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March 13, 2019

Murkowski and Manchin: Ds, Rs Can Work Together on Climate

By Tom Kleckner

HOUSTON — Sometime in the future, pigs may fly, the moon might turn blue and bipartisanship could break out in D.C. Until then, there’s the Senate Energy and Natural Resources Committee (ENR), led by Chair Lisa Murkowski (R-Alaska) and ranking member Joe Manchin (D-W.Va.).

Sen. Joe Manchin (D-W.Va.) at CERAWeek by IHS Markit | © *RTO Insider*

“We like each other. Being a Democrat and a Republican does not interfere with our job,” Manchin said during an appearance at the CERAWeek by IHS Markit energy conference Monday. “We represent our states and do what’s best for the country.”

“I always wonder when did energy become a partisan issue, and why does it have to be partisan? It used to be a regional issue,” said Murkowski, who has chaired or served as the committee’s ranking member for the past 10 years. “I like to think we can show the leadership in Congress that we should be working together in key areas.”

“Stand down on the rhetoric,” she continued. “I want to set a tone that is bipartisan, that is welcoming … where there is a safe space for dialogue that leads to pragmatic solutions.”

Murkowski and Manchin appeared together on a CERAWeek panel days after publishing an op-ed in The Washington Post that called for “responsible” action on climate change. “There is no question that climate change is real or that human activities are driving much of it,” they wrote, taking a position their constituents might consider heresy.

The op-ed was a follow-up to the ENR Committee’s hearing on climate change last week. (See Senate ENR Committee Discusses Climate Change.)

The column did not mention Manchin’s staunch support for West Virginia coal mining, nor Murkowski’s backing of oil drilling in the Arctic National Wildlife Refuge, policies that contribute to carbon emissions. Nor did it make any concrete policy proposals. They suggested only that the solution to climate change is unleashing American ingenuity, saying that the U.S. “must continue to lead the world in the development of new and improved technologies.”

“If we’re going to talk the talk about how we innovate our way to a lower-carbon economy, let’s make sure we facilitate and foster these really great ideas,” Murkowski said, referring to CERAWeek’s exhibit halls filled with the latest in energy technology. “It’s like dream stuff out there. This is what we need to advance a lower-carbon economy. Is it the government’s role to take every great idea and underwrite it? Absolutely not, but we can wisely help facilitate their development.”

President Trump’s proposed 2020 budget would cut funding for the Department of Energy’s Office of Energy Efficiency & Renewable Energy (EERE) by 70% and eliminate the Advanced Research Projects Agency–Energy. Congress rejected similar proposals last year.

“We come from communities with challenging environments. We have to reduce emissions in a way that does not leave the community worse off,” Murkowski said. “Let’s try to dial down some of the rhetoric out there. Let’s stop the messaging and the name-calling and the finger-pointing. Instead, let’s decide what are some of the paths forward.”

Manchin said coal and other fossil fuels still need to be part of the energy mix. “You’re not going to eliminate fossil fuels, so you better find the solution or next generation. There has to be a balance,” he said.

Sen. Lisa Murkowski (R-Alaska) speaks during a Q&A session at CERAWeek by IHS Markit. | © *RTO Insider*

Murkowski and Manchin both took shots at the proposed Green New Deal. Manchin referred to the resolution as a position statement, while Murkowski bemoaned its use as a political wedge. Senate Majority Leader Mitch McConnell (R-Ky.) intends to put the measure up for a vote to get the Senate on the record.

The Green New Deal has “created even more of a divide when we should be coming together to address the problem,” Murkowski said. “Now is not the time to put everyone in their corners and have them come out fighting with rhetoric. I find it distracts from the solutions. If you don’t like the Green New Deal, what is your plan?”

During both his press briefing and panel appearance, Manchin referred to a competing op-e d penned for CNBC by former Energy Secretary Ernest Moniz, who served under President Barack Obama, and Andy Karsner, who headed EERE during George W. Bush’s administration. Moniz and Karsner refer to a “Green Real Deal” that ensures a “wise and just transition to a low-carbon economy” and minimizes “stranded physical assets … workers and communities.”

“They say we’re not getting there as fast as we want, but we’re getting there as fast as we can politically,” Manchin said.

Murkowski worked for years with former ENR ranking member Maria Cantwell (D-Wash.) to craft a new energy policy to update the last sweeping energy bill, the Energy Policy Act of 2005.

“The energy bill is coming; we have not given up that,” Murkowski said. “When you think what has happened in the energy space, with LNG terminals, renewables, batteries … when you think how much we’ve done and how we’ve done it with the anchor of policy that hasn’t been enacted … there’s so much that is not fresh.”

But this time may be different, Murkowski said.

“You’re seeing others, not just Democrats, opening up the conversation, which you didn’t see five years ago,” she said. “How we move forward with it is going to be important. We’re putting together a conceptual plan. Saying you’re either for this or you’re part of the problem, that’s not the way to get started.

“The more we push people off in either lane here, it will be hard for people to get to the center to come up with solutions that gain political support. Let’s be practical about this.”

March 12, 2019

Wheeler: EPA’s Proposed Budget Cut ‘Common-sense’

By Tom Kleckner

HOUSTON — EPA Administrator Andrew Wheeler on Monday defended the Trump administration’s proposed 31% cut to his agency’s budget, saying it’s a “common-sense budget proposal.”

“We can accomplish our mission at that level,” Wheeler said, following an appearance at CERAWeek by IHS Markit. “It takes out some of the more voluntary programs and duplicity [sic] in statutes and programs.”

Andrew Wheeler at CERAWeek by IHS Markit | © *RTO Insider*

The 2020 budget would slash EPA funding from $8 billion to $6.1 billion. The reduction is similar to the administration’s previous two budgets, neither of which Congress enacted. This budget is considered DOA with the Democrats now in control of the House of Representatives.

The White House said it wants to ensure clean air and water and chemical safety, while “reducing regulatory burden and eliminating lower-priority activities.”

Wheeler highlighted a $50 million grant program EPA wants to establish for communities with aging school facilities, with the intention of creating safer and healthier environments.

The EPA says it wants to focus on investing in water infrastructure, efficiently cleaning up Superfund sites, strengthening protections from toxic chemicals and continued regulatory and permitting reforms.

In comments to the CERAWeek audience, Wheeler called for the American energy industry to promote its environmentally-conscious process and procedures “that are better than anywhere else in the world.”

“Our natural gas, oil, coal and fossil fuels are extracted in a more environmental-friendly manner here,” he said. “That should be a selling point for anyone selling energy around the world to adopt our programs.”

Wheeler was confirmed as the EPA’s administrator last month, replacing scandal-ridden Scott Pruitt. He has been serving as acting administrator since July and worked at the agency from 1991 to 1995. (See Wheeler Confirmed to EPA on 52-47 Vote.)

EPA’s enacted budget, FY 2019 ($ millions) | *EPA*

“Some of the issues we were dealing with in 1991 are the same ones we’re still looking at today,” he said. “It’s just become much more politicized over the last 30 years, which is a shame. We’re doing a lot of things for the environment Republican administrations just don’t get credit for.”

Asked to explain the reason for that by moderator Daniel Yergin, IHS Markit’s vice chairman, Wheeler said the environment has become a large campaign issue and “money-maker” for the political parties.

“I think that’s what’s created the partisan divide in Congress,” he said.

March 12, 2019

Pa. Lawmakers Unveil $500M Nuke Subsidy Bill

By Christen Smith

With two months to go before Exelon says it will pull the plug on Three Mile Island, Pennsylvania lawmakers unveiled legislation Monday to spend $500 million annually to subsidize the state’s nuclear fleet.

The Keep Powering PA Act (House Bill 11) would add a nuclear power mandate to the 2004 Alternative Energy Portfolio Standards Act (AEPS). Prime sponsor Rep. Thomas Mehaffie (R), who was joined by 19 co-sponsors, said the bill “properly values the environmental benefits the nuclear power industry has been delivering to our state for decades.”

“While the market is designed to price electricity on a day-to-day basis, it is the role of the legislature to set the long-term policies for this state,” he said during a press conference on Monday at the Ironworkers Local 404 Union hall in Harrisburg. “The markets do not treat all clean sources of energy the same and they do not penalize polluters. As state legislators, we need to take a step back, recognize this and we need to take truly into account the cost of doing nothing.”

Pennsylvania Rep. Thomas Mehaffie (R) introduces House Bill 11. | *Facebook*

3rd Tier

HB 11 would create a third tier of resources in the alternative energy portfolio from which companies must purchase at least 50% of their electricity by 2021: nuclear, solar, geothermal and low-impact hydropower. The first two tiers of the legislation include 16 resource types with targets of 8% and 10%. (See Draft of Pennsylvania Nuke Subsidy Bill Leaked.)

Mehaffie said his bill would provide consumer protections through capped pricing and the prevention of “double dipping” across programs. He estimated the bill would cost $500 million — one-eighth of the $4.6 billion in annual costs he claims would result should all five nuclear plants in the state shut down: $788 million in higher electric prices; $2 billion in lost state GDP; and $1.86 billion in costs associated with carbon emissions and harmful criteria air pollutants, including SO₂, NO_X and particulate matter.

“For the state legislature to ignore the challenges facing these plants, it would be one of the most irresponsible and irreversible decisions we’ve made in a generation,” he said.

The Pennsylvania Rural Electric Association and several union officials endorsed the bill, as did Exelon, which has threatened to shutter TMI later this year if lawmakers fail to act by May. (See Exelon: Need Pa. Action by May t o Save TMI.)

David Fein, Exelon Generation’s senior vice president of state governmental and regulatory affairs, urged support for the bill in an emailed statement on Monday, saying it “will put Pennsylvania on a path to a clean energy future [and] preserve 16,000 good-paying jobs.”

Exelon successfully lobbied for nuclear subsidies in New York and Illinois after threatening to close plants experiencing financial strain. Exelon manages the largest nuclear fleet in the country, with three facilities located in Pennsylvania alone. (See Seeking Subsidy, Exelon Threatens to Close Three Mile Island.)

Joe Gusler, president of the Central PA Chapter of Building and Construction Trades Council, speaking in favor of House Bill 11. | *Facebook*

Criticism

Critics argue the plan awards undeserved subsidies and have questioned generators’ claims of hardship.

“The notion that if we do nothing, nuclear power plants will simultaneously shut down and prices will be impacted is disingenuous at best — Exelon, FirstEnergy Solutions and Talen Energy are making too much money to justify shutting down,” said Steve Kratz, spokesman for Citizens Against Nuclear Bailouts, a coalition of power generators and energy, business and manufacturing associations, in an email Monday. “What does Rep. Mehaffie know that industry experts — who have all testified that competition and reliability aren’t a problem — do not?”

He noted that Exelon appl ied in July to extend the license of its Peach Bottom Units 2 and 3 through 2054. The group also cited research by the Kleinman Center for Energy Policy at the University of Pennsylvania that projected the subsidies would increase Pennsylvania’s electric rates by $981 million annually.

“Adding already profitable nuclear power plants to the AEPS is a bailout that would significantly increase consumer electricity prices, eliminate consumer choice and fundamentally change the way Pennsylvania’s competitive energy markets operate,” Kratz said.

He also pointed to data from PJM’s Independent Market Monitor, whose most recent State of the Market report noted improved earnings for the RTO’s nuclear fleet. Although a “significant proportion” of nuclear plants did not cover annual avoidable costs in 2016 and 2017, the Monitor reported that nuclear plants benefited from substantially higher LMPs and forward prices in 2018.

A coalition of environmental groups — including the Sierra Club, Natural Resources Defense Council, Clean Air Council and Conservation Voters of Pennsylvania — said the bill also locks the state into propping up aging and expensive nuclear plants at the expense of more efficient renewable technologies.

“Pennsylvania’s policymakers ought to be working to significantly scale up clean, safe and affordable renewable energy from wind, solar, geothermal and low-impact hydropower,” the group said. “Building a clean energy economy around renewable energy in tandem with a declining, enforceable limit on carbon pollution from power plants will reduce emissions significantly in Pennsylvania as well as create jobs and protect health and the environment.”

Supporters of the bill argue, however, no plan for a cleaner Pennsylvania succeeds without nuclear power — which they say generates 93% of the state’s zero-carbon electricity. Mehaffie said one nuclear plant produces more power than all of the state’s wind and solar assets combined. Nuclear generation supplied about 42% of Pennsylvania’s net generation in 2017, compared with 4.5% for renewables, according to the Energy Information Administration.

“If we lose one or more of these plants, then we might as well forget about all the time and money we’ve invested into wind and solar,” Mehaffie said. “It’s the only baseload power supply being created without any carbon emissions. If our state wants to move forward with a cleaner environment, there is simply no way possible to get there without our nuclear power plants being open.”

Gene Barr, president and CEO of Pennsylvania’s Chamber of Business and Industry, said the nuclear mandate unnecessarily walls off 70% of the market, potentially forcing the state to import power — a reversal of the state’s role as an energy exporter.

“The General Assembly must be aware of the possibility that FERC will soon direct the grid operator to deduct the value of these state subsidies out of market payments, leaving the state in an even worse position — significantly higher energy costs with no tangible benefit,” he said.

MOPR Ruling

Last June, a FERC order concluded that increasing state subsidies for renewable and nuclear power were suppressing PJM capacity prices. The commission’s 3-2 ruling required PJM to expand the minimum offer price rule (MOPR) to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits and zero-emission credits for nuclear plants. The MOPR currently covers only new gas-fired units. (See Little Common Ground in PJM Capacity Revamp Filings.)

Stu Bresler, PJM’s senior vice president of markets and operations, testified before both the House Environment Resources & Energy Committee and the Consumer Affairs Committee on Monday that the success of the RTO depends upon its ability to evolve with technology and consumer demand. However, stakeholders’ recent focus on refining capacity market rules has left PJM’s reserve and energy markets ignored, he said.

“It is imperative that the resources called upon by PJM to maintain system reliability are appropriately valued for the services they provide, and today’s reserve and energy pricing rules fall short of that mark,” he said. “By setting energy and reserve prices to levels that accurately reflect system conditions both during normal conditions and most importantly when reserve quantities become tight, resources operating to protect reliability collect revenues for the capability to respond when needed most.”

March 12, 2019

ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff

By Michael Kuser and Rich Heidorn Jr.

The New England Power Pool Markets Committee last week rejected ISO-NE’s interim proposal for compensating generators for fuel security. But the RTO plans to file the plan with FERC with or without stakeholder endorsement, it said Monday.

The proposal, which would cover capacity commitment period 14 (2023/24) and 15 (2024/25), received only 42% support, short of the 60% threshold to recommend it to the Participants Committee.

[Editor’s Note: This account of the meeting is based on the committee actions notice posted after the two-day session March 5-6. Like most NEPOOL meetings, it was closed to the public and the press.]

ISO-NE spokeswoman Marcia Blomberg said the RTO will seek a vote on its proposal at the NEPOOL Participants Committee meeting Wednesday and plans a FERC filing by the end of the month regardless of the outcome. “In its advisory role, NEPOOL provides input on ISO proposals, and the ISO has filed proposals in the past when we haven’t had the full support of NEPOOL,” she said via email. “The ISO always evaluates NEPOOL’s input, but I can say that we are working toward a filing on the interim compensation proposal.”

ISO-NE said the plan — which it estimated could cost more than $100 million over the last winter reliability program — is intended to prevent otherwise economic resources from retiring because they are not fully compensated for their winter energy security attributes. It would trigger when gas availability is low and system conditions were tight.

Under a two-settlement structure, resources would be paid or charged for deviations between the inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — representing energy maintained during each trigger condition.

The plan is intended to be an interim measure until the RTO completes development of a market-based compensation scheme for energy security, which will not be filed before retirement bids are due for Forward Capacity Auction 14 this month.

Amendments also Rejected

The committee also rejected efforts by the Union of Concerned Scientists (UCS), PSEG Energy Resources & Trade and energy services firm Energy New England (ENE) to amend the ISO-NE proposal.

ENE argued that the RTO’s proposal “far exceeds” its stated goal of retaining resources for fuel security reliability and preventing uneconomic retirement bids, saying its “resource eligibility is too broad and extends beyond target resources.”

The company recommended limiting compensation to oil, natural gas, demand response and electric storage, “resources capable of improving winter energy security by providing incremental reliability benefits.” ENE said its proposal would reduce the cost of the program by about $50 million.

ENE’s amendment received only 48% support, winning backing from most End Users and Publicly Owned Entities but overwhelmingly opposed by the Generators, Suppliers, Alternative Resources and Transmission sectors.

The PSEG amendment would have set the inventoried energy base payment rate on April 30 immediately prior to the delivery period.

“It is widely recognized that setting the energy base payment rate for the winter delivery period over four years prior to when the contracts are expected to be obtained increases the likelihood that the rate will be inconsistent with market conditions when resources are expected to go to market to obtain those contracts,” PSEG’s Joel Gordon said in a memo to the committee. “If the rate is too low, the program will fail to procure the additional fuel security needs of the system. Conversely, if the rate is too high, the overall cost of the program will be greater than otherwise required to achieve its objectives.”

It failed with 42% support, with strong backing from Generators and strong opposition from End Users.

Abigail Krich, president of Boreas Renewables, was to present on behalf of the UCS a proposal guaranteeing that energy actually provided would receive the same compensation as inventoried energy.

Krich’s presentation said that renewable resources that provide energy during cold weather are also essential to reliability but that they would not be compensated like fossil fuel plants because they have no “inventoried” energy. The UCS proposal, which would have amended Tariff Section I.2.2 and Appendix K of Market Rule 1, failed on a show of hands.

Energy Efficiency Exemption Impact

The Markets Committee also rejected a proposal by the New England Power Generators Association (NEPGA) to address a disconnect in the calculation of Pay-for-Performance penalties during scarcity conditions in off-peak hours. The proposal was introduced by NEPGA member Dynegy Marketing and Trade.

Because of an exemption ordered by FERC, energy efficiency resources are subject to ISO-NE’s PfP requirements only during DR on-peak and seasonal-peak hours. That became an issue on Labor Day 2018, when EE resources were treated as if they had hit the stop-loss limits, resulting in $9.7 million in settlement imbalance charges to other capacity resources, according to NEPGA.

The association said because most EE resources are in Massachusetts and Connecticut, the cost of the exempted performance obligations should be allocated to the states based on their shares.

NEPGA’s proposal received less than 35% support, winning majorities from only the Generation, Supplier and Alternative Resources sectors.

An alternative amendment by Vermont Energy Investment Corp. (VEIC) fell just short of approval with 58.4% support, strongly backed by End Users, Publicly Owned Entities and Transmission and strongly opposed by Generation, Suppliers and Alternative Resources.

VEIC’s proposal was presented by Synapse Energy’s Doug Hurley, who said the balancing ratio (BR) used to compute penalties removes EE from the numerator but not from the denominator during non-peak hours.

Hurley said the proposal would revert the mutual insurance pool to its original intent of covering resources that reach stop-loss limits. “The BR for any interval would be calculated based upon those resources that are subject to payments or penalties in that interval, as the FERC order intended,” he said.

In a related matter, the committee agreed to ask the Demand Resources Working Group to consider how EE resources’ performance could be established in all hours and what standards and reporting mechanisms are necessary to make the change. The committee acted on a problem statement that noted the lack of a consensus on EE performance measurements in off-peak hours.

New Ancillary Services and Multi-day-ahead Market

The meeting also featured a presentation on the introduction of three categories of new ancillary services to be procured in the day-ahead market and an update on the previously introduced multi-day-ahead market (M-DAM).

ISO-NE Principal Analyst Andrew Gillespie was scheduled to present the committee with conceptual details, as well as a timeline for a FERC filing by Nov. 15, in line with the RTO’s January request for a four-month extension to file a plan. The delay request is currently pending before the commission (EL18-182).

The presentation to the committee acknowledges the RTO has “heard a number of questions and concerns about the length of the market horizon, primarily how this may not align with participants’ hedging strategies.”

The Massachusetts attorney general’s office commissioned London Economics International (LEI) to prepare an alternative to the RTO’s M-DAM proposal, which LEI found “conceptually and operationally complex” and said would “require substantial administrative costs.”

Complete revamping of the day-ahead market into an M-DAM is an unproven mechanism and may not meet all the RTO’s goals, LEI concluded, proposing instead a “forward stored energy reserve” ancillary service.

The advisory firm contends that while the RTO’s proposal might increase revenues for some power plants and prevent inefficient retirement, the resulting higher energy prices may lower net cost of new entry, which would suppress capacity market prices and potentially accelerate retirement.

Calpine was scheduled to present its case for a “forward enhanced reserves market” (FERM), with analyst Rebecca Hunter arguing all problems that fall within a planning horizon time frame are left unsolved without a forward price signal. (See “Market Reaction,” New England Talks Energy Security, Public Policy.)

The FERM would have no offer cap, but awards to resources with capacity supply obligations would be incremental to the clearing price. In addition, FERM resources would have daily day-ahead must-offer obligations in winter months only. The construct would allow participation from resources without a supply obligation, such as energy-only resources that only plan to be available for peak days in the winter.

March 12, 2019January 21, 2024

California: CCAs, Decarbonization Pose Reliability Challenges

By Hudson Sangree

California officials expressed concern last week that the state’s push toward 100% clean energy and the rapid growth of community choice aggregators could imperil grid reliability if not carefully orchestrated.

The development is worrying enough that state regulators are considering creating a centralized process to ensure resources needed for long-term resource adequacy (RA) get sufficient financial support.

Michael Picker, president of the California Public Utilities Commission, told lawmakers Wednesday that the state has moved away from its traditional model of vertically integrated utilities, with a few big owners of generation and wires also providing service to retail customers.

Now there are dozens of different load-serving entities delivering electricity to consumers. Not all of them can meet the basic legal requirement, enacted after the California energy crisis of 2000/01, that they have enough electricity available to meet demand on the year’s hottest days, when demand soars, Picker said.

“Here’s where we get into our uncharted and potentially dangerous territory,” Picker told the State Assembly Utilities and Energy Committee. “We’re neither here nor there.

“The cleanest way would be if we had vertically integrated utilities or we went to full competition where everybody picked their electricity provider and then you had discrete transmission and discrete distribution companies,” he said. “That’s what Texas and New York do. It works for them. [It’s] not clear if it would work here, but it’s also clear we’re not going to go back to a vertically integrated system.

“So the question is, ‘What do you do?’”

‘One of the Things that Scares Me’

Picker made his comments at an informational hearing titled “The Metamorphosis of the Energy Sector: Maintaining Reliability and Affordability on the Road to Decarbonization.” Panelists were asked to address the challenges facing California’s grid as it pursues the legal mandates of SB 100 and other bills that set ambitious clean-energy goals — including a mandate that the state’s LSEs deliver 100% zero-carbon electricity by 2045.

CCAs will require more than 5,700 new generation projects at a median size of 1.75 MW to meet those goals, Picker said. [An earlier version of this story contained the median figure of 175 MW used by Picker at the hearing. The PUC later said he misspoke. The median figure was derived from 56 projects totaling 2 GW that the CCAs had under contract in a recent count. Those projects range in size from less than 1 MW to 200 MW, with a median of 1.75MW and an average size of 40 MW.]

“It’s a challenge,” he said. CCAs, many of which are startups, have customers but not the financial assets to get financing for generation projects, he said. To scale up quickly, you need “large companies with big balance sheets,” he said.

Last year the PUC received an unprecedented 11 requests to waive RA requirements. Ten of those requests came from electric service providers (ESPs), which sell directly to a limited number of nonresidential customers, and one came from an IOU. This year’s batch of waivers may include one or more CCAs, according to the PUC and a group representing CCAs.

In the relatively small geographic pockets controlled by CCAs, there may not be enough transmission capacity to bring in power from outside on peak-demand days, so the CCAs must be able to purchase electricity from generators within their territory, Picker said. But many can’t muster the financial resources to compete for those resources and must ask the PUC for waivers, he said.

“I consider that to be a weakness in the design,” the PUC president said. “I think it’s a big problem.”

If a day arrives when a CCA has insufficient power to serve its customers, the problem could spiral out of control, he said.

“This is one of the things that scares me,” he said. “You may be a small company, but your failure to provide electricity to your customers can cause a brownout that can escalate, and it can actually affect customers in somebody else’s service area.”

State Could Establish a Central Buyer

The state recently required CCAs to secure three-year RA procurement contracts, instead of annual contracts, and many are hoping the change will help the CCAs compete for reliability resources, Picker said. But if the situation doesn’t improve by the end of this summer, “we may actually impose a central buyer,” he said.

Picker said it’s uncertain who might fill that role, but the state’s big investor-owned utilities — Southern California Edison, Pacific Gas and Electric, and San Diego Gas & Electric — would be likely candidates.

“We know that we have to keep the grid whole, and we know that … three large central procurers have made it work,” he said.

SCE’s vice president of energy procurement, Colin Cushnie, urged lawmakers at the hearing to make the IOUs central buyers for the sake of grid reliability.

“We do think the central buyer framework should be adopted for local resource adequacy,” Cushnie said. “We also believe that the IOUs, who are the reliability custodians of our grid, should be the ones designated to be those central buyers.”

AB 56 — introduced in December by Assemblyman Eduardo Garcia, a Democrat who sits on the energy committee —would require the PUC and California Energy Commission to provide the legislature with a joint assessment of options for establishing a central statewide procurer of electricity for all retail customers by March 31, 2020. As currently written, Garcia’s bill focuses on procurement of renewable and other “preferred” resources under state law, which include demand response and behind-the-meter generation.

CCAs Seek Joint Procurement

To some, the idea of a central buyer is anathema to efforts to establish local control of energy procurement and distribution.

Beth Vaughan, executive director of the California Community Choice Association, said the problems cited by Picker could be solved by CCAs banding together to buy electricity, as some have already done.

Four CCAs in Southern California are now purchasing as one entity, and Monterey Bay Community Power and Silicon Valley Clean Energy jointly put out a request for 280 MW of solar coupled with 340 MWh of battery storage for two projects in Kern and Kings counties, she said.

“There’s a lot of experimentation going on in terms of joint procurement, in terms of being able to go out and procure those large sums of megawatts that President Picker referred to,” Vaughan told the committee.

Rainy Days Get CAISO Down

Mark Rothleder, CAISO’s vice president of market quality and renewable integration, told the committee the state is still dependent on natural gas peaker plants and imports of out-of-state electricity to meet its evening ramps and peak demand days.

CAISO Vice President Mark Rothleder said stormy days can cut the state’s solar generation by up to 90 percent.

“As we transition to a low-carbon grid, the ISO may find meeting its demand when the renewable supply is not producing, such as evenings or stormy days, becoming more and more difficult,” Rothleder said.

There are some days, he said, when CAISO’s load is served almost entirely by renewable and zero-carbon resources, including nuclear and hydroelectric. Other days, however, solar output drops to 10 to 20% of its installed capacity, requiring the ISO to make up the difference. Behind-the-meter rooftop solar also falls away, meaning those households need thousands of extra megawatts.

That happened during four days in mid-January, he said.

Such a severe reduction in solar meant the ISO had to round up 14,000 MW of imported electricity, equivalent to the output of seven nuclear plants, he said. It was able to do so in January, but such large quantities of imported electricity are not always available, he said. There are times when the whole West is hot, and the interior West and desert Southwest have little electricity to spare.

“We need to secure that [imported electricity] if we’re going to rely upon it,” Rothleder told the committee.

The state’s gas fleet is becoming more economically distressed because it’s not being called on as much and faces competition from cheaper solar power, he said.

“If [gas plants] start retiring in large numbers, we won’t have those resources available,” he told lawmakers.

The challenge, Rothleder said, is maintaining the right set of resources and capabilities to ensure reliability.

“I am not suggesting we should shy away from the challenge,” he said. “I’m saying we need to be thoughtful about meeting that challenge.”

March 12, 2019

ERCOT Stakeholders Dig into Real-time Co-optimization

By Tom Kleckner

ERCOT stakeholders last week began taking a deeper look at real-time co-optimization (RTC), the market tool that procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

Asked by Texas’ Public Utility Commission to “reinitiate discussions” with stakeholders on the tool, ERCOT held a workshop on Wednesday. The PUC, which wants to see RTC “sooner rather than later,” is working to hold its own workshop in early June and is soliciting stakeholder feedback on a list of related issues. (See “PUC, ERCOT Set Real-time Co-optimization Workshops,” Texas PUC Briefs: Week of Feb. 25, 2019.)

Meanwhile, the member-led Technical Advisory Committee, which makes recommendations to the ERCOT Board of Directors, has been gathering member feedback on an RTC task force in advance of its upcoming March 27 meeting. TAC Chair Bob Helton, of ENGIE, said in an email to members that the committee’s leadership would like to see the task force led by two co-chairs reporting directly to the committee.

“The task force would not be a voting body, and [its] leadership would report any recommendations to TAC, including any minority positions,” Helton wrote.

The TAC will endorse the group’s final structure, leadership and other details, with the board making the final decision.

“This is a good opportunity for our stakeholders to come together and work to ensure we design something that helps achieve our objectives and reflects the value of ancillary service,” ERCOT COO Cheryl Mele said at a recent market summit.

ENGIE’s Bob Helton and ERCOT’s Cheryl Mele | © *RTO Insider*

Staff told stakeholders during the workshop that RTC will efficiently coordinate the provision of energy and AS in the real-time market and, similar to the operating reserve demand curve (ORDC), price AS shortages according to their defined demand curves.

Sai Moorty, ERCOT’s market design and analysis principal, said the RTC process will be executed with each security-constrained economic dispatch run, yielding “better visibility of the constraints and the capabilities of the resources.”

“As a result, the system can be operated more economically and reliably,” he said. “This benefits loads by selecting the lowest-cost resources to provide energy and AS.”

Unlike the ORDC, the SCED engine will apply a demand curve for each AS product, establishing offer-based prices for energy and AS types in the real-time market, staff said. The defined AS demand curve will set AS shortage conditions, and ORDC price adders will no longer exist.

“Real-time co-optimization will definitely impact temporary price spikes we’ve seen outside the ORDC,” NRG Energy’s Bill Barnes said at the same summit. “Demand curves for ancillary service … ensure we’re sending proper price signals during times of scarcity.”

ERCOT’s Operations Center | © *RTO Insider*

ERCOT grid operations have not yet identified a reliability need to define a local reserve product, staff said, noting the RTC design will co-optimize the required reserves.

The PUC, which has opened a project for RTC (48540), is considering whether to allow financial-only AS offers.

Staff have said it will take four to five years and about $40 million to implement the RTC process and software.

March 12, 2019April 22, 2024

Overheard at Transmission Summit East 2019

ARLINGTON, Va. — Transmission developers, planners and regulators gathered last week on the top floor of the Key Bridge Marriott, overlooking D.C. from across the Potomac River, for Infocast’s annual Transmission Summit East. Panels and presentations covered a little bit of everything, from energy storage to cybersecurity.

Hoecker, Demarest Propose Interstate Tx Siting Bill

James Hoecker and William Demarest, both senior counsel at Kansas City-based law firm Husch Blackwell, proposed to the conference a legislative solution to the problem of getting high-voltage interstate transmission lines built.

The pair’s proposal would essentially give FERC jurisdiction over siting interstate transmission projects, similar to how the Natural Gas Act gave the commission siting approval over gas projects, but with numerous caveats and exceptions that they said would preserve some state authority. Crucially, only projects that have facilities in multiple states would be subject to FERC approval. Intrastate transmission projects, unlike intrastate gas pipelines, would remain solely under the purview of the states.

Hoecker, a former FERC chairman, said demand for renewable resources is growing as states increase their portfolio targets. Currently, transmission developers must get approval from a “multiplicity” of regulatory agencies in each state their projects pass through, he said. But “if the momentum picks up for interregional and multistate forms of transmission, I think there’ll be a growing drumbeat to somehow limit state authority in this area.”

The desire to access cleaner generation will be come a very powerful force in the transmission industry, Hoecker predicted. But without a good policy, “you could have states essentially getting steamrolled.”

Demarest elaborated on that point, noting his years working for Rep. John Dingell (D-Mich.). When members of Congress “get on a course, they tend to take political, rather than economic … solutions. They are frequently looking for a solution, and it need not be the best solution, because they delude themselves into believing that they can come back and address it and adjust it and fix it, which they never or rarely do.” State regulators and industry need to find a solution before Congress imposes something they don’t like, he said.

Under their plan, transmission rates for interstate service would be regulated by FERC, but any intrastate service rates would be regulated by each state the project serves. It also would not eliminate, nor allow FERC to eliminate, any state rights of first refusal for incumbent utilities to build intrastate projects. These projects would also not be subject to an “affecting commerce” standard, even though they’re still part of interstate commerce.

RTOs would continue their role as planners, but RTO sponsorship would not be necessary. “RTOs, at least in my view, are political critters, often captive to certain stakeholders,” Demarest said.

Order 841’s Impact on New York

New York is a very desirable market for the energy storage industry, but NYISO’s proposed compliance with FERC Order 841 is somewhat concerning, speakers said during a panel on the order’s implementation.

“When we think about what drives the business case for storage … by and large it is the need for capacity,” said Ray Hohenstein, market applications director for storage developer Fluence. Peaking plants are retiring at a faster rate because of the state’s increasing emissions targets. “New York is a state where if they get FERC 841 right, there could be a lot of energy storage that is making money.”

The state’s Public Service Commission has set a goal of 3 GW by 2030, with an interim target of 1.5 GW by 2025.

In its Order 841 compliance filing, NYISO said it would offer four modes for storage resources to participate: ISO-committed fixed, ISO-committed flexible, self-committed fixed and self-committed flexible. In the ISO-committed modes, suppliers would leave it up to NYISO to determine the most optimal dispatch times for their resources.

Last month, the Energy Storage Association filed responses to the grid operators’ compliance filings. With NYISO, the group focused on what it called “rules that bias against self-management of state of charge.”

Steve Wemple of Consolidated Edison, however, had an optimistic view on NYISO managing resources’ state of charge. The ISO would “look at the beginning charge level and look forward and try to find the right pairs of charging and discharging to meet the bidder’s economic desire … so I think that’s very positive.”

Hohenstein agreed. “I think state-of-charge management is one of the keys to unlocking participation in wholesale markets in general. It actually is a really great development to have the ability to … define your beginning and end-of-hour state of charge to ensure that you are available, for instance, if you have to provide a peak reliability service for part of the day. So it provides a lot more certainty.”

As an example, he said a resource could tell the ISO that it was bidding into the frequency regulation market but it has to be fully charged by 6 p.m.

Melissa Kemp, policy director at Cypress Creek Renewables, was skeptical of that. “I think if it were something that nuanced, we would not have a problem with it. My understanding of what they filed is that it’s not that nuanced, and that it’s more ‘We need to control what you’re doing here’ and that there’s a lot of concern from a lot of stakeholders in the ISO process [who] would like the option to select the ISO to control … but that just simply turning over the ability to control the asset to the ISO is a great concern and kind of a nonstarter.”

The ‘Weakest Link’ in Cybersecurity

A panel on cybersecurity focused on figuring out the most effective practices, which speakers said don’t apply to every utility in the country.

Among the panelists was Iowa Utilities Board Member, and president of the National Association of Regulatory Utility Commissioners, Nick Wagner, who said criminal or hostile foreign hackers are probably not interested in taking down a rural, municipal cooperative in his state.

When asked about NERC critical infrastructure protection standards, Wagner said, “I think those are important beginning points. I don’t necessarily [think] they should be a hard-and-fast rule that everybody should follow. One of the nice things about … our grid today is a conglomerate of very different systems, which in itself is inherently secure. So if a person gets in a system of one utility, that doesn’t necessarily mean that they’ll be able to get into every system. …

“Government does not move at the speed of industry. And it certainly does not move at the speed of hackers. So we will, from a standards standpoint, always be behind. And we want our utilities and our industry and our suppliers to move faster than that and be able to keep up with the threats that are out there,” he said.

Instead, Wagner said, industry needs to focus on training employees to recognize hacking attempts. “People are the weakest link,” he said. “Whether we like to admit it or not, we are the weakest link. … I’ve gotten into the habit of, when I get an email from my family, I call them up and say, ‘Did you send this email?’ Because that’s how sophisticated these hackers are getting.”

Pennsylvania Public Utility Commission Chair Gladys Brown said that applies to state regulatory agencies as well. Agencies “have a wealth of information” that hackers would love to get their hands on, she said. Brown said that despite the robust training NARUC directs, even she has fallen for a phishing attempt, when she responded to an email from someone she thought was a state cabinet secretary. (Thankfully there was no link in the email to click.)

As part of the Electric Power Research Institute’s training, the organization sends out its own phishing emails to test its employees, said Ralph King, cybersecurity program manager. And “if you actually click on a phishing email, you get to sit down with someone pretty high up in the company.”

But King also warned that one utility company he worked with went too far in its training. “They had to back it off because all the employees, anything external, they deleted. And so they were missing a lot of emails.”

King also said that many cyber experts think “the biggest threat in the next five years are insider threats. These could be malicious; they could be mistakes.” Noticing unusual employee behavior — logging into a system in the middle of the night, logging into systems they’re unauthorized to access, etc. — will be key to preventing disruptions. He told the story of another company he worked with that had an employee displaying “very odd behavior. And by looking for these things, we actually uncovered a serious health problem that they didn’t know about. So it’s not always malicious; it could be other things. But regardless of what it is, you want to be able to identify it.”

“It may not impact the grid or the system overall, but it can certainly impact you as individuals and be a real pain to have to deal with some of that stuff,” Wagner said.

March 12, 2019

AWEA Balks at PJM Plan on Wind, Solar Capacity

By Christen Smith

VALLEY FORGE, Pa. — The American Wind Energy Association on Thursday said that PJM’s proposal to change how wind and solar capacity values are calculated does not account for the technologies’ performance improvements over the last decade.

After a year of stakeholder discussions, PJM staff will ask the Planning Committee in April to endorse calculations based on effective load-carrying capability (ELCC), which measures the additional load that a group of generators can supply without a reduction in reliability. Jerry Bell, of PJM’s resource adequacy department, presented the Manual 21 changes during the March 7 PC meeting.

PJM’s five-step process for delivery year 2022/23 begins with an average of the ELCCs for each year since 2012/13. The RTO determined that the composite ELCC is 4,181 MW, 21% of the 19,910 MW of nameplate wind and solar capacity projected for 2022/23.

After calculating the ELCC’s for the two generation types separately, PJM then prorated the shares between wind and solar, resulting in capacity factors of 12.3% and 45.1%, respectively. (See “PJM Pushes Change in Wind, Solar Capacity Measurements,” PJM PC/TEAC Briefs: Feb. 7, 2019.)

PJM would assign the ELCCs to existing individual units based on their output during the top 10 daily peak load hours in the 10 most recent delivery years. Future units will get the class average credit unless they request a project-specific calculation.

PJM is proposing to change its capacity calculation for wind and solar resources. In step 1 of the plan, the RTO determined that the composite effective load-carrying capability (ELCC) is 4,181 MW, 21% of the 19,910 MW of nameplate capacity projected for 2022/23. | *PJM*

AWEA Proposals

Travis Stewart, Gabel Associates | © *RTO Insider*

Representing AWEA, Gabel Associates’ Travis Stewart told the PC that the RTO’s proposal understates the current fleet’s capacity value by giving equal weight to all years in the sample.

Stewart said federal data shows wind capacity factors increased from 30.2% to 42.5% between 2009 and 2016, while solar’s capacity factors increased from 20.8% to 26.8% between 2010 and 2016. PJM’s equal weighting ignores the fact that older, less productive projects represent a small share of the current fleet, AWEA says.

“When PJM attaches an ELCC average to the entire renewable generation fleet, it fails to account for the individual generator’s share,” Stewart said.

The association proposed two options for remedying its concerns:

Option 1: Find the average ELCC for each renewable project vintage across all historical years, and then calculate the ELCC for the current fleet by weighting according to each vintage’s share of the current fleet.
Option 2: To account for Option 1’s potential to mask the underlying renewable performance trend, AWEA proposes building a larger dataset by combining each year’s renewable output profile with corresponding load patterns to calculate an average ELCC. The trendline of ELCC change across years could then be used to weight PJM’s results under its current method to recreate what ELCC performance in prior years would have been with the current fleet.

Patricio Rocha Garrido, PJM | © *RTO Insider*

Patricio Rocha Garrido, of PJM’s resource adequacy department, said staff have “some issues” with AWEA’s second option.

“We want to capture the relationship between wind output and load. … Once you start mixing outputs from one year with load shapes from another year, then that relationship gets totally missed,” he said. “You achieve your goal of increasing sample size, but you totally lose that correlation.”

Next Steps

PJM will present a first read of the manual changes at the March 21 Markets and Reliability Committee meeting before seeking an endorsement in April. The discussion will likely rehash stakeholder concerns over the handling of capacity interconnection rights (CIRs). (See related story, Showdown Set on PJM Must-offer Exceptions.)

“We purchased a lot of these CIRs through upgrades. … [PJM is] making a change here; this is not us retiring units,” said John Brodbeck of EDP Renewables. “This is not the good Lord knocking a whole bunch of towers down. This is a decision to rerate units by PJM and that has a different impact than anything else. We don’t like to see our assets taken away.”

John Brodbeck, EDP Renewables | © *RTO Insider*

PJM’s ELCC formula represents a shift in thinking for the RTO, which had been pushing an alternative method using average values. The new methodology is more representative of the incremental value of adding a new unit to the existing fleet, PJM’s Tom Falin said in February.

The Manual 21 changes include a new section devoted to obtaining, maintaining or losing CIRs, as well as sections devoted to installed capacity calculations and testing requirements.

New rules on testing within temperature bounds will take effect June 1 with rules on simultaneous testing and the ELCC effective for delivery year 2022/23. Wind and solar units losing CIRs would be notified before Jan. 1, 2025.

Notably, the testing window for generators remains June 1 through Aug. 31 after stakeholders expressed concerns over an earlier proposal from PJM to instead start in July. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)

PJM wants MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. They would not affect UCAP values from prior auctions.

March 12, 2019

MISO Prototyping Short-term Reserve Product

By Amanda Durish Cook

CARMEL, Ind. — MISO will prototype its proposed short-term reserve product to demonstrate cost and benefits to its members.

The move comes in part at the behest of stakeholders, who want more information on the availability of resources that might provide the reserves; the cost and reliability impacts of a reserve product; and how the product would interact with out-of-market commitments, according to MISO Market Design Adviser Bill Peters.

MISO has said it hopes to roll out the product in mid-2021, supported by its soon-to-be-replaced market platform. (See New MISO Platform Headed to the Cloud.)

The product would be designed to furnish capacity within 30 minutes. The RTO has said it will be especially helpful in MISO South, which has less than 500 MW of offline capacity available within that time frame.

However, Robert Francis, speaking on behalf of the Entergy Operating Companies, questioned whether MISO South’s load pockets even have an adequate number of offline resources to support the 30-minute response time.

“One concern is that there may not be sufficient online and offline resources in the load pockets to enable the proposed product to work as intended,” Francis said in comments to MISO. “Of the load pocket units that are typically online during periods of system stress, are these units historically dispatched at levels that they would lend themselves to the [reserve] product?”

Peters said the reserve product will better compensate available resources while “incenting new capability for offline response.” He said there won’t be a minimum target amount of such reserves.

MISO Director of Market Design Kevin Vannoy said the short-term reserves would differentiate themselves from the current contingency reserves by addressing either an excess of flow on the regional dispatch transfer constraint or restoring normal operating conditions in a load pocket following the loss of a generator sooner to avoid violations of contracts and reliability standards.

“This is a method of making sure we’re able to replenish contingency reserves following a contingency. To date, we’ve been flush, but we’re finding” that reserves are thinning, Vannoy said. He added that the short-term reserve’s price signal will attract more generation willing to furnish reserves.

MISO has published a conceptual design of short-term operating reserves where online resources and offline resources can either register as a supplier or provide availability through hourly offers in the day-ahead and real-time markets. It plans to clear the resources according to opportunity costs, offer prices and a demand curve when insufficient amounts of the reserve exist.

Restoration Energy, Uninstructed Deviations and Tx Settlements

MISO plans to form a task team later this month to begin discussions on how it should price restoration energy — energy delivered to restore the system in the event of the real-time market ceasing to function. The RTO and stakeholders revived the idea of a plan to compensate restoration energy last year. (See Old Analysis Could Guide MISO Restoration Pricing Effort.)

It will also begin holding weekly conference calls Thursday to answer questions about its new uninstructed deviation threshold. The new threshold calculates a generator’s uninstructed deviation with a tolerance based on the minimum of five times the real-time ramp rate or 12% from the average set point instructions. Generators in MISO are currently flagged after they deviate by more than 8% from dispatch signals over four consecutive intervals. (See MISO Plans for New Uninstructed Deviation Rules.)

Lastly, MISO has delayed the introduction of its new transmission settlements system until spring. The new system was slated to go live March 1, but the RTO decided it required more test runs before rollout.

John Weissenborn said MISO decided to delay the new system “to allow testing and validation from market participants.” He said it will schedule a follow-up conference call in the middle of March to evaluate testing progress and discuss implementation.

March 12, 2019

LSE Load Forecast Documents Incomplete, MISO says

By Amanda Durish Cook

CARMEL, Ind. — In an assessment of this year’s load forecast Wednesday, MISO told its load-serving entities they could do more to support their individual forecasts with documentation.

MISO adviser Michael Robinson began the annual load forecast review with an anecdote that Lake Superior was days away from freezing over completely.

“Every 30 or 40 years it typically does this,” Robinson said. “Assuming no forced outages and instantaneous replacement,” it would take one Zamboni 693 years to resurface the lake, he said.

“It hasn’t taken us that long to assess the load forecast, but it has taken us some time,” Robinson joked.

Michael Robinson addresses the RASC. | © *RTO Insider*

He said that while all of MISO’s 140-plus LSEs submitted demand forecasts, supporting documentation was often incomplete.

This year, MISO posted a template of information to emphasize the kinds of information and documentation it expects.

“Last year when we did this, we weren’t happy with the initial response we got from LSEs and the documentation supporting the coincident peak demands,” Robinson said.

Despite the written expectations, Robinson said LSEs again provided spotty documentation supporting their forecasts. MISO this year conducted a random sampling of 11 LSEs with peak demand under 1 MW and 17 LSEs greater than 1 MW, representing 48.5% of the RTO’s peak demand. It said it found “many instances where information was initially missing.”

“Well over half of our LSEs have given us insufficient information on the first go-round,” Robinson said. “We need to do better next year.”

However, Robinson said once MISO got the requested information, it resulted in only minor revisions to the load forecasts.

MISO this year expects a coincident peak load of nearly 122 GW systemwide and a 135-GW planning reserve margin; the RTO says it has about 172 GW of totaled installed capacity to cover it.

This is the last year MISO will use its historic load forecasting method. For its 2020 Transmission Expansion Plan, the RTO will rely on a blended forecast that will have Purdue University’s State Utility Forecasting Group and consulting firm Applied Energy Group work with 20-year forecasts provided by LSEs. (See “MISO Under New Load Forecasting Method,” MISO Planning Week Briefs: Feb. 12-13, 2019.)

Capacity Auction Nearing

MISO will post final Planning Reserve Auction load forecast data on or about March 18 and plans to hold a conference call on the final data March 20. (See MISO Preliminary PRA Data up Slightly from Early Prediction.)

This year’s capacity auction offer window will open at 12:01 a.m. on March 26 and close at 11:59 p.m. on March 29. Results will be publicly available on April 12.

LMR Registration Steady Despite New Requirements

The number of load-modifying resources registering for this year’s auction is in line with last year, MISO’s Eric Thoms reported. The RTO registered 809 LMRs representing 11.7 GW for the 2019/20 planning year. Traditional behind-the-meter generation (BTMG) totaled 340 resources at 3.6 GW, and demand response totaled 280 resources at 7.3 GW. The total also includes 189 intermittent BTM resources at 913 MW.

According to MISO’s count, 48% of traditional BTMG and DR LMRs have a lead time of fewer than two hours, while about 27% have a lead time of between two and six hours. Slightly less than 25% have a notification requirement of six or more hours.

About 81% of the traditional BTMG and DR reported availability for more than nine months out of the year. This is the first year that LMRs had to provide firmer and more clearly documented commitments regarding their availability before participating in the PRA. In years past, MISO LMRs were only required to be available for dispatch in the summer months. (See MISO LMR Capacity Rules Get FERC Approval.)

During the registration process this year, MISO created a bulk LMR registration template to allow market participants could register several LMRs at once, after the RTO noticed owners of multiple LMRs were experiencing a time-consuming process, Thoms said. Because MISO’s Tariff filing was intended to ensure that LMRs are available as promised, resource owners this year had an extended registration deadline. (See “LMR Registration Confusion,” MISO Preliminary PRA Data up Slightly from Early Prediction.)