Page 1267 – RTO Insider

November 14, 2017

PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017

VALLEY FORGE, Pa. — PJM’s Asanga Perera presented stakeholders at last week’s Planning Committee meeting with a problem statement and issue charge to address issues the RTO sees with its current process for evaluating market efficiency projects.

pjm market efficiency projects planning committee — Perera | © *RTO Insider*

“We have conducted two cycles to date since FERC Order 1000 was established, and during these two cycles, we recognized various challenges that we think are important to address going forward,” he said.

One of the issues, Perera explained, is that PJM’s benefit-to-cost calculations beyond 10 years are extrapolations, not more accurate simulations.

“We have discovered, in certain instances, we may end up either overstating benefits or understanding benefits, especially on a longer horizon,” he said.

PJM also must address modeling issues, timing of the proposal-window process, interregional analysis and project re-evaluation, Perera said.

Sharon Segner of LS Power applauded the focus on the process but asked if it could go further.

“This is a great discussion in terms of some of the challenges that the market efficiency window is facing,” Segner said. “Is there anything missing?”

PJM staff resisted suggestions to include a review of cost calculations, saying that’s being handled elsewhere.

Segner also warned against making any retroactive changes.

“It’s important to not undermine the work of the past, because that’s going to create a lot of regulatory uncertainty,” she said.

If the initiative is approved, the work would be assigned to a task force, Perera said.

Light-Load Analysis

PJM has compiled some data to begin updating parameters for modeling light-load conditions. PJM’s Mark Sims presented the data.

“There’s definitely plenty of activity happening out there to draw some conclusions,” he said.

One focus is comparing high-voltage alarms with instances when high-voltage emergency procedures were taken. The alarms, which require generators receiving them to take action, precede emergency procedures that PJM takes.

“The alarm data is a good proxy to use moving forward to look for statistical values to develop parameters” for a test, Sims said.

PJM is also considering how to address the lag between recognizing an issue and compiling all the information to address it effectively.

“Between it happening and us fixing it, it could be a couple of years,” Sims said.

Summer Demand less than Expected

Mild weather meant load never came close to reaching the peak summer forecast, PJM’s John Reynolds said.

The summer peak of 145,331 MW on July 19 was 5% below the forecasted peak of 152,999 MW and 4.4% below the 2016 peak of 151,945 MW. “The champ still reigns,” Reynolds said, referring to PJM’s all-time peak of 166,876 MW on Aug. 2, 2006.

There were 0.4 MW of load management July 19, he said, and there have been anecdotal accounts of a “significant amount” of peak shaving this summer.

The decline in weather-normalized load won’t mean an immediate drop in load forecasts.

“That would be an assumption that people should not make,” Reynolds said. “It will take time for that to work its way in full.”

The call for patience confounded Calpine’s David “Scarp” Scarpignato.

“I don’t want to wait 18 years to get the forecast right,” he said.

ARR Analysis IDs Constraints

An analysis of Stage 1A 10-year auction revenue rights found “infeasible facilities” both within PJM’s footprint and in market-to-market interactions with MISO, Perera said.

The internal constraint will be addressed by a project (b2774) in the Regional Transmission Expansion Plan, which is expected to be in service in 2020. Of the remaining nine M2M constraints, one will be addressed by a MISO Transmission Expansion Plan project that is expected to be in service this year. Three others have projects under consideration, two will be included in a future targeted market efficiency project proposal window and three are pseudo-tie flowgates.

Asked specifically about lines connecting to the Ohio Valley Electric Corp. — which is attempting to join PJM as a transmission zone — Perera said no new issues were identified. A project between OVEC’s Clifty Creek Power Plant and the Trimble County substation is one of nine M2M constraints under consideration.

— Rory D. Sweeney

November 14, 2017

PJM’s Markets Competitive, Energy Prices Up, Monitor Finds

By Rory D. Sweeney

PJM’s markets were competitive in the first nine months of the year and energy prices were up $1/MWh compared to the same period last year, the Independent Market Monitor found in its quarterly State of the Market Report.

“Energy prices in PJM in the first nine months of 2017 were set, on average, by units operating at, or close to, their short-run marginal costs, although this was not always the case during high-demand hours,” the report said. “This is evidence of generally competitive behavior and resulted in a competitive energy market outcome.”

state of the market report — Quarterly total price and quarterly inflation adjusted total price ($/MWh): January 1, 1999 through September 30, 2017 | *Monitoring Analytics*

The load-weighted, average LMP in PJM was 3.5% higher in the first nine months of 2017 than during the same period in 2016, rising to $30.36/MWh. The Monitor said the increase was “primarily” due to higher fuel prices.

Coal and natural gas costs rose faster than electricity prices, undercutting generator revenues. Average energy market revenues decreased by 51% for new gas-fired combustion turbines, 28% for new combined cycle units and 17% for a new coal plant, while increasing 6% for nuclear units, the Monitor said.

Coal units’ dominance has dipped over time, while gas has risen. In 2008, coal represented 75% of the marginal resources and gas 20%. In the first nine months of this year, coal stood at 32.5% and gas rose to 52.9%, the Monitor said.

Wind continued to depress prices as the marginal unit. In the first nine months of 2017, 74.1% of the wind marginal units had negative offer prices, 18.9% had zero offer prices and 6.9% had positive offer prices.

Total energy uplift charges decreased $16 million (15.7%) to $86.3 million during the nine-month period. Demand response payments also decreased by $167.2 million (31.1%) to $370.6 million, while congestion costs fell $366.8 million (44.6%) to $455.4 million.

The impact of FERC’s ruling on balancing congestion — rejecting the notion that financial transmission rights are only intended to benefit load — was also evident this year. Revenues from auction revenue rights and FTRs offset 98.1% of total congestion costs for load during the 2016/2017 planning period, but only 79.7% of those costs for the first four months of the 2017/2018 planning period. In January, FERC accepted PJM’s compliance filing in response to the commission’s requirement that the RTO develop a method for allocating ARRs that doesn’t consider extinct generators. Under the new rules, PJM assigns balancing congestion to real-time load and exports and regularly updates its ARR allocations to reflect generator retirements. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)

November 13, 2017April 9, 2024

Overheard at GTM US Power Renewables Summit

AUSTIN, Texas — Greentech Media’s inaugural U.S. Power & Renewables Summit drew an international crowd of energy sector participants to hear from industry leaders and experts. Panel discussions and one-on-one interviews focused on renewable energy’s effects on the power markets, the disruptors of today’s markets, navigating uncertainty and building a new energy future.

DOE Report Author: Identify, Pay for Resiliency Services

Energy consultant Alison Silverstein, who drafted the technical portions of the Department of Energy’s “Staff Report on Electricity Markets and Reliability,” took no credit for the department’s Notice of Proposed Rulemaking asking FERC to prop up baseload coal and nuclear generators in competitive markets (RM18-1).

“The fact of the matter is, what we see in the DOE NOPR has no justification in the staff report, except for a few cherry-picked items that politicos wrote into the report,” said Silverstein, who readily admits she is “not a big fan” of capacity markets. “There’s a direct line from the old capacity markets to the NOPR. We ought to think what resiliency services are, and pay for that. We need to be very specific, and very clear, as to the value of what things matter for effective grid operations … and we need to pay for every one of them.”

Saying that the energy markets are not facing a market problem, but a “glut,” Silverstein said the “best cure for over-capacity is retirements.”

“If we can clear out some of the inefficient plants sucking away money, we can see whether it’s a price-formation problem or too many plants lowering the revenue share for everyone,” she said. “The reason so many coal and nuclear plants are retiring — and they should be — is not renewables and it’s not regulations. They are old plants. They’ve done their job, they’ve made money, they’ve paid their dues, and it’s time for them to move on. It’s not a tragedy for the market as a whole; it’s a transition. It’s what should happen, enabling a more nimble market to occur.”

Speaking on the same panel, Keith Collins, executive director of SPP’s Market Monitoring Unit, said the lack of retirements in the face of “tremendous growth” in wind energy and other renewables, has led to complaints from generating resources not having sufficient revenues and thermal resources self-committing outside the market.

“All these pressures are causing prices to be distorted,” he said. “We’re looking for solutions to keep resources around, when the signals are saying we don’t need these resources.”

Collins called for further developments to find value in ramping products, as he said CAISO and MISO are currently doing.

“When you think of the LMP, it takes into account the spatial elements of congestion. Ramp is the time element,” Collins said. “Even today, if you look at the five-minute prices, you see signals being sent. A ramping product can better capture that value, and do it in a technologically neutral way.”

“We’re trying to make the market mechanics work harder than they should be,” Silverstein said, agreeing with Collins. “We’re trying to pile way too much into energy prices. If we want ramping, by God, let’s have ramping. If we want cycling, by God, let’s have cycling — but let’s pay for it. Let’s stop trying to make the energy price so complicated. We should be saying, ‘These are the 10 products we need. For these five, you must be able to deliver them in return for being interconnected to the market.’”

Bay Says ‘Healthy’ Reserve Margins Disprove DOE’s NOPR

When a former FERC chairman appears at a conference amid a proposed rulemaking, naturally he will be asked his opinion.

Norman Bay, who resigned from FERC in February after the Trump administration replaced him with Commissioner Cheryl LaFleur, did not hold back. He made it clear he doesn’t believe the grid is facing a reliability threat and said the commission could be taking a legal risk in propping up coal and nuclear baseload plants.

“That’s the problem … the [DOE] recommendation does not support the problem,” Bay said. He made a note of the generally positive RTO/ISO winter assessment reports made during FERC’s October open meeting. (See New England, SoCal Gas Supplies Top FERC Winter Concerns.)

“The reserve margins are healthy across the U.S. In some of markets and ISOs, the reserve margins are well above what they need to be,” Bay said. “A reasonable argument could be made that there’s not too little capacity, but too much, which is suppressing revenues for other resources in the markets. The DOE’s own study said system reliability was adequate. The month before, NERC said reliability was strong.

“Where’s the record of support for this proposal, and how do you get to 90 days of supply?” he asked. “I think there’s a real legal risk for FERC to adopt the rulemaking in its current format. How does FERC deal with the discrimination against resources? FERC has prudently in the past been revenue-neutral, and not picking winners and losers in the marketplace.”

Bay said the NOPR could wind up being rolled into the commission’s examination on the effect of state policies on wholesale markets and price formation.

“There are some measures FERC could adopt that would be constructive,” he said, referring to proposed rulemakings on uplift allocation and fast-start resources. “This amounts to no-regret measures.”

Vistra Energy Exec Responds to Recent News

Anthony Maselli, vice president of development and strategy for Vistra Energy, addressed recent events involving his company: the announced $1.7 billion acquisition of Dynegy and the closure of three coal plants with about 4 GW of capacity. (See ERCOT OKs Luminant Coal Retirements.)

“The Dynegy situation is working out. It will be months and months before closing,” he said. Dynegy’s assets mean Vistra’s portfolio would now be participating in five markets (CAISO, ERCOT, MISO, PJM and SPP) instead of just Texas, Maselli noted.

“It will be dramatic change,” he said.

Maselli saw less drama in the retirements. “While retirements are something we had to announce, they’re not the end all, be all. I don’t think the world is cratering around a 1,500-MW reduction retirement,” he said, referring to ERCOT’s recent approval of two smaller coal plants.

The Texas grid has had record-low prices the last two years, and with ample resources to handle the latest retirements, the effect on prices could be relatively minimal.

“There hasn’t been significant scarcity pricing in the last six years. I’m very hopeful that after all the market reform we’ve endured since the unforgettable summer of 2011, that this summer will be a good dress rehearsal for scarcity pricing,” said Shell Energy’s Greg Thurnher.

“The most recent retirements moved the needle with respect to forwards, which I think was a very natural market response,” he said. “We have some faith that ERCOT will remove impediments from a transmission perspective, to make every megawatt deliverable from an economic perspective. If forwards are indicative of the price volatility we can anticipate next summer, then those who have fast and flexible resources will be tremendously rewarded.”

AEP Sees a Bright Future with Wind, Solar Energy

American Electric Power Executive Vice President Charles Patton recalled when his company merged with Central and South West in 2000, it resulted in the “largest coal burner in the Western Hemisphere,” with a fuel mix consisting of 90% coal.

Fast forward to today, when coal accounts for 47% of AEP’s fuel capacity and renewables make up 13%. The Ohio-based company has announced a $4.5 billion wind farm project in the Oklahoma Panhandle, and said during its most recent earnings call that it plans to add 8.4 GW of wind and solar by 2030.

“I will confess, there was a time I did not believe I would have publicly stated that you would be able to interject or intermingle renewables to the extent we’ve been able to,” said Patton, who is responsible for the corporation’s external affairs. “If you were a utility guy, that wasn’t something that you necessarily believed would be possible to the degree it is today. We see even more possibilities as we move toward the future, but you still have to get the regulators on board.”

Patton recalled when the renewable industry would intervene in AEP rate cases and ask the company to move faster.

“The reality is, when you’re a regulated utility, you’re not the one calling the shots,” he said.

Patton said AEP realizes the future of its remaining coal plants is “limited,” even after “we spent more money making them compliant with EPA standards than it took to build them in the first place.” Many of AEP’s units are scheduled to retire around 2040, he said.

And in their place?

“Everything we look at tells us wind and solar are good,” Patton said, referring to their prices. “They’re very good with [tax credits], they’re good without. With or without the tax credits, we see wind and solar in our future. We can put that $4.5 billion project into rate base and actually lower customer rates, because of the [credits].”

Actions in DC Creating Problems for Renewables

Participating on a panel discussing changing market fundamentals, Amy Francetic, senior vice president with generation and energy storage developer Invenergy, said a House Republican tax bill that would cut the wind production tax credit by more than a third only adds to instability in the market. (See GOP Tax Bill Would Trim PTC, Drop Credit for EVs.)

“The wind and solar industries had a deal that’s been agreed upon,” Francetic said. “We agreed upon a phaseout. The industry has spent the last year, meeting all the leaders in Congress. ‘Don’t worry, we had a deal. We won’t change it.’ Then lo and behold, the tax plan had a reduction in the PTC. … It sends a message to the industry and halts financing. There’s really no good reason for it.”

All is not lost, Francetic said, pointing to continued technological advances.

“What we have going for us is that physics is on our side. The physics of the equipment area is producing cheaper and cheaper prices. [The advancements] are not going to stop.”

Todd Glass, a partner with the California-based Wilson Sonsini Goodrich & Rosati law firm, agreed with Francetic, saying what is happening in D.C. isn’t helping the industry.

“We continue to design markets that allow for competition, price signals and innovation,” he said. “The deregulation craze that’s going on in the EPA is doing more damage in the long run than anything else.”

Besides, the markets are working, said Thomas McAndrew, a founder of Texas distributed energy provider Enchanted Rock. As evidence, he pointed to the Vistra plant retirements.

“ERCOT is shifting from the old model to the new model,” he said.

The Digital Grid of the Future

A panel of “out-of-the-box” thinkers took on how best to integrate renewables in a regulated industry that moves slower than the world around it.

“The entire structure enables the incumbents,” said Kerinia Cusick, cofounder of the Center for Renewables Integration. “At the same time, they’re hampered by a regulatory structure that requires them to go through a two-to-three process to approve any changes they want to make. But the technology’s already moved on. It’s already changed.

“It makes it hard to work in that environment. Our entire structure is one of who’s got the money to lobby, who’s on all these boards of directors and governance. A lot of the incumbents have been fat and happy, but they’re not so fat and happy right now.”

Sanjeev Addala, GE Renewable Energy’s chief digital officer, said renewable energy itself is “ripe for transformation.”

“We’re creating an economic digital system for the new industry,” Addala said. “How do we collect all the data and apply analytics to improve their performance? Next-level artificial intelligence is putting the computing resource at the wind-farm level, so you understand the forecast and the analytics right at the edge.

“In the future, the grid is going to become very autonomous,” he predicted. “Wind farms could become a self-loading system, with everything talking to each other.”

“I’ve heard all this hype about smart homes, but I wonder when the solar system on my roof will be smart enough to communicate with my home system,” said the Environmental Defense Fund’s Lenae Shirley. “That way, when a cloud passes over, I will be able to keep my demand flat. That’s why digitization is so important.

November 13, 2017

Wildfires Color California PUC Utility Decisions

By Jason Fordney

SAN FRANCISCO — Utilities are dealing with several wildfire-related proceedings at the California Public Utilities Commission, which is exploring taking a larger role in responding to natural disasters and emergencies.

CAISO PUCO Colorado Public Utilities Commission withholding — The CPUC passed a series of electric-related emergency measures for utility customers | © *RTO Insider*

The commission Nov. 9 unanimously approved a series of emergency protections for electric ratepayers affected by the wildfires, but it delayed until Nov. 30 a decision on whether San Diego Gas & Electric (SDG&E) will be a permitted to recover costs from fires occurring a decade ago.

Up to 30 separate fires raged in Northern California in October, prompting PUC President Michael Picker to discuss an increased role for the commission in responding to such events, such as sending out recovery teams to help residents.

“There seems to be more effective things we can do as people move into recovery,” Picker said. “I am curious to see whether we can institutionalize this in a more formal way.”

The commission’s decision requires utilities to waive deposits for residents re-establishing residential electric and gas service and stop billing homes that cannot receive service. It also disallowed disconnections for nonpayment and extended payment options, among other protections.

“It’s not as if this is the only catastrophe that we are going to have to respond to,” Picker added. “They are clearly increasing more in frequency and severity.” The PUC also heard about widespread loss of telephone service during the emergency because of power outages and structural damage.

“Acting quickly to protect consumers that have been affected by these tragic fires is very important,” said Commissioner Liane Randolph, highlighting the suspension of customer referrals to collection agencies.

Commissioner Martha Guzman-Aceves noted that utilities “are already acting on many of these under their own discretion,” and “it is one of those positive incidences where everyone is working towards the same end.”

Commissioner Carla Peterman suggested exploring a set of standard protections and memorandum accounts to track costs. She also thought protections for small businesses and institutions should be explored.

California Public Utilities Commission CPUC California Wildfires — Rechtschaffen | © *RTO Insider*

“These are quick responses — we may need to do much more,” Commissioner Clifford Rechtschaffen added.

At the meeting, the PUC also temporarily waived the regulatory requirement that Pacific Gas and Electric charge affected customers for electric service related to wildfires. The utility asked for permission to waive the cost of estimated installation and remove costs to provide temporary power. It will instead include the costs in a future application under its Catastrophic Event Memorandum Account.

PG&E Fights Wildfire Lawsuits

PG&E is already fending off legal action related to the most recent fires. The utility on Nov. 9 asked the Judicial Council of California for a stay of 15 lawsuits by residents regarding fires that occurred within 12 counties. The company said that preliminary investigation shows that one blaze, the Tubbs fire, could have been caused by utility equipment installed by a third party not named in the suits.

“Although plaintiffs have rushed to file complaints while the fires are still burning, the reality is that no one knows what caused any of the fires,” PG&E said. “For the fires that cause can be determined, the cause could be a variety of factors.”

It said the fires had many different locations, causes and damages.

“Plaintiffs’ effort to lump the fires together, both in their complaints and with respect to coordination, is an attempt to diminish their burden of proof with respect to causation,” PG&E said.

PG&E Files to Close Diablo Canyon

The commission is due to vote next month on whether to allow PG&E to retire the Diablo Canyon nuclear power plant in San Luis Obispo by 2025.

The PUC’s interim chief administrative law judge, Anne Simon, issued a proposed decision on Nov. 8 allowing the utility to retire the 2,240-MW plant and collect about $1.8 billion in costs from ratepayers. About $1.3 billion of that amount is to implement energy efficiency measures to replace the plant’s capacity.

PG&E first filed with the commission in August 2016 to retire the plant, submitting a proposed settlement between the utility, San Luis Obispo County, several local cities and environmental groups regarding the closing of the facility. (See PG&E Files Diablo Canyon Shutdown Request.)

The company proposes to close both units at the plant upon the expiration of their licenses: Nov. 2, 2024, for Unit 1 and Aug. 26, 2025, for Unit 2. The utility said there is less need for the plant because of new energy efficiency, distributed generation, renewable generation and customers moving to community choice aggregators and direct access.

“In fact, PG&E believes that the continued operation of Diablo Canyon beyond 2025 would exacerbate overgeneration, requiring curtailment of renewable generation,” Simon said in the decision. “PG&E’s analysis indicates that there is no need to replace Diablo Canyon in order to maintain system reliability.”

The proposed decision found that electricity procurement to replace the capacity should be obtained through the state’s integrated resource planning proceeding.

PG&E has requested approval to procure three tranches of greenhouse gas-free resources to partially replace the plant’s output; retention, retraining and severance for Diablo Canyon employees; and recovery of other costs.

November 13, 2017

MISO’s Plans for Wintertime Offer Caps Stalled by FERC

By Amanda Durish Cook

CARMEL, Ind. — FERC on Thursday rejected MISO’s Order 831 compliance filing just hours after the RTO told stakeholders it would head into winter with a $1,000/MWh soft cap and a $2,000/MWh hard cap on energy.

MISO FERC IRPs Conservation Law Foundation — Hansen | © *RTO Insider*

MISO’s changes were to go into effect Dec. 1, according to Markets System Analyst Chuck Hansen, who spoke at a Nov. 9 Market Subcommittee meeting before the FERC order was released later that day.

The commission ordered the RTO to make a new compliance filing within 60 days (ER17-1570).

Order 831, issued a year ago, required RTOs to cap energy offers at the higher of $1,000/MWh or a price based on Market Monitor-verified costs (soft cap), and to cap those cost-based offers at $2,000 (hard cap). While cost-based offers above the hard cap — or those above the soft cap but unable to be verified before the market clears — would be excluded from setting LMPs, generators making those offers would still be eligible for make-whole payments once their costs were verified (RM16-5). (See New FERC Rule Will Double RTO Offer Caps.)

However, FERC determined that MISO completely prohibited resources from submitting cost-based offers above the hard cap.

“Although Order No. 831 requires that such offers are prohibited from being used to set LMP, resources with verified costs exceeding $2,000/MWh must be eligible to recover costs above $2,000/MWh through uplift,” FERC said. “Although MISO proposes to increase the maximum incremental energy offer from $1,000/MWh to $2,000/MWh, there does not appear to be any mechanism, outside of proxy offers, that would allow a resource to make a cost-based incremental energy offer above $2,000/MWh. We therefore find that MISO has not met this requirement of Order No. 831.”

But based on Hansen’s statements at the subcommittee meeting, it appears the RTO did not foresee a problem with its filing.

“It’s possible that you can have costs even above $2,000/MWh and have those costs verified and be eligible for make-whole payments, but payments over $2,000/MWh will not be available to set price,” Hansen said.

Such offers will be verified by the Independent Market Monitor after market close, Hansen said. The Monitor will also continue to review generator energy offers above $1,000, he said, before they can be used to calculate LMPs. Hansen also said the processing of offers under $1,000 will remain unchanged in MISO’s market system.

MISO offer cap — MISO’s proposed offer cap process | *MISO*

Those statements are all in compliance with Order 831. In its ruling, however, the commission said MISO didn’t satisfactorily explain what factors would be considered when verifying offers, and whether those factors would be new to the RTO’s existing mitigation measures. MISO also failed to lay out a process for dispensing uplift payments when an offer in excess of $1,000/MWh is verified after market close or detail how a resource’s reference level may factor into that verification, although the RTO’s revisions suggested a relationship between reference level and uplift payment, FERC said.

Order 831 was a response to the 2014 polar vortex, in which a severe cold snap sent natural gas prices soaring. Many generators complained they were unable to recover their fuel costs because of grid operators’ hard $1,000/MWh offer caps.

Resource-Neutrality, External Transactions

The order also stipulated that offers be resource-neutral, and that external and virtual transactions also be capped at $2,000/MWh.

MISO’s market currently automatically blocks all offers above $1,000/MWh. The RTO’s new proposal was to block energy offers above $9,999/MWh from generators, Type I demand response resources and external asynchronous resources, as well as virtual offers and those from Type II DR r and price-sensitive demand resources above $2,000/MWh.

However, FERC found that MISO failed to show how its verification process applies to DR and that, with the exception of external asynchronous resources, the RTO was “silent with regard to import and export transactions or the requirement that external transactions be able to make offers up to $2,000/MWh without verification.”

For the last two winters, FERC has granted MISO a waiver of its $1,000/MWh offer cap for verifiable offers, although MISO has not needed to use it. (See MISO Granted Winter Waiver on Offer Cap.)

Other RTOs

Where MISO failed, other RTOs succeeded — mostly.

FERC found that NYISO (ER17-1561), PJM (ER17-1567) and SPP (ER15-1768) complied with its directives on bifurcating their offer caps and showed that their existing verification processes were sufficient and resource-neutral.

However, NYISO and PJM failed to specify that any price adders included in cost-based offers be limited to $100/MWh, another stipulation of Order 831. Such adders also can’t be recovered through uplift payments.

In PJM’s case, the RTO acknowledged this and laid out further revisions in an answer to a protest filed by its Independent Market Monitor.

In NYISO’s, FERC found the ISO also incorrectly included opportunity costs as an adder. As it explained in its clarification order, “verifiable opportunity costs should not be subject to the $100/MWh limit on adders above cost because opportunity costs are legitimate short-run marginal costs and not adders above cost.”

“NYISO’s proposal prevents resources from recovering opportunity costs through uplift when NYISO is unable to verify these costs before the close of the relevant market,” the commission said. “Accordingly, we direct NYISO to ensure that opportunity costs for bids exceeding $1,000/MWh are eligible for uplift, even if they are not verified before the close of the relevant market, if such costs are submitted as part of the resources’ bid, those costs were timely submitted and supported with documentation, and that those costs were verified by NYISO after-the-fact.”

PJM also failed to address external and virtual transactions — both of which have $2,700/MWh hard caps — in its filing, the commission found.

FERC directed PJM and NYISO to submit further compliance filings by Dec. 9. It accepted SPP’s revisions in full, with an effective date of April 1, 2019 — the day the RTO estimates it will launch its new settlement system software.

The commission itself, however, did not rule on ISO-NE’s compliance filing. Instead, its Office of Energy Market Regulation accepted the RTO’s changes under delegated authority (ER17-1565). This was because, unlike the other grid operators’ filings, no intervenors filed any comments or protests to ISO-NE’s.

The RTO was also granted an Oct. 1, 2019, effective date by staff. Like SPP, ISO-NE said this was needed to give it time to implement software changes necessary to comply. Unlike SPP, however, ISO-NE needs to start from scratch.

“ISO-NE anticipates that it will take approximately 18-24 months to design, develop, implement and fully test the necessary software and process changes to implement the Order 831 revisions,” it told FERC in its May compliance filing. “The requested effective date of Oct. 1, 2019, is aggressive and assumes that each phase of the implementation goes smoothly and is not delayed due to demands from competing priorities.”

CAISO in May asked FERC for an extension until May 1, 2018, to submit a proposal for implementing Order 831, saying it doesn’t currently have market mitigation measures in place to verify cost-based offers prior to market clearing. The commission has not yet ruled on that request.

MISO VoLL also Rejected

MISO’s plan to similarly raise the limit on its operating reserve demand curve was likewise rejected by FERC because of its reliance on the RTO’s offer cap revisions (ER17-1571).

“We agree with MISO that changes to MISO’s operating reserve demand curves may be necessary to accommodate the requirements of Order No. 831,” FERC wrote in its brief order. “However, because MISO’s proposal relies upon definitions and provisions that are not part of MISO’s effective Tariff, we reject this filing without prejudice to MISO submitting another filing as may be necessary to accommodate Tariff revisions made in its future compliance filing for Order No. 831.”

MISO was planning to maintain its $3,500/MWh cap on the value of lost load (VoLL) for the time being, with staff acknowledging that it still needs to conduct analyses to update it. This year, Market Monitor David Patton recommended that the cap be increased to almost $12,000/MWh to create a more sloped contingency reserve demand curve. (See MISO Board Hears State of the Market Recommendations.) MISO’s proposed curve is much flatter, hovering at $2,100/MWh unless the RTO clears less than 8% or more than 96% of its requirement level.

“In principle, we agree with potentially looking at the value of lost load, but we wanted to take some time, not rush into anything and get stakeholder input because this does impact prices,” MISO’s Hansen said.

Jeff Bladen, MISO executive director of market design, said the existing VoLL is a “historical artifact at this point.”

Michael Brooks, Michael Kuser and Robert Mullin contributed to this report.

November 13, 2017

FERC Rejects SPP Change on Network Resource Upgrades

By Rich Heidorn Jr.

FERC last week issued rulings in three SPP transmission cases, mostly siding with the RTO but rejecting its proposal to change the conditions for classifying service upgrade costs for designated resources.

SPP’s Tariff allows service upgrades associated with new or changed designated resources to be classified as base plan upgrades, subject to regional cost allocation, if the load-serving entity’s resulting capacity does not exceed 125% of its projected system peak responsibility.

SPP said its proposed wording changes clarify and update its rules and have “no practical or detrimental effect” on its study process.

The commission disagreed, saying the proposed Tariff language was inconsistent with SPP’s representation of how it calculates customers’ “highest hourly load” (ER17-1795).

It also took issue with the RTO’s plan to calculate “highest hourly load” on an aggregate basis for network customers with multiple service agreements that include the same designated resources. The commission said SPP had not proven that its proposal was not unduly discriminatory to customers with multiple agreements that do not include the same designated resources.

Z2 Waiver Upheld

The commission denied rehearing requests on its July 2016 order waiving the one-year limit for adjusting payment obligations and revenue distributions for transmission projects under Tariff Attachment Z2. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)

SPP FERC KEPCo upgrade costs — Member Coops | *Kansas Electric Power Cooperative*

FERC said the challengers — American Electric Power, Xcel Energy, Kansas Electric Power Cooperative (KEPCo) and Southern Co. — incorrectly applied the commission’s criteria for granting waivers (ER16-1341-001).

“Specifically, the arguments made on rehearing conflate the waiver’s scope (i.e., the provisions to be waived) with its potential consequences,” FERC said. “The parties on rehearing also ignore the waiver’s purpose because they assert that SPP must demonstrate that it will implement the crediting mechanism correctly before the waiver can be granted. The purpose of the waiver is to remove barriers to implementation. The process of implementation itself is beyond the scope of this proceeding.”

Split Decision in KEPCo Dispute

The commission partially granted KEPCo’s November 2016 complaint in a separate transmission dispute with SPP (EL17-21). The commission also denied some claims and set settlement judge procedures on others.

FERC rejected KEPCo’s allegation that SPP inappropriately directly assigned the cooperative $6.2 million in costs for network upgrades in violation of four network integration transmission service (NITS) agreements and the filed rate doctrine.

“Even though the NITS agreements did not list any network upgrades for which KEPCo would be directly assigned cost responsibility, KEPCo knew that … there may be possible Attachment Z2 revenue credit payment obligations and also that SPP was in the process of developing the [Crediting Process Task Force] white paper, with a methodology that would identify the network upgrades with more certainty,” the commission said.

FERC also rejected KEPCo’s claim that SPP’s allocation of upgrade costs was made too late under its Tariff. “To the extent SPP’s original analysis did not capture certain creditable upgrades, we also find it is reasonable to permit SPP to make corrections to the list of network upgrades so that upgrade sponsors are compensated for transmission service that their sponsored upgrades have facilitated, and which KEPCo has received,” it said.

SPP also prevailed on KEPCo’s claim that it violated the “but for” test in directly assigning costs for certain network upgrades.

The commission agreed with KEPCo that SPP had “improperly applied” its cost allocation rules in one instance but said the violation had no impact on the costs allocated to the cooperative.

Finally, FERC set hearing and settlement judge procedures to resolve whether KEPCo’s transmission service requests had a material impact on the Rice-Circle transmission project — a new Rice substation and an upgrade of the 28-mile line between it and the Circle substation to 230 kV from 115 kV.

“The specific issue is whether, according to a transfer distribution analysis, KEPCo’s transmission service requests cause at least a 3% impact on the Rice-Circle facility, and therefore, are considered to impact the facility and should be assigned costs for that facility,” the commission said.

— Tom Kleckner contributed to this article.

November 13, 2017

MISO Seeks to Gauge Risk of Peak Season Planned Outages

By Amanda Durish Cook

CARMEL, Ind. — Facing an increased number of outages from an aging fleet of baseload generators across the footprint, MISO officials are examining how they can capture the risk of planned and maintenance outages occurring during peak load.

maintenance outages miso peak load — Westphal | © *RTO Insider*

Ryan Westphal, MISO resource adequacy coordinator, said an investigation by the RTO’s Loss of Load Expectation Working Group suggests a need to account for intentional outages, but stakeholders have not yet reached consensus on how to proceed.

“Every year [since 2012], we saw some number of both planned and maintenance outages that happen on peak,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.

Westphal said MISO has looked into incorporating a combined average volume of planned and maintenance outages into its loss-of-load-expectation (LOLE) calculation, which would bump up the RTO’s predicted 17.1% planning reserve margin by about 0.4% in the 2018/19 planning year. The increase would lead to an additional 600 MW being cleared in this year’s capacity auction, MISO estimated.

MISO currently does not model any planned and maintenance outages at peak load, assuming such outages are optimized and not occurring during peak demand, but the RTO may want to revise its LOLE study to include the probability that some outages will occur during the peak, Westphal said.

“It leads us to think that all the risk isn’t being captured in our planning reserve margin today,” he said. Over the last several years, MISO has carried a sufficient reserve margin to cover outages that occur on peak, he added.

During July 2016, MISO experienced about 3.4 GW of planned outages and 1.8 GW of maintenance outages. The following month saw planned and forced outages of 2.4 GW and 4.2 GW, respectively. While those outages combined were nowhere near the volume of forced outages in the summer (12 GW in July, 10 GW in August), they helped nudge total outages above 16 GW during both months, a benchmark that was surpassed only once before in August 2015.

Duke Energy’s Brian Garnett asked how a maintenance outage occurs that’s not already planned or forced.

MISO defines maintenance outages as less severe mechanical issues that don’t result in an immediate outage trip but must be scheduled for repairs, Westphal said.

Indianapolis Power and Light’s Ted Leffler asked if the new calculation will be applied universally across the footprint or target individual units.

“I would caution that not every generation unit that has planned outages has load,” Leffler said.

Westphal said MISO would discuss the proposal again next month, and asked stakeholders to send written feedback before the Thanksgiving holiday.

November 13, 2017

MISO Stands by Load Forecast Confirmation Method

CARMEL, Ind. — MISO is defending its methods for validating utility load forecasts after Dynegy last month charged that Ameren Illinois miscalculated its summer peak load forecast.

Michael Robinson, MISO principal adviser of market design, said the RTO’s Tariff obligates it to draw a random sample of load-serving entity demand forecasts to “assess credibility” of the forecasts. For the LSEs selected for the sample, MISO performs an ex post review of their previous year’s forecast and works with them to reconcile differences between their forecasts and those produced by Purdue University’s State Utility Forecasting Group.

MISO FERC Dynegy summer peak Ameren — Left to right: Mike Robinson with RASC Chair Chris Plante and RASC liaison Shawn McFarlane | © *RTO Insider*

“Ameren was a draw in the random sample last year,” Robinson confirmed at a Nov. 8 Resource Adequacy Subcommittee meeting. “We did have to come back and ask them for additional documentation. Some of their documents were a bit sketchy, I guess, but they gave us everything we needed.”

Last month, Dynegy called on MISO to develop a new process for verifying load forecasts produced by LSEs, claiming Ameren’s forecasts led to under-procurement in the capacity auction for Zone 4. (See Dynegy: MISO LSE Load Forecasts Require Tune-up.)

MISO said it found no evidence of systemic bias in forecasts. Robinson said Zone 4 was slightly hotter than normal at coincident peak this summer and all local resource zones were within two standard errors of their forecast values.

“The way we design this is the LSEs are the experts in the sense that they know when customers are building. They certainly have more information than we do,” Robinson said. “We don’t forecast ourselves on the zonal level for the coincident peak. We don’t have that kind of information.”

— Amanda Durish Cook

November 13, 2017

Chatterjee to Push Interim ‘Lifeboat’ for Coal, Nukes

By Rich Heidorn Jr.

FERC Chairman Neil Chatterjee said last week he will seek an interim “lifeboat” to ensure the survival of struggling coal and nuclear plants while the commission ponders long-term rule changes.

FERC ISO-NE Cheryl LaFleur Neil Chatterjee — Chatterjee | © *RTO Insider*

He laid out his plans in remarks at an industry conference and in an interview Thursday on Bloomberg television.

Chatterjee has said the commission will take action by Dec. 11 on Energy Secretary Rick Perry’s call for “full recovery” of coal and nuclear plants’ costs in RTOs with energy and capacity markets, including PJM, ISO-NE and NYISO. More than 700 comments were filed in response to the Department of Energy’s Notice of Proposed Rulemaking (RM18-1). (See NOPR Backers, Foes Seek Last Word at Comment Deadline.)

In a meeting with reporters last month, Chatterjee said FERC’s options include initiating its own rulemaking, convening a technical conference or issuing a final rule based on DOE’s NOPR.

Now, facing legal and political obstacles to winning approval of a final rule, Chatterjee said he is seeking a short-term plan to rescue as many plants as possible while the commission does additional fact-finding.

“What I don’t want to have is plants shut down while we’re doing this longer-term analysis, so we need an interim step to keep them afloat,” Chatterjee told the S&P Global Platts Energy Podium in D.C. “I don’t know that we can get everybody in the lifeboat,” he added.

“My approach is going to be one of no regrets,” he said in the Bloomberg interview. “The worst-case scenario would be we do the long-term analysis, we figure out we actually did need these plants, but they’re gone. They’re offline and we can’t get them back.”

He said his plan will not alter RTO dispatch practices or distort markets.

Chatterjee also disclosed he had met with FirstEnergy CEO Chuck Jones “to really kick the tires on what they proposed [in their comments on the DOE NOPR] and challenge them on some of what they had put forward.” FERC’s ex parte rules, which bar commissioners from private discussions with parties in “case-specific, contested proceedings,” do not apply to rulemakings, according to a 2010 presentation by FERC Associate General Counsel Lawrence R. Greenfield (18 CFR 385.2201(a), (b), (c)(1)(ii)).

FirstEnergy proposed that the commission require RTOs and ISOs adopt a pro forma Resiliency Support Resource (RSR) tariff agreeing to make monthly payments to “fuel-secure, resilient generators.” The payments would be “equal to its full costs of operation and service” and a “and a fair return on equity,” minus its revenues for capacity, energy and ancillary services.

Chatterjee, a native of coal state Kentucky and a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), has made no secret of his desire to aid coal generators. Commissioners Robert Powelson, a Republican, and Cheryl LaFleur, a Democrat, have reacted more warily to the Perry proposal, expressing concern it could damage wholesale markets.

Republican Kevin McIntyre and Democrat Richard Glick, who were confirmed to FERC by the Senate on Nov. 2, are awaiting their swearing-in and have not commented publicly on the proposal. Chatterjee told Bloomberg that he had not discussed the NOPR or his interim proposal with McIntyre, who will replace him as chairman.

“Kevin is somebody with a lot of expertise. He’s a smart, thoughtful guy. … And I hope that he will ultimately be persuaded to follow the course that I’ve laid out,” Chatterjee said.

Perry’s Sept. 28 proposal requested that FERC issue a final rule within 60 days. But even if Chatterjee won the two additional votes he needs to approve a final rule in December, it could be vulnerable to court challenges on the grounds that it was rushed through without sufficient notice to the public and proper evaluation by the commission.

November 13, 2017

FERC to Examine DTE Reactive Rate Reduction

FERC last week opened a fresh settlement proceeding to determine the fairness of DTE Electric’s decreased revenue requirement for reactive power services, an issue already under scrutiny by the agency (ER17-2465).

DTE in April asked the commission to approve an $11 million annual revenue requirement for reactive supply in the ITC transmission pricing zone, down 14% from the current $13 million requirement (ER17-1414). The Detroit-based utility submitted the revised request in September to account for an additional $118,000 decrease stemming from the Nov. 14 retirement of St. Clair Unit 4, an aging coal-fired generator. The first request had been under settlement proceedings for four months by the time of the second filing (EL17-71).

FERC MISO revenue requirement DTE — St. Clair Power Plant | *Inland Mariners*

The company cited seven retirements, increased investments in generation units that provide reactive service, and the replacement of its total revenue requirement with unit-specific revenue requirements as reasons behind the rate decrease.

FERC said preliminary analysis shows that DTE’s rate schedule may still be unreasonable even with the $118,000 decrease, and consolidated the newly opened settlement proceeding with the existing one under a new docket, EL18-23.

“Because DTE Electric is proposing a rate reduction, but a further rate decrease may be appropriate, we will institute a Section 206 proceeding,” FERC wrote.

— Amanda Durish Cook