VALLEY FORGE, Pa. — Exelon told the PJM Operating Committee last week it is near agreement with RTO staff on business rules for non-retail behind-the-meter generation (NRBTMG) that would exclude retail community solar and aggregate net energy metering programs.
Exelon told the Markets and Reliability Committee in August that it approves of the concepts and reporting requirements outlined in the changes to Manuals 13 and 14D but wanted more time to review the differences in the application of the rules — specifically whether community solar programs and aggregate net energy metering are within scope. It asked the MRC to delay its vote for 30 days. (See “Non-retail BTM Generation Vote Delayed,” PJM MRC Briefs: Aug. 22, 2019.)
Since then, both parties have agreed that neither program should fall under the category of NRBTMG. Exelon will bring its revisions to the MRC meeting scheduled for Sept. 26, Sharon Midgley, the company’s director of wholesale development, told the Operating Committee on Sept. 10.
NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary service and administrative fee charges.
Hot August Spawned 4 Weather Alerts
Soaring temperatures last month spawned four hot weather alerts Aug. 18-21. A feedwater control valve issue also tripped units at Salem 2, creating the first spinning event of the summer.
Manuals Endorsed
Staff must update all three manuals to comply with FERC Order 841’s energy storage participation mandates.
Manual 14D adds metering requirements specific to energy storage resources, outage reporting requirements and generating unit reactive capability curve specification and reporting procedures.
In Manuals 36 and 40, PJM updated the exception to critical cranking power to include non-hydro energy storage resources and added a lower megawatt threshold for electric storage resource training requirements.
CARMEL, Ind. — MISO will suspend updates on its resource availability and need (RAN) project through November to allow time for analysis that may drive future draft rules.
During a Resource Adequacy Subcommittee meeting Wednesday, MISO planning adviser Davey Lopez said the RTO will skip the monthly RAN presentation at next month’s meeting to analyze its loss-of-load methodology, a possible seasonal auction and new capacity accreditation for planning resources.
By the first half of 2020, MISO expects to finish a filing to alter capacity accreditation.
MISO is mulling an available capacity estimate that includes a measure of historical availability and the impact of planned and maintenance outages in addition to already-counted forced outages. The RTO is also considering distinct accreditations for intermittent, load-modifying and emergency-only resources.
MISO also wants its loss-of-load expectation modeling “more closely aligned to the real world,” Lopez said. The new LOLE may rely on seasonal data and might become a seasonal result itself. More detailed data, including extreme weather scenarios, historical outages, actual load-modifying resource participation, external assistance from neighboring balancing authorities and the capabilities of intermittent resources may be incorporated.
Customized Energy Solutions’ Ted Kuhn urged MISO to be innovative in adjusting or redefining seasons. He said it might be that September is found to be sufficiently risky that it warrants a spot among the summer months, or a separate loss-of-load risk might need to be defined for winter.
“Just be thoughtful when you go through these, and don’t straight jacket solutions,” Kuhn urged.
Lopez said MISO will examine monthly risk and whether it should change the calculations behind its planning reserve margin and local reliability requirements.
MISO’s fall pause doesn’t mean other smaller RAN initiatives are on hold. The RTO expects to make a filing by October to improve the modeling of LMR participation in the capacity auction and create “reasonable expectations” for capacity availability during the planning year.
New PRA Deadlines Before FERC
MISO has filed with FERC to shift the offer window times and data submission deadlines for its Planning Resource Auction (ER19-2559).
The changes would allow more time for market participants to prepare data submittals to MISO and end the RTO’s middle-of-the-night closings and openings of the offer window.
MISO Manager of Capacity Market Administration Eric Thoms said the RTO expects a FERC ruling before the RASC meeting Oct. 9.
The filing would take effect beginning with the 2020/21 PRA, altering deadlines for demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data. In most cases, the deadlines would be extended into the winter from late fall. (See “Timeline Change Next Year,” MISO Ponders Changes After Latest PRA.)
MISO is also proposing to open and close the offer window during normal business hours instead of the usual midnight-to-midnight run of the four-day window. The RTO requested permission to open the offer window at 8 a.m. ET and close at 6 p.m.
Thoms also said the RTO is readying the 2020/21 PRA in MISO software.
CONE Increases
MISO also filed its annual update of cost of new entry values this week, with prices up over last year’s estimates across all local resource zones (ER19-2781).
This year, staff and the Independent Market Monitor calculated the CONE at an average $251/MW-day for the entire footprint. Last year, the average CONE was about $238/MW-day footprint-wide.
Arkansas and East Texas’ Zone 9 has the lowest CONE value of about $237/MW-day, while Lower Michigan’s Zone 7 has the highest, with about $258/MW-day.
MISO’s CONE is used as the RTO’s maximum clearing price and maximum clearing offer in the PRA. CONE represents the estimated cost of constructing a 237-MW combustion turbine in different locations in the footprint.
Stakeholders asked why CONE numbers were up year-over-year. To that, MISO adviser Michael Robinson pointed to the philosophy behind Isaac Newton’s and Gottfried Wilhelm Leibniz’s calculus of infinitesimals.
Robinson said “several contributing factors” — including small upticks in cost of debt, operation and maintenance costs, and tax rates — contributed to the increase.
“When you add them all up, it contributes to about a 5 to 6% increase,” he said.
Wind, Solar, Storage Focus of New Deliverability Proposal
MISO will move ahead with a stricter capacity deliverability requirement for its intermittent planning resources.
“This is something we’re going forward with, so it’s not up for debate if we are or aren’t going to do this,” MISO’s Darrin Landstrom said.
Landstrom said MISO would return with a proposal and examples at the Oct. 9 RASC meeting.
According to the RTO, stakeholders were most receptive to an approach that would use an intermittent resource’s transmission service request value as the maximum output for calculating the average capacity factor, which would reduce capacity credits. (See MISO Deliverability Plan Prompts Skepticism.)
MISO expects to make a FERC filing in December. The proposal would only apply to wind, solar and electric storage resources that offer capacity beginning in the 2020/21 planning year. The RTO draws a distinction between conventional and intermittent resources for deliverability.
Still, some MISO stakeholders maintained last week that the RTO has not demonstrated its current process is causing stranded intermittent capacity during peak hours.
But Landstrom said the proposal will stave off potential problems from MISO assuming planning resources will perform to an installed capacity deliverability level when they’re only required to demonstrate deliverability up to an unforced capacity level.
“The IMM [and] FERC have recommended we close this gap, and MISO agrees with them,” Landstrom said.
Former FERC Commissioner Cheryl LaFleur was elected to a three-year term on the ISO-NE Board of Directors on Friday, just two weeks after leaving her job in D.C.
LaFleur will replace Director Raymond Hill, who is completing his third consecutive three-year term this month.
Re-elected were Directors Barney Rush and Vickie VanZandt, each of whom will begin their third consecutive term, the maximum allowed. Absent a waiver, an incumbent board member cannot serve more than three consecutive three-year terms.
Although LaFleur’s second term on FERC ended June 30, she served until the end of August, as allowed by law in the absence of a successor. She announced she would not be appointed to a third term in January. (See LaFleur Announces Departure from FERC.)
Returning to New England
The announcement represents a homecoming for LaFleur. Prior to joining the commission, LaFleur worked at National Grid, ultimately serving as executive vice president and acting CEO of the U.S. subsidiary. She had served at various times as COO, president of the company’s New England distribution companies, and general counsel.
LaFleur said in a statement that she was excited to join the board. “New England is my home and where I have spent most of my career, and I welcome the opportunity to be part of an organization that serves electricity consumers across the region.”
ISO-NE Board Chair Philip Shapiro said LaFleur “not only will bring insights from her long tenure at FERC, but also from her experience at National Grid.”
“Cheryl is a welcome addition to the ISO New England board,” ISO-NE CEO Gordon van Welie said. “The sum of her career experience will be put to good use as the region’s grid continues its transition to a future with cleaner, more distributed resources.”
Barney Rush | ISO-NE
Rush also serves on the board of Azure Power Global, which develops solar plants in India, and is a senior representative for Fieldstone, a regional investment bank that raises capital for power plants and infrastructure in Africa and other emerging markets. He is the former group CEO for Mirant Corp. in Europe. He is also the mayor of the town of Chevy Chase, Md.
VanZandt runs VanZandt Electric Transmission Consulting, based in Washington state, and is the Western Electricity Coordinating Council’s program manager for the Western Interconnection Synchrophasor Program. She retired from the Bonneville Power Administration in 2009 after 35 years, including a position as its senior vice president of transmission services. She served as BPA’s chief engineer for a decade.
Committee Assignments
Vickie VanZandt | ISO-NE
The slate of board candidates is selected by the Joint Nominating Committee, endorsed by members of the New England Power Pool’s Participants Committee and confirmed by the board and the New England Conference of Public Utilities Commissioners (NECPUC). The nominating committee is composed of 14 members: six PC members representing their sectors; one member of NECPUC; and seven members of the board.
Van Welie announced that the board had also elected Director Kathleen Abernathy to replace Shapiro as chairperson. Committee assignments, as listed in the CEO report posted with the meeting materials, are as follows:
Audit and Finance Committee: Michael Curran, LaFleur and Shapiro, with Christopher Wilson as chair;
Compensation and Human Resources Committee: Abernathy, Brook Colangelo and VanZandt, with Roberto R. Denis as chair;
Joint Nominating Committee: Abernathy, Curran, LaFleur, Rush, VanZandt and Wilson, with Shapiro as chair;
Markets Committee: Curran, LaFleur and Wilson, with Rush as chair;
Nominating and Governance Committee: Abernathy, Curran and Rush, with Shapiro as chair;
System Planning and Reliability Committee: Colangelo and Denis, with VanZandt as chair; and
Special Committee on Information Technology and Cyber Security: Colangelo and Wilson will serve on the temporary committee, with Colangelo as chair.
Age Limit
Voting directors on the RTO’s board serve staggered, three-year terms. A nominee cannot stand for election or re-election if they have reached the age of 71.
However, on Aug. 15, ISO-NE and NEPOOL filed amendments to the Participants Agreement to authorize the Joint Nominating Committee to waive the age limit (ER19-2616). That filing is currently pending and, if accepted, would permit the amendments to become effective Oct. 15.
ISO-NE said each of the candidates on the 2019 slate was under the age limit but declined a request for the current board members’ ages, calling it “personal information.”
“I can tell you that candidates’ ability to meet eligibility requirements are evaluated by the members of the Joint Nominating Committee and then by members of the NEPOOL Participants Committee, and all members of the board, including the slate taking office Oct. 1, currently meet the eligibility requirements,” ISO-NE Spokeswoman Marcia Blomberg said.
BOSTON — More than 150 people turned out for a public forum Thursday to discuss ISO-NE’s draft 2019 Regional System Plan (RSP), which uses a 10-year planning horizon to estimate the need for energy resources.
Anne George, vice president for external affairs and corporate communications at ISO-NE, welcomed the participants, including several members of the RTO’s Board of Directors, as well as state officials.
Among those in attendance: New Hampshire Public Utilities Commissioners Kathryn Bailey and Michael Giaimo; Jared Chicoine, director of the New Hampshire Office of Strategic Initiatives; New Hampshire Rep. Kat McGhee; Andrew Landry, Maine deputy public advocate; and Massachusetts Department of Public Utilities Commissioner Matt Nelson.
“We’re pleased to have with us experts on not only what’s happening in the energy space in New England, but what’s happening in other regions and other industries as well,” ISO-NE Director Vickie VanZandt said. “The energy industry is changing, and there are many questions that we’re all asking. How will residences and businesses be using electricity 10 years from now? What resources will be supplying that energy?”
VanZandt on Friday was re-elected to her third consecutive three-year term, as was fellow Director Barney Rush. They shared the slate with former FERC Commissioner Cheryl LaFleur, who was elected to her first term. (See related story, LaFleur Elected to ISO-NE Board.)
The following is some of what we heard at the forum.
Green and Lean
Young people that want to make a difference in the world should get into the area of electrical energy, said Damir Novosel, president and founder of Quanta Technology, as he delivered a keynote presentation on resilient and affordable energy.
“Sometimes we are not communicating this to the young generation,” Novosel said.
He had additional advice for the grown-ups in the room.
“Another point is that as you make regulatory and business decisions, it’s so important to look at the technical facts,” he said. “Objective technical facts or issues are very often distorted for the sake of some business or political aspects. … I want to make sure here that society looks at a technical fact as the key to be able to make some of the decisions going forward.”
Today’s decisions will affect the future grid, “so it’s important we get our grid modernization priorities right,” Novosel said.
“What we’re finding is that retirement is a key driver for new resources … and near load is the best place to develop new resources, particularly [in] southern New England,” Henderson said. “I do ask developers to exercise caution, because resources must be situated where they work best on the system electrically.”
The interconnection queue determines reliable points of interconnection, he said. As of April 1, there were more than 19,000 MW of resources in the queue, including more than 11,300 MW of wind (9,000 MW of which is offshore), almost 3,100 MW of large-scale solar and about 1,400 MW of battery storage.
“ISO-NE now uses cluster studies that can account for allocating transmission interconnection costs among developers seeking to interconnect to the system. The first such study was completed for northern and western Maine, and the second one, essentially in the same area, is planned for completion by the end of this year,” Henderson said.
As he had at the previous week’s Consumer Liaison Group meeting in Portland, Maine, Michael Macrae, energy analytics manager at Harvard University, asked how the RTO plans to improve its emissions reporting, particularly on locational marginal emissions. (See “Emissions Reporting,” Overheard at ISO-NE Consumer Liaison Group: Sept. 5, 2019.)
“There’s always a lag in these reports,” Henderson said. “The 2018 report won’t come out until late this year, and that does account for the units that are locational and marginal units on our system. In terms of real-time data, I do know that it’s something we’ve been thinking about, not so much real-time, but perhaps after the fact, maybe a week later.”
Henderson emphasized that the RTO might “be looking at posting something a week or so afterward, as doing so in real time could cause any number of issues, ranging from data to releasing market intelligence that we shouldn’t in real time.”
Disruptive Technologies
ISO-NE Director Brook Colangelo moderated a panel on disruptive technologies.
Marshall Van Alstyne, professor of information systems at Boston University, discussed how new technologies are disrupting other industries and how the new phenomenon of “network economics” or “platforms” affects the energy industry.
“We are going through a fundamental shift in the nature of how work is done,” Van Alstyne said.
For evidence, he compared the market capitalizations and number of employees for century-old industrial giants like BMW and General Electric with the new titans such as Apple and Facebook, which can have three to five times the market capitalization on a mere 20% of the workforce.
“I can promise you the engineering’s always going to be the same; physics don’t change,” said
Katherine Prewitt, president of transmission for Eversource Energy, answering Colangelo’s question about her “favorite” disruptive technology. “The engineering, as complicated as it is, is the easiest part.”
Mark O’Malley, chief scientist for energy systems integration at the National Renewable Energy Laboratory, said, “Your change here is irrelevant. If you think you’ve got issues now, wait and see what’s about to come. New England is actually a fairly lackluster place when it comes to change. You’ve virtually no renewables on your system.
“All you have to do is be nice to the Canadians, be nice to Hydro-Québec,” O’Malley said. “They have supply equivalent to 2 billion Tesla cars.”
O’Malley said the 2019 RSP’s approximately $1.3 billion in transmission spending is a drop in the bucket compared with expenditures in other parts of the world: “The Chinese are building multiple transmission projects thousands of miles long.”
As for a five-year planning horizon, O’Malley said that in 2005 planners were looking at 2 GW of wind penetration in Ireland in a couple decades, which looked like “an extraordinarily high number, way out there, but now it’s 2020 and [Ireland has] 5 GW. … My point is that if you’re thinking large, in a few years it will look small.
“I think people will change, how we think [about technology] will change, so it’s a social change rather than technological,” O’Malley said.
“People have been moving in the absence of the grid operator, and in the absence of the utilities for years,” said David Ismay of the Conservation Law Foundation. “I like what I’m starting to hear, but again, you’re 10 or 15 years back.”
Rep. McGhee, who sits on the state House Science, Technology and Energy Committee, said, “It’s been interesting to see the ISO is dedicated to reliability, and the generators’ organization is working on rates, and the overall sense of urgency with the public that something needs to be done, and it needs to be done soon.
“The goals are also not really as aligned as they should be because bending the carbon curve is the thing we should all be in service of,” McGhee said. “Where does that fit into the paradigm of the regional plan?”
Last September, we documented the gradual departure of more than 25 GW of independent power producer-owned and -operated generation out of MISO.1 Today we will review and disclose the fundamental cause as to why merchant generation has been forced to exit MISO. As background, more than 22 years ago, the functional unbundling of transmission and generation assets as required under FERC’s landmark Order 888 was intended to promote wholesale competition among generators and preclude vertically integrated utilities from restricting access to the transmission system in order to favor their own generation resources.2 The first and most important fundamental characteristic FERC defined was independence, and those RTOs approved as consistent with Order 2000 were required to be independent in their decision-making process, with FERC explicitly stating, “the regional transmission organization must have a decision-making process that is independent of control by any market participant or class of participants.”3 My late wife, Karen, had always questioned the entire concept of “ISO independence,” dating back to the end of my time at FirstEnergy in 1997, when she steadfastly maintained that an ISO’s independence was never a realistic hypothesis because the ISO’s decision-making process would never be the product of truly independent thinking. Karen loved to ponder and debate the question of independence with family, where she concluded there was no such thing as independence. When dealing with the human element, she insisted that once we are born, it is universally true that because the human condition it is not possible to be independent. Each and every living being evolves and grows and gradually becomes a product of their environment based on their life’s experiences.
To address this reality, the ISO’s senior management must be populated with industry experts with a deep-seeded awareness and responsibility that it is incumbent upon the RTO/ISO to remain fair and balanced in its decision-making process and not appeal solely to the interests of those business models representing the majority. Unlike the rest of the country, RTOs are not a democracy subject to majority rule; instead, they are supposed to be independent and also represent the interests of those in the minority. The MISO transmission owners are collectively a class of participants, which, except for the standalone transcos, are composed of vertically integrated utilities that also own and operate a significant amount of affiliated generation assets. As such, MISO is purportedly independent and precluded from making market design decisions that would favor the TOs, which have voluntarily transferred functional control of their assets over to the RTO. This lack of independence is not unprecedented, given MISO senior management’s favoritism of certain TOs, including Ameren, Northern Indiana Public Service Co. and FirstEnergy in the context of a preferential and more lucrative distribution of revenue sufficiency guarantee payments, which was the subject of a nonpublic investigation performed in 2007 by the FERC Office of Enforcement (IN07-32).4
In 2011, things really “hit the fan,” as MISO received FERC acceptance of its current Planning Resource Auction design, relying on a fundamentally flawed vertical demand curve under a residual capacity construct.5 This design certainly favored the incumbent TOs because by operating under a vertical demand curve, even the slightest surplus results in near zero auction clearing prices that cannot sustain merchant generation over the long term and has resulted in the continued inevitable demise of merchant generation. More recently, in a protest concerning MISO’s refiling of its entire PRA construct, which has resulted in unreasonably low auction clearing prices ranging from $1.50 to $10/MW-day in recent years, the RTO’s own Independent Market Monitor, David Patton, stated:
“The commission relies on well-designed competitive markets to produce prices and market outcomes that are just and reasonable. No objective analysis of the MISO capacity market could demonstrate that the outcomes under the current Module E are just and reasonable by any appropriate standard. In fact, the flawed design of the market precludes it from producing just and reasonable prices. … Further, MISO made no attempt to provide evidence that its capacity market has produced reasonable outcomes or that it is an economically sound market design.”6
| Coalition of Midwest Power Producers
Patton has demonstrated that with a properly shaped demand curve, the auction clearing prices would be in the range of $65 to $150/MW-day. The vertically integrated entities comprise 95% of the MISO market and are subject to traditional cost-of-service regulation administered by state regulatory commissions, where, based on publicly available FERC Form 1 data, the affiliated generators received on average $300/MW-day for capacity cost recovery as collected within the utilities’ bundled retail rates. In filing this flawed approach, and arbitrarily favoring the generation assets affiliated with the MISO TOs back in 2011,7 the underlying silent intent on MISO’s behalf was aimed at ensuring the remaining TOs stayed put in the RTO and has forced a large majority of the merchant generators to exit, leaving the TOs owning generation with the dominant market share.
While Order 888 promoted open access to the grid, MISO’s TOs still retain significant influence and leverage over MISO’s market design decisions, given the ever present veiled threat to pull their assets out. This has resulted in an inherent bias on MISO’s behalf to support a capacity construct that favors “The Owners” and their affiliated generators. It’s no coincidence that FERC accepted MISO’s flawed capacity construct right after FirstEnergy and Duke Energy Ohio had decided to leave MISO for PJM’s better designed forward capacity market. The continued departure of otherwise economic merchant owned generation will eventually leave consumers in a “market” dominated solely by the incumbent vertically integrated utilities owning the major market share of MISO’s total generating capacity. The Organization of MISO States needs to do what is best for their ratepayers because consumers will be harmed and eventually see a rise in prices given the absence of competitive supply alternatives.
Promoting competition among wholesale generators was one of the cornerstones of Orders 888 and 2000 and has been severely compromised because of a lack of independence in MISO. This is not the result of unintended consequences. Wholesale competition in MISO is in danger of extinction given the rapid departure of competitive merchant generation. The facts demonstrate MISO purposely and consciously designed its resource adequacy construct to unduly discriminate against the economic interests of merchant generators in violation of the independence requirement, by arbitrarily benefiting the financial interests of those generation assets affiliated with MISO’s vertically integrated TOs. This untenable situation is not working as originally envisioned by our federal regulators in D.C., where Orders 888 and 2000 were designed to promote wholesale competition among generators — not kill it!
Mark J. Volpe is the president & CEO of the Coalition of Midwest Power Producers (COMPP), a nonprofit trade association focused on the continued evolution of fully robust wholesale energy and capacity markets in MISO. He is the former Senior Director of Regulatory Affairs for Dynegy Inc.This column does not represent the opinion of COMPP or any of its members.]
4FOIA FY 2011 Log Report – Federal Energy Regulatory Commission.
5Midwest Independent Transmission System Operator, Inc. Filing to Enhance RAR By Incorporating Locational Capacity Market Mechanisms (“Resource Adequacy Filing”), Docket No. ER11-4081-000 filed July 20, 2011, and order accepting MISO Resource Adequacy Proposal, 139 FERC ¶61,199, June 11, 2012.
6See Motion to Intervene Out of Time and Protest by MISO’s Independent Market Monitor, FERC Docket No ER18-462, page 4, Feb. 7, 2018.
UNION, Wash. — Sadness over the recent death of Robert Kahn suffused this year’s annual meeting of the Northwest & Intermountain Power Producers Coalition, where speakers remembered and praised the energy veteran.
Kahn, the longtime executive director of NIPPC, died in early August following a brief battle with cancer.
In addition to his policy expertise and advocacy, Kahn was known for organizing the trade group’s annual meeting at the Alderbrook Resort & Spa on Washington state’s Hood Canal, a natural fjord that’s part of Puget Sound.
In a lunchtime address, Elliot Mainzer, head of the Bonneville Power Administration, acknowledged the rain pouring outside the hotel conference room Sept. 9.
“I think it’s pretty appropriate the sky is shedding a few tears today for Bob,” Mainzer said as he began his remarks.
“Bob was a really good friend,” he said. “He was a guy who could take you to task and then join you for a beer. [He was] one of a kind. We’re going to miss him.”
A sign memorializing Kahn stood at the entrance to the meeting. It implored members to “Carry On!” — one of Kahn’s favorite expressions.
NIPPC’s lifetime achievement award was renamed for Kahn this year. Before he died, Kahn selected its recipient, Randy Hardy, a former BPA administrator and superintendent of Seattle City Light.
“I can think of no one more deserving,” Kahn had written.
Hardy introduced the meeting’s final presenter Sept. 10, Arne Olson of Energy and Environmental Economics.
“I felt his presence throughout this event, even in his absence,” Olson said. “I think that says a lot about the size of his personality, that he can still dominate this event; the event can still be Bob’s event, even after he’s gone. I think that personality will really be missed in the region.”
Olson said Kahn used his standing in energy circles to be “a thorn in the side of the utilities, a persistent advocate for competition and a breath of fresh air from the outside in an industry that, from my perspective, really, really needs that.”
As part of a carbon policy panel, Glenn Blackmon, with the Washington State Energy Office, noted his state recently passed a bill mandating electric utilities to rely on renewable and carbon-free energy sources by 2045. California passed a similar bill last year.
The measure, SB 5116, is far more detailed than California’s landmark SB 100 but still requires policymakers to tackle thorny problems, he said.
“One of those areas is figuring out how to make our clean electricity policy work with the regional markets,” Blackmon said. “We want to make sure that our utilities and other power suppliers are able to participate [and] get the benefits of organized markets. But we also want to make sure we meet the clean electricity objectives of our statute.
“We’d like to see the markets develop in a way that if you want to trade clean … you’re able to do that,” he said.
CAISO’s Western Energy Imbalance Market and SPP’s new Western Energy Imbalance Service (WEIS) are generally seen as a way to buy and sell clean energy across the Western Interconnection. Concerns linger, however, about the uneasy alliance between the coal-burning states of the interior West and coastal states seeking to go all-green. (See Patchwork of Carbon Policies Troubles Western EIM.)
“It looks like there is going to be meaningful competition for market platforms in the West, which I think is a good thing,” Steve Wellner, FERC’s director of Western regulation, said at the NIPPC meeting.
If BPA joins the EIM, as it hopes to do by 2022, it would bring an area of the Pacific Northwest the size of France into CAISO’s interstate wholesale trading market. In June, BPA kicked off a monthlong public comment process in hopes of signing an implementation agreement with the EIM this month. (See Customers Probe BPA on EIM Impact.)
“We got 100% support for signing that agreement,” Mainzer told the NIPPC audience.
CAISO is evaluating adding an extended day-ahead market (EDAM) to the real-time EIM to increase its usefulness as a regional marketplace, and the BPA administrator said he believes the EDAM is needed to help move BPA’s hydropower and other renewable resources across the West.
“It’s not going be enough to sell all this stuff on a five-minute market,” Mainzer said.
PG&E Corp. announced Friday it had reached an $11 billion settlement agreement with nearly all the insurers trying to recoup their payments to victims of wildfires sparked by the utility’s equipment in the past two years.
The insurers — collectively known as the Ad Hoc Subrogation Group — were the second largest bloc financially, after wildfire victims, that PG&E had to confront in its Chapter 11 reorganization proceedings begun in January.
The agreement must be approved by the bankruptcy court, along with other settlement offers by PG&E. The company had already agreed in June to settle claims by local governments and agencies against it for $1 billion.
“Today’s settlement is another step in doing what’s right for the communities, businesses and individuals affected by the devastating wildfires” of 2017 and 2018, PG&E CEO Bill Johnson said in a news release.
PG&E is attempting to exit bankruptcy by June 2020 to be able to take advantage of a new $21 billion wildfire recovery fund established by the state of California to compensate fire victims. The fund was created by Assembly Bill 1054, passed in July. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
It’s also trying to head off what’s essentially a hostile takeover attempt by its unsecured bondholders, which have offered PG&E a $30 billion cash infusion in exchange for a controlling interest in the utility and guaranteed payment of their notes. (See Judge Weighs Competing PG&E Bankruptcy Plans.)
In a separate statement, the Subrogation Group said it was accepting a settlement that’s a little more than half of what insurers claim they’re owed.
“While this proposed settlement does not fully satisfy the approximately $20 billion in group members’ unsecured claims, we hope that this compromise will pave the way for a plan of reorganization that allows PG&E to fairly compensate all victims and emerge from Chapter 11 by the June 2020 legislative deadline,” it said.
The deal PG&E struck with insurers is $2.5 billion more than the trust, capped at $8.5 billion, that PG&E proposed in its reorganization plan filed Sept. 9. In that plan, $16.9 billion was to be split about equally between individual wildfire victims and insurance companies. (See PG&E Offers $16.9B for Wildfire Claims in Chap. 11 Filing.)
Whether the increase for insurers means wildfire victims could get less will be determined in court, but victims’ lawyers had already criticized PG&E’s initial plan of compensation as falling far short of what they deemed acceptable.
PG&E filed a document Friday with the U.S. Securities and Exchange Commission showing it had secured promises of $14 billion in new equity investment to help cover its wildfire payment plan. It also said it was increasing its total compensation package for victims, insurers and local governments by $1 billion — still $1.5 billion short of Friday’s proposed increase for the subrogation claimants.
PG&E filed for bankruptcy in January, saying it couldn’t afford at least $30 billion in wildfire claims from a series of deadly and hugely destructive fires in 2017 and 2018.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) said PG&E equipment sparked November’s Camp Fire, the deadliest and most destructive in state history, and a rash of fires in Northern California wine country in October 2017.
Insurance is helping homeowners rebuild from the Tubbs Fire, which destroyed part of Santa Rosa, Calif. | City of Santa Rosa
Cal Fire determined a private landowner’s faulty wiring started the Tubbs Fire, which leveled part of the city of Santa Rosa, killed 22 people and caused billions of dollars in damages in October 2017. But Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, allowed fire victims and insurers to move ahead with lawsuits in state court that blame PG&E for the Tubbs Fire.
Friday’s settlement includes the Tubbs Fire, a PG&E spokeswoman said, though the lawsuit remains active for now, pending the bankruptcy court’s approval of the settlement.
PG&E’s beleaguered stock price rose nearly 11% after Friday morning’s announcement, going from $10.10/share at close of trading Thursday to $11.18/share by 4 p.m. Friday.
CARMEL, Ind. — MISO doesn’t expect any challenges meeting demand this fall, announcing last week that its supply should outpace its relatively tame peak forecast by about 36 GW.
The RTO estimates it will have 148 GW in total available capacity for the season, plenty to cover an expected 112-GW fall peak.
“That 112 GW is 3 GW lower than what we experienced in September 2017,” Jeanna Furnish, MISO manager of outage coordination, said at Thursday’s Market Subcommittee meeting.
But in keeping with the past several seasonal assessments, the RTO was careful to say that high-load, high-outage scenarios could trigger emergency procedures.
To generate its load forecasts, MISO partly relies on data from the National Oceanic and Atmospheric Administration, which has predicted higher-than-normal temperatures for the southern and eastern portions of the RTO’s footprint.
Furnish began the seasonal outlook by polling stakeholders on a family dispute. “When does fall start? The astronomical definition of Sept. 23 at 3:50 a.m. [EDT], or the meteorological definition of Sept. 1?”
Those at MISO’s headquarters overwhelmingly favored the astronomical approach.
MISO’s fall, however, is effective throughout September, where the risk of emergency procedures is most pronounced in the face of high load. During the month, the RTO could dip into its load-modifying resources and operating reserves in a 117-GW, high-load scenario even when outages aren’t considered a problem.
Furnish said a high-load, high-outage scenario paints a “bleaker picture” in which MISO might use the top end of its 13.7 GW in reserves. However, the RTO expects an average 111.3 GW of probable load during September. In October and November, MISO load is not expected to exceed 96 GW, and probable load will likely hover around 90 GW.
Furnish ended by joking she wouldn’t be doing her MISO duty if she didn’t urge members to submit outages as early as possible.
“Please make sure your company’s outages are in, for not only this fall, but also next spring. … It’s never too early to think about spring,” she said.
CARMEL, Ind. — After experiencing a surge in new projects, MISO is hoping bring solar generation under the umbrella of its dispatchable intermittent registration for market participation, the RTO signaled last week.
MISO’s proposal, issued Thursday, seeks to put solar generation on par with wind generation in the dispatch process. The method to be used provides a bit of déjà vu for some seasoned stakeholders.
Kun Zhu, MISO manager of resource retirement, said the proposal was precipitated by the flood of solar projects lining up for interconnection. “Quick story: Based on what’s coming in the queue, we’re set to have a big surge in solar,” he said in opening the Market Subcommittee meeting Thursday. “Now we expect the same challenge we saw 10 years ago,” referring to the wind generation boom that took hold about a decade ago.
Zhu said MISO’s plan is to require future commercial solar generation to register as dispatchable intermittent resources (DIRs), as it does for wind resources. Currently, solar generators can choose to be DIRs or simply remain intermittent resources, which are price-takers in the market and ineligible for dispatch. DIRs can submit price-sensitive offers and be dispatched by the market.
While MISO currently has just 243 MW of solar under the DIR registration, it reports that more than 9 GW worth of solar projects have executed generation interconnection agreements or are close to doing so. Beyond that, about 52 GW of solar are in the early stages of the interconnection study process.
“The time is now to expect the challenge and mitigate it,” Zhu said, adding that MISO can avert the growing pains it experienced in 2008 and 2009 when operators had to initially manually curtail wind generation over the phone. “It was cumbersome and not optimal and not ideal, and it caused big challenges in the control room.”
MISO won FERC approval in 2011 to create the DIR category for wind.
“We’re bringing solar to the same playground as wind,” Zhu said, pointing out that FERC recently accepted a similar change to solar treatment in SPP.
Just as in the original DIR filing for wind, MISO is proposing a two-year transition period to register solar resources. Solar projects with interconnection agreements before the time of the filing have two years to convert from intermittent resources to DIRs. Solar projects with no interconnection agreement in place before the effective date of the new tariff rule must register as DIRs immediately with no grace period.
MISO
Customized Energy Solutions’ David Sapper asked how the proposal would treat hybrid solar and storage projects.
Zhu said the hybrid angle is outside the scope of the proposal — for now. MISO is holding a special workshop in early October to discuss the rules and implications around hybrid projects. (See MISO to Host Hybrid Projects Workshop.)
“Hybrid is a new topic. What we’re discussing now is 100% pure solar generation, limited by the weather,” Zhu said.
MISO hopes to make a Tariff filing sometime in December.
FERC last week rejected Louisville Gas & Electric and Kentucky Utilities’ proposed transition for exiting from market power mitigation measures the commission had imposed to address the companies’ 1998 merger and withdrawal from MISO in 2006 (ER19-2396, ER19-2397).
The rate de-pancaking mitigation provisions were imposed to resolve horizontal market power concerns. In March, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers after the mitigation is removed. It conditioned the removal on a transition mechanism to protect customers that had relied on transmission service on the MISO system.
FERC said that “although it determined that there would continue to be a sufficient number of competitive suppliers in the LG&E/KU market if the de-pancaking mitigation was terminated, termination will affect the relative economics of competing suppliers in different markets by making the cost of purchases from resources located in MISO more expensive.”
Eligible for the transition were contracts by the Kentucky Municipal Power Agency to supply KU requirements customers that went into effect on May 1; a requirements contract between the city of Benham and American Municipal Power; a requirements contract between the city of Berea and AMP that went into effect on May 1; and a contract between the city of Owensboro and Big Rivers Electric Cooperative.
The commission said the proposed transition mechanism filed by the companies in July was overly narrow and spelled out changes the companies must make regarding which customers and power purchase agreements should be covered and the definition of “covered” transmission service requests. It also ordered changes regarding which MISO schedules are eligible for reimbursement, reimbursement adjustments and the handling of exports.
In an accompanying ruling rejecting rehearing of its March order, the commission also identified three additional customers as eligible for the transition: KYMEA and member cities Paducah and Princeton (EC98-2-002, ER18-2162-001).
LG&E serves 411,000 electric customers in Louisville and 16 surrounding counties. KU serves 553,000 customers in 77 Kentucky counties and five counties in Virginia. The two companies, which are now PJM members, are owned by Allentown, Pa.-based PPL.
