ATLANTA — The ballroom at NERC’s Human Performance Conference was pin-drop quiet Wednesday as Joseph W. Pfeifer, former chief of counterterrorism and emergency preparedness for the New York City Fire Department, gave an hourlong speech recounting his experience leading firefighters into the World Trade Center on Sept. 11, 2001.
Pfeifer’s experience was captured in brothers Gédéon and Jules Naudet’s documentary, “9/11.”
One of the filmmakers accompanied Pfeifer, then a battalion chief, as he and his men rushed to the World Trade Center after the North Tower was hit by the first highjacked airliner at 8:46 a.m. The film captured the chaos and confusion when the second plane hit the South Tower at 9:03 a.m., then the collapse of the South Tower at 9:59 a.m., which left the glass-walled lobby of the North Tower pitch black.
It was then that Pfeifer ordered his firefighters to abandon rescue efforts and evacuate the North Tower, he told the conference, which was co-hosted by the Department of Energy and the North American Transmission Forum.
“That sounds like a simple order when you look back in hindsight. I had no idea that the whole [South Tower] had collapsed. I thought the only people in trouble were us. But giving an order where you are pulling the rescuers out and leaving a thousand people behind is not an easy order at all. But it’s using that two parts of the brain — the intuitive part and the analytical part.”
Pfeifer was back out on the street when the second tower collapsed at 10:28 a.m., sending him and others running away.
Pfeifer said the event illustrated “organizational bias” — how firefighters, EMTs and police tend to stay in their own groups even when working together.
After the first tower collapsed, police in a helicopter circling the North Tower reported that the building’s top 15 floors were “turning red” and the corner of the building was starting to buckle. “‘Pull everybody back three blocks,’” Pfeifer said the copter warned, fearing the second building’s collapse.
“That message never got through to the fire department, and the fire department never asked,” Pfeifer said. “Here you have two great organizations — NYPD and FDNY — and they didn’t talk to each other at the most critical time.”
Some 71 law enforcement officers and 343 firefighters — including Pfeifer’s brother — died that day, along with almost 3,000 civilians. Among those killed were the top-ranking firefighter on the scene and other command chiefs.
“We had no command staff. They were all gone. So how do you re-establish command?” Pfeifer asked.
After the second building toppled, Pfeifer recalled, his immediate boss, Deputy Assistant Chief Peter Hayden, got on top of a burned-out fire truck and gathered the surviving firefighters and reinforcements together.
“The chief said, ‘I want you to take off your helmets, and we’re going to have a moment of silence, because we lost a lot of people today,’” Pfeifer recalled. “And we took off our helmets.
“And then he asked us to put back on our helmets. And in the moment of putting back on the helmets, he re-established command, because there was a lot of stuff to do. There were rescues to be made, and fires to be put out. But what he did, he used what I’m calling now ‘crisis empathy.’ … He listened to what we were feeling.
“We knew it was bad, and we knew we lost a lot of people, but by him being able to recognize that and then articulate it, [it] made all the difference in the world and it re-established command. So, sometimes those small gestures mean a lot more than it sounds.”
American Municipal Power said Wednesday that PJM’s rush to file its energy price formation proposal with FERC leaves the door open for design flaws.
AMP CEO Marc Gerken sent a letter to the PJM Board of Managers criticizing the RTO’s “arbitrary” and “self-inflicted” deadline to implement a revised set of rules that a majority of stakeholders doesn’t support. (See PJM Advances Own Energy Price Formation Plan.)
“Broad review of all aspects of market changes is one of the primary benefits of the stakeholder process; a benefit PJM staff seems disinterested in availing itself of,” Gerken wrote. “While PJM and stakeholders are often under tight timelines, that is not the case here. There is simply no need for PJM to rush ahead with this [Federal Power Act Section] 206 process.”
Section 206
The letter comes two weeks after PJM staff hosted a meeting with stakeholders reviewing the evolving language of its proposal, which they said would be filed by March 31. Nine sections to be added to the Operating Agreement had not yet been finalized, Gerken said, while manual revisions memorializing the changes had yet to be drafted.
Filing under FPA Section 206 allows PJM to submit a proposal that doesn’t have stakeholder consensus. Stu Bresler, senior vice president of operations and markets, told stakeholders in February that staff would recommend the board submit the RTO’s proposal to FERC after multiple compromise packages failed to garner enough support. (See Last Gasp Bid on PJM Price Formation Falls Short.)
Gerken argued that PJM’s lack of preparedness suggests the stakeholder process could have carried on despite the Jan. 31 deadline for a compromise set by the board in December. (See PJM Board Demands Action on Energy Price Formation.)
“That this level of detail is still being developed should be a clear sign to the board that PJM was no more prepared than the rest of the stakeholders to act within the board’s arbitrary deadline,” he said. “Forcing a solution and an unrealistic deadline has resulted in PJM being forced to make an FPA Section 206 filing rather than a [Section] 205 that could have resulted from a reasonably managed process.”
He also criticized staff’s decision to let manuals determine key aspects of its proposal, saying “it does not strike the appropriate level of granularity that should be included in the Operating Agreement.”
“Not addressing these components of PJM’s proposal fails to give stakeholders the opportunity to understand and provide feedback on PJM’s proposed changes,” he said.
Undisclosed Changes
Gerken’s letter further chastised PJM for making changes to its proposal after the Jan. 24 meeting of the Markets and Reliability Committee. He said staff posted PowerPoint slides detailing the changes online 24 hours before the March 14 meeting, some of which he described as “significant” alterations.
PJM presented the following changes to stakeholders during the meeting, including:
Capping demand response procurement at 50% instead of the previously recommended 33%;
Changing how equivalent demand forced outage rates are reflected in the operating reserve demand curve (ORDC);
Recalculating lost opportunity costs for offline resources;
Revoking market participants’ ability to self-schedule resources as secondary or non-synchronized reserves;
Changing real-time treatment of inflexible resources with a day-ahead reserve commitment; and
Using the ORDC to calculate a secondary reserve nonperformance penalty.
“PJM had an obligation to inform stakeholders of such fundamental changes prior to voting at either the January MRC or the special [Members Committee meeting] that was called to vote on the consensus proposal,” Gerken said.
An Unusual Step
PJM took an unprecedented step earlier this month when it convened a meeting to discuss the Section 206 filing with stakeholders. Typically, feedback isn’t sought on 206 filings.
Dave Anders, director of stakeholder affairs, said staff decided to organize the meeting after members requested to view the proposed tariff revisions. Engaging stakeholders prior to filing with FERC is a lesson the RTO learned when implementing Capacity Performance rules, he said.
It appears the board won’t be stalling the process any further, however. Jeff Shields, a PJM spokesman, told RTO Insider on Thursday that staff will file the plan Friday afternoon.
“It will be a timely and comprehensive proposal addressing well-documented, much-needed reforms to the way reserves that ensure reliability and flexibility are priced and compensated in our markets,” Shields said.
FOLSOM, Calif. — CAISO’s Board of Governors on Wednesday unanimously approved a proposal meant to address concerns that the ISO’s market power mitigation rules disincentivize Pacific Northwest hydroelectric resources from participating in the Western Energy Imbalance Market.
The concerns arose shortly after Canada-based Powerex joined the EIM last April as the market’s first non-U.S. member. The company, responsible for marketing the ample surplus generation produced by BC Hydro, quickly determined that transmission constraints at the U.S.-Canada border were frequently triggering CAISO’s local market power mitigation (LMPM) processes in the EIM, which requires use of default energy bids (DEBs) to settle transactions. (See Troubled Waters for Powerex in EIM.)
Powerex found that the inflexibility of the formulas underpinning the DEBs left its market operations out of the money by forcing it to sell power into low-priced, oversupplied markets, when in fact it was attempting to buy on the cheap for later arbitrage. Other operators of the region’s fast-ramping hydroelectric resources noted the rules posed a similar risk for them.
“This issue is particularly acute in the Western Energy Imbalance Market because of the Northwest’s numerous hydro resources that have opportunity costs for energy sales because of their water limitations. Suppliers operating these resources may have disincentives to offer these needed flexible hydro resources to the EIM if they cannot reflect their costs,” CAISO Vice President Keith Casey wrote in his memo to the board regarding the proposal.
In response, the ISO proposed a set of market changes designed to prevent the LMPM process from resulting in the dispatch of resources at prices below their costs.
The plan, which still must be approved by FERC, would create a standard DEB for hydropower resources. The measure is needed, Casey wrote, because CAISO’s “market power mitigation process reduces a market participant’s submitted energy bid to a resource’s default energy bid, calculated by the ISO, in the event it detects market power. Default energy bids are intended to reflect a resource’s actual marginal costs of energy.”
The new option for DEBs is “specifically designed for hydro resources that better estimates these resources’ actual costs, which typically consist of opportunity costs reflecting their limited water availability,” Casey said in the memo.
Severin Borenstein, the newest board member appointed by California Gov. Gavin Newsom in January, indicated he wasn’t entirely comfortable with the proposal, but he voted for it nonetheless.
“I’m still trying to wrap my head around the economics of this,” said Borenstein, an MIT-trained economist and faculty director of the Energy Institute at the University of California, Berkeley’s Haas School of Business. “Cleary the hydro producers in the Northwest care about this” because they are getting value from the market and want it to operate in a way that’s more favorable to them, he said.
In other matters:
The board unanimously elected David Olsen to another one-year term as its chair and named Angelina Galiteva as vice chair.
Over objections from Pacific Gas and Electric and Southern California Edison, the board approved a plan to expand the EIM’s scope of authority on changes to real-time market rules when the primary driver of the changes is the EIM.
The board approved CAISO’s 2018/19 transmission plan, with several major changes over last year’s plan. The plan, intended to ensure grid reliability, identified 13 new transmission projects at a projected cost of $644 million, all within PG&E’s service territory. It also recommended canceling six transmission projects in PG&E’s territory that planners concluded were no longer needed, eliminating $440 million to $550 million in future costs.
RMR/CPM Updates
The board approved a plan to improve CAISO’s reliability–must-run (RMR) and Capacity Procurement Mechanism (CPM) programs, which let the ISO procure energy and keep generators online that might otherwise be retired. Of particular concern are the state’s gas-fired plants that are essential for meeting peak demand but are under financial strain from the falling costs of solar and wind power.
The newly approved plan is intended to simplify and clarify the RMR process in accord with current market conditions and to compensate generators for keeping plants online.
Some stakeholders and board members expressed concerns that generators might propose retiring or mothballing plants to game the market. CAISO planners said they believed a new provision, requiring generators to submit an affidavit explaining their reasoning and intentions for retiring resources, would help mitigate those risks.
RENSSELAER, N.Y. — NYISO on Wednesday reported that it confronted minimal operating challenges this past winter as New York enjoyed relatively mild weather for most of the season.
Emilie Nelson, ISO vice president of operations, told the Management Committee that there were two noteworthy periods of cold conditions this winter.
The first cold wave produced the winter peak of 24,728 MW on Jan. 21 — Martin Luther King Jr. Day — topping the 24,330-MW 90/10 day-ahead forecast. In advance of the holiday weekend, NYISO coordinated with transmission owners and neighboring RTOs, and participated in calls with the Northeast Power Coordinating Council. The ISO also recalled some New York transmission facilities back into service, she said.
The second cold period began when an arctic front arrived Jan. 30 and stretched into Feb. 2.
“The ISO’s fuel survey inventories indicated sufficient alternate fuels, so again we appreciate that process,” Nelson said. She noted there was no need for statewide supplemental capacity commitments, demand response, emergency actions such as voltage reduction or public appeals, or emergency energy purchases from neighboring regions.
The New York Control Area’s transmission infrastructure provided excellent performance, she said.
Winter peak loads (MW) | NYISO
Interstate and local natural gas pipelines all remained in service, though they issued many gas alerts, daily and hourly operational flow orders (OFOs), and notices signaling that interruptible gas customers may not be able to get gas.
“Even with relatively few cold days, New York experienced a high number of OFO conditions this season, which may become more prevalent and constraining at higher temperatures than compared to the past,” Nelson said.
She pointed out the record amounts of LNG shipped this winter, with the Northeast Gateway Deepwater terminal hitting a record sendout flow rate of more than 800,000 MMBtu/day on Feb. 1, while Canaport and Everett LNG also saw high levels of imports this season.
Fuel assurance will continue to be important, highlighting the significance of NYISO’s ongoing fuel and energy security project, Nelson said.
Increasing Board Compensation
Interim CEO Rob Fernandez said NYISO is proposing to raise compensation for its Board of Directors in order to remain competitive in recruiting members.
Under the proposal, the annual retainer for each board member would increase to $65,000 from $55,000, while compensation for attending meetings would rise to $3,500 from $3,000 per meeting. Directors would also earn a flat fee of $5,000 per committee meeting day, which typically entails three or four meetings, compared with the current compensation of $2,000 per committee meeting.
Fernandez asked stakeholders to provide comments by April 5.
ISO Customer Satisfaction Improves
NYISO last year scored an “extraordinarily high” 90% in overall satisfaction among its customers and market participants, said Don Levy, director of the Siena Research Institute, which conducted the member surveys.
“We’re sort of on the outside end of a satisfaction bell curve, so it is challenging to keep moving it up, but this year we did see it move up a point,” Levy said.
The survey comprised three platforms: customer inquiry, market participants and CEO strategic outreach.
Levy said areas for improvement identified in the surveys included how the ISO explains policies and procedures; transparent operations; considerations of individuals’ input; conducting comprehensive long-term grid planning; advancing technological infrastructure; and providing information to policymakers, stakeholders and investors.
“We will note that, in terms of transparency, we have seen significant improvements over the year,” Levy said.
New Zone J Operating Reserves Go to Board
The MC approved establishing operating reserve demand curves that assign a $25/MWh value to the proposed reserve requirements for Zone J (New York City), following a recommendation by the Business Issues Committee. (See NYISO Business Issues Committee Briefs: March 13, 2019.)
Ashley Ferrer, NYISO energy market design specialist, reiterated her presentation to the BIC showing that the requirements would necessitate procuring 500 MW of 10-minute reserves and 1,000 MW of 30-minute reserves.
The greater New York City area (Zone J), as seen from the International Space Station in 2013 | NASA
NYISO is not proposing to revise the Zone J requirement during Thunderstorm Alert (TSA) events in order to ensure implementation for June. However, Ferrer said that, absent further evaluation of the appropriate reserve requirements during TSA events, use of a $500/MWh demand curve price could result in unnecessarily high pricing outcomes during those events.
TSAs are called when actual or anticipated severe weather conditions lead the ISO to reduce transmission limits into Southeast New York.
The ISO will submit the proposal to the board in April and file Tariff revisions with FERC seeking approval to implement them in June.
Tariff Revisions Clarify TCC Credit Calculation
The MC approved Tariff revisions to clarify how to calculate the holding requirement for historic fixed-price transmission congestion contracts (HFPTCCs) that do not align with the beginning of a capability period by using proposed enhancements previously approved by stakeholders.
Sheri Prevratil, NYISO’s manager of corporate credit, said three HFPTCCs have start dates that do not match the first day of a capability period. The ISO identified the issue while developing software to use the market clearing price to calculate the credit requirement for fixed-price TCCs.
“The [proposed] methodology is consistent with the current methodology,” Prevratil said.
Gas-fired generation continues to rapidly gain market share at the expense of coal, a trend likely to accelerate this year and into the near future, according to two reports released this week.
A U.S. Energy Information Administration report released Monday showed the power sector pushed U.S. natural gas consumption to record levels last year as gas-fired generators continued to steadily displace coal plants.
Gas consumption surged by 10% in 2018, rising across all economic sectors but boosted largely by a 3.8-Bcfd increase in uptake by power generators, EIA found. Gas-fired capacity additions of 14.5 GW and weather-related factors drove the increase.
The power sector consumed 29 Bcf of gas per day last year, 35% of domestic consumption. The sector set an all-time consumption record of 39.9 Bcfd in July, hitting its second-highest level of 38.6 Bcfd in August.
Gas-fired plants accounted for 35% of all generator output during the year, followed by coal (27%), nuclear (19%) and hydro (7%). Renewables accounted for 6.5%, according to an EIA report issued last week. (See Report: U.S. Renewable Generation Doubled Since 2008.) Nearly 13 GW of coal generation were retired in 2018, EIA said. Gas first supplanted coal as the sector’s leading fuel source in 2016.
The power sector led the boost in U.S. natural gas consumption to record levels in 2018. | U.S. Energy Information Administration
While EIA forecasts that coal’s share of power output will slip below 25% this year, a report released Tuesday by the Institute for Energy Economics and Financial Analysis (IEEFA) contends that outlook “could even be understating the decline.”
“We expect the erosion of the utility market for coal to accelerate through 2019 and into the coming decade due to a combination of factors that have fundamentally changed the domestic electricity generation sector, the prime market for the U.S. coal industry,” said IEEFA, which describes its mission as accelerating “the transition to a diverse, sustainable and profitable energy economy.”
Chief among those factors: price drops for natural gas and renewables; the aging of the utility coal fleet and a growing utility sector interest in retiring the plants; increased corporate interest in greener resources; and growing concerns about CO2 emissions and climate risk.
IEEFA noted that total U.S. coal consumption dropped 4% last year to 688 million tons (MT), falling below the 700-MT level for the first time in 40 years. The report showed that, based on EIA statistics, the electricity sector accounted for 93% of the country’s demand for coal from 2007 to 2018.
While EIA projects that utility-sector coal consumption could drop to 563.9 MT this year, IEEFA thinks the level “could even fall more given the amount of coal-fired capacity retired last year, coupled with expectations of more closures going forward.”
IEEFA says 2019 “is already shaping up to be another important year for coal plant retirements, with almost 10 GW of planned closures announced through the end of February.” The group acknowledges that a year ago, it sharply underestimated this year’s closures, projecting just 4 GW in retirements.
“That figure has shot upward over the past year and now is nearing 10 GW, which would put it on pace to be the third-highest total for coal plant retirements ever,” IEEFA wrote. “And more announcements could be on the way, as the sector’s worsening economics continue to force utility decision-makers to move ahead with closures.”
The institute noted that Georgia Power has recently asked state regulators to approve immediate closure of a combined 982.5 MW of coal-fired capacity at its Hammond and McIntosh plants, while Alabama Power plans to shutter its 1,062-MW Gorgas plant in April.
The IEEFA report also points to the decline in performance for coal plants relative to natural gas. Coal plant capacity factors, about 70% in 2009, has held at about 54% over the past four years.
“It is important to point out here that this decline has occurred even as 75 GW of coal-fired capacity were closed from 2011 to 2018, much of it older and operated only occasionally. All else being equal, those retirements should have improved the average coal-fleet capacity factor, but that proved not to be the case,” the report said.
In contrast, average capacity factors for combined cycle generators have risen from 39.8% in 2009 to 57.6% last year.
The group’s report also points out that, for the first time last year, the capacity of natural gas combined cycle plants exceeded that of coal, 263 GW to 243 GW, “with the two sectors trending in opposite directions.”
That trend in buildouts “has fundamentally changed market operations in the utility sector to coal’s lasting detriment,” IEEFA said.
The industry has made it clear, with the support of President Trump and Energy Secretary Rick Perry, that it will not go down without a fight. On Wednesday, coal trade group ACCCE (which no longer spells out the unrealized potential of its original name, American Coalition for Clean Coal Electricity) released its latest white paper making the case for coal’s “fuel security” and “fuel diversity” value.
It’s been nearly three weeks since Pennsylvania lawmakers proposed a $500 million plan to subsidize the state’s nuclear fleet, and hearings on the issue still appear to be weeks away.
The clock is ticking if lawmakers want to save Three Mile Island from shutting down in September. Exelon promised to begin the four-month deactivation process June 1, leaving legislators a small window of opportunity to intervene.
The plan places nuclear power in a newly created third tier in the state’s Alternative Energy Portfolio Standard (AEPS) Program, from which suppliers must buy 50% of their electricity. Should the state lose all five nuclear reactors, Mehaffie said taxpayers will foot an estimated $4.6 billion in costs, including: $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, NOX and particulate matter.
Mehaffie told RTO Insider on Wednesday that no amendments have been made to his bill, though he believes a hearing is scheduled in the House Consumer Affairs Committee sometime during the first half of April.
Committee Chairman Brad Roae (R) said in an email that an official schedule will be released soon. “This is a very complex and technical issue, and we are conducting hearings on the legislation to educate legislators so that we can make good decisions,” he said.
Asked if there’s any sense of urgency among lawmakers to move the bill, Roae did not respond.
The Associated Press last week reported that opposed lawmakers could throw their support behind a modified plan that includes environmental policies aimed at reducing carbon emissions or subsidizing renewable resources.
“The crisis is here and we need … to deal with it,” Rep. Carolyn Comitta (D) told the AP on March 22. “Even things we thought were problems in the past need to be part of the solution.”
Critics of the legislation argue the “bailout” prioritizes aging, expensive nuclear facilities at the expense of cheaper sources like natural gas and coal. Others insist the concept defies the purpose of PJM.
“By the end of this, the bill is going to be chock-full of handouts to grease the skids,” tweeted former Montana Public Service Commission Vice Chairman — and National Association of Regulatory Utility Commissioners President — Travis Kavulla, now director of energy and environmental policy at R Street Institute. “Begging the question: Why the hell should Pennsylvania pass a law because a single power plant is out of the money?”
Meanwhile, State Sen. Ryan Aument (R) has yet to introduce his version of the bill. Chief of Staff Ryan Boop told RTO Insider on Wednesday the final language of the proposal is close to resolution, though he declined to say whether Aument’s version included the same elements of HB 11 or any concessions to sway critics.
Naive, overconfident staff and underlying market flaws allowed a small trading shop to amass the largest portfolio of financial transmission rights in PJM history without the collateral to back it up, an independent review concluded on Tuesday.
The RTO’s Board of Managers commissioned a special report on the GreenHat Energy debacle in October, just four months after the company defaulted on 890 million MWh of FTRs and racked up $100 million (and counting) in losses.
The review concluded PJM staff ignored red flags about the company’s assets and exhortations from other members about the portfolio’s financial shortcomings — a failure of protocol that CEO Andy Ott said “needs to change.”
“PJM needs to get better,” Ott told RTO Insider. “Quite frankly, we’re just not used to this type of behavior from a market participant.”
Independent Review
The board hired three consultants to focus on the RTO’s role in enabling the default, handing off the task to Robert Anderson, Neal Wolkoff and Arleigh Helfer. Anderson serves as executive director of the Committee of Chief Risk Officers, whereas Wolkoff has consulted with the U.S. Commodity Futures Trading Commission and has held leadership positions at the New York Mercantile Exchange and the American Stock Exchange. Helfer is a litigation attorney based in Philadelphia.
“It is clear what a significant outlier GreenHat was,” the report reads. “GreenHat’s trading pattern was conspicuous in that its positions were far larger and of longer tenor than those of other financial participants in the FTR market.”
The report tracked a four-year timeline of events, beginning with GreenHat’s 2014 entry into PJM despite “a questionable history,” followed by unchecked growth in FTRs that more than doubled each year between 2016 and 2018, as well as warnings from at least four other market participants who estimated the portfolio was short by as much as $40 million. It ended with the company defaulting on a $624,000 collateral payment last June.
“Long tenor of a financial position is riskier than a near-term duration because less is known about the distant future than the near future, and more events can intervene to affect the value of a position over time,” the report said. “GreenHat’s portfolio was very risky because of its size and the length of time the positions would be open and subject to market forces before settlement.”
Size and tenor of GreenHat’s portfolio versus others | PJM
GreenHat, which listed its address as a UPS store in Coronado, Calif., was owned by two traders who previously gained notoriety as participants in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the Doubling Down – With Other People’s Money.)
FERC Commissioner Richard Glick said in January the commission must investigate participants who willfully manipulate the market through fraud and escape any sort of punishment, thereby perpetrating their schemes on other RTOs. “That investigation should consider the full extent of our existing authority under the Federal Power Act and whether any legislative action is needed to ensure the commission has the authority to preclude these individuals from continued participation in wholesale electricity markets,” Glick said. “I hope this is an issue we can address in the months ahead.”
The consultants also determined a flaw in PJM’s methodology for calculating collateral adjustments created “counter-intuitive” and “sometimes directionally incorrect” collateral requirements. The faulty approach meant even as GreenHat’s portfolio became increasingly risky, its collateral requirements actually shrank, leaving healthier portfolios to essentially subsidize the entire FTR market, the report found.
The report’s authors noted that “best practices incorporate forward information to determine collateral requirements for market participants. In contrast, PJM’s assessment of risk was based entirely on historical, or backwards looking, information.” They recommended PJM require use of mark-to-auction values from more frequent auctions, include long-term FTRs in monthly or bimonthly auctions, and base collateral on forward-looking metrics to better capture risk.
Growth with declining collateral requirement | PJM
PJM Response
Ott said the RTO takes the report’s deep criticisms “very seriously,” announcing Tuesday a list of reforms it will implement immediately, starting with the hiring of a chief risk officer — someone with the knowledge and experience to prevent such calamities from befalling the market again.
“We realize we need to get better at credit risk management,” he said.
PJM will also review and revamp its credit risk assessment and monitoring procedures, as well as facilitate stronger coordination between PJM’s markets, credit/finance and legal groups, and the Independent Market Monitor.
“We expect this report will provide the momentum to move these issues forward,” Ott said in a press release Tuesday. “PJM will work with our members and federal regulators to examine changes recommended by the report designed to strengthen the regulation of our FTR market. It is our job to make sure this never happens again.”
Ott said federal regulators identified issues with PJM’s credit risk management practices in 2010, but stakeholders expressed reluctance over the potential costs of implementing a more sophisticated system.
Independent reviewers confirmed a 2007 FTR default by Tower Research Capital spawned recommendations on how to improve risk management policies and market surveillance, including increasing the frequency of auctions, limiting positions based on participant’s capital, basing collateral on forward-looking metrics and shortening the time period of settlement for outstanding charges.
After lengthy discussions, stakeholders agreed only to the latter recommendation. The review blames PJM staff for not effectively communicating the critical necessity of the other suggested changes.
“This is something where we have to look at ourselves and what we could we have done better and there’s plenty there,” Ott said on Tuesday.
Ongoing Fallout
At the Market Implementation Committee meeting on Feb. 6, PJM CFO Suzanne Daugherty told members that a FERC order to rerun the July 2018 FTR auction to liquidate GreenHat’s positions could add $250 million to $300 million to the $186 million the RTO had earlier projected the default would cost members. (See PJM: FERC Order Could Boost GreenHat Default by $300M.) On Tuesday, the commission issued a tolling order giving it more time to rule on PJM’s rehearing request on the issue (ER18-2068).
“We recognize the shortcomings identified in this review,” Ott said. “PJM takes the cost of this default very seriously, and we are committed to reforms that better protect market participants in the future.”
GreenHat’s significant growth in exposure and MTA loss | PJM
The review faults “dismissive” attitudes from the PJM executive team and flawed legal advice regarding the RTO’s ability to revoke GreenHat’s trading rights after concerns grew over its projected losses. Daugherty acted on her own authority in 2017 when she halted the company’s ability to participate in future FTR auctions — held in June and December each year — before reversing her decision three weeks later, fearing possible Tariff violations and legal repercussions.
Daugherty, who retired as CFO last month, had declined to say whether her departure was related to the GreenHat fallout. (See PJM CFO Retiring in Wake of GreenHat Default.) Tuesday’s report better illuminated her role in the debacle, noting she and other PJM staff put too much faith in verbal and written agreements with GreenHat guaranteeing the company held $100 million in assets and would receive a $62.2 million payout from two bilateral contracts.
“If PJM knew its customer better, PJM may have recognized these instances as red flags indicating the GreenHat pledge agreement may have actually been a sham before signing,” the report said. “These red flags may have helped PJM to conclude that GreenHat did not have an asset worth $62 million to pledge and assign.”
Ott said Tuesday other organizational changes lie ahead for the RTO but declined to comment on the status of specific staff members, noting there “is certainly a need to strengthen different departments.”
After serving a four-year term as chair of the Massachusetts Department of Public Utilities, Angela O’Connor became a free agent last month — just like some of the basketball players she knew during her decade helping to market the Boston Celtics.
That job had her wearing a headset behind sportscaster Marv Albert and Los Angeles Lakers star Earvin “Magic” Johnson while she coordinated timeouts with referees.
Asked about the Lakers’ conspiracy theories regarding their “heated” locker room in Game 5 of the 1984 NBA Finals at the Boston Garden, when temperatures in the arena neared 100 degrees Fahrenheit, O’Connor said, “Whatever you heard, it was probably true.”
O’Connor, known as Angie to her friends, is more circumspect when it comes to her time at the DPU, crediting “incredible staff expertise” with helping her to run the agency “at the busiest time in its history.”
She is most proud of the work DPU did helping Gov. Charlie Baker position the state to procure Quebec hydropower and getting ISO-NE to become the first grid operator in the country to change its market rules to accommodate state procurement of clean energy contracts through Competitive Auctions with Sponsored Policy Resources (CASPR).
The RTO in February concluded Forward Capacity Auction 13, the first run under the new CASPR rules, at the lowest clearing price in six years. (See ISO-NE Completes FCA 13 Despite Controversy.)
“That was a lot of work to try to convince folks, ‘you got to do this,'” O’Connor said. “And Massachusetts wasn’t doing it to crush a price because there’s a recognition that you can’t run the system on wind, solar, storage, fairy dust and unicorns. You need power plants to be able to back up those intermittent resources, tremendously flexible plants, and they are gas plants, largely.”
Private and Public
In all her regulatory work, O’Connor said she “wanted to make sure that whatever we did would not be a barrier to innovation. Massachusetts is a small state but a thought leader.”
Though she had no state government experience prior to her role at DPU, O’Connor was conscious of the need to work with public officials, having come to the job from being Northeast region executive director at TechNet, a trade association representing the technology industry to state and federal policymakers.
And she went to TechNet from the New England Power Generators Association, which she founded and where she served as president.
“It’s very different coming from the private sector into government,” she said. “We were the first state to regulate Uber and Lyft, known as transportation network companies or TNCs, which we started in 2015. People just didn’t associate that with DPU … but then we also oversee the [Massachusetts Bay Transportation Authority] for public safety.
“It’s all about how you handle things, and all those skills are transferrable to other industries, but I do love energy,” O’Connor said.
She refuses to speak on the record about her toughest experience at DPU, overseeing the agency’s response to the Columbia Gas pipeline explosions around Lawrence last September, in which one person was killed and about two dozen others were injured. Her reticence around the incident — the largest such disaster in U.S. history that forced the evacuation of three towns — is because it is still under investigation by the National Transportation Safety Board and the DPU.
“I would like to add how proud I am of the work the team did to support the governor and [Energy Secretary Matthew Beaton’s] work on the ground, especially Pipeline [Safety] Division Director Richard Wallace,” O’Connor said.
‘A Privilege’
“Regulation is like a black hole to some people in other industries,” O’Connor said. “They think, ‘We’re saving the planet, you don’t have to regulate us,’ which is not true. However, I came to appreciate that perspective because from the private sector, you want to get things done, but making good policy takes time.”
O’Connor once headed up energy policy at Associated Industries of Massachusetts (AIM), the commonwealth’s main statewide employer organization, a job she came to from managing operations for the Massachusetts Health and Educational Facilities Authority (MHEFA) PowerOptions program in the 1990s, which today is the largest energy-buying consortium in New England.
MHEFA was a bonding authority for colleges, universities and nonprofits, and after the move into energy aggregation, “we had under contract [more than] 500 MW of load, which was MIT, Harvard, Boston College, Northeastern, Mass. General Hospital … the Museum of Science [and] the Museum of Fine Arts,” she said.
“That was my first energy job, and I remember we also had Sister Mary Ruth and Little Sisters of the Poor,” O’Connor said. “We had a two-year contract with a one-year extension, or a five-year contract, and Little Sisters of the Poor was the same cost as Boston College or MIT. One little facility, but that was one price.”
Massachusetts went all-in on restructuring the electricity industry, she said.
“I really liked this energy thing, and [as] scary as it sounds, I liked the process of [the New England Power Pool]. I liked all the people around a table. I liked how do you figure things out, how do you bring consensus,” O’Connor said.
[NEPOOL voted in March to admit this RTO Insider correspondent as an End User member under strict rules that prevent the publication from reporting publicly on what he hears in meetings. O’Connor said she hopes FERC does the “right thing” in its ongoing proceeding over the matter and directs the organization to allow press to report on the meetings. (See RTO Insider Reporter Admitted to NEPOOL.)]
“Even though there were challenges, public service really is a privilege,” O’Connor concluded. “I remember when I was sworn in, [Baker] said that — over my four years I learned he was right — it truly is a privilege to serve the people of the Commonwealth and to give back. I have been blessed with a number of amazing jobs, and working for this administration was by far the best of all.”
SPP Vice President of Operations Bruce Rew last week said that he “feels pretty confident” the RTO will meet its first major target in providing reliability coordination services to 12% of the Western Interconnection’s load.
During a Wednesday meeting of the Western Reliability Executive Committee (WREC) in Tucson, Ariz., Rew said SPP is “doing well” in preparing for the certification process, which begins with the Western Electricity Coordinating Council’s on-site certification visit Aug. 13.
Rew said staff are updating and creating new procedures to include the Western footprint. He told the WREC the procedures will not be shared with customers, but a summary of methodologies will be provided.
SPP is updating and validating its system model, using Peak Reliability’s as a benchmark. Peak has provided RC services in WECC since 2011 but it will wind down operations at the end of the year.
SPP staff are also working with the RTO’s Congestion Management and Seams Task Force to identify a “consistent and agreed-upon” congestion management approach between SPP West transmission owners and balancing authorities. The approach includes a redispatch methodology for congestion within the SPP West RC.
SPP is scheduled to go live with its RC services Dec. 3. It announced in September it had signed RC contracts with more than a dozen Western entities.
SPP’s timeline for launching its RC services | SPP
The WREC met following a two-day meeting by the Western Reliability Working Group, which spent much of its time discussing SPP’s communications processes, coordination among reserve sharing groups and emergency operations preparedness.
SPP staff encouraged new members to sign up for NERC’s GridExV on Nov. 13 and 14, in which the RTO will participate as a player. Staff said more than 200 employees, including senior officers, will participate in the biennial exercise, which tests response to and recovery from simulated cyber and physical attacks. GridEx IV, in 2017, had more than 6,500 participants from 450 organizations.
NEW ORLEANS — MISO will attempt to divide its ongoing market platform replacement into a series of smaller agreements with vendors rather than one large contract with an outside party — a move that could affect the project’s timeline.
The RTO says the move will avoid overreliance on any single vendor, and that it is continuously evaluating possible impacts to the timeline and scope of the platform redesign. It had planned to begin to move its system from a server-based platform to the cloud in 2020. (See New MISO Platform Headed to the Cloud.)
MISO Vice President of Market System Enhancements Todd Ramey last week said the RTO can “lean on” its legacy platform system a little longer than originally anticipated if necessary. It was planning for a complete swap-out by 2023, under some pressure from existing platform vendor General Electric, which originally said it would also end IT support for the platform around that time.
However, GE is now willing to support the existing platform through 2030 at no additional costs to MISO, Ramey said. He said MISO and GE have “proactively negotiated an annual cost to run the existing platform until 2030 in advance should it be needed.”
“So quite a bit more runway if we need to do that,” Ramey said during a Board of Directors meeting Thursday.
Director Barbara Krumsiek half-jokingly asked for assurances that it won’t take until 2030 for a complete replacement.
“We’re working hard to make sure we can make the transition much sooner,” said Ramey, adding that MISO’s goal is to stick to its original timeline. He stressed that the RTO has not yet found any reason to extend use of the legacy platform and hasn’t made any such decision.
The multi-contract move will negate MISO’s earlier plans to reveal a chosen single vendor at the beginning of 2020 after finishing an evaluation of alternatives to GE.
MISO will provide its next update on the platform redesign to the board in June. Ramey said staff are already training members on how to work on the new platform.
Noting that cybersecurity was one of the reasons MISO cited for moving to a new platform, Director Thomas Rainwater asked RTO executives to include an update on how they will bolster cybersecurity measures if they prolong the use of the legacy system.
At a March 19 meeting of the board’s Technology Committee, Director Baljit Dail asked if GE might have any expectations of a single, large contract. MISO Executive Director of Market Development Jeff Bladen said GE was in agreement about moving forward with a series of smaller agreements.
