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December 27, 2024

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October Poses Little Challenge for MISO

By Amanda Durish Cook

MISO successfully managed an uneventful October that went from unseasonably warm to unusually chilly.

Demand peaked at 96.4 GW on Oct. 3 during an early month heat wave, while average load was 71.5 GW, up from 70 GW a year earlier. However, the average systemwide temperature was 3 degrees Fahrenheit lower than in October 2017. MISO did not call any maximum generation actions during the month.

Executive Director of Market Operations Shawn McFarlane told an Informational Forum on Nov. 15 that the month began with the RTO managing warmer-than-usual weather, though it quickly transitioned to cold weather. He remarked that it seemed like Indianapolis transitioned directly from winter to summer this year and said the inverse appeared to be happening for fall in the Midwest.

Energy prices in MISO averaged $30.67/MWh for the month, up 15% from October 2017’s average of $26.68. Day-ahead and real-time peaks averaged $38.58/MWh and $34.80/MWh, respectively, while off-peak averaged $27.54 and $26.62. The RTO said its natural gas prices increased 16% year over year to about $3.25/MMBtu.

MISO October RT dispatched fuel mix | MISO

In real time, the RTO on average dispatched a fuel mix consisting of 46.6% coal, 23.8% natural gas, 14.5% nuclear and 9.5% wind. The remainder came from dual-fuel units, solar, hydro and waste-to-energy. Wind output peaked at 14.6 GW, higher than last October’s peak of 14.1 GW.

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FERC Rejects Request for CAISO Capacity Market

By Hudson Sangree

FERC rejected a request to order CAISO to develop a capacity market to ensure traditional independent generators remain financially stable as renewable energy prices continue to fall and drive down wholesale electricity prices.

“As CAISO and several protesters correctly observe, the commission has not required a centralized capacity market as part of a just and reasonable market design,” the commission said in its Nov. 19 order (EL18-177). “Indeed, the commission has consistently rejected a one-size-fits-all approach to resource adequacy in the various RTOs/ISOs due, in large part, to significant differences between each region and also due to the well-established tenet that there can be more than one just and reasonable rate.”

The request was made by CXA La Paloma, the operator of a 1,124-MW gas-fired plant in Kern County, Calif., which began commercial operations in January 2003. It was acquired by its current owner in a bankruptcy proceeding in December 2017. When La Paloma filed for bankruptcy, it cited $524 million in debt and an “inhospitable regulatory environment.” (See CAISO Proposal Would Permit Economic Outages.)

FERC denied a complaint by CXA La Paloma, owner of a natural gas plant in Kern County, alleging CAISO had facilitated an unjust market by failing to develop centralized capacity procurement. | Kern County, California Public Health Services Department

In June 2016, prior to the bankruptcy, the plant’s then-owner, La Paloma Generating Co., filed a complaint with FERC over CAISO’s denial of a request for an outage for economic reasons. The commission rejected the complaint, finding the ISO had administered its Tariff properly when it denied the outage request.

In its complaint filed in June 2018, CXA La Paloma argued “that regulation of the wholesale power market in California is fragmented and compartmentalized, and that in failing to develop centralized capacity procurement, CAISO has facilitated an unduly discriminatory, unjust and unreasonable market design that is harmful to both market participants and ratepayers,” according to FERC.

But the commission cited a recent MISO case in which they rejected a mandatory centralized capacity market, “despite low capacity prices and concerns that the existing construct was failing to ensure the availability of generation needed for reliability.”

“The commission also recently accepted a proposal for a resource adequacy construct in SPP based on bilateral contracting,” it noted.

“While the commission has opined on the benefits of specific features of the eastern RTO/ISO centralized capacity markets within the context of those specific regions and market designs, the commission has not imposed a centralized capacity market in an RTO/ISO or found that it is the only just and reasonable resource adequacy construct to attract and retain sufficient capacity. With respect to the eastern RTOs, the capacity markets originated through Section 205 filings or developed through settlements.

“Thus, we find that CXA La Paloma’s reliance on commission precedent pertaining to the eastern centralized capacity markets is inapt here.”

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Connecticut Likely to OK Millstone for Zero-carbon RFP

By Michael Kuser

Dominion Energy has inched closer to the finish line in a two-year marathon to win state-subsidized energy contracts for its Millstone nuclear plant in Connecticut.

The state’s Public Utilities Regulatory Authority issued a draft decision Nov. 16 (Case 18-05-04) categorizing the 2,111-MW plant as “an existing resource at risk for retirement” without ratepayer support, which would allow it to qualify for special consideration in the state’s solicitation for up to 12 million MWh of zero-carbon electric power. Resources deemed to be at risk have their bids considered in terms of environmental and grid reliability benefits, as well as price.

Millstone’s retirement would not trigger need for new capacity in Connecticut, but it would for new generation capacity in New England as a whole. | Dominion Energy

The PURA said it will accept comments on the draft decision until Nov. 27, hear oral arguments at its headquarters on Dec. 21 and likely issue a final decision Jan. 2, 2019. The plant in Waterford, on Long Island Sound, supplies approximately 45% of the state’s electricity.

ClearView Energy Partners estimates a 75% probability that state regulators will include Millstone’s capacity in its zero-carbon procurements, likely limiting the award to no more than half the plant’s annual generation.

Ken Holt, Millstone’s communications manager, told RTO Insider that the PURA had been given access to the company’s confidential information, done its own analysis and concluded that Millstone is at risk. He said Dominion is now focused on the zero-carbon procurement by the state’s Department of Energy and Environmental Protection.

“We made numerous offers that would both ensure Millstone’s continued operations and provide benefits to Connecticut ratepayers ranging from the hundreds of millions of dollars to billions of dollars,” Holt said.

Gimme Shelter

Dominion has been following the lead of Exelon, which secured state subsidies for its nuclear plants in Illinois and New York after their profit margins started slipping in competition against low-priced natural gas.

Last year Dominion sought similar legislation in Connecticut, but the General Assembly failed to pass it, prompting Gov. Dannel Malloy that year to order both the DEEP and PURA to assess the viability of the Millstone plant and determine whether the state should provide financial support.

The agencies in January issued a report on the current and projected economic viability of Millstone and signaled support for state procurement of its output under a program reserved for renewable resources such as large-scale hydropower, wind and solar. (See Conn. Regulators Signal Support for Millstone.)

Given the record of opposition to that move by consumer groups and non-renewable resource owners, it is not clear what new information the PURA expects to hear between now and January to justify its decision.

Millstone reactor unit | Dominion Energy

The DEEP last month issued its final determination on six projects selected for its January request for proposals for Class I renewable energy sources, including one offshore wind project, one anaerobic digestion project, three fuel cell projects and one fuel cell project with combined heat and power.

According to the department, the selected projects total 254 MW and 1,285,360 MWh/year, equal to 4.7% of the state’s load, with a levelized 2018 constant dollar load-weighted average price of $80.04/MWh for energy plus renewable energy credits.

Winners among the approximately 100 projects that responded to Connecticut’s zero-carbon RFP must enter power purchase agreements with either of the state’s two leading utilities, Eversource Energy and United Illuminating.

Class Act

In written comments filed with the PURA last year, Eversource contended that Millstone is neither a Class I, II nor III renewable resource and “cannot simultaneously be a competitive merchant generator and receive state-sponsored financial support.” The utility argued that any financial remedy “should be based on cost-of-service principles with correspondingly limited returns on equity to reflect the reduction in risk resulting from Millstone’s receipt of state financial support that is unavailable to other non-renewable merchant generators.”

Under Connecticut’s renewable portfolio standard, Class I represents resources such as solar, wind, geothermal, biogas, sustainable biomass, and wave or tidal power, as well as run-of-river hydropower facilities not exceeding 30 MW in capacity. Class II resources include trash-to-energy facilities that have obtained required permits, while Class III covers customer-side CHP systems, electricity conservation and load management programs, and systems that recover waste heat or pressure from commercial and industrial processes.

Emissions Costs

The DEEP’s analysis showed that while Millstone’s retirement would not trigger a need for new capacity in Connecticut specifically, it would for new generation capacity in New England as a whole. Replacement capacity procured through ISO-NE would likely be gas-fired, exacerbating security and system reliability issues because of the region’s heavy reliance on gas for power generation.

If Millstone’s two units stopped operating, CO2 emissions for the entire New England electric sector would increase by 80 million short tons, or 25%, through 2035, according to the department. Replacing at least 25% of Millstone’s output with hydropower, demand reduction, energy storage and zero-emission renewable energy would be necessary for Connecticut to achieve its statutory greenhouse gas emissions-reduction targets, costing the state’s ratepayers an estimated $1.8 billion, the department said.

Even with that investment, regional emissions would increase by 20%. Replacing 100% of Millstone’s output with zero-carbon resources would cost Connecticut ratepayers approximately $5.5 billion, the DEEP said.

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Stressed in US, Capacity Markets Come to Ontario, Alberta

By Rich Heidorn Jr.

TORONTO — Ontario and Alberta are developing capacity markets even as those in the U.S. face increasing stress from subsidized resources and growing resistance from states and public power.

The Alberta Electric System Operator (AESO) plans to add a capacity market in 2019, with the first contracts awarded in 2020 or 2021. (See related story, “Alberta also Adding Capacity Market,” Overheard at APPrO 2018.)

Ontario’s Independent Electricity System Operator (IESO) is developing an incremental capacity auction as part of its “Market Renewal” project, which also includes moving to a single pricing schedule, launching a day-ahead market and improving real-time commitments.

IESO says the Market Renewal program, which was announced in 2016, is “the most significant suite of reforms” since Canada’s largest province introduced competitive wholesale markets in 2002 and will produce at least $3.4 billion ($2.6 billion USD) in savings over 10 years.

Ontario has used a mix of regulated and contracted resources to meet its system adequacy needs and to eliminate coal-fired generation and add renewables. But that “approach did not always ensure that capacity was procured most cost effectively, that excess capacity was not procured, and that opportunities existed for innovative and emerging technologies,” IESO acknowledges.

The capacity market, with the first auction expected in 2023, will reduce costs by getting more competition for future resources, IESO says.

Political Shift

High electric rates were a major issue in last June’s provincial elections, when the Progressive Conservative party ended 15 years of Liberal party control. Ontario’s electricity rates, the highest in Canada, rose four times as fast as inflation between 2006 and 2017. After rate reductions in 2017, Ontario’s time-of-use rates now range from 6.5 cents/kWh for off-peak to 13.2 cents/kWh for on-peak.

To fund the renewable contracts under the Green Energy Act, and the costs of conservation programs, gas capacity expansions and nuclear power refurbishments, the province added a Global Adjustment surcharge, which rose from 1 cent/kWh in 2008 to about 10 cents in 2017.

Since taking office June 29, the new government has:

Forced the resignations of the board and CEO of Hydro One, the province’s transmission and distribution utility, which the party accused of waste and mismanagement. The Hydro One Accountability Act, introduced in July, requires a new compensation scheme for executives, the board and the CEO. The previous CEO was nicknamed the “$6 Million Man” for his salary.

Introduced legislation in September to repeal the 2009 Green Energy Act, which provided feed-in tariffs to expand renewable energy, encourage conservation and create clean energy jobs. Critics said it caused an increase in electricity costs as the province overpaid for power it didn’t need. The new government also canceled 758 renewable energy contracts totaling $790 million ($600 million USD) over 20 years and declared a moratorium on new contracts.

Canceled Ontario’s carbon tax and cap-and-trade program and prohibited trading of emission allowances.

Still on the government’s to-do list are promises to cut electric rates by 12% for “families, farmers and small businesses” and “aggressive reforms” to “stabilize” industrial electric rates.

Mike Richmond, co-chair of McMillan LLP’s Power and Energy Law Group, displayed the Conservatives’ energy plan on a single PowerPoint slide during a presentation at the Association of Power Producers of Ontario’s 30th annual conference last week.

“It’s not a complicated plan. That means there’s not a lot of wiggle room to do anything but this,” Richmond said. “In fairness, in less than four months, they’ve already done most of it.”

The new energy minister, Greg Rickford, told the conference that his party is committed to lowering high prices that he said had resulted in a “devastating exodus of jobs” during the Liberals’ control.

Rickford said the canceling of renewable generation projects was not an attempt to “put renewables out of business.”

“It simply suggests that we’re looking, in typical Tory pragmatic fashion, [for] solutions that work for families and … businesses.

“Moving forward, we’re evaluating and reassessing the structure of energy in the province — the system from regulation to procurement and all points in between — in an effort to drive [electric] costs down.”

Is Capacity Market the Answer?

Rickford said he was confident that IESO’s Market Renewal initiative and its incremental capacity auction will lower costs and increase efficiency. “We believe that because other jurisdictions have used capacity markets with much success,” he said.

Not everyone at the conference was so sure.

“I think people in the sector are — I’m not sure I’d use the word ‘skeptical’ — but questioning whether in fact that is the right answer to the kind of electricity system we’re likely to see in the future,” said APPrO President David Butters, who said the auction is unlikely to attract new generation. “It might be an opportunity to extend existing facilities, but there are contractual issues around that have to be considered. But it is probably worthwhile going in that direction, if only to get some experience.”

IESO is planning a forward period of three and a half years (although the first auctions may contract one or two years in advance). It will seek one-year commitments for existing resources (six months for seasonal resources) and multiyear commitments for new resources.

In September, IESO released projections showing it may have a capacity shortfall of 1,400 MW during winter and summer peaks beginning in 2023. The shortfalls could rise to 3,700 MW in 2025 before plateauing at 2,000 MW through 2030, when the province expects to have all its nuclear capacity operating again following refurbishment projects. Butters said the projections assume continued use of existing resources whose current contracts will expire, particularly in the late 2020s. IESO, he says, must address the gap “without delay.”

But IESO CEO Peter Gregg told the conference the grid operator won’t decide until the end of 2019 whether it needs to act to address the gap.

Barbara Ellard, IESO’s director of markets and procurement, said Market Renewal is an acknowledgment that the grid operator needs different products and services to maintain reliability into the future.

“Market Renewal is really only the first step to get us there. It is about building a better foundation. And a lot of Market Renewal is about price, obviously,” she said.

In September, the grid operator released its high-level design for the single schedule market, which will introduce locational energy prices, and is intended to align pricing and dispatch, reduce the need for out-of-market payments and enable the launch of a day-ahead market.

IESO currently uses an “unconstrained schedule” to set a single price across the province for every five minutes, which does not account for actual system conditions and operational constraints. To ensure reliability, it runs a separate dispatch schedule that selects units based on system conditions.

“Our energy market has many, many flaws,” Ellard acknowledged. “We’re not right-sized. We often have too much generation on or we have too little generation on as we get into real time. We don’t have the right price signals that make sure that we get those right resources operating at the right time.

“On the capacity side … we are looking to make sure we only procure … capacity that we need.”

Judy Chang of The Brattle Group, which IESO hired to produce a cost-benefit analysis for Market Renewal, said there is a limit to what Ontario can learn from more mature markets. “We can’t just think about what’s been done already in other markets. We really have to build a foundation in a way that’s adaptable to the future,” she said.

Limit to Grid Defection?

One audience member suggested that with electric production becoming more decentralized with microgrids and behind-the-meter generation, IESO was pursuing a solution that “seems more appropriate for 2002.”

“We do not foresee a future any time near where there isn’t a wholesale need,” Ellard responded. “We are decentralizing, [but] I think some of the modeling that’s going to come out is going to show there will be a natural limit to this concept of grid defection. So, from a system operator perspective, whether it is a 10,000-[MW] demand or a 30,000-[MW] demand, we need to figure out how to meet that demand.”

In a panel discussion on regulation, speakers criticized both IESO and the Ontario Energy Board, which regulates electric transmission and distribution, and nuclear and baseload hydropower generation.

Attorney George Vegh, the head of McCarthy Tetrault’s energy practice, said IESO should face a “reckoning” for its inefficiencies.

“Before we jump in and say we know all the solutions, let’s find out what the problems were,” said Vegh, former general counsel of the OEB.

“There are some hard questions that we should be asking ourselves. If you look at operational efficiency in particular … someone should be asking the question: ‘Why was this not the IESO’s day job over the last 15 years?’ The things that we’re talking about — single-schedule market or day-ahead market — these have been on the agenda for over 10 years.”

Ontario Energy Board’s Role

Vegh said OEB also has a role in creating a favorable climate for generation investments.

“Investment in long-term assets requires confidence that government will keep its commitments. What makes it credible is constraints and checks and balances.”

OEB “hasn’t played any role at all,” Vegh said. “There has been no oversight. A lot of these decisions were very uneconomic.”

Vegh said the OEB should be challenging the assumptions behind IESO’s load forecast and reserve requirements.

“All of these things should be looked at much more transparently in a much more open process with the ability to test some of these assumptions instead of just being told: ‘Oh, we might have a capacity gap, but we might not.’

“What are the resources that might be available to meet that gap and how should they be evaluated? There’s no clear criteria for any of that. We’re just told, ‘Don’t worry, we can change some reserve requirements. We can tweak this and tweak that.’ I don’t think that’s good enough. I think that what we need to do is to have much more independent oversight around these assumptions for planning and the assumptions for procurement.”

Minister Rickford also called for ways to “strengthen transparency and trust” in the OEB. “This regulator has not had a significant examination for many years. It is in need, in some respect, of a modernization,” he said.

Brian Rivard, director of research at the Ivey Energy Policy and Management Centre, also called for expanded oversight of IESO.

“The onus should be on the IESO to put forth changes … to the market rules or changes to the market design and prove that it has to do so because there are inefficiencies in the sector, that the remedy it’s proposing will correct those inefficiencies and, thirdly, that [in] doing so, the benefits that will be achieved … [outweigh] the costs. The OEB’s there to allow for a transparent review of that.”

A.J. Goulding, president of London Economics, lamented that “there’s been some chipping away at OEB oversight” in the past decade.

He said OEB’s job will become increasingly challenging “as we start thinking about things like … connection charges, an interconnectivity standard across distribution utilities … thinking about whether we need to … extend the principle of open access down to the distribution level.”

Role of Energy Ministry

At the same time, Goulding said, the energy ministry should resist temptations to micromanage IESO.

“To me the IESO is the appropriate place for planning for the sector. The ministry’s job is policy,” he said. “We also need to stop over-planning. Ultimately, if we believe in the incremental capacity mechanism, then we need to let it do its job. We need to make sure that it is technology-neutral and let the market drive choices for future optimization.”

APPrO’s Butters said he had three words of advice for government. “Leave us alone,” he said. “Actually, four words: please,” he added, drawing laughter.

“Very Canadian,” chuckled moderator Linda Bertoldi, chair of Borden Ladner Gervais’ National Electricity Markets Group.

“We’ve got a really good system. We have invested a lot of money in making it reliable and making it cleaner, and there’s a cost to that,” Butters said. “Let’s not make short-term decisions that will have longer-term consequences.”

Jason Chee-Aloy, managing director at consulting firm Power Advisory, said Ontario “lacks the environment for merchant investment” because of the dearth of bilateral contracting, market rules that don’t value flexible generation and excessive regulatory risk and government intervention.

“FERC isn’t the end-all and be-all in the U.S. But it is an independent body that issues orders. It doesn’t always agree with the system operator. Sometimes it sides with customers; sometimes it sides with producers. We don’t have that here. So, I think that weak governance is going to affect how we make decisions on investments.”

Brattle’s Chang said the U.S. regulatory system is no panacea, noting that her home state of Massachusetts is impacting wholesale markets by signing long-term supply contracts. “The fights between the states and the federal [government] is not something that I would hope for anybody else to have to deal with,” she said.

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Camp Fire Prompts Talk of PG&E Bailout or Breakup

By Hudson Sangree

President Trump and California Gov. Jerry Brown toured the scene of the Camp Fire on Saturday, Nov. 17. Trump called it “total devastation.” | California Governor’s Office

California’s deadliest and most destructive wildfire has set off a new round of turmoil in the state’s utility sector, with wildly swinging stock prices and questions about what policymakers will — or won’t — do to protect the state’s investor-owned utilities from fire liability.

As of Monday, the Camp Fire in the Sierra Nevada foothills of Butte County has killed at least 77 people, with 1,000 still missing. It has destroyed more than 10,000 homes and burned 150,000 acres, including nearly the entire town of Paradise, which until 10 days ago had 27,000 residents. Thousands who survived are holed up in shelters, tents and RVs, with winter on the way. Many are waiting for word on friends and family members lost in the fire.

Gov. Jerry Brown called the Camp Fire “probably the worst tragedy that California has ever faced, at least from a fire situation,” after touring the post-apocalyptic scene in Paradise with President Trump on Saturday. In a joint press conference with Brown, Trump described the scene of an entire town turned to ash as “total devastation.”

Picker Addresses PG&E’s Woes

After the fire started, San Francisco-based Pacific Gas and Electric watched its stock price plummet from roughly $48/share to less than $18/share — a 62.5% drop in one week. Suspicion quickly fell on the investor-owned utility for starting the fire. (See Destructive Fires Drive Down PG&E Stock.)

Southern California Edison faced similar scrutiny, and a big drop in stock price, for the Woolsey Fire, which killed three and destroyed 1,500 structures in Ventura and Los Angeles counties this month. In addition, SCE recently admitted its equipment may have caused last year’s Thomas Fire near Santa Barbara, one of the largest fires in state history. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)

The Woolsey and Camp fires began the same day, Nov. 8.

That day, PG&E filed a report with the California Public Utilities Commission, saying it had experienced an outage on a 115-kV line and observed damage to a transmission tower near the Camp Fire ignition point. The company later wrote in a news release that the “information provided in this report is preliminary, and PG&E will fully cooperate with any investigations. There has been no determination on the causes of the Camp Fire.”

A week later the company informed the PUC that it had experienced a second outage on 12-kV line in Concow, near Paradise, on the morning of Nov. 8, and the California Department of Forestry and Fire Protection identified a second possible second ignition source for the Camp Fire.

The news sent PG&E’s share price crashing, but the utility’s stock rallied on Thursday after CPUC President Michael Picker took part in a call with Wall Street analysts in which he said allowing PG&E to go bankrupt wouldn’t be good public policy, Bloomberg and other media outlets reported.

Picker reiterated those comments in at least two newspaper interviews and discussed the possibility of legislative action to relieve PG&E’s financial burden.

The PUC president also said, however, that he was concerned about PG&E’s lack of accountability. He told The Wall Street Journal that breaking up the company might be an option for regulators to consider. In a news release, Picker said he intended to expand an ongoing investigation into PG&E’s “safety culture” that the commission had opened after the San Bruno gas line explosion in 2010.

“In the existing PG&E safety culture investigation proceeding,” Picker said in the statement, “I will open a new phase examining the corporate governance, structure and operation of PG&E, including in light of the recent wildfires, to determine the best path forward for Northern Californians to receive safe electrical and gas service in the future.”

PG&E’s stock rose back to around $24/share Friday after Picker’s comments and stood at about $22/share on Monday — less than half of what it was before the Camp Fire started.

In an interview with The Sacramento Bee, Picker said he didn’t think PG&E was headed toward bankruptcy, as some speculate. He said the company’s woes are “a small slice of a bigger shit pie. That’s a technical term.”

“What is California doing about wildfires?” Picker told the Bee. He called climate change a major unanswered issue, and said, “We have to have other solutions.”

Picker did not respond to a request for comment from RTO Insider.

Smoke from the Camp Fire covered the San Francisco Bay Area and the Sacramento Valley for more than a week, providing a potent reminder of the disaster to the north. | NASA Earth Observatory

What will Lawmakers Do?

The Camp Fire has revived talk of PG&E’s safety failings and financial liabilities — and what state policymakers might do to deal with both problems.

The company’s financial fate became the subject of concern following a series of devastating wildfires in 2017. State fire investigators have said PG&E was responsible for at least 17 of the 21 blazes. An investigation by Cal Fire has not yet determined the cause of the worst of the 2017 fires: the Tubbs Fire, which wiped out a large part of the city of Santa Rosa, Calif., killing 22 and destroying 5,643 structures in October 2017. Until the Camp Fire, it was the most destructive in state history.

The 2017 fires could subject PG&E to billions of dollars in liability under California’s unique system of holding utilities strictly liable for all damage caused by power lines and equipment, regardless of negligence. (Citigroup estimated PG&E could face $15 billion in liability for the 2017 fires and another $15 billion for the Camp Fire, The New York Times reported.)

Earlier this year Brown proposed doing away with the strict-liability standard, known as inverse condemnation, arguing it threatened electric reliability and the state’s efforts to completely exclude carbon emissions from its power grid by the middle of the century.

Lawmakers tasked with formulating a major wildfire bill, SB 901, ultimately left inverse condemnation intact while creating a method by which utilities could issue long-term bonds to pay for some fire damage. (See California Wildfire Bill Goes to Governor.)

Critics protested the bill as a bailout for utilities, but Brown signed the legislation in September.

PG&E executives recently said in an earnings call that the new law was insufficient, and they intend to seek an end to inverse condemnation through the courts and legislature. (See PG&E Outlines Fire Strategy in Earnings Call.) That was before the Camp Fire, however, and the anti-utility political backlash it might well create.

In the meantime, SB 901 provides some relief for PG&E for the 2017 fires. It established a financial stress test that would allow IOUs to be held liable for the 2017 wildfires but only to the extent that the costs do not harm ratepayers or materially impact a utility’s “ability to provide safe and adequate service.” The bill also provides for bond issuance starting in 2019, but the new law left utilities completely exposed to financial liability for 2018 fires.

Picker and others have said the situation likely could be addressed through clean-up legislation that includes the 2018 fires within the scope of SB 901.

Others, however, have called for more aggressive action toward PG&E when the State Legislature reconvenes Dec. 3. Lawmakers could call a special session to deal with IOU wildfire liability, potentially speeding up the lawmaking process.

State Sen. Jerry Hill, a Silicon Valley Democrat and a harsh critic of the utility, told the Los Angeles Times he’s interested in legislation that could break up PG&E and sell off its pieces to local governments.

“Many have argued that PG&E is too big to fail,” Hill said. “I think it’s too big to succeed.”

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NETL Repeats Doubts over PJM Bomb Cyclone Performance

By Rory D. Sweeney

In the latest salvo in an ongoing statistical squabble, the National Energy Technology Laboratory last week accused PJM of providing misleading analysis of its resource availability during last winter’s “bomb cyclone.”

NETL in March published its own analysis of the importance of coal-fired generation during the 13-day cold snap and found that in PJM “demand could not have been met without coal” and “it was primarily coal that responded resiliently, with some contribution from oil-firing units.”

Across the six RTOs/ISOs analyzed, the lab found that “coal provided 55% of the incremental daily generation needed” and “fossil and nuclear energy plants provided 89% of electricity during peak demand.”

Pleasants Power Station is a coal-fired plant in West Virginia.

NETL, which is organized under the Department of Energy’s Office of Fossil Energy and can trace its roots to a coal-mining research facility established in 1910, said that coal generation increased by approximately 30,000 MW to roughly 50,800 MW per day during the storm. It argued that a “lack of sufficient natural gas pipeline infrastructure” caused price spikes and fuel unavailability as gas demand for home heating surged during the cold spell.

That analysis prompted PJM to publish a response in which it said unused gas generation was available throughout the event, but that coal units were cheaper during some periods.

“This is a ‘good news’ story for coal resources from an economic viewpoint, but the fact that additional coal resources were dispatched due to economics is not a basis to conclude that natural gas resources were not available to meet PJM system demands or that without the coal resources during this period the PJM grid would have faced ‘shortfalls leading to interconnect-wide blackouts,’” the RTO wrote, taking issue with some of NETL’s conclusions.

Reserves exceeded 23% of peak load demand, “and there were few units that were unable to obtain natural gas transportation, even for most units that relied only on interruptible service,” the RTO said.

Regarding the lab’s characterization of coal units that came online “suddenly” during the cold weather, PJM said that 57% of coal generation was self-scheduled and 41% was scheduled based on economic offers.

For the peak day of Jan. 5, PJM said that 28,883 MW of gas generation was available and “mechanically able to operate but may not be scheduled based on economics.”

“While a unit may be ‘mechanically able to operate,’ this is no indication of whether the output of that unit would be deliverable to serve load,” the RTO said.

In April, PJM unveiled a three-phase plan to value fuel security in its markets, and on Nov. 1 it released the summary of a “stress test” study indicating the RTO should develop a market mechanism to compensate fuel security. (See PJM Begins Campaign for ‘Fuel Security’ Payments.)

NETL Response

But NETL responded Nov. 7 that PJM’s analysis of its performance remains flawed for several reasons. Among them, the lab said aggregation of available resources at the RTO level was inappropriate because it didn’t account for pipeline and transmission constraints.

“Total reserves were likely more than adequate in the aggregate; however, considering gas limitations and forced outages, functional and truly operable reserves were likely significantly less, on the order of half or less that of the reported reserves,” NETL wrote. “There was only 601 MW of idle fuel secure generation within the entire footprint at peak, with the balance providing some level of service to the system.”

Additionally, gas price spikes made it not only uncompetitive with coal but a lesser alternative to fuel oil, usage of which increased 455% during the bomb cyclone to 111 GWh, NETL said.

“For the last several days of the bomb cyclone, natural gas prices exceeded $20/MMBtu, allowing oil generation to displace gas-fired generation at a price equal to seven times the early December 2017 average PJM natural gas price for generation.”

PJM Reaction

But PJM stood by its original analysis.

“NETL seems to take PJM to task for not relying more on coal. However, NETL continues to erroneously conclude that the relative economics of coal and nuclear vs. natural gas during the cold snap, which drove the dispatch of coal units, indicates that the system would have faced shortfalls leading to interconnect-wide blackouts,” PJM wrote in an email to RTO Insider.

“PJM had adequate amounts of resources to supply power — the price of natural gas relative to coal and nuclear during the cold snap drove the dispatch decisions. … Our analysis of the cold snap showed that, with excellent coordination and cooperation with our members, the grid in the PJM footprint is diverse and strong and remains reliable.”

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Advocacy Group Seeks CFTC Oversight of PJM FTRs

By Rory D. Sweeney

A public advocacy group is urging the Commodity Futures Trading Commission to start overseeing PJM’s embattled financial transmission rights market after a massive default that could saddle stakeholders with more than $180 million in costs.

Tyson Slocum, director of Public Citizen’s Energy Program, believes PJM’s embattled FTR market needs additional federal oversight. | © RTO Insider

Public Citizen Energy Program Director Tyson Slocum made the request both in a letter to CFTC Chairman J. Christopher Giancarlo and a filing in the docket of a DC Energy complaint before FERC seeking immediate changes to PJM’s credit requirement (EL18-170).

In the complaint, DC Energy seeks to fast-track changes to PJM’s FTR credit policy to forestall what has become a historic portfolio default by GreenHat Energy, causing substantial tension between the RTO and its stakeholders and prompting an investigation by its Board of Managers. (See “GreenHat Default Update,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

On Sept. 25, FERC accepted a PJM filing to impose a 10-cent/MWh minimum monthly requirement on FTR portfolios (ER18-2090) and established a paper hearing in the complaint “to determine whether the Tariff is unjust and unreasonable even with PJM’s new Tariff revision in place.” Comments on the hearing were due Nov. 9.

CFTC Exemption

Slocum argues that CFTC’s 2013 decision to exempt FTRs from its jurisdiction was made on the condition that it could “suspend, terminate or otherwise modify or restrict” its order as conditions warranted. GreenHat’s default coupled with PJM’s subsequent handling and FERC’s inaction means CFTC must get involved, according to Slocum.

“It appears PJM’s catastrophic failure to properly oversee its FTR market, combined with PJM’s misrepresentation of key facts in its [request for the CFTC exemption], should result in the CFTC suspending the exemption it granted,” he wrote. “Furthermore, FERC’s refusal to take minimum steps to assert regulatory control over the situation forces Public Citizen to conclude that only the CFTC is in a position to protect consumers from abuses in FTR markets going forward.”

Calling PJM’s staff “incompetent” and “clearly unprepared and overmatched” to handle FTRs, Slocum said any FERC effort to revise credit requirements “will be meaningless” under PJM’s “lax” oversight, which is “by design.” He noted several examples of what critics have seen as PJM’s mishandling of the situation, including failing to increase credit requirements and apparent bungling attempts to seek additional collateral from GreenHat.

Slocum said the conditions of the CFTC exemption appear to have been broken on several counts. First, Public Citizen could find no clear evidence that PJM’s Independent Market Monitor was “directly involved” in the negotiations seeking additional collateral as CFTC’s order requires. Additionally, GreenHat was purely a financial trader that could not be categorized as among the “commercial participants that are in the business of generating, transmitting and distributing electric energy” that the exemption allows.

No Transparency

Slocum also pointed out that while companies seeking to participate in PJM’s competitive energy markets must seek FERC approval to do so and subject themselves to public scrutiny and comment, FTR market participants need only register with the RTO.

“PJM does not offer public notice and comment of FTR applications, and it does not condition their approval by first offering the public an opportunity to inspect the applications,” he wrote. “Had Greenhat been required to submit its ownership structure to public notice and comment at FERC, then groups like Public Citizen would have had an opportunity to raise serious concerns about a firm owned by two former JP Morgan traders directly implicated in one of the most brazen market manipulation schemes in history obtaining authorization to trade FTRs.” (See GreenHat: (Some of) the Rest of the Story.)

Slocum noted that another former trader in PJM’s FTR markets, Tokamak Energy Partners, was founded by the head of power trading for Deutsche Bank during the period the company was caught manipulating the California power market.

“Who knows how many frauds and market manipulators have set up shop to trade FTRs. FERC doesn’t know, because FERC effectively has ceded regulatory jurisdiction to PJM, and PJM operates its FTR market with little to no public transparency,” he wrote.

A PJM spokesperson confirmed that the RTO will be filing a response to the Public Citizen complaint, but the content of that response has not been finalized.

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Overheard at APPrO 2018

By Rich Heidorn Jr.

TORONTO — The Association of Power Producers of Ontario’s annual conference attracted about 300 people last week, a sharp drop from past years, when more than 500 attended.

But things are looking up, APPrO President Dave Butters told the gathering. After “a couple of difficult years” in which the group cut its office space in half to save $50,000 annually, he said the group collected a record $830,000 in membership revenue in 2018.

Butters said the group may consider a name change under a business plan it will unveil in about a month to broaden its membership. “We want to be an organization that is broader and wider than just centralized generation,” he said. “We see [distributed energy resources], storage — all these things are potentially opportunities.”

Here are some of the highlights of what we heard.

Alberta also Adding Capacity Market

The Alberta Electric System Operator (AESO) plans to add a capacity auction to its energy-only market in late 2019, with the market operational by 2021. AESO said it is making the change to improve reliability, increase price stability, give generators greater revenue certainty and allow market forces to drive innovation and cost discipline.

AESO has proposed a one-year term for its capacity market, although that could change, said Evan Bahry, executive director of the Independent Power Producers Society of Alberta (IPPSA).

Bahry said Alberta’s market is being challenged by the province’s plan to eliminate coal-fired generation and add 5,000 MW of renewables by 2030. “We’re a thermal market, reliant on coal and natural gas historically; very little hydro,” he said.

The industry also must deal with “a lot of agencies in our marketplace, all of which have their own independent mandates,” he said.

“We in our business make 20-, 30-year investments. Billions of dollars are required to replace retiring assets and to meet future load growth. This requires coherence, requires stability,” Bahry said. “We’re [seeing] greater change … now than we’ve seen in the last 20 years. That’s a lot for investors to digest.”

Harsh Critique from TransAlta Boss

Dawn Farrell, CEO of Calgary-based TransAlta, offered a harsh critique of policymakers and customers.

Of consumers: “They want electricity to be cheap. They don’t want it to be affordable, and they don’t want it to be reasonably priced. They want it cheap. They’ll pay a lot of money for cable, they’ll pay a lot of money for their phones and data streaming and for movies.

Of Alberta’s market: “The new market in Alberta has 500 rules. That’s not a market. Markets don’t have 500 rules.”

She said policymakers should take a lesson from the large regional transmission grids in the U.S. “Electricity flows wherever it wants to flow, and you get the benefits of the economies of scale there. And they get the benefits of the different resources in the different jurisdictions. You think about Canada and for some reason there’s these invisible lines in between the provinces, which are just political constructs.”

She said the failure to take advantage of transmission dooms innovative ideas, such as the proposed pump storage project at TransAlta’s 355-MW Brazeau hydroelectric plant. “It’s too big for Alberta. … It would be great for Alberta and Saskatchewan.”

“As a country,” she lamented, “we do not have our best interests at heart. We do not think about competitiveness.”

New England Faces Another Tight Winter

Robert Ethier, vice president of market operations for ISO-NE, discussed the RTO’s challenges with insufficient winter gas supplies and states’ reluctance to allow new pipelines or transmission. Asked about a proposed transmission line from Quebec’s hydro resources, he said, “We’d love to have it.”

He noted the RTO is seeking a reliability-must-run designation for Exelon’s Mystic generating station, which has access to LNG storage. The proposal, which is pending before FERC, “has not gone over very well in New England,” he said. “It’s going to be very expensive.” (See FERC Advances Mystic Cost-of-Service Agreement.)

He said the RTO is “trying to strike a balance” in shifting to renewables, noting that solar generation, with a capacity factor of less than 5%, “doesn’t help at all” in meeting winter needs.

“Our system is not ready to have these old coal and oil units retire,” he said.

Dan Dolan, president of the New England Power Generators Association, said that although gas prices spiked during last January’s deep freeze, the “system … worked.”

“In the face of the longest, deepest cold snap in over 100 years, with tremendous outages due to transmission line failures, we didn’t have a single reliability shortfall. And we saw tremendous responses in investment and performance from the generators on the system optimizing the fuel infrastructure that does exist,” Dolan said.

He said he was concerned about the market providing enough revenue to prevent the retirement of coal and oil generators needed during winter peaks. He said state-contracted resources are projected to grow from the current 17% of the market today to 60% within a decade.

“The question is, is the existing market design sufficient to maintain this half-pregnant status of a tremendous portion of the market being merchant with the rest of the market … made up of resources that are indifferent to that market price? And I would argue that the answer is no, on both the energy and capacity end.”

Storage vs. Peakers

It’s a question that comes up often at energy conferences: When will storage be versatile and cheap enough to compete with natural gas peakers?

Not soon in the frozen north, speakers said. Despite declining prices, solar/storage combinations cannot help New England in winter, Dolan said. “It’s awfully hard for solar to perform when it’s under a foot and a half of snow,” he said, adding that current battery storage can only fill gaps for hours, not days.

Bahry said storage will struggle to compete as long as natural gas prices remain cheap. “If we’re dealing with gas a buck a [gigajoule], nothing competes … with dispatchable peakers in that pricing environment,” he said.

Nuclear Refurbishments

Jeffrey Lyash, CEO of Ontario Power Generation, gave an update on the status of his company’s $12.8 billion ($9.7 billion USD) refurbishment of the Darlington nuclear plant, calling it “Canada’s largest clean energy program.”

Darlington is a CANDU (Canada deuterium uranium) pressurized heavy-water reactor that has been producing about 20% of the province’s electricity since the early 1990s. Unit 2 was taken offline in 2016, beginning what is expected to be a 10-year project involving all four units. The refurbishment — which Lyash said is far more extensive than projects to extend the lives of U.S. pressurized water reactors and boiling water reactors — is expected to allow the plant to run until 2055.

He said he feels the “weight of responsibility” to deliver the project on time and on budget because Unit 2 is the first of 10 reactors, including six at the Bruce Power plant, scheduled for retrofits. OPG, which is owned by the province, is sharing best practices on the renovations with privately owned Bruce Power, which plans to spend $13 billion.

“The future of the nuclear industry hinges on the success of this project,” Lyash said.

The Future of LDCs

Gordon Kaiser, CEO of Alberta’s Market Surveillance Administrator and former vice chair of the Ontario Energy Board, had a provocative answer in a panel on what local distribution companies will look like in 2025.

“They won’t exist,” he said. Instead they will morph into larger, integrated utilities with generation assets, he predicted. Municipal ownership of LDCs will decline because of the need for professional boards of directors to manage the investments. They will replace boards of municipal “councilors looking for hockey tickets,” he said.

Kaiser’s vision was not shared by other panelists.

Moderator David McFadden, chair of Toronto Hydro, said municipal utilities are not ready to sell yet.

Toronto Hydro CEO Anthony Haines said LDCs will be even more important in the future.

Former FERC Chair Joseph T. Kelliher, executive vice president of NextEra Energy, said he didn’t see such a shift happening in the U.S. either because of the large number of municipal utilities and political obstacles to mergers. He acknowledged, however, that some munis are selling their transmission to escape liability for NERC reliability standards.

Kelliher said many U.S. utilities remain inattentive to controlling costs despite earnings pressure and flat energy demand. Cost-of-service regulation is of limited use, he said. “I’ve always thought it was misnamed, because cost-of-service regulation really is profit-level regulation, because it’s the rate of return that’s regulated, not really the cost,” he said. “Cost-of-service regulation is very ineffective in weeding out routine excessive costs.”

“Competition hasn’t really fully affected LDCs,” he continued. “It’s remarkable how many utilities are not attentive to controlling costs.”

Complexity

Jason Chee-Aloy, managing director at consulting firm Power Advisory, said he senses stakeholder fatigue after more than a decade of competition and repeated changes in market design.

“I do think that stakeholders in general — we’re a firm that’s all over North America — are starting to throw their hands up in the sense that this stuff is getting really, really complicated,” he said.

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NYISO Business Issues Committee Briefs: Nov. 14, 2018

By Michael Kuser

Possible Penalty for External Resources Failing in SRE

NYISO is considering penalizing external resources that fail to perform when dispatched following a supplemental resource evaluation (SRE), Rana Mukerji, senior vice president for market structures, told the Business Issues Committee on Wednesday.

The ISO presented the proposal — part of an effort to clarify the minimum deliverability requirements for external capacity from PJM — at the joint Oct. 18 meeting of the ICAP and Market Issues working groups.

It would penalize an external capacity resource selected for an SRE that fails to bid in a way that will get it scheduled, is not available and operating to provide the capacity sold for the duration of the SRE call, or is unable to deliver its energy from its control area to the New York Control Area border.

The penalty would be equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours that a supplier fails to respond. It would not apply if the resource is in a forced outage during an SRE call; such an instance would instead impact its equivalent forced outage rate (EFORd).

Mukerji, who mentioned the issue during his monthly Broader Regional Market report, said the ISO will return to future working groups to continue stakeholder discussions.

He also updated the BIC on a complaint filed in July with FERC by the Independent Power Producers of New York seeking to bar the ISO from allowing PJM resources to sell installed capacity into Zone J using unforced capacity deliverability rights facilities (EL18-189).

NYISO filed an answer to IPPNY on Sept. 20, he said. The ISO argued that IPPNY mischaracterized its position and made inaccurate claims regarding alleged reliability threats.

Con Edison Newtown substation | Con Edison

Approves T&D Manual Updates

The BIC unanimously approved Transmission and Distribution Manual updates in conformance with FERC Order 831 on offer caps.

The changes replace “$1,000/MWh” with “$2,000/MWh” in two locations in the manual that refer to day-ahead and real-time exports not designated as a coordinated transaction scheduling interface bid, said Padam Singh, senior energy market business analyst.

Order 831 requires grid operators to cap a resource’s incremental energy offer at the higher of $1,000/MWh or its verified cost-based incremental energy offer, and cap verified cost-based incremental energy offers at $2,000/MWh. (See FERC Grants NYISO ‘Cold Snap’ Offer Cap Waiver.)

Automate ICAP Import Rights

The BIC unanimously approved changes to the Installed Capacity Manual for implementation beginning in the Summer 2019 Capability Period.

ICAP Market Operations Engineer Joe Nieminski said the manual changes include revised definitions, a request period for first come, first served (FCFS) import rights, and language regarding buyer confirmation and supporting documents.

Beginning with the summer 2019 capability period, NYISO plans to automate the FCFS import rights process to replace the fax process; replace market participants’ obligations to provide supporting bilateral contracts with an automated bilateral confirmation process; and automate steps now performed manually by ISO staff.

Day-ahead Demand Response Program Manual Updates

The BIC also approved updates to the day-ahead demand response program (DADRP) manual to comply with FERC Order 745, as presented by Sarthak Gupta, associate distributed resources operations engineer.

NYISO last updated the DADRP manual in 2003.

The changes represent an overall refresh, removing obsolete language and replacing redundant language with relevant Tariff and manual references, Gupta said.

NYSEG transmission | NYSEG

BIC Elects Chris Wentlent Vice Chair

The BIC elected Chris Wentlent to a one-year term as committee vice chair. Formerly Exelon’s director of state governmental affairs in New York until January 2018, Wentlent now represents the Municipal Electric Utilities Association of New York State (MEUA), which represents municipal utilities and rural electric cooperatives.

MEUA is a member of the Public Power and Environmental Sector.

LBMPs Down 7% in October

NYISO locational-based marginal prices averaged $35.85/MWh in October, down 7% from $38.70/MWh in September, but higher than $28.35/MWh in the same month a year ago, Mukerji said in his monthly operations report. Day-ahead and real-time, load-weighted LBMPs came in lower compared to September.

Year-to-date monthly energy prices averaged $45.03/MWh through October, a 29% increase from a year ago. October’s average sendout was 399 GWh/day in October, lower than 458 GWh/day in September 2018 and higher than 398 GWh/day in the same month last year.

Transco Z6 hub natural gas prices for the month averaged $2.91/MMBtu, up from $2.75/MMBtu in September and up 23.2% from a year ago.

Distillate prices climbed slightly compared to the previous month but were up 32.4% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $16.65/MMBtu and $16.66/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour came in lower than September, with the ISO’s 27-cent/MWh local reliability share in October down from 37 cents the previous month, while the statewide share dropped from -48 cents to -56 cents. Uplift, excluding the ISO’s cost of operations, was -30 cents/MWh, lower than -11 cents in September.

Thunderstorm alert costs in New York City were 75 cents/MWh, more than double the 33 cents in September.

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Study: MISO Grid Needs Work at 40% Renewables

By Amanda Durish Cook

MISO will need to take significant steps to reinforce its grid to handle 40% renewable penetration, according to RTO findings released last week.

At that share of renewables in its generation mix, MISO will experience a sharp increase in grid complexity in terms of resource adequacy, steady state operating reliability and hourly energy adequacy. The changes will require the RTO to roll out mitigating measures that could include buildout of new transmission, the study found.

“Interim results indicate integration complexity increasing sharply from 30% to 40% renewable penetration,” Policy Studies Manager Jordan Bakke said.

The findings are the latest in MISO’s yearslong renewable integration impact assessments, which seek to determine what volume of renewables it can incorporate into its footprint before the integration becomes “significantly” complex. The RTO is in phase two of the three-phase study.

In spring, MISO published study results showing that increased renewable integration, especially solar generation, will shift peak load to evening hours, with a spikier but shorter daily loss-of-load risk. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

MISO last month said it could reliably absorb a 20% renewable penetration without undercutting frequency response. (See MISO: 20% Renewable Limit for Adequate Frequency Response.)

“We’re seeing that as renewable penetration increases, so do the operational complexities,” Bakke said.

The RTO now says that the variability swings resulting from 40% renewables could increase curtailment of renewables to about 18.2% of intervals. Bakke said various mitigating measures could halve curtailments.

MISO also said that, under current conditions, an overall capacity mix consisting of 40% renewable resources will translate into actual renewable penetration of just 34.7%, which could increase to 38.5% if the RTO introduces additional measures, including new transmission. Renewables at 40% could serve 41.7% of near-peak load, 67% of light load and 81.3% of load during peak conditions for renewables.

The MISO footprint at 10% and 40% renewable penetration | MISO

After studying about 11,300 new transmission project candidates, Bakke said MISO identified about 80 that would be cost-effective and allow it to “utilize the diverse variable resources.”

Veriquest’s David Harlan said MISO’s study did not demonstrate how capacity from gas and coal generation could help facilitate renewable expansion. He said the RTO may want to consider whether its markets are providing the right price incentives so coal and gas generation stay in the market.

But Bakke said the increasing variability resulting from a 40% renewable penetration can be addressed by ramping from its online conventional generators.

Bakke said MISO’s study shows the footprint will continue to need conventional generation. He said even though average ramping needs change slightly at a 40% renewable mix, the remaining conventional generators will have more pronounced requirements, needing to provide greater volumes of up and down ramping.

As MISO nears a mix with 50% renewables, he said, it will experience more renewable energy available than needed for load at certain times of the year, resulting in a “net negative” load.

MISO will hold a workshop on the assessment Nov. 28, where stakeholders will discuss the preliminary impacts of increasing levels of renewable penetration in more detail.