Page 1096 – RTO Insider

November 19, 2018January 30, 2024

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.

November 19, 2018

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.”

November 19, 2018

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.”

November 19, 2018

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.

November 19, 2018January 30, 2024

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.

November 19, 2018

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.

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.

November 19, 2018

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.

November 19, 2018

MISO Elects Lange to Board; Keeps 2 Incumbents

By Amanda Durish Cook

CARMEL, Ind. — MISO’s membership has elected to keep Directors Phyllis Currie and Mark Johnson while also approving the somewhat controversial installment of current Minnesota Public Utilities Commission Chair Nancy Lange.

MISO Senior Vice President and Board Secretary Stephen Kozey announced the Board of Directors elections results at a Nov. 15 Informational Forum. Voting opened Sept. 27 and concluded Nov. 2.

MISO Informational Forum — MISO’s Informational Forum on Nov. 15 | © *RTO Insider*

Each candidate received a majority of membership votes, the RTO revealed. Kozey said the eballot performed “soundly” with no outages from election vendor VoteNet.

“It was not hacked,” Kozey joked, a tongue-in-cheek reference to the recent fear of cyberattacks on the midterm elections.

Kozey said 96 of 139 members voted, well above the 35-member quorum required.

Members voted Lange to the board despite concern by some stakeholders over a sitting commissioner being appointed to the oversight body. Stakeholders said MISO should consider requiring the same one-year moratorium for regulators in the RTO’s states that it requires of directors coming from member companies. MISO’s bylaws require a yearlong cooling period for “directors, officers or employees of a member, user or an affiliate of a member or user.” (See MISO Members Uneasy over Board Nomination.)

This is the first time the RTO has elected either a sitting commissioner or a commissioner from one of the states in its footprint to the board.

Stakeholders noted that Lange made decisions about the grid on behalf of Minnesota customers and utilities up until her election.

Lange will fill the seat vacated by retiring Director Michael Curran, who has served on MISO’s board since 2007. The trio will begin their three-year terms on Jan. 1. Lange’s term at the Minnesota commission doesn’t expire until Jan. 7. Kozey has said Lange will avoid overlap by resigning her post at the regulatory agency early.

Stephen Kozey of MISO at Forum — Stephen Kozey | © *RTO Insider*

Kozey said MISO has requested that its board address whether the moratorium should apply to regulators.

“Because of the issue raised by stakeholders, we’ve asked the Corporate Governance and Strategic Planning Committee [of the Board of Directors] that the applicability of the stay-out be an item that they address,” Kozey said.

The RTO’s Advisory Committee will also discuss the issue at its Dec. 6 meeting during Board Week.

In a release, CEO John Bear said MISO is “fortunate to have an exceptional depth of experience across our Board of Directors.”

Members also approved a $7,000 raise for all directors, raising the current base retainer from $89,000 to $96,000 per year. (See MISO Board of Directors Briefs: Sept. 20, 2018.)

After reporting on election results, Kozey announced that he would be retiring from MISO by the end of the year.

“Thank you for putting up with me and my attempts at humor over the years,” Kozey said, choking up. Kozey was one of the RTO’s 21 original employees in 2000. (See “MISO Looks Back at 15,” MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017.) Kozey founded the RTO’s legal department 18 years ago and served as chief legal officer until 2016.

“We have accomplished so much together, and we are now at a good point for me to transition to retirement. I will miss MISO, the people and working with all of our members, but after a fulfilling and satisfying career, it is time to think about the next stage of my life. I can leave the RTO without hesitation that we have the right leadership in place to take this organization into the future,” Kozey said later in a press release.

MISO said it has a succession plan in place and will announce Kozey’s successor later.

November 19, 2018

Overheard at the 2018 NARUC Annual Meeting

By Tom Kleckner

ORLANDO, Fla. — The National Association of Regulatory Utility Commissioners’ annual meeting attracted about 1,000 regulators, industry representatives, consumer advocates and other stakeholders.

Attendees participated in discussions on the energy-water nexus, physical and cyber challenges to the nation’s critical infrastructure and EPA’s Affordable Clean Energy Rule proposed in August.

Here are some highlights.

NARUC attendees listen to the Electricity Committee. | © *RTO Insider*

RTOs Agree They are Policy Takers, not Makers

A panel of grid operators engaged in a lively discussion over the balance between states’ rights and market operations.

PJM CEO Andy Ott referred to his RTO as a “referee,” balancing resource adequacy requirements with other states’ integrated resource plans.

“Somebody has to step up and say there’s a cost shift here, and unfortunately, now that seems to fall on us,” Ott said. “The big debate is when you start to have competitive states take action to preserve competitive generation or favor certain generation, the crowd on the other side says, ‘Hey, I’m putting my money at risk. It’s unfair.’

“One of the big disappointments of the past year was our proposal to accommodate states and still have competition and integrity in the market. Folks are taking that proposal as being against green, anti-environmental, which is absolutely not the case. We’ve got to create a balance and make sure states’ interests are accommodated or respected.”

“We’re policy takers, not policymakers,” MISO COO Clair Moeller said. “All of the states maintain their statutory obligation to resource adequacy.”

MISO COO Clair Moeller | © *RTO Insider*

Moeller said MISO’s problems are different from PJM’s because MISO’s residual capacity market is less volatile.

“The economics are between the asset owner and the regulator, predominantly,” he said. “The policy of whether we retire this coal plant or don’t is policy-driven. The predictability of those retirements is better because of that regulatory compact. It’s less volatile on the capacity side because the states maintain that obligation. Our obligation is to maintain the assets people bring to the market.”

The Brattle Group’s Kathleen Spees | © *RTO Insider*

Kathleen Spees, a principal with The Brattle Group, said she saw another mission for grid operators: help the states achieve their policy objectives.

“First and foremost is a carbon-free policy. Every decision the markets make helps or doesn’t help the state meet those goals,” Spees said, referring to Moeller’s comment on RTOs being policy takers. “I didn’t hear a solution for how you guys can use the markets to achieve the states’ objectives. Markets have proven to be really effective in achieving reliability.”

“We had a successful tranche of transmission construction to accommodate renewable portfolio standards,” Moeller said. “No one should confuse the construction to achieve those standards with what got built. What got built was to achieve the economic goals of those states. We’re charged with doing things in the public interest. It’s not up to us to pick between generation owners and the states. It’s up to us to decide this is the best path forward in the consumers’ interest.”

“We’ve tried to ensure we’re not putting up barriers to what state policies are trying to achieve,” said Anne George, ISO-NE’s vice president of external affairs. “The states have seen a lot of their environmental policies achieve what they were hoping to achieve. Because they had success, now we’re looking at more aggressive targets. They’re taking actions to move forward. Our job is to look at the marketplace and see how we have the market facilitate what the states are looking to achieve, and to see that others’ part of that regulatory compact have the revenues to provide reliability to the region.”

In the end, Ott said, maintaining confidence in the markets is the best way to ensure open competition.

“If we can’t have a viable market, then Plan B is to flip back to something like competitive procurement, where it’s almost like a synthetic reregulation at a regional level,” he said.

Panel: Flexible Resources not Being Fully Used

Speaking on a panel on flexible resources, Grid Strategies Vice President Michael Goggin said grid operators are not benefiting from all the capabilities renewable energy and distributed generation offer. Were RTOs to remove barriers to full market participation, he said, flexible resources would be able to provide ancillary services and operating reserves.

“All U.S. ISOs have rules that are either directly or indirectly preventing wind and solar from providing services they never thought they were capable of doing,” Goggin said. “Capacity markets are not ideal for bringing out the best of these resources. They’re focused on megawatts, not procuring flexibility. Real-time incentives, through operating reserves and ancillary services and energy markets, provide a much better way of procuring that service when it’s needed. Self-scheduled resources aren’t fully participating in the centralized dispatch, an impediment to bringing about the full capability of these resources.”

California’s Liane Randolph and Iowa’s Richard Lozier take note of comments by Grid Strategies’ Michael Goggins. | © *RTO Insider*

David Nemtzow, director of the Department of Energy’s Building Technologies Office, suggested buildings provide another resource that can be tapped. He noted there are 124 million buildings, 118 million of which are homes, in the U.S. They account for 40% of the country’s energy usage, at a cost of $380 billion per year.

“Buildings are an integral part of the electric system. The challenge is to make them flexible without any degradation of the services they provide,” Nemtzow said. In addition to reducing demand through LED lighting and sophisticated sensors that adapt cooling/heating systems and lighting to the number of people present, buildings can be “interoperable, integrated systems … that are grid-responsive,” he said.

“Buildings can signal the utilities, so when the system is stressed or needs resources, a signal can be sent to the building owner or operator and they can make voluntary decisions and participate with the grid,” Nemtzow said.

Ric O’Connell, executive director of GridLab, said the two most significant trends he sees in the industry are the adoption of large, central renewable generation by utilities and policymakers, and the adoption of distributed energy resources by customers.

“The real question is, how do these two major changes interact?” he said. “Do they complement each other, or do they frustrate each other?”

Answering his own question, O’Connell cited a paper he recently published that found the two trends do complement each other. “Part of that is because DERs add flexibility to the grid and enable the addition of more renewables,” he said.

“On a utility-scale system, think of wind and solar as must-take. Sometimes, the rest of the system needs to be there for them. DERs are that thing your system operators are constantly grumbling about. This technology isn’t actually that new. We’re just allowing these resources to expose these characteristics.”

O’Connell referred to Minnesota, where he said modeling revealed that DERs’ flexibility is key to unlocking higher renewable penetrations, and that limiting DERs would dramatically increase the cost to decarbonize the system. “We have to start thinking about how we connect these new technologies,” he said.

Minnesota’s Nancy Lange | © *RTO Insider*

Minnesota Public Utilities Commission Chair Nancy Lange, speaking on a separate panel, said the state is doing just that.

Quoting Wayne Gretzky’s strategy of skating to where the puck will be, not where it’s been, Lange said that in distribution planning, the commission thinks it knows where the puck is going.

“We have 4,500 [electric vehicles] in Minnesota. Are we going to have 10,000 in a year, or 7,000 in a year, or 20,000?” she asked. “Those are some of the skate-to-where-the-puck-is-going questions.”

Commissioners Share Their Market Concerns

During an Electricity Committee devoted to market issues, Western regulators shared with their peers the latest developments in the Western Interconnection: CAISO’s expansion of its real-time balancing market; CAISO’s and SPP’s offerings of reliability coordination services as Peak Reliability enters its last year of business; and SPP’s life-support effort to integrate some of the Mountain West Transmission Group.

Utah Public Service Commissioner David Clark quoted NERC CEO Jim Robb, the former Western Electricity Coordinating Council CEO: “The transition that will occur in reliability coordination services in the West is the single most important reliability coordination effort facing the U.S. in the next two years. We have our eye carefully on this transition process.”

Clark said Western states outside of California are concerned about CAISO’s “further extension” of market services.

“The principal challenge for many is the area of governance,” he said. “In Utah, we have a great desire to retain our self-determination, with respect to our energy policy. If we ever become involved in a market being served by vertically integrated utilities, we would want a voice in the government. We would want the operations of that market to be transparent.”

New Mexico’s Cynthia Hall | © *RTO Insider*

“There’s still skepticism with states and utilities in the West when it comes to take that step to join an RTO,” New Mexico Public Regulation Commissioner Cynthia Hall said. “There’s a growing concern relative to the problems created by seams issues. There’s a reticence to becoming a[n RTO] member. The reasons are multiple, not the least of which is if they have to pay to play — they would have to pay a greenhouse gas adder in California.”

Illinois Commerce Commissioner John Rosales discussed his problems with PJM’s capacity market construct, which he said has succeeded in lowering wholesale prices and the cost of operating reserves.

“What’s been somewhat contentious are the parts that don’t work well, which is pretty much everything else,” he said. “For me, it’s inherently flawed and extremely complex. The capacity construct is constantly being revised. … There have been well over 30 revisions, which becomes very frustrating for the states. We don’t call it a market, because there are so many features that are administratively determined … price caps, the cost of new energy fluctuates, performance requirements. Most of us agree that generally, this construct fails to send the proper price signals to ensure the proper fuel mix.”

Left to right: Illinois’ John Rosales, Utah’s David Clark and Washington’s Ann Rendahl follow the conversation. | © *RTO Insider*

Competitive markets have a supporter in Michigan Public Service Commission Chair Sally Talberg, who said, “Whether deregulated or fully regulated or something in between … at the end of the day, we want affordable, reliable service. We all have a common goal in fostering those competitive environments. I feel like we’re dancing around with a patchwork of dos and don’ts at the state level, and that creates uncertainty.”

Indiana Utility Regulatory Commissioner Sarah Freeman said her concern is with a rapidly changing fuel mix. She said her state expects four coal-fired units to retire by 2023, and she noted there are no new builds on the horizon.

“If it’s happening in Indiana, it’s happening bigger and faster somewhere else,” she said. “Once RTOs become involved, we need to maximize our cooperation and avoid any protectionist tendencies we have.”

Seams issues topped Illinois Commissioner Sadzi Oliva’s lists of concerns. She said market inefficiencies show up on the seam, “typically as a result of incompatible market rules.”

“This increases the ultimate cost to the ratepayers,” Oliva said. “The seam between MISO and SPP will be the concern for the majority of us. Illinois’ concern is receiving an unwarranted cost allocation.”

November 19, 2018

DOE Workshop Gathers Input for Tx Congestion Study

By Rory D. Sweeney

Amid an uptick in spending on transmission infrastructure that has attracted increased scrutiny from those paying the bills, customers and developers met Thursday for a workshop on how to get to the grid of the future.

The Department of Energy convened the daylong session at the National Rural Electric Cooperative Association’s conference center in Arlington, Va., to gather information for the department’s 2019 electric transmission congestion study.

American Municipal Power’s Ed Tatum summed up what transmission customers want: “Sunshine is the best.”

Tatum wasn’t alone in his call for transparency. Traci Bone, an attorney with the California Public Utilities Commission, took issue with transmission projects that receive little or no RTO review. Known as supplemental projects in PJM, they are usually developed by incumbent transmission owners within their own zones to address their own planning criteria. (See FERC Upholds PJM TOs’ Supplemental Project Rules.)

She noted FERC’s rejection in September of a complaint by the CPUC and others who argued that Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)

It’s “very concerning” that FERC has taken “such divergent views” from ratepayers, she said.

During audience questions following Bone’s panel, Exelon’s David Weaver criticized it as “a very one-sided panel” and said the decision to spend on resilience and security upgrades is not as straightforward as addressing reliability criteria.

“I think it can be perceived that wrong investments are being made,” he said.

“Not so much that they’re making the wrong investments, but we don’t know what investments they’re making,” Bone responded. “We need to have a say in that.”

LS Power’s Sharon Segner, who was also on the panel, argued for increased competition for transmission projects. Following a stakeholder campaign led in part by Segner earlier this year, PJM has begun considering developers’ cost-containment guarantees as part of its analysis of competitive transmission proposals. (See Cost Containment Clears MC Vote Despite PJM Plea.)

Segner noted that eight states — North Dakota, South Dakota, Minnesota, Oklahoma, Nebraska, Alabama, North Carolina and Indiana — have passed right of first refusal laws “to thwart Order 1000” and FERC’s efforts to introduce competition. Order 1000 eliminated ROFRs from FERC-approved tariffs and agreements, but the commission says it is powerless to block states from enacting such laws to protect incumbents’ monopolies.

Public Engagement

The workshop also looked at the importance of public engagement in getting large interregional projects completed. Dan Belin, of engineering firm Ecology & Environment, compared the permitting processes of the Great Northern Transmission Line — to link Minnesota with Manitoba’s hydro resources — and Northern Pass, which would have delivered Quebec hydropower into New England.

Great Northern “had a very robust public-involvement program” that included engagement with the Minnesota Department of Commerce prior to submitting its application, Belin said. The project was approved within the state Public Utilities Commission’s statutory 15-month timeline.

Northern Pass held no meetings prior to submitting its application. The filing attracted 9,000 public comments, and the seven-year review eventually ended in rejection by New Hampshire.

“That significantly draws out the process,” Belin said. “The public involvement piece was a big differentiator between the two projects.”

“What we saw in Minnesota is not typical and it should be more typical,” said Rich Sedano, president of the Regulatory Assistance Project.

He described transmission development as “a public process that is largely shielded from the public” and advocated for improving transparency and public engagement. The process should also remain within state authority, and the industry should “accept the stress it’s going to cause,” he said.

Bess Gorman, assistant general counsel with National Grid, suggested involving the public in the tangible benefits of projects, such as finding ways to include them in benefiting from cost savings.

“As much as you can do,” she said of the need for public engagement. “That’s how you’re going to get the project through.”

Rob Gramlich, president of consulting firm Grid Strategies, credited transmission expansions such as MISO’s multi-value projects, highway/byway projects in SPP and ERCOT’s Competitive Renewable Energy Zones with precipitating the growth in renewables.

“I don’t think we would have half of the wind industry that we have without these plans in the middle of the country,” he said.

Culture Change

Others discussed difficulties winning approval for interregional projects. EDF Renewables’ Omar Martino described a “quadruple hurdle” for one project that required satisfying individual criteria of MISO and SPP and their mutual criteria in addition to securing local approval. The host utility vetoed the project, he said, because it preferred to use an operating guide.

“Something is just not right,” he said. “There’s a gap that needs to be fixed.”

He and others called for culture changes at decisional bodies throughout the process.

“You have to create these programs … inside utilities, inside the RTOs. You also have to have the right culture, the right leadership, the right guidance,” he said.

Gramlich said “the concepts are generally in Order 1000” for interregional planning, “but it didn’t get the job done,” and decisions since then have “weakened” it.

“Nobody wants to pay for something they don’t benefit from, so there’s a healthy skepticism in the RTO process,” he said.

On Nov. 9, the Governors’ Wind and Solar Energy Coalition wrote a letter to FERC advocating for unifying the Eastern, Western and Texas interconnections via ultra-high-voltage lines. The coalition, which includes 19 state governors, compared the proposal to creating the nation’s interstate highway system 60 years ago and the $315 billion grid China is building today.

The coalition cited a study by Iowa State University that estimated the impact of two transmission expansion scenarios: a $40 billion investment in transmission that could allow renewable penetration to rise to 40% nationwide, and an $80 billion investment that could push renewables to 50%.

Cost Allocation

Determining how much transmission is needed and who’s going to pay for it are also obstacles to such ambitious proposals.

In the first morning panel, PJM’s Ken Seiler said that reliability has vastly increased from earlier in his career when “we were hanging on by our fingertips” daily during late-afternoon summer peaks.

Tatum, who shared the panel with Seiler, agreed that there’s no clear measure to “know if we’re over- or under-building” the grid. But he said that it is clear that developers are now making up for a “dearth of investment” in previous years. He noted that PJM is on track to add $7 billion to its Regional Transmission Expansion Plan this year, which would be the biggest addition in the plan’s history.

And then there’s the question of who picks up what portion of the tab.

“Everything goes really, really well until you get in to the concept of cost allocation,” Seiler said. “Once you start talking about money … that’s when the discussion gets really, really tough.”

Participants and audience members cited several examples of cost allocation fights, notably the ongoing debate over the Artificial Island project, PJM’s first competitive project under Order 1000. (See Del. Group Seeks to Block Artificial Island Project.)

“It’s really all about the cost allocation, but if you can solve that, the rest of this stuff is easier,” Gramlich said.

He advocated for broad, beneficiary-pays allocations in which many stakeholders shoulder smaller portions of the bill. Still, that won’t solve everything.

“There is no perfect solution for cost allocation except [to] pay a lot of lawyers for a lot of litigation,” Exelon’s Steve Naumann said.