curtail their output or maybe be willing to spill energy so they can provide services and determine whether that capability can be used to meet the attributes we require for the market,” DeSocio said. “And all of this is built around reliability, keeping the lights on for New Yorkers.”

March 16, 2021

PJM Operating Committee Briefs: March 11, 2021

PJM proposed allowing generators deemed to be critical for determining interconnection reliability operating limits to recover their required upgrade costs.

PJM has proposed developing a cost recovery mechanism for generators forced to upgrade their facilities to comply with certain NERC Critical Infrastructure Protection (CIP) standards regarding interconnection reliability operating limits (IROLs).

Darrell Frogg, senior engineer for generation at PJM, provided a first read of the problem statement and issue charge of the proposal at last week’s Operating Committee meeting.

An IROL is any system operating limit that, if exceeded, could jeopardize the entire grid. PJM is required to develop a list of “IROL-critical” facilities, Frogg said, which means the limits mostly derive from those facilities. Generators on the list may then be required to upgrade. Generation owners have no control over the IROL-critical designation, with PJM in its role as the reliability coordinator solely responsible for the list.

Frogg said PJM was making the proposal on behalf of generator owners because the classification of a generator as IROL-critical is considered critical energy/electric infrastructure information.

If approved, stakeholders would study the relevant CIP standards, review how a generator’s status is determined by PJM and consider the types of costs that generators incur from being designated. Stakeholders would also look at how other RTOs and ISOs have addressed the issue, such as FERC OKs Payment Rules for IROL Facilities.) Stakeholders would also discuss which costs should be recovered and how, and ensure the entire process is transparent.

The OC will be asked to approve the issue charge at its next meeting. Frogg said PJM hopes stakeholders will be able to make a recommendation to the Markets and Reliability Committee in three to six months. He said work updates would also be provided to the Market Implementation Committee.

David Mabry of the PJM Industrial Customer Coalition said there are “potentially significant” incremental compliance costs in the issue charge. He wondered if the OC is the proper venue to discuss the issue given the possible links to multiple committees in the issue charge.

“I’m wondering whether we ought to bring the problem statement to the MRC for approval and let the MRC decide where this is best addressed,” Mabry said.

Frogg said PJM had internal discussions to determine the best committee to deal with the issue and found that the manuals allow the OC to work out proper market incentives. PJM, however, will continue internal discussions before the next OC meeting, he said.

Resource Tracker Ownership Endorsed

Stakeholders unanimously endorsed a “quick fix” to address information entered into the Resource Tracker application used by PJM.

Chris Franks of PJM reviewed the problem statement and issue charge to update language in Manual 14D regarding the application’s ownership confirmation requirement. Franks first brought the issue to the OC last month. (See “Resource Tracker Quick Fix,” PJM Operating Committee Briefs: Feb. 11, 2021.)

The proposal includes changing “market participants are requested” to the “generation owner, or designated agent, is required” to confirm resource ownership by Nov. 1. Last year PJM requested owners of 1,503 resources to confirm their information. Of those resources, 60 did not confirm by Nov. 1. As of Feb. 1, four have yet to confirm information.

The issue charge will now go to the MRC for a final vote in April.

TLR Buy-through Quick Fix

Stakeholders also unanimously endorsed a quick fix regarding the transmission loading relief (TLR) buy-through congestion process.

Chris Advena, senior lead engineer for PJM, reviewed a problem statement and issue charge to remove the process from Schedule 1, section 1.10.6A of the OA. Advena first brought the issue to the OC in February. (See “TLR Buy-through 1st Read,” PJM MRC/MC Briefs: Feb. 24, 2021.)

TLR buy-through is the tool PJM uses to curtail interchange transactions that cause loop flow to the RTO around the time emergency procedures are being conducted to reduce the impact on a flowgate or a transmission facility. The process was created when PJM was fully within the Mid-Atlantic region and was issued more frequently than it is today, according to the RTO.

PJM is seeking final approval at the Members Committee meeting April 21.

Manual Changes Endorsed

Stakeholders unanimously endorsed two different manual changes resulting from the periodic review by acclamation.

Matthew Wharton, PJM reliability engineer, reviewed changes to Manual 37: Reliability Coordination. The changes included correction of grammatical errors, updated links and added language for an alternative method for simulating transfers.

Jeff McLaughlin, PJM senior lead engineer, reviewed changes to Manual 02: Transmission Service Request. The minor changes included fixing broken hyperlinks, updating reference document names and the consolidation and relocation of two sub-sections to a “more appropriate section” of the manual.

Both manual sections will now go for final endorsement at the March 29 MRC meeting.

March 16, 2021

SPP M2M Hits Staggering $168.1M

SPP raked in another $27.87 million in market-to-market (M2M) settlements from MISO during December and January, pushing its total to $168.11 million since the two grid operators began the process in 2015.

MISO owes SPP $16.35 million in M2M settlements for December and $11.53 million for January. They were the third and fourth straight months the process has settled in SPP’s favor above the $10 million mark, though neither month approached November’s record of $22.87 million. (See SPP, MISO See $22.8M in M2M Settlements.)

Temporary and permanent flowgates were binding for more than 2,750 hours during the two months.

The grid operators exchange M2M settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm flow entitlements held by each RTO.

SPP market to market — SPP’s market-to-market settlements with MISO have exploded in its favor. | *SPP*

M2M settlements have been in SPP’s favor 15 of the last 16 months and 54 times in 71 months since the process began.

SPP staff shared the results during a March 11 conference call with the Seams Advisory Group. The group met for the first time since its name change from the Seams Steering Committee. Its February meeting was canceled because of a winter storm that put much of the Midwest into a deep freeze.

SPP, MMU Request Waivers from FERC

SPP and its Market Monitoring Unit filed a joint request March 11 with FERC asking for a limited waiver of three tariff provisions as the Monitor works to verify and calculate actual cost reimbursement for energy offer curves above $1,000/MWh during the February winter storm (ER21-1331).

SPP and its Monitor have proposed extending the 35-day deadline for market participants to submit information for offers above $1,000/MWh to be recovered through make-whole payments. The entities are asking for a 75-day deadline from the Feb. 11-20 operating days.

The RTO and Monitor are also proposing a 105-day deadline — instead of the normal 45 days from an operating day — to review the cost submissions. They additionally propose to waive the limitation on a market participant’s ability to dispute consecutive settlement statements.

Numerous offers exceeded SPP’s $1,000/MWh cap, and prices peaked at $4,274/MWh during the event. The Monitor is reviewing the offers under FERC orders 831 and 831-A, which require that energy suppliers receive a reasonable opportunity to recover their actual costs of providing energy.

March 16, 2021

NERC Cold Weather Team to Seek Faster Finish

NERC is considering accelerating the schedule for its cold weather standard project (Project 2019-06) after last month’s winter storm that led to prolonged mass outages in Texas lent a fresh urgency to the effort, project leaders told the standard drafting team (SDT) in a conference call Monday.

NERC Senior Standards Developer Jordan Mallory told participants that the team will seek permission from the Standards Committee to shorten the next formal comment and ballot period, scheduled to begin April 2, to 25 days from the standard 45. That will enable members to respond to comments and move to final ballot by May 14; if it is approved by stakeholders, the proposal will be submitted to NERC’s Board of Trustees when it meets on June 11.

The update may represent a shift in NERC’s thinking following February’s winter storm. In the immediate aftermath of the crisis, representatives said the organization was “not accelerating, but increasing [the] urgency” of the standard development effort and said the joint ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)

NERC Cold Weather Team — Members of the Texas National Guard assist a motorist stuck in the ice during February’s extreme winter conditions in Abilene, Texas. | *The National Guard*

In a webinar the same month, the team for Project 2019-06 said that the joint inquiry had not affected the schedule for its effort and that it expected development to wrap “by the end of the year.” (See Cold Weather Standards Team Sticking to Year-end Target.)

SPP’s Matthew Harward, chair of the SDT, said that the board “has requested the acceleration of the timeline.” However, in a follow-up conversation via email with ERO Insider, a NERC representative emphasized that “no action [has been] taken at this time” and that staff will work with the Standards Committee “to determine the timeline regarding the cold weather standards.”

Leaders See Positive Momentum

Harward acknowledged during Monday’s call that the revised schedule would require more intense work. He reminded members that “a lot has happened” during the most recent formal comment and ballot, which began on Jan. 27 and closed on Friday.

The ballot asked stakeholders for their approval of three updated standards: EOP-011-2 (Emergency preparedness), IRO-010-4 (Reliability coordinator data specification and collection) and TOP-003-5 (Operational reliability data). Proposed changes to the standards, respectively, included:

new requirements for cold weather preparedness plans on the part of generator owners, along with data specifications and collections for balancing authorities and annual maintenance and inspection requirements;
data specification requirements for reliability coordinators; and
data specification requirements for transmission operators.

None of the three standards met the two-thirds segmented-weighted threshold required for approval; IRO-010-4 came closest with 66.22%, while TOP-003-5 received 64.35% and EOP-011-2 had 49.39%. SDT leaders were nonetheless positive about the results, with Mallory observing that first ballots for standard projects “[are] usually a lot lower” and thanking team members for their outreach to industry after February’s webinar.

Over the next 11 days, the team will work through stakeholders’ questions and objections, particularly for EOP-011-2; a common concern expressed in comments was whether this standard, which addresses operational considerations, was a good fit for requirements relating to cold weather preparedness.

More Standards Actions Possible

Some stakeholders, particularly in areas where cold weather is commonplace, remain unconvinced that new, binding standards are needed at all — a theme in all of the previous comment periods for the project. (See Gen Operators Cool to Winter Preparedness Standard.) However, other respondents — notably Brandon Gleason of ERCOT — urged NERC to be even bolder in light of the recent emergency.

“ERCOT supports the proposed requirement to mandate weatherization plans as an important first step in ensuring reliability. However, an effective reliability standard would need to include clear and enforceable metrics, which the plan must be designed to achieve,” Gleason said. “It is apparent based on the February 2021 extreme cold weather event that having a plan may not be sufficient by itself to ensure reliability. ERCOT would support a subsequent reliability standard project in order to specify these clear and enforceable metrics.”

Harward echoed Gleason’s comment when he noted that last month’s storm “may result in additional requirements or standards development work.” But he reminded attendees that their mandate was to address only the recommendations of FERC and NERC’s joint report on the Jan. 17, 2018, cold-weather event in the South Central U.S. and warned against the temptation to overreach. (See NERC Panel Delays Action on Cold Weather Prep.)

“[Our] proposed standards may only be a first step in the evolution of cold weather preparedness for the industry, but it is a first step that we must take, and it is necessary and vital that we do this work,” Harward said. “I just ask you to be diligent so that we don’t let the scope creep or wander too far down rabbit holes, and … stay focused on the job ahead of us.”

March 16, 2021October 31, 2023

EV Policy Recommendations Take Shape in Oregon

Oregon Gov. Kate Brown can expect a raft of policy recommendations to land on her desk this spring prescribing how her state can build a comprehensive — and equitable — electric vehicle charging network.

But a number of the proposals will be difficult to implement — at least in the short term, according to one consultant working with the state’s Transportation Electrification Infrastructure Needs Analysis (TEINA) Advisory Group.

Established by Oregon’s Department of Transportation (ODOT), the group — comprising representatives from investor- and municipally owned utilities, municipalities, environmental organizations, labor groups, AAA and General Motors — must provide the governor with an EV charging infrastructure study by June.

“I just want to acknowledge that we won’t be able to solve all of the problems coming out of this study,” Rhett Lawrence, policy manager with consulting firm Forth, said Tuesday in presenting a set of draft recommendations during a virtual meeting of the TEINA group.

Oregon Senate Bill 1044, passed in 2019, established objectives related to the adoption of light-duty zero-emission vehicles (ZEV), including a goal of 250,000 ZEVs registered by 2025. The bill additionally set targets that ZEVs comprise 25% of all registered vehicles and 50% of all new vehicle sales in the state by 2030, with the sales target rising to 90% in 2035. The state currently has about 32,000 registered ZEVs, well short of SB 1044’s 2020 target of 50,000 vehicles.

A key challenge for Oregon’s EV adoption goals will be building sufficient infrastructure in areas classified as “Rural” (light green) and “Frontier” (dark green). | Oregon Office of Rural Health

As in other states, Oregon’s EV adoption rates evince a sharp urban-rural divide. While 65% of the state’s residents live in areas classified as urban, nearly all EV ownership is concentrated in those zones, confronting policymakers with the challenge of how to build reliable EV infrastructure to support people who live and travel through the state’s sparsely populated regions. Within urbanized areas, the state faces the additional problem of how to make EV chargers readily available to low-income residents and city dwellers living in multifamily buildings where off-street charging is unavailable.

Because of those complexities, Lawrence counseled the TEINA group to divide its policy recommendations into three categories based on the degree of difficulty for implementation: Enable, Accelerate and Drive. The recommendations are the product of a series of “listening sessions” with residents and stakeholders from across the state.

Putting the User First

Topping the lowest-difficulty category — “Enable” — is the recommendation that Oregon policymakers develop standards that create a consistent experience for EV drivers even as they use different charging network platforms throughout the state.

“This is something that came up in almost every listening session,” Lawrence said.

That consistent user experience would extend to expectations around the reliability and redundancy of chargers.

“You need confidence that anywhere you go in the state that you find a charger that will work,” Lawrence said. He suggested that once the state develops the standards, it could build them into the requirements of any state-funded grant programs intended to help finance construction of charging stations. Charging service providers could themselves begin to work together to create uniform standards, he added.

Another recommendation would see the Oregon Public Utility Commission and municipally owned utility governing bodies “enable and encourage” utilities to use ratepayer funds to build the underlying transmission infrastructure needed to support EV charging networks.

“EV make-ready funding should be made available to provide adequate electrical infrastructure up to and past the meter to install EV charging at places such as workplaces and multiunit-dwellings (MUDs),” the draft document said.

Kelly Yearick, program manager at Forth, suggested that Oregon could use revenues from its Clean Fuels Program to fund DC fast chargers (DCFCs), the Level 2 chargers in areas of high population densities to allow for charging by people living in MUDs.

Yearick also said utilities might need to alter rate designs to reduce demand charges — the flat fees utilities charge to recover costs from investments — for charging stations in areas that will see lower use. Those fees compromise the economics of charging stations in rural areas, where a smaller pool of potential EV drivers need a relatively larger proportion of stations because of the distances typically traveled in those areas.

Other “Enable” recommendations include:

incentivizing charging stations in highly traveled corridors through low-interest state loans;
directing local jurisdictions to develop or follow state guidelines to streamline charging station permitting;
developing EV charging education programs “to improve the general public’s awareness of this infrastructure and enhance the user experiences at EV charging stations”;
developing uniform guidelines on EV charging station signage and placement;
coordinating with local jurisdictions to develop public-private partnerships for charging electric bikes and scooters.

Getting to the ‘Hard Work’

The “Accelerate” category consists of policy recommendations “that could speed up the deployment of electrification infrastructure with medium difficulty of execution and implementation for the key players over the medium term.”

Included is a recommendation that the state offer incentives or direct grants for public charging stations, particularly in rural and low-income areas. Lawrence pointed out that some charging stations will face power supply issues, especially in rural areas where the distribution system may not be equipped to handle the load. “State funding can help bridge that gap in how you deal with power supply issues,” he said.

A second recommendation in the category calls for the state to adopt building requirements that require a minimum built-in electrical capacity for all new developments as well as “reach codes” that allow local jurisdictions to exceed state mandates.

A third recommendation would see the state direct municipally owned utilities to invest in DCFC projects.

The “Drive” category includes longer-term recommendations considered more difficult to implement, including state funding for EV charging infrastructure on state-owned property such as parks or workplaces. Another recommendation would see the state requiring a certain percentage of parking spots be EV-ready by an undetermined date.

“We need to acknowledge that’s easier said than done,” Lawrence said, noting that the funding structure for such a program is still uncertain.

The TEINA Advisory Group will review a final draft study document containing the recommendations at a public meeting on May 11.

During Tuesday’s meeting, ODOT Program Manager Mary Brazell pointed out that the group will be taking on additional follow-on studies, including for hydrogen fuel cells and electric bikes.

“TEINA isn’t the end; it’s just the beginning of where we are, and we hope to engage with you as we complete that [infrastructure] document, but beyond as well, when we really get to the hard work, which is implementing this,” Brazell said.

March 16, 2021November 2, 2023

Mass. Climate Bill Rewrites Roles of Key Agencies

Massachusetts lawmakers are set to pass a major climate bill that would create new roles for critical state agencies in meeting the goal of net-zero emissions by 2050, Sen. Mike Barrett (D) said Saturday.

“The climate issue has picked up velocity recently … and some key agencies have been slow to pivot,” Barrett said at a webinar hosted by MassEnergize, an organization that helps communities reduce greenhouse gas emissions.

Barrett said that the Massachusetts House of Representatives likely will pass the legislation Wednesday. A Senate vote on the climate bill was delayed last week by Senate Minority Leader Bruce Tarr (R), who requested more time to review the final version of the bill with amendments from Gov. Charlie Baker. (See Vote on Mass. Climate Bill Delayed in Senate.)

The bill rewrites the mission of the Massachusetts Department of Public Utilities (DPU) to align its existing regulatory goals under the overarching job of reducing emissions in the state.

“The job of the DPU needed to be modernized and given a 21st century look,” Barrett said.

The bill also directs Mass Save, a collaborative of Massachusetts’ natural gas and electric utilities, to demonstrate that its efforts to reduce emissions are working. The state program advises residents on how they can lower their utility bills and reduce energy consumption.

The collaborative has not been taking its role in reducing climate change as seriously as it could be, Barrett said.

Powering residential and commercial buildings makes up 27% of emissions in Massachusetts, according to data from the Massachusetts Department of Environmental Protection.

“In the deep plumbing of this bill, we say to Mass Save, ‘Every time you evaluate initiatives — every time you choose to replace a light bulb without talking about heat pumps — we want you to weigh your choices and consider the social value of greenhouse gas emissions,’” Barrett said.

The bill also requires Mass Save to state in its three-year plan how much it will reduce emissions. And the secretary of the Executive Office of Energy and Environmental Affairs will be required to set an emissions reduction goal for Mass Save at the start of every new three-year period.

The DPU will need to report to the Massachusetts legislature whether Mass Save met its goal within 18 months of the conclusion of each three-year period.

The goal of these requirements is to increase transparency between state agencies and the legislature to ensure major state agencies with a high profile “pull in the same direction as the other important actors in the emissions reduction scene,” Barrett said.

The Board of Building Regulations and Standards (BBRS) also faces changes under the climate bill. The agency will have a fundamental role in determining how much new construction in Massachusetts will reflect emissions reductions goals, but the BBRS does not have a full-time staff of professionals. The bill moves the task of designing the next stretch of energy code from BBRS to the Department of Energy Resources, which has a full-time staff of energy experts, Barrett said.

State legislators also will add four green building-conscious members to the BBRS’s board of directors, so the board “has a solid climate-aware majority to guide its fortunes going forward,” Barrett said.