VALLEY FORGE, Pa — Interim PJM CEO Susan J. Riley opened last week’s Market Implementation Committee meeting with an optimistic message about moving the organization forward after Andy Ott’s departure June 30.

“There’s a lot of work to do, particularly with our markets coming out of the whole FTR/GreenHat issue,” she said, referring to financial transmission rights trader GreenHat Energy’s default in June last year. “I’m here to assist with that and provide perspective to PJM. We’ve got to make these markets safe for participants.” (See Naive PJM Underestimated GreenHat Risks.)

Ott announced his retirement as CEO in May, marking the second top executive departure this year. (See PJM CEO Andy Ott to Retire and PJM CFO Retiring in Wake of GreenHat Default.)

Riley, a member of the Board of Managers, said she expects to serve as CEO for the next four months. She told the MIC that the organization is close to announcing the woman selected to be the RTO’s first chief risk officer, per the recommendation of the independent probe into how the GreenHat default unfolded.

“We are very excited to having her come on board,” she said. “There will be a lot more to come with ensuring the safety of our markets.”

5-Minute Dispatch and Pricing

Stakeholders unanimously endorsed a problem statement that criticizes the real-time security-constrained economic dispatch (RT SCED) and market pricing processes that PJM uses to send dispatch signals to generators and calculate LMPs.

Siva Josyula of Monitoring Analytics last month said a price publishing delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.

The MIC will spend the next several months reviewing the issue and recommending necessary changes.

Order 841 Manual Revisions Endorsed

The MIC approved a slew of manual revisions related to FERC Order 841 on electric storage participation. The changes include updating Manual 11: Energy & Ancillary Services Market Operations; Manual 18: PJM Capacity Market; and Manual 15: Cost Development Guidelines to align PJM policies with those outlined by the commission.

Laura Walter, senior lead economist for PJM’s advanced analytics and surveillance department, said Manuals 11 and 18 will clarify that storage resources can participate in the RTO’s markets and can dispatch and set price as seller and buyer. The revisions also note that stored megawatt-hours are billed at LMPs as wholesale.

In Manual 15, revisions detail business rules for cost offer development — specifically for hydroelectric resources and batteries and flywheels, PJM Senior Engineer Danielle Croop said. Staff also added definitions for efficiency factor, fuel cost, variable operations and maintenance (VOM) and ancillary service costs.

Efficiency factors measure the ratio of generation produced to the amount of electricity used to charge, Croop said. Fuel cost will use the average charging cost and will be defined in fuel-cost policies. Maintenance and operating cost inclusion and exclusion guidelines will be submitted in resources’ VOM templates, she said.

Modeling Units with Stability Limitations

The MIC is gearing up to discuss whether PJM should require generators to submit outage tickets during forced curtailments stemming from nearby transmission maintenance.

Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, presented a first read of the problem statement and issue charge he promised to bring during an Operating Committee meeting in May. His concerns arose out of proposed revisions to Manual 10 that would require generators to use outage tickets for stability-related limitations — possibly encouraging price distortion. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)

O’Connell argues PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.

As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and it must be used in each of the markets. He also encouraged the RTO to publicize stability limits on OASIS prior to contacting the affected generator.

The MIC will be asked to endorse the problem statement at the August meeting and work on possible solutions during the committee’s meetings over the next few months.

Deadline Approaching for Gas Contingency Comments

PJM’s deadline for comments on its new Tariff language for gas pipeline contingencies comes and goes July 17 — but it appears many stakeholders remain unhappy with the latest draft.

On Feb. 19, FERC rejected the member-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or fuel source because of pipeline breaks or the loss of compressor stations (ER19-664.) The proposal included nine categories of switching costs, such as park-and-loan service charges and overrun charges. (See FERC Rejects PJM’s Gas Pipeline Contingency Proposal.)

Thomas DeVita, PJM’s senior counsel, said FERC staff dropped some hints about how to tweak the filing for better success the second time around. (See PJM Revisits Gas Pipeline Contingency Plan.) He said staff discouraged the RTO from submitting an itemized list of switching costs, as it did in the first filing, and instead focused on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs.

Marji Philips, Direct Energy’s director of RTO and federal services, continues to believe the entire filing is fundamentally flawed and puts an unnecessary burden on load.

“If you want to have the right market response, you will look for other market incentives so that you’re not switching the cost of generation to load, because that’s what’s happening here,” she said. “The whole purpose of competitive markets is that the generator bears the risk, not load.”

She further argued that generators should be prepared to compensate during emergencies lasting 24 hours or more.

“If the conditions last longer than 24 hours, it’s no longer an emergency,” she said. “PJM shouldn’t be shifting the burden to load because the generator didn’t incorporate the risk into its CP offers. The generator guaranteed performance under CP, so it’s not load’s responsibility to cover the extra costs of that fuel.”

O’Connell agreed that mandatory operating instructions should only last for a set period of time, but he worried that memorializing such rules could encourage unsavory market behavior.

“One thing to address … the directive expires based on the rule, then 10 minutes later PJM issues the same directive,” he said. “Have we constructed a rule that can be worked around? Market participant perspective is that the market participant should be responsible for deciding what risks they care to take and what costs they care to incur, and if PJM overrides it, PJM should pick up the tab.”

It’s a sentiment Philips said she agrees with completely.

– Christen Smith