VALLEY FORGE, Pa. — PJM’s Tim Horger provided an update on the RTO’s efforts to comply with FERC’s plan on fast-start pricing at last week’s Market Implementation Committee meeting. The commission last month withdrew its Notice of Proposed Rulemaking on fast-start pricing because it said a uniform set of requirements isn’t appropriate for all RTOs and ISOs. Instead, it called on PJM, SPP and NYISO to make changes. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

Horger said PJM’s initial response is due Feb. 12 and that a final order is expected on Sept. 30. FERC indicated that PJM should:

• Allow for relaxation of all fast-start resources’ economic minimum operating limits by up to 100%, such that the resources are considered dispatchable from zero to their economic maximum operating limit for the purposes of setting prices;
• Apply the relaxation of a resource’s economic minimum operating limit to all fast-start resources, not just block-loaded fast-start resources;
• Consider fast-start resources within dispatch in a way that is consistent with minimizing production costs, subject to appropriate operational and reliability constraints;
• Modify pricing logic to allow the commitment costs of fast-start resources to be reflected in prices;
• Include in the definition of fast-start resources a requirement that those resources have a minimum run time of one hour or less;
• Include in the definition of fast-start resources a requirement that those resources be able to start up within one hour or less; and
• Set forth its rules and practices regarding the pricing of fast-start resources.

Horger said PJM plans to “generally support” the suggestions and provide additional feedback, including the definition of “fast start.” It will also supply recommendations on the relaxation method between economic minimum and “integer relaxation” — a pricing method designed to minimize uplift costs.

Day-Ahead Market LMP Confusion

Horger also provided an explanation of a situation that created stakeholder confusion when PJM announced it planned to revise day-ahead market LMPs, then retracted that plan: The aggregate percentages for the IMO interface — the pricing point between PJM and Ontario’s Independent Electricity System Operator — for Dec. 26 to 30 were “slightly off.”

Upon further review, staff determined that the issue was minimal and didn’t violate the Tariff, so they decided to retain the original values instead of disturbing the market.

Stakeholders pointed out that PJM’s series of communications, which initially said a change would be made before later reversing that decision, was confusing.

“Your feedback is on target. … We probably caused some confusion by jumping the gun,” PJM’s Stu Bresler said.

The normal process would be to announce that an issue was found and then later announce revisions will be made once the determination is complete, he said, instead of announcing them both initially.

“Historically, when we think a situation is cut and dry, we combine the first two steps: announcing the issue and saying we’re going to change things,” he explained. “We should have issued the notification that we found something, but not” the announcement that changes would be made.

Market Impacts of Cold Weather

PJM’s Joe Ciabattoni told stakeholders to expect more uplift from the cold snap that occurred over the holiday break, but “nothing near” the market impacts from the cold streak in 2014 known as “the polar vortex.”

“We had a couple of $2 million days,” he said, but “I don’t think that the magnitude will be anything near what we saw in the polar vortex” when there were days of $86 million and $50 million. The difference this time, he said, was that the cold temperatures were sustained.

“In 2014 and 2015, the temperatures were more extreme, though not as long of a time frame,” he said.

Unplanned outages began to “crop up” near the end of the cold period on Jan. 6, but conditions never triggered requirements that maintenance outages close out within 72 hours. Ciabattoni said there were “plenty” of new 30-minute reserves measurements developed to help address gas pipeline contingencies.

“We’re getting [outage] tickets in early, as opposed to the polar vortex, when we were surprised by some outages,” he said.

FTR Nodal Remapping

Stakeholders approved a problem statement and issue charge on remapping financial transmission rights nodes. PJM’s Brian Chmielewski explained that the nodes where FTRs begin or end can be terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one. PJM’s current process for that search “may not guarantee an optimum substitute” that provides the same economic value and might lack transparency.

Direct Energy’s Marji Philips expressed concern with the wording of the problem statement.

“The problem is if PJM can’t find [an electrically equivalent node], it just flat out terminates the FTR,” she said. “I’m not sure the statement actually captures that.”

Rules Endorsed for Enforcing Regulator Requirements on EE

With three abstentions, stakeholders endorsed rule changes that will allow state and local regulators to manage energy efficiency participation within their jurisdiction if they receive FERC approval.

PJM’s Pete Langbein explained the process, which stems from a December ruling in which FERC established its “exclusive authority” over EE participation in wholesale markets while also preserving a carveout it had previously approved for Kentucky utilities. (See FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out.)

Under the new process, PJM must alert all affected electric distribution companies about the impact of any such FERC approvals. EE that cleared the auction but isn’t allowed to deliver into a particular jurisdiction may be relieved of the commitment. EE providers will need to itemize deliveries in American Electric Power and Duke Energy zones whether or not they are in Kentucky. EDCs will review a list of whether that provider is allowed to deliver in Kentucky based on the relevant regulators.

Financial Traders Question IMM on Long-Term FTR Concerns

Seth Hayik of Monitoring Analytics, PJM’s Independent Market Monitor, presented analysis of data that the Monitor argues show that long-term FTRs aren’t improving the market. Financial stakeholders, who trade in the long-term FTR markets, questioned the findings.

Long-term FTRs, which are available for each of the next three planning years or a combination of all three, are intended to provide hedges for transmission congestion by reflecting the conditions expected in the future situations.

“They’re not reliable,” Hayik said. “What comes out of the long-term FTR modeling doesn’t necessarily reflect what’s going to” happen. PJM has taken steps to correct what it could in the model for the nearest planning year, but “I don’t know that there is a solution for those models” for the subsequent years, he said.

Financial traders acknowledged that the risk of erroneous predictions is intrinsic to forward markets.

“Generally, forward markets are forward markets, and you buy in those markets without perfect vision of what will happen when those become spot markets,” Vitol’s Joe Wadsworth said. “That’s true of any future market. You don’t have foresight into what could go right or could go wrong in those markets. You make your decision on value.”

“Look how competitive the markets have become,” DC Energy’s Bruce Bleiweis said. “That’s the evolution of a market; they become more and more competitive over time.”

The Monitor said prices have really been driven down by 50% reductions in line congestion, but Bleiweis said its data showed that market alignment has improved by 90%. He credited the long-term FTR market for the additional improvement.

Philips said it’s too early to make conclusions.

“We support what [the Monitor] is doing,” she said. “We would like to understand the impacts.”

Monitor Joe Bowring said better market structure in the single-year products “doesn’t mean the outcomes are competitive, and the outcomes are what we need to focus on.”

“In a competitive market we would expect to see the excess profits competed away, but that has not happened,” he said.

Stakeholders Battle PJM, Monitor on Market Path Alignment

Stakeholders continued to criticize proposals by PJM and the Monitor on a rule for evaluating designated market paths for energy sales coming into the RTO. The members have called for caveats that would allow them to explain their reasoning for paths PJM or the Monitor find questionable.

Along with their existing joint proposal, PJM introduced one that didn’t include Monitor endorsement. It excludes applying the rule to scheduled long-term path activity — annual, monthly or weekly — but allows for “potential referral” to FERC enforcement if “manipulative behavior” is suspected.

The proposal placated no one.

“The whole point of the original proposal was to have a rule. If there is no enforceable rule … then the rule is meaningless,” Bowring said. “I think the point of the rule is clear: It’s to prevent one participant from taking actions at the same time in different directions, explicitly manipulating the market.”

American Electric Power’s Brock Ondayko complained that the proposals seemed to tell participants “you can’t do this transaction because when we put it together with your other transactions, we see this grander transaction and that’s not allowed even though it might make complete financial sense to do that.”

“I don’t think we’re going to be very supportive of the idea of just prohibiting paths and referring people” or immediately resettling transactions because stakeholders could “get caught in a net,” said Carl Johnson, who represents the PJM Public Power Coalition.

Bowring assured that there’s no “automatic referring” in the joint proposal, but he reiterated that a definitive rule is necessary. “These can occur and will occur if permitted. We know that for a fact,” he said.

“A lot of what PJM [and the Monitor are] suggesting they’re going to do is discriminatory,” said Stephen Kelly of Brookfield Energy Marketing. “Every other company in this room is able to do that transaction.”

He called for allowing stakeholders “to present hard evidence … that these are separate transactions” based on different strategies. “We don’t think that’s asking too much.”

Emergency Pipeline Switching Instructions Sparks Rights Debate

PJM’s Rich Brown presented a proposed problem statement and issue charge on fuel switching that sparked pushback from stakeholders.

The proposal focuses on how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as backup oil or a different pipeline. Gas-fired operators argued that PJM’s plan would disincentivize flexibility and fails to recognize or sufficiently compensate operators who have paid extra for guaranteed pipeline capacity.

Being forced to switch fuel sources can decrease unit performance and increase the risk of the plant tripping off, Calpine’s David “Scarp” Scarpignato said, so “I’m actually being put in a worse situation for being more flexible.”

PJM’s Chantal Hendrzak acknowledged the RTO might need to identify other “attributes” for which generators should be compensated.

“There’s a recognition to do that,” she said. “It’s something that we realize that we need to talk about, but not only talk about, but figure out how to do.”

“In general, what you’re trying to do is a good thing,” said John Horstmann of Dayton Power & Light. “Given the fact that you’ve never done this before … what is the rush? … It looks like a short-term reaction with some big implications for generation-ownership rights and financial risk that are unresolved.”

“We have learned a lot,” Brown said. “As we educate ourselves, that has led us to operationalizing gas contingencies.”

Putting it all together, Hendrzak said, “that conversation might take a while.”

Bowring called the proposal “very reminiscent of cost-of-service in its worst sense. … This approach relies on command and control rather than market forces.

“I would ask you to put the market design elements into this,” he said. “How to get gas constraints into the market, that’s the real issue.”

Other stakeholders questioned who would pay for the additional compensation.

“We don’t think the costs should be on load,” said Dave Mabry, who represents the PJM Industrial Customer Coalition. The costs should be on the generators who don’t have guaranteed service to ensure “we are incenting folks to get the fuel supply they need and firm that up if necessary.”

Citigroup Energy’s Barry Trayers noted that the Capacity Performance rules and payments were designed to handle those needs.

PJM staff said they are in contact with pipeline companies to discuss these issues but stopped short of confirming they will be involved in the stakeholder process.

“It would be great if we could get some participation in the stakeholder meetings,” Hendrzak said. “I’m not sure if that will actually happen.”

— Rory D. Sweeney