SPP Regional State Committee Briefs: Jan. 28, 2019

By Tom Kleckner

Commission Staff Not Yet to Agreement on Cost Allocation Issues

NEW ORLEANS — Regulatory staffers have been unable to reach a consensus on possible revisions to cost-allocation rules for wind-rich areas and may table their year-long review, the Nebraska Power Review Board’s John Krajewski told the Regional State Committee Monday.

January’s Regional State Committee meeting | © *RTO Insider*

The Cost Allocation Working Group, which reports to the RSC, is considering changes to SPP’s highway/byway framework, which considers transmission facilities of 300 kV or more as highway infrastructure, with their costs allocated on a regionwide, postage-stamp basis. Facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the cost assigned to the host zone and one-third allocated regionwide. Projects less than 100 kV are allocated entirely to the host zone.

Among its options, the CAWG is considering changing the 100-300-kV allocation percentage to 50% or 66% as it ponders different ways of charging for load.

The working group is also evaluating whether to consolidate transmission zones for the SPP Tariff’s Schedule 11 charges, which cover transmission construction costs. Krajewski said zones encompassing diverse areas that include wind and non-wind zones would spread byway costs over a larger footprint.

Other options include modifying the 300-kV and less allocation percentage in wind-rich zones only and using a generation-injection rate applicable to all generation or just a subset.

CAWG Chair Cindy Ireland updates the RSC. | © *RTO Insider*

“As we’ve worked through this, I’ve worked on the assumption there was a problem and it needed to be fixed,” Krajewski said. “Some of my fellow CAWG members haven’t reached that point yet.

“If there isn’t a consensus [that] there’s a problem [at the group’s next meeting], we’ll put away what we’ve worked on. If we reach a point where there is a problem, I would like to see ourselves narrow those options to two or three, where we can give some detailed analysis,” he said. The CAWG’s next meeting is a conference call set for Feb. 12.

Should it come to an agreement, the CAWG plans to turn its work into a white paper and make recommendations to the RSC and the Holistic Integrated Tariff Team, which is taking a broader look at cost allocation. (See “HITT Educates MOPC on its Progress, Learnings,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)

“Those two processes need to be wedded up and worked together,” Texas Public Utility Commission Chair DeAnn Walker said of the CAWG and HITT work. “I understand there’s serious disagreement over whether there’s a problem, but there’s a lot of overlapping things here with the HITT that need to be worked on together.”

SPP, MISO Regulators in Educational Phase

Kansas Corporation Commissioner Shari Feist Albrecht told the RSC that MISO and SPP regulators working on the RTOs’ seam issues are still in the midst of their educational phase.

“We’re suffering from some beginning-to-operate-jointly pains,” said Albrecht, who represents SPP regulators on the SPP-RSC/OMS Liaison Committee.

The committee was created last year to work with SPP and MISO to improve market-based transactions and operations across the seam. (See Regulators Examine MISO, SPP Seams Issues at NARUC.)

Albrecht and Missouri Public Service Commissioner Daniel Hall moderated a panel discussion on seam issues during a recent Mid-America Regulatory Conference meeting. The committee will next meet Feb. 10 on the sidelines of the National Association of Regulatory Utility Commissioners’ winter policy summit, where it will discuss the stakeholder responses and the potential need for FERC or independent analyses.

South Dakota’s Kristie Fiegen jokes with Kansas’ Shari Feist Albrecht (left) much to the amusement of Missouri’s Scott Rupp and RSC Chair Kim O’Guinn (right) of Arkansas. | © *RTO Insider*

New Mexico’s Byrd Joins RSC

The RSC welcomed Jefferson “Jeff” Byrd as its New Mexico representative. He replaces Pat Lyons, who left the regulatory arena last year.

A rancher and environmental engineer, Byrd won election in November to one of five seats on the New Mexico Public Regulation Commission. It’s the first time he has held public office, following two unsuccessful runs at the U.S. House of Representatives.

January 29, 2019

FERC Claims Authority over PG&E Contracts in Bankruptcy

By Hudson Sangree

FERC said it shares authority with the federal bankruptcy court over any power purchase agreements Pacific Gas and Electric seeks to modify after filing for bankruptcy, as the utility did on Tuesday.

The commission ruled Friday in a petition by NextEra Energy (EL19-35) and on Monday in response to one by Exelon (EL19-36).

As part of its bankruptcy filing, PG&E asked the U.S. Bankruptcy Court on Tuesday to issue an injunction confirming its exclusive jurisdiction over the debtors’ rights to reject PPAs and other FERC-regulated agreements. (See related story, PG&E Files for Bankruptcy.)

The issue arose after NextEra and Exelon petitioned FERC for declaratory orders against PG&E because it was concerned, as many generators have been, that the utility would try to get out of high-cost contracts it had signed with owners of solar, wind and other renewable electricity sources.

NextEra’s and Exelon’s subsidiaries sell wind and solar energy to PG&E.

In its petition, NextEra asserted that the Federal Power Act created “a comprehensive regulatory framework for protecting the public interest” and entrusted the commission with “the authority to implement that framework.”

“According to NextEra, the core of the commission’s regulatory responsibilities under the FPA is the exclusive authority to regulate the rates, terms and conditions for interstate transmission and wholesale sales of electric energy under FPA Sections 205 and 206.8,” FERC wrote.

NextEra is concerned about its solar and wind power purchase agreements with PG&E if the utility enters bankruptcy. | *NextEra*

The commission explained that to protect its wholesale PPAs, “NextEra requests that the commission issue an order finding PG&E may not abrogate, amend or reject its commission-jurisdictional wholesale power purchase agreements with NextEra in any bankruptcy proceedings that may be initiated by PG&E without first obtaining approval from the commission under FPA Sections 205 or 206.6.”

NextEra cited the filed-rate doctrine to argue that rates filed and approved by FERC have the authority of federal regulations and cannot be undone except with FERC approval.

Dozens of generators and other entities filed motions to intervene and comments in support of NextEra’s petition. They include the 550-MW Topaz Solar Farms, in central California, one of the nation’s largest solar installations. Topaz, owned by Berkshire Hathaway Energy, saw its credit rating cut to junk status this month because it had an exclusive 25-year PPA with PG&E. (See PG&E Credit Woes Spread, Worrying CAISO Members.)

PG&E argued that a FERC order limiting its rights prior to its bankruptcy filing would violate the FPA and the U.S. Bankruptcy Code.

PG&E also contended that “NextEra’s petition is speculative and hypothetical because PG&E’s bankruptcy has not yet occurred and no action has been taken with regard to any particular contract. Additionally, PG&E claims that the commission’s jurisdiction under the FPA applies to the sale, but not the purchase, of power, and by extension, to sellers, but not buyers, of power. Accordingly, PG&E states that the commission is not authorized to order a buyer to continue to purchase power.”

FERC acknowledged that the law was unsettled when it came to contested authority between the FPA and Bankruptcy Code and between FERC and the courts. It took a middle road, saying the commission and courts share authority in cases like PG&E’s.

“Against this background, and given the unsettled state of the law, we have reviewed the FPA and Bankruptcy Code in light of the arguments raised in the petition and conclude that this commission and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts sought to be rejected through bankruptcy,” FERC wrote.

“We find that to give effect to both the FPA and the Bankruptcy Code, a party to a commission-jurisdictional wholesale power purchase agreement must obtain approval from both the commission and the bankruptcy court to modify the filed rate and reject the contract, respectively.”

In a research note issued to its clients Saturday, ClearView Energy Partners said FERC’s order did not bar PG&E from seeking to reject its PPAs before obtaining the commission’s approval.

“Instead, we read last night’s order as FERC asserting that as a generic matter such contract abrogation in the bankruptcy context would eventually require its approval,” the research firm said.

ClearView said the commission was taking the position established in the Boston Generating bankruptcy proceeding, where the litigating parties agreed that FERC and the U.S. district court had concurrent jurisdiction over changes to PPAs.

It concluded that “we continue to expect that PG&E may not have a free hand to reject the PPAs it currently holds,” specifically those signed with renewable resources needed to meet California’s public policy objectives.

January 29, 2019

PG&E Files for Bankruptcy

By Rich Heidorn Jr.

As expected, PG&E Corp. and its primary operating unit, Pacific Gas and Electric, f iled for reorganization under Chapter 11 of the U.S. Bankruptcy Code this morning.

The company said the filing in the U.S. Bankruptcy Court for the Northern District of California is an effort to provide “the orderly, fair and expeditious resolution of its liabilities resulting from the 2017 and 2018 wildfires.”

It said it made the filing after taking into account California officials’ statements last week clearing it of liability for the 2017 Tubbs Fire. (See related story, PG&E Cleared in Fire that Burned Santa Rosa.)

PG&E said it will continue operations during bankruptcy proceedings. | *PG&E*

The parent company listed total assets of $71.4 billion and debts of $51.7 billion. But those debts do not include all the expected wildfire claims. Its list of its 50 biggest creditors is dominated by banks, led by the Bank of New York Mellon and Citibank.

PG&E also filed a complaint asking the court to issue an injunction confirming its exclusive jurisdiction over the debtors’ rights to reject power purchase agreements and other FERC Claims Authority over PG&E Contracts in Bankruptcy.)

“Our most important responsibility is and must be safety, and that remains our focus. Throughout this process, we are fully committed to enhancing our wildfire safety efforts, as well as helping restoration and rebuilding efforts across the communities impacted by the devastating Northern California wildfires,” interim PG&E Corp. CEO John R. Simon said in a statement released shortly after midnight. “We also intend to work together with our customers, employees and other stakeholders to create a more sustainable foundation for the delivery of safe, reliable and affordable service in the years ahead. To be clear, we have heard the calls for change, and we are determined to take action throughout this process to build the energy system our customers want and deserve.”

PG&E asked the court’s approval to sign a $5.5 billion in debtor-in-possession financing agreement to allow the company to continue maintenance and investments in safety and reliability during the bankruptcy proceedings. JPMorgan Chase, Bank of America, Barclays, Citi, BNP Paribas, Credit Suisse, Goldman Sachs, MUFG Union Bank and Wells Fargo will act as joint lead arrangers.

“We believe that this process will make sure that we have sufficient liquidity to serve our customers and support our operations and obligations,” Simon said.

PG&E also filed motions seeking court approval to pay employees’ wages and benefits and continue its support of existing customer programs for energy efficiency and low-income ratepayers. The company said it will pay suppliers in full for goods and services provided going forward.

The company named James Mesterharm and John Boken, managing directors at AlixPartners, as chief and deputy chief restructuring officers, respectively.

PG&E shares, which closed Monday at $12.01, were up slightly in pre-market trading today.

January 28, 2019

NERC Standards Committee Briefs: Jan. 23, 2019

By Rich Heidorn Jr.

“This may be the quickest meeting we’ve ever had,” NERC Standards Committee Chair Andrew Gallo marveled after gaveling the committee to a close after a lickety-split 33-minute conference call Wednesday.

Team Gets Go Ahead on Standards Retirement Review

Members unanimously voted to authorize the standards drafting team (SDT) that arose from NERC’s 2017 Standards Efficiency Review (SER) to consider the retirements of all or part of more than 30 reliability standards (Project 2018-03).

The SER used a risk-based analysis to identify duplicative, administrative and otherwise unnecessary reliability standards. The SER team submitted a standard authorization request (SAR), which the Standards Committee accepted in August, before appointing the SDT in October.

“The establishment of the standards drafting team started the formal process to modify the standards, which includes finalizing the SAR and balloting the retirements,” NERC spokeswoman Kimberly Mielcarek explained.

In addition to retiring parts of existing standards, the SDT is considering the withdrawal of standard MOD-001-2, which was filed for regulatory approval in February 2014 and is still pending. The SAR says the standard is unnecessary because it concerns flowgates, transfer capability and congestion, “elements that impact transmission costs, rather than actual management of the” bulk electric system.

“Transmission operators, balancing authorities and reliability coordinators must operate the system in such a way that it’s reliable, both for current operations and for contingency conditions, and must remain impervious (according to FERC Standards of Conduct) to cost-related issues,” the SAR said.

Executive Committee Members Elected

Sean Bodkin of Dominion Energy; Linn Oelker of Louisville Gas & Electric; and Steve Rueckert of the Western Electricity Coordinating Council were elected to the SC’s Executive Committee.

Errata OK’d on Canadian Revisions to TPL-007

The committee unanimously approved a correction to the Canadian revisions to TPL-007 (Transmission System Planned Performance for Geomagnetic Disturbance Events) to note that no NERC standards are effective in Canada until approved by a Canadian governmental authority.

Jan. 31 Call Set to Appoint Drafting Team on Inverters

Members agreed to schedule a special call Jan. 31 to discuss and vote on nominees for a SAR drafting team for Reliability Standard PRC-024-2.

Members decided to table the item after declining to waive the five-day notice rule before votes. NERC staff had submitted its recommended nominees after the nomination period closed Jan. 18.

The SAR was prepared by the Inverter-Based Resource Performance Task Force (IRPTF) based on disturbance analyses and the development of the PRC-024-2 Gaps Whitepaper. The IRPTF identified potential modifications to PRC-024-2 to “ensure inverter-based generator owners, operators, developers and equipment manufacturers understand the intent of the standard.” (See NERC to Try Again on Inverter Rules.)

Howard Gugel, NERC senior director of engineering and standards, requested the vote before the Board of Trustees meeting Feb. 6.

Election to Replace Luminant’s Hampton

The committee will accept nominations through Feb. 18 for a replacement for Segment 6 representative Brenda Hampton, who has resigned from Luminant Energy.

Hampton’s replacement will serve for Segment 6 for the remainder of 2019 and 2020. The vote will be taken Feb. 25 to March 6. Hampton is moving to be closer to family, members were told.

January 28, 2019

PJM Rebuffs Stakeholders on Supplemental Projects

By Christen Smith

Wilmington, Del. — PJM riled stakeholders Thursday when it rejected manual language approved by more than two-thirds of members on transmission owners’ supplemental projects.

PJM Vice President of Planning Steve Herling said the RTO would not implement the proposed changes because they were “not consistent” with FERC rulings. “We don’t do this often, but we’re going to have to not implement what the members have approved,” he said immediately after the Markets and Reliability Committee approved the changes in a sector-weighted vote of 3.46 out of 5.

The proposal by American Municipal Power won unanimous support from the Electric Distributors and End-Use Customers sectors, 80% of Other Suppliers and 58% of Generation Owners. But it was opposed by all but one of the Transmission Owners.

2 Paragraphs

Most of the revision s to Manual 14B: PJM Region Transmission Planning Process, including those on the planning process work flow and supplemental projects, were not in dispute.

What PJM rejected were two paragraphs propos ed by AMP and backed by Old Dominion Electric Cooperative to increase the transparency of TOs’ supplemental project planning process. Aaron Berner, PJM’s manager of transmission planning, called the disputed text an “overreach” of the RTO’s Regional Transmission Expansion Plan, which he said is limited to studies of load flows, short circuits and stability.

AMP’s proposal said supplemental projects “should be based on written articulable criteria, models and guidelines that are measurable and, to the extent available, quantifiable (e.g., asset replacement prioritization) so stakeholders can replicate TO planning decisions and validate their proposed solutions.” AMP cited the transparency principles in FERC Order 890, saying TOs should disclose asset-specific condition assessments and the criteria and models supporting supplemental projects.

‘Useful’

The RTO also declined AMP’s proposal to strike the word “useful” from references to “end of useful life.”

Ed Tatum, AMP’s vice president of transmission, said the word could be interpreted as an accounting term associated with the depreciable life an of asset. AMP proposed using “operational” instead.

“We don’t replace facilities just because they’ve depreciated,” he said. “If people aren’t going to replace things until their operational life is done, I think it’s OK to say that.”

PJM officials said they did not interpret the word under its accounting definition but rather as an indication of a facility’s reliability and operational effectiveness.

“That language has been accepted by FERC in discussions around this topic,” Berner said. “We don’t believe a clarification is necessary.”

After further discussion, however, PJM committed to insert language indicating that “useful life” is not intended to indicate that facilities might be replaced solely based on them being fully depreciated.

Removing Supplemental Projects

PJM’s rejection of the AMP proposal rendered moot LS Power’s amendment requiring PJM to remove supplemental projects from the RTEP model if they are rejected by state regulatory commissions or their need has been eliminated by other PJM projects. AMP had agreed to accept the LS Power language — which said supplemental projects rejected by state commissions or siting agencies “will generally be removed from the RTEP” — as a friendly amendment.

Sharon Segner, LS Power | © *RTO Insider*

“There is no place in the current manual that addresses the issue of how supplemental projects get removed from the plan,” said Sharon Segner, vice president of LS Power, who also called for Operating Agreement changes to address broader issues with supplemental projects. Given the increasing spending on TO projects, she said, “That’s too big of an oversight.”

Segner also said that the manual could blur the line between the supplemental and regional planning processes.

According to AMP, TOs added $7.2 billion in projects in 2018 ($5.7 billion in supplemental projects and $1.5 billion in TO baseline projects) while PJM added only $560 million in baseline projects.

Herling opposed the LS Power language.

“There’s a lot of different outcomes that can follow the denial of the [certificate of public convenience and necessity], and it doesn’t make any sense that the manual should have black-and-white rules about when it should be removed from the process,” Herling said. “We feel we have received very clear guidance from the commission as to what goes into the RTEP and what does not.”

Supplemental projects — managed by TOs and not deemed necessary for compliance under PJM’s reliability, operational performance or economic criteria — have tripled over the last 13 years, accounting for 62% of the submitted RTEP project costs since January 2017, according to AMP.

“It is a staggering statistic,” Segner said of the supplementals’ growth. “This is a key issue — that the supplemental process does not dwarf the regional planning process.”

Deferral

After Herling rejected the AMP revisions, Segner pressed for a separate vote to add her amendment to the manual changes the RTO will implement. Her request was opposed by some stakeholders as a circumvention of the committee process.

“To me procedurally what it is saying is ‘I want to bring manual changes straight to the MRC; I don’t want to go through the lower committees,’” said Alex Stern, manager of transmission strategy and policy at Public Service Electric and Gas. “I think everyone needs to look at themselves around the room and think about that.”

Stern’s motion to remand the issue to the Planning Committee failed. But Segner then moved to delay a vote until the Feb. 21 meeting. It passed with 3.69 in favor.

January 28, 2019

MISO Moving Quickly on Initial SATA Rules

By Amanda Durish Cook

CARMEL, Ind. — MISO and stakeholders are hoping to complete policies allowing storage to qualify as transmission for the RTO’s 2019 Transmission Expansion Plan (MTEP 19).

The RTO hopes to file its first plan to allow storage as a transmission asset (SATA) with FERC by June. Initially, proposed SATA will only be allowed to solve transmission reliability needs and will be ineligible to simultaneously participate in MISO’s energy markets. The RTO currently has one reliability-based storage project proposal lined up for evaluation in MTEP 19.

“This storage-as-transmission [development] process is really short. … Folks want to get this right. Backtracking on policy once it’s been filed and accepted isn’t impossible, but it’s a really heavy lift,” Energy Storage Task Force Chair John Fernandes said during a Jan. 24 meeting. Fernandes commended MISO’s initiative on envisioning storage in the transmission realm, saying it is one of the first markets nationwide to do so.

“Storage might be able to go in where others can’t due to permitting,” Customized Energy Solutions’ David Sapper said.

The Energy Storage Task Force will hold a workshop on storage functioning strictly as transmission on Feb. 14. Ahead of the workshop, Fernandes urged stakeholders to think about how such projects would advance through the MISO stakeholder process and what criteria they might have to meet.

No Mixed-mode SATA, yet

MISO Director of Planning Jeff Webb said the RTO is choosing to “carve up” the SATA concept into less complex uses so it can better understand it and plan incremental approaches.

For now, MISO is proposing that SATA function solely as transmission — solving thermal, voltage or stability issues — and precluding it from energy market participation. MISO said it will develop rules for mixed-mode SATA use later. “We don’t know how to mix those two just yet,” Webb said.

Because mixed-use storage will not be permitted at first, the RTO will not require SATA to enter its generation interconnection queue. However, MISO does plan to model previously approved SATA in its interconnection studies. It said it will consider SATA’s “capabilities to inject or withdraw energy as needed to best mitigate reliability issues” as part of the network upgrades study during the definitive planning phase study in the queue.

SATA will also be modeled in MTEP reliability studies. MISO said it will gauge a proposed SATA project’s ability to “resolve the identified transmission issue at specified critical system conditions, consistent with the facility design capabilities.”

MISO said it will also create a special interconnection agreement among it, the storage owner, and the transmission system that the SATA is connected to. SATA operators must also complete MISO’s market participant registration.

Invenergy’s 31.5-MW Grand Ridge Energy Storage project | *Invenergy*

MISO in Functional Control

MISO proposes SATA be compensated like other transmission owners, with the storage facilities under the functional control of the RTO. MISO said keeping functional control of SATA will be practical as storage owners inevitably transition to mixed-mode use.

“MISO contemplates that most SATA will eventually desire to participate in markets in addition to providing cost-based transmission services. The ability to coordinate use of the asset in this mixed mode requires MISO as market operator to instruct the charging and discharging of the SATA for the provision of transmission services,” the RTO said. “Independent market operator control of the device for transmission service purposes will enable accounting for energy injections and withdrawals whether such transactions are instructed by MISO for transmission service purposes or as cleared market transactions. Further, control of the device by MISO for transmission purposes will mitigate concerns about inappropriate use of the device to the advantage of any particular market participant.”

Hisham Othman, of transmission and distribution consulting firm Quanta Technology, said reliability should always take precedence over any market benefits for mixed-mode SATA. He also said reliability requires very fast SATA controls, able to respond within a millisecond following a contingency to restore voltage and mitigate line overloads.

After stakeholder questioning, Webb said MISO will seek to quantitatively evaluate the benefits of SATA in the MTEP process as it’s able to recognize them. “If we can understand them and repeat them, then we’ll document them,” he said.

Some stakeholders asked if MISO might evaluate storage projects based on how mobile they might be. But Othman said there’s upgrade costs to be considered when a storage asset is physically moved to serve another area. “The reality is there’s a cost to picking it up and moving it.”

January 28, 2019

PJM MRC/MC Briefs: Jan. 24, 2019

By Christen Smith and Rich Heidorn Jr.

Markets and Reliability Committee

Revisions on Incremental Capacity Transfer Rights Endorsed

WILMINGTON, Del. — The Markets and Reliability Committee on Thursday endorsed a change to align PJM’s Tariff with manual language on the process for requesting incremental capacity transfer rights (ICTRs) calculations.

Steve Herling, PJM vice president of planning, said the “very limited” change requires new service customers to request the calculations during the facilities study phase and limits each request to no more than three locational deliverability areas.

The change comes in response to a FERC order that found PJM had not been following section 234.2 of the Tariff for assigning ICTRs. The RTO had clarified the procedure in Manual 14E: Upgrade and Transmission Interconnection Requests, but FERC said it must also be added to the Tariff (EL18-183).

The Tariff requires the RTO to identify the increase in the capacity emergency transfer limit (CETL) resulting from an interconnection, merchant transmission facility or customer-funded upgrade.

“As a practical matter, it would be impossible for us to calculate the increased CETL for every generator in the queue,” Herling said, citing estimates that it would take 54 hours per case to study deliverability to all 27 load delivery areas. “Bottom line is, for us to keep putting out system impact studies in compliance with the Tariff, we have to make to a change. Either we will have to stop putting out studies, or projects will be significantly delayed.”

The MRC on first read unanimously endorsed the change, which also was approved unanimously by the Members Committee later Thursday.

Markets and Reliability Committee Secretary Dave Anders and Chair Suzanne Daugherty | © *RTO Insider*

Fuel Security Issue on Tap for Feb. MRC

PJM will present the first read of a problem statement and issue charge on Phase 2 of its fuel security initiative at the February MRC, with a vote targeted for March, PJM’s Tim Horger said.

The RTO will recommend assigning the issue to a new senior task force reporting to the MRC. Among the issues to be discussed will be attributes that define a fuel-secure resource, whether a minimum quantity of fuel-secure resources is necessary, and market and operational mechanisms that could ensure fuel security.

Horger said PJM will be seeking a market-based solution, potentially through changes to the capacity market.

In mid-January, the RTO published 324 scenario templates from the fuel security analysis it released in December, which concluded that it should take “proactive measures” to value fuel security attributes of its generators.

The analysis found that “on-site fuel inventory, oil deliverability, availability of non-firm natural gas service, location of a pipeline disruption and pipeline configuration become increasingly important as the system comes under more stress.” (See Full PJM Study Makes Case for Fuel Security Payments.)

The RTO hopes to make a FERC filing in December or early 2020, Horger said.

The issue is likely to spark a renewed battle between supply and load interests. Tom Rutigliano, representing the Natural Resources Defense Council, said the issue should first be dealt with under the Capacity Performance program, noting that many risk factors listed in PJM’s analysis are unit-specific and thus part of generators’ CP obligations.

Although PJM acknowledged no individual generator could address systemic risks such as pipeline breaks or cyberattacks on supply systems, “the risks found in their study are mostly interruptible fuel contracts and lack of trucks, both of which can be solved by individual generation owners,” Rutigliano explained later. “Pipeline breaks play a relatively small component in the study results.”

Manuals Approved

The MRC unanimously endorsed the following manual changes:

Manual 38: Operations Planning: Periodic review and update to procedures.
Manual 40: Training and Certification Requirements: Cover-to-cover periodic review.
Manual 14G: Generation Interconnection Requests Planning Process: Cover-to-cover review.

PJM’s Adam Keech also notified members of a change made earlier this month to Manual 11: Energy & Ancillary Services Market Operations to clarify the current procedure regarding transient shortage pricing.

Keech said the manual did not fully describe the process for determining reserve shortages. He said the RTO became aware of the issue following a July 10 incident in which its area control error fell to -2,942 MW with a low frequency of 59.903 Hz.

PJM determined the low frequency resulted from several causes, including multiple unit trips, non-approved cases from real-time security-constrained economic dispatch and poor synchronized reserve response.

Members Committee

Members approved a revised definition of “on-site generators” in the market participation rules in the Tariff and Operating Agreement. The new definition recognizes that behind-the-meter resources can participate as both demand response to reduce load and as generation to inject power.

FTR Mark-to-auction Credit Requirements OK’d

With one objection, the committee approved a new a mark-to-auction component for financial transmission rights credit requirements, a change prompted by the GreenHat Energy default.

Although a decline in market value can indicate increasing FTR risk, PJM’s rules do not provide for a collateral call when an FTR portfolio’s value is deteriorating. The change would consider the difference between the FTR purchase price and most recent market price. It cleared the MRC in December. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)

The mark-to-auction rules chosen by PJM stakeholders (package G1) would affect only 4% of accounts, excluding GreenHat Energy. | *PJM*

Opportunity Cost Calculator Manual Revisions

Members endorsed revisions to Manual 15: Cost Development Guidelines governing generators’ use of the Independent Market Monitor’s calculator as an alternative method of calculating energy market opportunity costs.

A vote on related revisions to Schedule 2 of the OA was deferred again, until February. (See “Opportunity Cost Calculator Vote Deferred,” PJM MRC/MC Briefs: Oct. 25, 2018.)

Liaison Committee Meetings to Change

Members heard the first read of a charter revision that would require the scheduling of Liaison Committee meetings with the Board of Managers before the board’s regular meeting. Under current rules, Liaison Committee meetings alternate between before and after the board meeting. The change came out of discussions at the Stakeholder Process Forum.

January 28, 2019

MISO Plans for New Uninstructed Deviation Rules

By Amanda Durish Cook

MISO will this March begin testing new rules to deal with generators’ uninstructed deviations from dispatch orders, stakeholders learned last week.

The RTO announced its plan to move ahead with implementing a new deviation threshold during a Jan. 25 conference call — coincidentally the same day FERC approved its filing in a delegated order (ER1 9 -199). The new standard will be based on comparing real-time performance with day-ahead offer ramp rates.

During the call, MISO said it was preparing for the new thresholds despite not yet receiving FERC approval. Hours later, FERC issued a brief order approving MISO’s proposal just in time to meet the RTO’s requested decision date. The commission said it did not receive any “adverse comments” to the filing.

MISO Market Quality Manager Jason Howard said the RTO is on track to start testing the new threshold by the first week of March and have a full implementation by mid-spring.

“As long as we don’t see something or run into any issues of this testing phase … we’ll implement this by May 1,” Howard said.

MISO will test the new system using singular past operating days with forecast data from market participants, Howard said. He said MISO is using singular operating days instead of running full weeks of data because the testing represents “a significant amount of work” for RTO staff. The testing approach will be similar to that used prior to implementing five-minute market settlements.

MISO’s proposal calculates a generator’s uninstructed deviation with a tolerance based on the minimum of five times the real-time ramp rate or 12% from the average set point instructions. Currently, generators in MISO are flagged after they deviate by more than 8% from dispatch signals over four consecutive intervals.

The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a performance rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance. The change means that a generator that fails four or more consecutive five-minute dispatch intervals within an hour by either providing excessive or deficient energy will not automatically lose its eligibility for make-whole payments.

Additionally, MISO only plans to assess excessive or deficient energy charges on dispatchable intermittent resources during intervals when the market participant’s forecast is provided or when the resources are economically dispatched below the RTO’s forecast.

January 28, 2019

NERC Standards Committee Briefs: Jan. 23, 2019

Team Gets Go Ahead on Standards Retirement Review

Executive Committee Members Elected

Sean Bodkin of Dominion Energy; Linn Oelker of Louisville Gas & Electric; and Steve Rueckert of the Western Electricity Coordinating Council were elected to the SC’s Executive Committee.

Errata OK’d on Canadian Revisions to TPL-007

Jan. 31 Call Set to Appoint Drafting Team on Inverters

Members agreed to schedule a special call Jan. 31 to discuss and vote on nominees for a SAR drafting team for Reliability Standard PRC-024-2.

Members decided to table the item after declining to waive the five-day notice rule before votes. NERC staff had submitted its recommended nominees after the nomination period closed Jan. 18.

Howard Gugel, NERC senior director of engineering and standards, requested the vote before the Board of Trustees meeting Feb. 6.

Election to Replace Luminant’s Hampton

The committee will accept nominations through Feb. 18 for a replacement for Segment 6 representative Brenda Hampton, who has resigned from Luminant Energy.

Hampton’s replacement will serve for Segment 6 for the remainder of 2019 and 2020. The vote will be taken Feb. 25 to March 6. Hampton is moving to be closer to family, members were told.

— Rich Heidorn Jr.

January 27, 2019

NYISO Looks at Carbon Charge Tariff Impacts, Residuals

By Michael Kuser

RENSSELAER, N.Y. — NYISO stakeholders last week discussed how pricing carbon in the wholesale market will impact the ISO’s Tariff, while additional materials posted by the ISO provided insight into how it will handle residual allocations stemming from carbon charges.

“Tariff revisions will be necessary to effectuate carbon pricing in the ISO’s markets,” Ethan D. Avallone, NYISO senior energy market design specialist, told the Market Issues Working Group (MIWG) on Jan. 22.

Avallone provided an overview of the Tariff sections impacted by a carbon charge and that will be reviewed over the coming months, mainly related to the social cost of carbon (SCC), emissions data reporting, emission rates in reference levels, credit requirements and the carbon component of locational-based marginal prices (LBMPc).

Stakeholders will begin discussions on revisions to credit rules, if necessary, this fall, Avallone said. To avoid delays, any related Tariff changes will be separate from the second-quarter vote on implementing the carbon charge.

The above chart shows the results of allocating the carbon residual to load using consumer impact analysis data, after considering the impact to the LBMP from dynamic effects brought about by carbon pricing. | *NYISO*

Several stakeholders said that if there’s a chance that a carbon charge will have a material impact on suppliers’ credit requirements, they have a right to know ahead of time what that impact will be.

“Our approach here is to assess the credit impact once we know the market design,” Avallone said.

Sheri Prevratil, NYISO manager of corporate credit, said that while carbon pricing “will affect the LBMP, we don’t see any changes in the credit methodology as it relates to energy credit requirements. … Where we see a possible change is in the projected true-up exposure credit requirement. Based on what we understand the market design to be right now, those are the only changes we currently foresee.”

New York’s Implementing Public Policy Task Force (IPPTF) last month turned its carbon pricing proposal over to the ISO’s stakeholder process through the MIWG, which began its work earlier this month. (See Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off.)

The MIWG has scheduled meetings to review the carbon pricing Tariff revisions for Jan. 31, Feb. 15 and March 18.

Allocating Residuals

NYISO is recommending that the carbon charge residual resulting from levying suppliers for their emissions be allocated proportionally to consumers across all zones to ensure an equitable impact, consistent with the current allocation of renewable energy credit costs, Avallone noted in slides not presented to the MIWG because of time constraints.

The carbon residual is the total dollar amount of carbon charges collected by the ISO from suppliers and allocated to load.

At an Oct. 29 meeting of the IPPTF, the ISO revised its proposal on carbon residual allocation after a Brattle Group analysis showed that the proportional allocation methodology minimizes cost shifts among consumers. (See NY Task Force Talks LBMPc, Residuals, Hedge Effects.)

The above example assumes a positive carbon residual. | *NYISO*

According to Avallone’s presentation, load-serving entities would pay the full LBMPc to suppliers, who would then pay NYISO the carbon component. The ISO would then allocate the carbon residual to each zone based on its LBMPc.

The allocation would use the LBMPc from the binding real-time interval (nominally five minutes) to calculate the time-weighted integrated (TWI) LBMPc, according to the presentation.

Supplier emissions would be reported on an hourly basis, so the carbon residual would therefore be on an hourly basis, and the ISO would use TWI LBMPc, the hourly carbon residual and real-time actual internal load to determine the allocation.

NYISO is considering how to calculate the carbon residual allocation under two scenarios thought to be unlikely, according to the presentation: if the LBMPc for a given zone is less than zero, and if the carbon residual is less than zero.

The ISO expects the LBMP to increase slightly under carbon pricing to reflect the emissions of the marginal unit, and carbon-free opportunity cost resource bids are likely to increase as a result of carbon pricing in some hours.

Opportunity cost resources represent those carbon-free resources able to store energy and structure their bids to achieve delivery schedules during the most economic periods of the day. In periods of the day with lower prices, the bids of such resources therefore reflect the estimated opportunity cost of profit from periods of the day with higher prices. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)

The MIWG will discuss calculating the LBMPc and identifying the marginal units on Feb. 15, and on March 4 will cover carbon bid adjustment for opportunity cost resources.