While FERC’s technical conference last week was ostensibly focused on reliability, resiliency became the theme as many panelists agreed: It’s not possible to avoid a major grid disruption forever (AD16-15).
Speaking from recent experience, Miranda Keating Erickson, vice president of operations for the Alberta Electric System Operator (AESO), put a fine point on it.
“We must remember that no amount of standards can prevent all events from happening that will impact the reliability of our electricity system. Snow storms will happen. Ice storms will happen. Tornados and hurricanes will happen. As I well know, floods and wildfires will happen,” she said, referring to the Fort McMurray wildfire, which has destroyed 2,400 homes and buildings and caused the largest wildfire evacuation in the province’s history since it began May 1.
“And let’s not kid ourselves; at some point, somewhere, cyber and physical attacks will happen. That means resiliency is just as important as prevention. It is critical that we also focus on our ability to minimize impacts and improve response and recovery time when these events do occur.”
FERC called the conference to mark the 10 years since Congress gave the commission the power to impose mandatory reliability standards. The commission asked speakers to identify the accomplishments of the last decade and the challenges of the future.
Gerry Cauley, CEO of NERC, which was designated by FERC to develop and enforce the standards, started the conference by noting that the 10 largest grid “integrity events” each year from 2012 through 2015 were caused by weather. The last operational issue to make the list was in September 2011.
Cauley, however, cautioned that the shift to natural gas and intermittent generation will require renewed focus on issues such as ramping, frequency control, voltage control and inertia. “As we move forward with this evolution, however, we are experiencing a change of operating characteristics for the grid,” he said.
He highlighted measures being recommended by NERC’s Essential Reliability Services Task Force that would provide better monitoring and control of frequency and voltage.
Others agreed that the increasing dependence on natural gas generation is impacting grid stability.
FERC Commissioner Tony Clark noted that it’s a “challenging prospect to conceive how those [gas] assets can be physically protected.”
Paul Koonce, CEO of Dominion Generation Group, who spoke on behalf of the Edison Electric Institute, urged the importance of building out the necessary natural gas infrastructure, including long-haul pipelines, to ensure the gas can be moved easily.
Paul Stockton, the managing director of D.C.-based consulting firm Sonecon, thanked FERC for its recent reports on the interdependence of the natural gas and electricity industries, calling them “terrific work.”
“I would ask you to continue to focus on the challenges of the resilience of black-start capabilities … [and] the increasing reliance of many companies on natural gas as a source of fuel for their generators,” said Stockton, former assistant secretary of defense for homeland defense. “This, my friends, deserves careful attention.”
Stockton was among several speakers who noted growing concerns with cyber and physical security. Cauley cited the threat of a physical attack on infrastructure as his greatest worry “because of the potential long-term impact and the difficulty recovering, possibly lasting weeks and months.” (See Critics: Koppel Doomsday Scenario Ignores Prep.)
Patricia Hoffman, the Energy Department’s assistant secretary for electricity delivery and energy reliability, said the growing impact of distributed energy resources has created new needs. “The need for new metrics, new kinds of data and new data-sharing protocols is just as important at the distribution level as at the bulk-power level,” she said. “In fact, this need is probably more challenging than at the bulk-power level, if only because we are starting from a less developed base.
“The grid is the battery for the system. It’s basically the backup for the system,” she said. She voiced concern that security threats will be “malicious in nature” and not addressed simply by preparing for N-1 contingencies. “Unfortunately, these investments are not valued by the market.”
Clark expressed hope that NERC’s cost-effectiveness method pilot program will result in new strategies. “Personally, I hope [it] will lead us to some important discoveries regarding how costs can be better contemplated and assessed in the standards-development process.”
Koonce also supported many of NERC’s recommendations and counseled that FERC review issues in a “broad context and with systemwide considerations.”
“Corporate strategic and management actions rest on a strong foundation, and decisions are made with great care and deliberation. Application of these business principles to NERC and electric reliability would naturally invite broad long-term strategic questions, questions that will very likely yield different answers when compared to looking at day-to-day problems or events, or individual components,” he said.
Koonce said that EEI believes version 5 of NERC’s Critical Infrastructure Protection standards is an “appropriate and reasonable approach.” But, he added, “vendor management risks under consideration by the commission for potential new NERC requirements to address cyber-related asset procurement raises some broad questions on the business risks beyond the control of jurisdictional entities, as well as the reach of commission jurisdiction.”
Flexibility was also a big concern for Erickson, who noted AESO’s ability to consider NERC standards and decide if they want to adopt them.
For Joseph Eto, a staff scientist with Lawrence Berkeley National Laboratory, the question was what’s not being considered? “Not all that counts can be counted and not all that can be counted counts,” he said, quoting an adage. He urged expanding metrics on interruptions to calculate the economic impacts on customers.
Carnegie Mellon University professor Marija Ilić summed it up, saying what worries her most is the sheer complexity of the system. The 2003 blackout could have happened anywhere, she said, but also could have been prevented if complexity were handled in more systematic way.
“It’s my belief that we’re going to have more of those events,” she said.
While there was consensus on the importance of maintenance and tree trimming, there was disagreement over whether the industry should standardize equipment. Several industry representatives noted that equipment is sized specifically for its intended use. Arizona State University professor Anna Scaglione, however, said resistance to standardization was as much about lack of vision as engineering — a “cultural problem of industry,” she called it, where no one is considering the interoperability of equipment.
Chris Murray, the project support lead for the Navy’s Renewable Energy Program Office, said the military branch is highly supportive of efforts to increase energy security and is open to having infrastructure projects sited on its properties throughout the country. “If there’s land on our base that you think makes sense, let us know,” he said. “We are marching down a path that most folks haven’t done in the government. … Things are changing and we need your help.”
Hector Beltran, the director general of Mexico’s Energy Regulatory Commission, said his country is making strides to develop its bulk-power systems and hopes to create a system reliable enough to integrate with the North American system very soon.
Mexico awarded its first round of long-term generation contracts in March, he said, and plans to build a series of interconnections along the border with the U.S. so that the networks can freely interact with each other. He noted that the following day, representatives from both the Mexican and American power industries were meeting in Mexico City to identify collaboration opportunities.
Barely a year after it went public as an independent company, Talen Energy is going private.
The company announced Friday that it had agreed to be acquired by Riverstone Holdings, which is offering $14/share in cash for the company’s outstanding shares, a $2 premium to the closing price Thursday. While the total cost of the stock will be approximately $1.8 billion, the deal has a total value of approximately $5.2 billion including assumed debt. It is expected to close by the end of the year.
Talen was formed last June from the merger of PPL’s generation assets with some of Riverstone’s power plants. Through its affiliates, Riverstone already owns a 35% stake in the Allentown, Pa.-based competitive power producer, which owns or controls 16 GW of capacity in eight states. Most of Talen’s capacity — which is divided between gas (47%), coal (39%) and nuclear (14%) — is in PJM and ERCOT.
Tough competition and tight profit margins battered Talen’s valuation from the beginning, and analysts saw Riverstone’s move as a chance to buy the assets at a bargain.
Formed during a period of historically low natural gas prices, Talen’s stock started to drop the day it hit the exchange and never fully recovered, losing more than half its initial value of $21.23/share within five months. On news of the deal, Talen’s stock — which had been rising amid rumors of the deal — jumped nearly $2/share to settle just shy of the $14 Riverstone is offering.
Talen noted in its announcement that the purchase price represents a 56% premium to the closing price of $9/share on March 31, 2016, the last trading day before public reports of the potential sale CEO Paul Farr said the deal “offers compelling value to our stockholders.”
The agreement provides a 40-day period for Talen to find a better deal and another 20 days to enter into a transaction. Should Talen accept a superior proposal during the “go-shop” period, Talen will pay $25 million to Riverstone. Otherwise, its cost to terminate the agreement for a superior proposal will be $50 million.
The deal is being funded by conversion of Riverstone’s existing Talen stock, Talen’s cash on hand and a $250 million new secured-term loan.
In a research note Friday, UBS Securities suggested Talen shares might rise further on expectations of a better offer.
“With a relatively small go-shop fee and even more secured debt capacity … we would not be surprised to see shares even trade above $14,” UBS said.
UBS said Talen fared worse than its peers in last month’s PJM capacity auction, with fewer assets clearing than last year. It estimated that Talen’s PJM capacity revenue will decline by $230 million to $320 million.
The deal is subject to approval by FERC and the Nuclear Regulatory Commission as well as the 65% non-Riverstone shareholders.
“The scenario under which a deal might not be approved [by shareholders] is if commodities rallied prior to shareholder approval date such that the bid was no longer commensurate with the market environment,” UBS said.
But the analysts said shareholders are unlikely to see another suitor willing to pay more because other independent power producers already have concentrations of generation that would likely trigger market power screens. Talen’s coal generation is anathema to Calpine, and its Susquehanna nuclear plant is likely to scare off anyone not already running a nuclear fleet, UBS said. Dynegy and NRG Energy are in restructurings and unlikely to be able to make a purchase, they added.
“Despite the argument that the company is being bought effectively using its own liquidity and leverage capacity, we do not see an obvious outside bidder desiring to pay such a premium,” they said.
A New Hampshire court has dismissed a complaint by a conservation organization seeking to block development of land alongside a state highway needed to bury a section of the Northern Pass transmission line.
The Coos County Superior Court said the Society for the Protection of New Hampshire Forests cannot deny access to project developers in its attempt to halt the line, saying the decision ultimately rests with state transportation officials (15-CV-114). (See Northern Pass Facing Challenges over Siting.)
The organization owns a parcel of land along Route 3 in northern New Hampshire known as the Washburn Family Forest, and it granted easements to the state Department of Transportation in 1931 for road construction through the land.
The society argued that those easements did not include underground construction, but the court disagreed.
“The court finds that under the plain language of [state law], NPT’s proposed use is a proper use of the public highway easement … [and] the DOT has exclusive jurisdiction over whether to grant NPT a permit to install the proposed transmission line below the stretch of Route 3 at issue,” Judge Lawrence A. MacLeod Jr. wrote in the May 26 opinion.
The court also declined to consider the merits of the 192-mile line, which would transmit 1,090 MW of Canadian hydropower to the New England market. It said such questions were “speculative” until the DOT gave its approval.
“The DOT, not this court, must decide … whether a proposed project meets the ‘public good’ requirement of” state law, the court said.
The society said it was not surprised by the ruling.
“The decision effectively kicks the can down the road relative to the ultimate resolution of important property rights issues involving Northern Pass, the DOT and private landowners,” spokesman Jack Savage said in a statement. “We note that the state Constitution expressly prohibits the use of the state’s power of eminent domain for elective transmission projects and would have preferred not to wait for the DOT to potentially issue a license before resolving that constitutional conflict.”
Savage told RTO Insider on Wednesday an appeal to the New Hampshire Supreme Court is one option under consideration.
Project developer Eversource Energy lauded the ruling.
“We are pleased the court recognized long-standing New Hampshire law that allows for the use of public roadways for projects like Northern Pass,” Bill Quinlan, president of Eversource Operations in New Hampshire, said in a statement. “We look forward to continuing the permitting process and moving one step closer to delivering the clean energy and economic benefits to New Hampshire and the region.”
Developers Seek Shorter Schedule
On Tuesday, Northern Pass Transmission, an Eversource subsidiary, asked the state’s Site Evaluation Committee for a written decision on its application by June 30, 2017.
“The proposed schedule seeks to strike a balance between the statutory requirement to complete the evaluation within 12 months and the need for adequate time to evaluate a project the size and scope of Northern Pass,” NPT said in a statement.
The committee last month informally indicated it would need nine more months than the year required by state law for its study of the project route, which would push its decision back to about Sept. 30, 2017. In a motion filed Monday, NPT is asking for a ruling three months earlier. A formal ruling by the committee on its schedule is pending. (See Northern Pass Decision Delayed Nine Months.)
FERC on Wednesday approved CAISO’s plan to temporarily alter its market rules and operations in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility (ER16-1649).
The grid operator last month sought expedited approval for the Tariff changes, designed to ensure reliable operations in Southern California in the face of potential gas shortages this summer — the region’s peak period for power generation. (See CAISO Board Approves Aliso Canyon Response.)
The commission also directed staff to convene a technical conference to evaluate the effectiveness of the provisions and determine the need for additional longer-term measures, addressing a concern of a number of CAISO stakeholders.
“Substantial efforts have been made by CAISO, California regulators and the energy companies to enhance planning and preparation, communication and coordination, and situational awareness,” FERC Chairman Norman Bay said in a statement. “That being said, the situation remains a serious one, and we will continue to monitor Aliso Canyon very carefully.”
Under new pipeline requirements effective June 1, Southern California Gas customers face penalties as high as 150% of daily gas indices when their daily burn deviates from nominated flows by more than 5%. The region’s generators have complained they would likely incur financial losses when the ISO’s real-time dispatch instructions cause them to burn more or less gas than planned for on a given operating day.
The new market rules will help generators manage their burns to avoid system-balancing penalties and allow them to recover costs after the fact, while ensuring the ISO is capable of moving generation into the region when gas supplies are constrained.
Key provisions of the plan include:
The release of advisory schedules by CAISO two days ahead of an operating day to help scheduling coordinators plan for gas procurement further in advance;
Inclusion of a gas adder and an after-the-fact cost recovery mechanism for generators connected to the SoCalGas system, allowing those units to recover costs based on same-day gas prices — including potential penalties — rather than day-ahead gas indices;
Implementation of a new constraint in the CAISO market that limits the minimum and maximum amount of gas that can be burned by generators in the affected area during periods of restricted gas supply;
Reservation of transmission capability on the Path 26 transmission line linking the Pacific Gas and Electric (PG&E) and Southern California Edison service territories in order to ensure adequate capacity to deliver energy into the southern part of the state during gas restrictions; and
Suspension of virtual bidding in circumstances when CAISO determines the practice could produce market inefficiencies.
FERC rejected a request by NV Energy and Calpine for CAISO to develop a gas adder for generators located outside the SoCalGas network. The two companies contended that limited gas supplies in that system would likely drive up fuel prices in neighboring areas. The commission instead determined that the adders are designed to specifically address the conditions confronted by Southern California gas-fired generators, which “need a mechanism by which to manage gas-balancing requirements within tightened tolerance bands.”
“This is not the case with resources outside of Southern California,” the commission said.
The commission also rejected PG&E’s request that the ISO perform a market simulation before rolling out the plan, saying that “timely implementation of these market changes outweigh the potential benefits of requiring market simulation in this instance.”
The commissioners additionally declined a request by NRG Energy that CAISO be ordered to implement long-term changes to its market rules related to gas cost recovery by Dec. 1, 2016. During stakeholder calls earlier this year, the company repeatedly raised concerns about its exposure to increased gas costs and balancing penalties.
“We find that it is premature to require CAISO to implement long-term changes by a date certain when the scope and duration of any potential problems are currently unknown,” the commission said, adding that those measures should be addressed in the upcoming technical conference.
Exelon will close its Clinton and Quad Cities nuclear plants after the Illinois General Assembly adjourned this week without acting on a bill that would have subsidized the money-losing stations, the company said Thursday.
Clinton will shut down next June 1, and Quad Cities will close the following year. Together, the plants have lost $800 million in the past seven years, Exelon said.
Clinton Nuclear Plant Source: Exelon
The company will be submitting permanent shutdown notifications to the Nuclear Regulatory Commission within 30 days. Among other steps toward closure, Exelon will be ending capital investment projects at the plants, taking a one-time charge of $150 million to $200 million for the year, accelerating about $2 billion in depreciation and amortization and canceling fuel purchases and outage planning, Exelon said.
Ceasing the investment projects will impact more than 200 workers, and more than 1,000 outage workers will be affected, according to the company.
“We have worked for several years to find a sustainable path forward in consultation with federal regulators, market operators, state policymakers, plant community leaders, labor and business leaders, as well as environmental groups and other stakeholders,” CEO Christopher Crane said. “Unfortunately, legislation was not passed, and now we are forced to retire the plants.”
Crane had given legislators a May 31 deadline to help shore up the struggling generators if the 1,819-MW Quad Cities station did not clear the PJM Base Residual Auction for delivery year 2019/20. It failed to do so. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price was insufficient to cover operating costs, Crane said.
According to Exelon, their closures will represent a $1.2 billion loss in economic activity and 4,200 direct and indirect jobs. The plants employ 1,500.
Next Generation Energy Plan
The Exelon-backed legislation, called the Next Generation Energy Plan, incorporates pieces of a similar bill the company proposed last year as well as part of the competing Clean Jobs Bill. The latter proposal aimed to reduce energy demand by 20% through energy efficiency; increase the renewable portfolio standard from 25% by 2025 to 35% by 2030; and create an estimated 32,000 jobs annually by creating a market mechanism to reduce carbon emissions.
A key element of the new plan is a shift to a zero-based emission standard, which would provide financial support for struggling nuclear plants in recognition of their lack of carbon emissions.
Exelon said the standard would address stakeholder concerns by requiring state regulators to review plants’ expenses to ensure that only those whose revenues are insufficient to cover their costs and “operating risk” would receive compensation.
On Friday, the bill received the endorsement of Ameren Illinois, but on the condition of an amendment changing energy efficiency targets that could make it unpalatable to environmentalists.
Quad Cities Nuclear Plant
In introducing the energy plan, Exelon said it was an outgrowth of discussions among it, Commonwealth Edison and members of the Clean Jobs Coalition, a group representing Illinois’ environmental, business and faith communities.
The coalition supports the bill’s expansion of ComEd’s energy efficiency programs, which it said would save customers at least $4 billion over a decade. But it said the Ameren amendment would exclude that utility’s customers from the expansion.
“While ComEd has offered a strong energy efficiency plan, the Ameren proposal … is a half-measure that will leave downstate customers with fewer jobs and higher bills than people in Chicago and Northern Illinois. Ameren is really leaving Central and Southern Illinois in the dark,” the coalition said in a statement.
Exelon said it will continue to push the legislation.
“While these needed policy reforms may come too late to save some plants, Exelon is committed to working with policymakers and other stakeholders to advance an all-of-the-above plan that would promote zero-carbon energy, create and preserve clean-energy jobs, establish a more equitable utility rate structure and give customers more control over their bills,” it said.
A ‘Tragedy’
Marvin Fertel, CEO of the Nuclear Energy Institute, issued a statement calling the plants’ closure “a tragedy” that threatens the “nation’s ambitious clean air commitments.”
“At-risk nuclear plants are struggling because the electricity markets do not appropriately value the attributes of nuclear plants, including reliable electricity generation and their carbon-abatement value. This is fixable, but federal and state policymakers, the Federal Energy Regulatory Commission and regional electric system operators must address these shortcomings with urgency to prevent other power plants from shutting down prematurely.”
The Illinois General Assembly adjourned Tuesday without acting on a bill that Exelon says it needs to save the Clinton and Quad Cities nuclear plants.
“At this time, the future of the Next Generation Energy Plan remains unclear,” Exelon said. “We’ll have more to say about the path forward within the next few days.”
“We knew it would be a challenge when the legislature is working through competing budget shortfall issues. We will continue to work with the legislature and other interested parties throughout the summer to implement a comprehensive energy solution for Illinois,” said David Onufer, external communications manager at Dynegy.
The Houston-based company wants to move the Commonwealth Edison and Ameren service areas in Central and Southern Illinois from MISO Zone 4 into PJM, saying the retail-choice state is a mismatch in MISO’s markets.
Exelon’s Deadline
Clinton Nuclear Plant Source: Exelon
CEO Christopher Crane had given legislators a May 31 deadline to help shore up the money-losing nuclear plants if Quad Cities did not clear the PJM Base Residual Auction for delivery year 2019/20. It failed to do so. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price was insufficient to cover operating costs, Crane said.
If Exelon sticks to its word, it will close Clinton next June and the 1,819-MW Quad Cities plant the following year.
Together, the facilities have lost $800 million from 2009 to 2015, Crane said. According to Exelon, their closures would represent a $1.2 billion loss in economic activity and 4,200 direct and indirect jobs. The plants employ 1,500.
Revised Plan
The Next Generation Energy Plan incorporates pieces of similar legislation introduced last year by Exelon along with the competing Clean Jobs Bill. The latter proposal aimed to reduce energy demand by 20% through energy efficiency; increase the renewable portfolio standard from 25% by 2025 to 35% by 2030; and create an estimated 32,000 jobs annually by creating a market mechanism to reduce carbon emissions.
A key new element of the plan is a shift to a zero-based emission standard, which would provide financial support for struggling nuclear plants in recognition of their lack of carbon emissions.
The company said the standard would address stakeholder concerns by requiring state regulators to review plants’ costs to ensure that only those whose revenues are insufficient to cover their costs and “operating risk” will receive compensation.
On Friday, the bill received the endorsement of Ameren Illinois, but on the condition of an amendment changing energy efficiency targets that could make it unpalatable to environmentalists.
In introducing the energy plan, Exelon said it was an outgrowth of discussions among it, ComEd and members of the Clean Jobs Coalition, a group representing Illinois’ environmental, business and faith communities.
The coalition supports the ComEd bill’s expansion of energy efficiency programs, which it says would save customers at least $4 billion over a decade. But it says the Ameren amendment would exclude that utility’s customers from the expansion.
“While ComEd has offered a strong energy efficiency plan, the Ameren proposal … is a half-measure that will leave downstate customers with fewer jobs and higher bills than people in Chicago and Northern Illinois. Ameren is really leaving Central and Southern Illinois in the dark,” the coalition said in a statement.
FERC on Tuesday rejected PJM’s Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load.
The changes, approved in April by the Members Committee after months of stakeholder debate, were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. Such behavior, PJM said, would pose operational challenges and create reliability issues. (See “MRC, MC Endorse Interim Ramp Rate for Performance Assessment Hours,” PJM Markets and Reliability and Members Committee Briefs.)
“Given the importance of the penalty structure to the Capacity Performance design, we … must carefully weigh whether the operational concerns documented in the record justify the negative impact that PJM’s proposed penalty exemption would have on these performance incentives,” FERC ruled. “We conclude that PJM has not met that burden here” (ER16-1336).
Under PJM’s proposal, resources’ energy offers would include a historical three-month average ramp rate.
The Independent Market Monitor and LS Power said that PJM had not proven its assertion that self-scheduling before an emergency period would cause operational issues.
“According to the Market Monitor, if resource owners self-schedule their resources in anticipation of tight conditions in the energy market, it is less likely that emergency procedures would be triggered and would instead indicate that nonperformance charges are working as intended to incent generation to operate during high-demand conditions,” FERC said.
“The Market Monitor argues that PJM’s proposal is discriminatory and disincents flexibility by holding more flexible resources (i.e., those with faster ramp rates) to a higher standard for expected incremental megawatts during a performance assessment hour than less flexible reserves.”
Calpine and Rockland Capital argued that generators should not be excused from penalties because of their choice of the type of capacity they offer into the market.
The PJM Power Providers Group, the Delaware Public Service Commission and Dayton Power and Light supported PJM’s proposal.
In rejecting the Tariff changes, FERC quoted from PJM’s own initial filing proposing Capacity Performance, which said, “Parameter limits should not be viewed as a permanent entitlement to underperform. Instead, those limits should be exposed to financial and market consequences: If sellers of resources with fewer operating limits earn more from the capacity market … than sellers of resources with more restrictive operating limits, then all sellers will be incented to find ways to minimize those operating limits, which should over time increase overall fleet performance and benefit loads in the region.”
Great Plains Energy, the parent of Kansas City Power and Light, announced Tuesday it would buy Westar Energy for $12.2 billion in a deal that will give Great Plains a customer base of 1.5 million in Kansas and Missouri, nearly 13,000 MW of generation and 10,000 miles of transmission lines.
Great Plains will pay $8.6 billion in cash and stock while also assuming $3.6 billion in Westar debt.
Under the terms of the agreement, Westar shareholders will receive $60/share, consisting of $51 in cash and $9 in Great Plains common stock. Westar closed at $52.92/share on Friday.
Talk of a Westar acquisition has been percolating through the industry for weeks, with Ameren named as one of the potential buyers. Bloomberg reported earlier in the month that an investment group from Canada was also eyeing Westar.
But it was Great Plains that clinched the deal. Great Plains and Westar currently co-own and operate the 1,200-MW Wolf Creek Nuclear Generating Station, as well as the 1,418-MW La Cygne and 2,155-MW Jeffrey coal plants.
“Westar and KCP&L are trusted neighbors and have worked together for generations in Kansas. The combination of our two companies is the best fit for meeting our region’s energy needs,” said Terry Bassham, CEO of Great Plains Energy and KCP&L.
“This is an important transaction for Kansas and our entire region. By combining our two companies, we are keeping ownership local and management responsive to regulators, customers and regional needs, while enhancing our ability to build long-term value for shareholders.”
Bassham said the merger would create efficiencies that would help reduce future rate increases resulting from increasing environmental standards, cybersecurity threats and slow demand growth.
Great Plains, which operates as KCP&L and KCP&L Great Missouri Operations, has been growing. In 2008, it acquired Aquila, an electric utility that operated adjacent to its territory in Missouri. Headquartered in Kansas City, Mo., it has more than 838,000 customers in Missouri and Kansas and owns about 6,446 MW of generation.
Westar, based in Topeka, Kan., has about 700,000 customers in east and east-central Kansas and about 6,267 MW of generation, mostly coal fired.
After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs still exists.
First in a Series
By Tom Kleckner and Rich Heidorn Jr.
LITTLE ROCK, Ark. — SPP has interfered with the autonomy of its internal Market Monitoring Unit and FERC should order changes to ensure its independence, according to two former monitors who say they were fired for voicing their concerns.
Catherine Tyler Mooney and John Hyatt, who were fired in December, say they were forced out for resisting pressure to conform to policy positions of SPP management and members.
FERC assigned market monitors a key function in the nation’s wholesale electricity markets, making them responsible for ensuring markets are competitive, efficient and provide residential and business ratepayers with just and reasonable rates. Unchecked by independent, effective monitors, RTO stakeholder processes could shift market risk from generators, increasing their profits at the expense of ratepayers.
Mooney and Hyatt say SPP’s system is fatally compromised and that it should give at least some functions to an external monitor.
External market monitors are the norm, with Virginia-based Potomac Economics keeping tabs on the markets in ERCOT, ISO-NE, MISO and NYISO, and Monitoring Analytics performing the same duties for PJM. Only CAISO and SPP have internal MMUs.
Hyatt, a Ph.D. mathematician, and Mooney, who holds a doctorate in economics, were two of three staffers who reported directly to MMU Director Alan McQueen. They said McQueen told them he faced pressure to follow the policy positions of SPP members and RTO management, and that he proposed concessions to mollify generation owners as a result.
Despite FERC rules prohibiting RTO management from supervising their market monitoring units, SPP management, including CEO Nick Brown and COO Carl Monroe, took part until recently in performance reviews of MMU Director Alan McQueen and helped determine annual performance bonuses for MMU employees. Under SPP’s Tariff, the MMU was to report to the SPP Oversight Committee. But OC Chairman Joshua Martin III refused to meet with former monitors Catherine Mooney and John Hyatt when they raised concerns about the independence of the MMU, referring them to McQueen, the target of their complaints, and General Counsel Paul Suskie.
“Some in SPP’s leadership and membership dreaded the idea of the MMU publicly disagreeing with the RTO before FERC,” Mooney said.
“There were examples where [we were told] to change our stance on an issue because if we didn’t change our stance, the MMU could get shut down. We were told we have to think about people and politics and relationships, to think about preserving the internal MMU.”
Under SPP’s Tariff, the MMU is supposed to report to the Board of Directors’ Oversight Committee, which is composed of three outside directors. But the chairman of the committee refused to meet with the monitors after they wrote him a letter outlining their concerns in September.
In addition, despite FERC rules prohibiting RTO management from supervising their MMUs, SPP management took part until recently in performance reviews of McQueen and in reviewing the bonuses of other MMU employees. Management also attended Oversight Committee meetings with the MMU.
Meanwhile, FERC’s Office of Enforcement, which was aware of the monitors’ allegations, effectively ended an audit of SPP and the MMU in April without interviewing the committee. FERC declined to comment.
The independence concerns raised by Hyatt and Mooney resulted from FERC’s compromises in Order 719, its 2008 rule spelling out MMUs’ duties and their relationships with their RTOs (RM07-19, AD07-7). The commission rejected protections urged by some stakeholders, allowing RTOs to choose their structures and declining to provide job security protections for MMU employees. (See related story, Order 719: FERC Balanced MMU Independence Against RTO Autonomy.)
McQueen declined to say why Hyatt and Mooney were terminated, adding it is the “MMU’s policy not to publicly discuss human resource matters.” He said “they were not fired because the market monitor is not independent.”
Joshua W. Martin III, chairman of the Oversight Committee, said he refused to meet with the monitors because their letter, which outlined the problems with the internal monitoring function, proposed an external monitoring function that they offered to join.
“What stood out for me more than anything else in that letter was the fact that there was this issue of a contract that they wished. And obviously directors do not negotiate contracts with employees,” said Martin, who says he supported the monitors’ firing.
Mooney and Hyatt said they proposed an external monitor to solve the problems they experienced, not out of any desire to increase their incomes. They said it was SPP officials who initiated the discussion of a contract; the letter does not mention the word.
“We had very good jobs [at SPP],” Mooney said. “All we had to do to keep them was to keep our mouths shut. But we felt that was a compromise of our principles. We were not acting in our own self-interest.”
The two monitors agreed to tell their stories after resettling in suburban Philadelphia, where they have joined the staff of PJM’s Independent Market Monitor, Monitoring Analytics. They told RTO Insider that they hope going public with their concerns will lead to improvements at SPP.
“I really like this work,” Mooney said. “I think it’s really important, and I would like to see something good come of what happened to us.”
“I think what we’re showing is that the internal market monitor framework has some really big problems with it,” Hyatt said.
Echoes of PJM Monitoring Flap
Mooney and Hyatt’s departure from SPP recalls Monitoring Analytics’ own formation in 2007, when founder Joe Bowring — then a PJM employee — complained to FERC that his reports were being censored by then-CEO Phil Harris.
“You cannot do your job as a market monitor if you’re not independent, if you’re not free to criticize the RTO and its members, if you’re told to pull your punches,” Bowring said in a recent interview. “I am amazed [SPP] had the chutzpah to do this — fire the two best monitors they have. We’re very fortunate to have hired them.”
“I don’t know how we would do this job effectively if we weren’t independent,” agreed Potomac Economics President David Patton.
McQueen insisted in an interview that he has had no problems maintaining the MMU’s independence despite its place within SPP.
SPP Headquarters Source: WER Architects
“That’s demonstrated by our record,” he said in an interview at SPP headquarters, citing the MMU’s three filings opposing SPP positions last year. “We oppose the RTO. We oppose the Board of Directors. That’s our right and that’s our responsibility to do that when we determine it’s appropriate.”
Oversight Committee Chairman Martin also defended the MMU’s independence, saying it has taken positions contrary to RTO staff and stakeholders both in FERC filings and stakeholder meetings.
But Mooney said that, until recently, the MMU dropped any opposition once an issue left the stakeholder meetings, failing to inform FERC when it disagreed with an SPP Tariff filing, as required by FERC Order 719.
Days after the firing of Hyatt and Mooney, the Oversight Committee adopted a revised statement on the MMU’s independence, which included two substantive policy changes: It made the committee responsible for all salary and bonus decisions for McQueen and other MMU employees and ensured that the MMU director could meet with the committee in executive sessions without RTO officials present. The statement also reiterated its choice of the internal market monitoring structure.
Martin announced the statement at January’s board meeting, adding that McQueen will retire by the end of the year.
SPP acknowledged that until the revised policy statement in January, CEO Nick Brown, COO Carl Monroe and SPP’s other officers had reviewed performance compensation bonuses for all RTO employees, including the MMU.
Spokesman Dustin B. Smith said the review of bonuses is separate from the annual performance reviews, which he said McQueen performed for MMU employees.
“Performance compensation, or annual bonuses, are given in the first quarter of each year based upon the prior year’s successes,” Smith said. “Nick, Carl and the other officers would only have reviewed these employees’ payout amounts in the context of their impact on the overall performance compensation budget. During this process, Nick and Carl did not change substantive performance compensation payouts as recommended by the director of the MMU.”
“We believe that SPP has been in compliance with Order 719,” Smith said, adding that the revised policy statement was “not to bring SPP into compliance with Order 719 but to further insulate MMU employees.”
Martin acknowledged that Hyatt and Mooney’s complaints and the FERC audit contributed to the decision to revise the statement.
“We were very attuned to the fact that SPP is under a magnifying glass in terms of … the independence of its MMU structure,” he said in an interview at his law office in Wilmington, Del. “I don’t want my answer to lead you to believe that what Catherine and John said made us generate this statement that came out in January. I know that that would not be accurate. But by the same token, obviously the concerns that they were expressing were one of the factors that were playing out in this process.”
FERC spelled out its rules on the structure and independence of market monitors in Order 719 in 2008. It allowed internal market monitors, external monitors and hybrid structures using both.
“Order 719 was a vast improvement and important, but … this is evidence that the RTO can still put a lot of pressure on the market monitor,” Hyatt said. “I would hope [that FERC takes] another look at whether this purely internal market monitor system really does work.”
Members of SPP’s MMU, which typically carries a staff of about 12, work alongside members of SPP’s market design, transmission congestion rights, internal audit and communications departments at the RTO’s headquarters in Little Rock. In the open seating, conversations two or three rows away can easily be heard. [SPP has also used outside consultants, including Monitoring Analytics, Potomac Economics and D.C.-based Boston Pacific.]
Joining SPP
Hyatt, who has a doctorate in applied mathematics and a master’s in economics, came to SPP from Arkansas’ Public Service Commission in 2008.
In about September 2014, he was promoted from supervisor to principal market monitor. He led the work on the RTO’s first annual State of the Market report and a study on frequently constrained areas. He also designed the mitigation plan for SPP’s energy and ancillary services markets.
Mooney joined SPP in 2011 from the University of Oklahoma, where she was an assistant professor of economics. She has a doctorate and master’s degree in economics and worked before graduate school as an economic consultant for Hagler Bailly and PA Consulting Group, where she focused on utility merger and anti-trust filings.
The SPP job was a homecoming for Mooney, who grew up in Little Rock. “I thought SPP was a great place for someone like me to analyze the industry and market power issues from an independent perspective,” she said. “And I could go home. It was a dream come true to me.”
But Mooney said she began to have concerns with the structure of the MMU immediately after joining the RTO.
At first, things appeared to be going well. Mooney received SPP’s President’s Award in December 2013 for helping launch the Integrated Marketplace, which gave the RTO a day-ahead market, a real-time balancing market, transmission congestion rights and a centralized balancing authority. About a year later, she was promoted to a position as a manager and lead market monitor, responsible for investigations, special studies and market-design issues.
With her promotion, Mooney became one of three who directly reported to McQueen, along with Hyatt and Barbara Stroope, a Ph.D. sociologist who is manager of market monitoring. Stroope, who joined the MMU seven years ago, remains with the MMU and sat in on RTO Insider’s interview with McQueen.
McQueen, who has a bachelor’s degree in environmental science and a master’s in economics, joined SPP in 2003 as a market analyst after 20 years at American Electric Power and Central and South West Corp.
SPP organizational chart, dated March 1, 2011 shows MMU Director Alan McQueen reporting to SPP’s vice president and chief compliance officer, in apparent violation of FERC Order 719.
He was hired by Richard Dillon, SPP’s director of market design, and worked under him when Dillon oversaw both the market monitoring and market design functions. In about March 2011, following FERC Order 719, the market monitoring function was moved from Dillon’s operation, with McQueen reporting to Stacy Duckett, then vice president and chief compliance officer.
SPP’s MMU staff is required to abide not only by Order 719 but also the RTO’s bylaws, which state among their “values and principles” that SPP is “a relationship-based organization” employing “member-driven processes.”
“It’s a member-friendly organization, and I felt SPP wants the MMU to be a part of that,” Mooney said.
The message starts at the top of the organization, the former monitors say, with CEO Nick Brown’s quarterly staff meetings, at which he stresses the need for SPP staff and stakeholders to reach “consensus” on contentious issues. Brown declined to comment, referring questions to Oversight Committee Chairman Martin.
‘You don’t understand the pressure I’m under.’
Hyatt and Mooney said McQueen, in turn, pressured them to compromise their positions in order to minimize conflicts with SPP management and stakeholders.
In 2013, for example, they said SPP management blocked them from asking FERC to reconsider changes to rules regarding physical withholding and uneconomic production because of fears they might delay SPP from the promised March 2014 start of the Integrated Marketplace. SPP boasted in a press release that it was the first RTO “to design, build and deliver a Day 2 market on time.”
After the market opened in 2014, Hyatt said, McQueen proposed a change that would have essentially increased generators’ make-whole payments by 25% — an effort, he said, to pacify generators upset by how the MMU was calculating cost-based offers.
“There was really no economic justification for this,” said Hyatt, who said he and Mooney were able to block the change. “It seemed to me that the MMU was expected to make some sort of significant concession … to appease the market participants.
“I never held the position that the policy was perfect,” he said. “But I do hold firmly to the belief that the general construct of the mitigation policy is sound, and I repeatedly disagreed with the concessions that the MMU director was pushing.
“Alan would say on many occasions, ‘You don’t understand the pressure I’m under,’” Hyatt said.
McQueen declined to say whether he had made such a comment.
“We all live under pressure,” he said. “The Market Monitor … we disagree with all different levels of the stakeholder process. If you don’t disagree with different groups at various times, then you’re probably not doing your job.”
McQueen added that he takes input from all sides before taking a position. “I listen to all sides, but I listen most to what [the MMU] staff has to say, and that’s absolutely where the primary position comes from in everything that the Market Monitor does.”
Mooney, however, said that until late 2014, the MMU was not fulfilling its responsibility to notify FERC when it disagreed with RTO filings. It began to change only when MMU management believed FERC wanted the MMU to become more vocal, Mooney said.
FERC Audit
It’s unclear how much of this FERC auditors knew when they arrived in Little Rock in March 2015. The commission has regularly looked over the MMU’s shoulder, however.
Following an audit in 2008, FERC ordered SPP to appoint an independent director for its NERC-deputized Regional Entity. The commission said an SPP officer was improperly wearing two hats — serving as an RTO official and overseeing the RE, which is supposed to police SPP’s compliance with NERC reliability standards (PA08-2, AD09-3).
In late 2013, members of FERC’s Division of Analytics and Surveillance traveled to Little Rock for a briefing on metrics, screens and dashboards the MMU was developing in preparation for the day-ahead market start-up.
In its audit initiation letter in late February 2015, FERC Enforcement said that, in addition to evaluating SPP’s compliance with the MMU rules in Order 719, it would be evaluating SPP’s obligations under its Open Access Transmission Tariff, the implementation of its Integrated Marketplace and compliance with commission accounting regulations and reporting requirements (PA15-6).
Over the next several months, according to Oversight Committee minutes, FERC auditors conducted weekly or biweekly conference calls with the MMU. FERC sought briefings on stakeholder activities regarding proposed changes to the SPP mitigation rules, the MMU told the committee. By September, FERC had issued three sets of data requests and broadened its questions to “all aspects of the Integrated Marketplace,” including “special studies, market efficiency, market anomalies, market participant [involvement] in new markets, Market Working Group issues and market screen results,” the MMU said.
The Beginning of the End
Mooney and Hyatt said they felt that the FERC audit presented an opportunity to address the MMU’s lack of independence. They also believed speaking up could jeopardize their careers at SPP.
For more than a year before the auditors arrived, Mooney said she had been told that some in SPP management disliked her independence.
In early 2014, Mooney said she was told by Hyatt — then her supervisor — that in the performance evaluation for her bonus, COO Carl Monroe had expressed concern that she was taking policy advice from the PJM Market Monitor. Monitoring Analytics has provided SPP technical assistance, including data collection and development of rules for cost-based offers, since 2012.
“SPP’s displeasure was apparent among staff, and [John and I] were not alone in the fear that it could lead to one or both of our eventual terminations,” Mooney said.
In September 2014, Mooney says, she succumbed to the pressure. At McQueen’s direction, she said, she advocated market design changes regarding mitigated offers “with the goal of appeasing SPP members’ complaints taking precedence over supporting an efficient market” (ER15-2268).
“This was a turning point for me,” she said. “I did not like being put in that position.”
Mooney said she began to fear being fired in about December 2014.
A later SPP organizational chart, dated Jan. 1, 2015 adds the Oversight Committee and describes the relationship with SPP management “for administrative purposes,” the limitation FERC imposed in the order.
“RTO and MMU staff would come to me, behind closed doors, to tell me that SPP was unhappy with the fact that I would not back down from MMU positions when under pressure from the RTO and members,” Mooney said. “Sometimes they would tell me how much they respected what I was doing, but that they would understand if I backed down out of fear that I might lose my job.”
As the FERC auditors asked more questions during 2015, that fear grew. “We received our first negative performance evaluations in August 2015” — just after FERC’s auditors announced they wanted private meetings with the two, they said.
Hyatt said McQueen told him in his review that he needed improvement in “teamwork” and that he was “not interested in developing a consensus.”
His review occurred two days before he met with FERC auditors, Hyatt said. Although McQueen was not present for that interview, an attorney for the MMU was and confirmed he would be reporting to McQueen on what was said.
As a result, Hyatt said, he was reluctant to discuss his concerns with the auditors. He said he was more forthcoming after FERC requested yet another conversation — this time without the MMU lawyer.
Letter to Oversight Committee
In September 2015, Mooney and Hyatt wrote a letter to the Oversight Committee outlining their concerns and proposing a hybrid structure, with an independent monitor.
Martin declined to meet with Mooney and Hyatt, instead telling them to discuss their concerns with McQueen and his superior, Executive Vice President and General Counsel Paul Suskie. The monitors had what Hyatt called a “fairly cordial” meeting with McQueen and Suskie. But the monitors said the account of the meeting that Suskie and McQueen later wrote was inaccurate and incomplete.
At a second meeting with the two, Hyatt said, Suskie stated that, as SPP general counsel, he was acting as counsel for the Oversight Committee. Hyatt said he found Suskie’s role “confusing.”
“I had been encouraged to take issues to the Oversight Committee, and the one time I did go to the Oversight Committee with a concern, they dispatched the RTO general counsel and executive vice president to represent them in discussions on the issue.”
Suskie said in a statement that Hyatt and Mooney proposed that they would form their own company, and that SPP would fund their startup costs and award them a no-bid contract — essentially the arrangement that PJM agreed to with Joe Bowring when he left the RTO’s payroll and founded Monitoring Analytics in 2008.
Suskie said a no-bid contract would violate SPP’s purchasing policies. “When asked whether this contract should be competitively solicited, Mooney and Hyatt said that SPP’s failure to award them a contract could constitute retaliation for their statements to FERC staff,” Suskie said in a comment. “SPP estimates that such a contract would have amounted to a multi-million-dollar, no-bid contract for Mooney and Hyatt, which SPP’s board refused to consider.”
Mooney said it was Suskie and McQueen who initiated the discussion of contracts. “John and I felt that this was premature. The OC needed to make a policy decision about whether to pursue an external unit first,” she said. “We discussed whether an open request for proposals for an external MMU contract could be conducted in a way that would protect our careers given the retaliation we were experiencing. John and I never ruled out any options. We did not ask for a contract.”
If SPP had chosen an open solicitation, it’s unlikely it would have received more than a couple of responses. Market monitoring requires an analytical infrastructure that few firms possess, and many of those that do would be prevented from bidding because they consult for market participants. When Texas issued a solicitation last year for monitoring of ERCOT, only incumbent Potomac Economics submitted a bid.
Firing
At its Dec. 7 meeting, the Oversight Committee went into an executive session that included discussion of “MMU matters.” Executive sessions are typically called to discuss legal or personnel issues. In this case, Hyatt and Mooney were on the agenda.
McQueen confirmed that he informed the committee of his intention to fire Hyatt and Mooney but would not say if the committee formally voted to endorse the terminations.
Martin said the decision to fire Hyatt and Mooney was made by McQueen and SPP’s human resources department. “I thought that this was an appropriate decision for management to take,” he said. “Recognize that as a board member I’m not involved in making that decision. This is not a policy decision. This is a personnel decision and this had worked its way through the various personnel levels and I felt that what was being requested was not unreasonable and I saw no basis for the Oversight Committee to refute what was getting ready to happen. It wasn’t our position to second guess the human resources structure.”
A week later, the two monitors were called separately to human resources and fired within minutes of each other.
Both were told they had violated SPP’s Code of Conduct, but they say they were given no details of the allegations. McQueen told Mooney he had “lost faith” in her judgment, she said.
When Mooney filed an application for unemployment with Arkansas, she reported to the state Department of Workforce Services that she had been discharged “for alleged violation of company rules or policies.” The department approved her compensation, however, reporting, “Insufficient evidence has been presented by the employer to establish misconduct.”
SPP spokesman Smith said the RTO “does not comment on human resource matters.”
“In keeping with this policy, SPP did not report anything to the Arkansas Department of Workforce Services regarding the reasons for Mooney’s termination,” he continued. “Likewise, although SPP was given the opportunity to object to Mooney’s unemployment application, SPP chose not to do so.”
Revised Policy Statement
On Dec. 23, nine days after Hyatt and Mooney’s firing, the committee adopted a revised position statement on the MMU’s independence, which had last been updated in 2012.
The statement reiterated SPP’s choice of an internal monitor, saying “an internal MMU provides both an appropriate level of independence and the level and depth of expertise needed to perform its functions and does so at a more economical cost than an external contractor.”
“In addition,” the statement says, “the Oversight Committee believes that an internal MMU provides the tailored focus and overall consistency that would be more difficult to achieve with an external contractor.”
The statement did make two substantive changes.
In contrast with prior practice, the MMU will be able to meet with the Oversight Committee without RTO management present. The new statement says that “to maintain confidential communication between the MMU and the Oversight Committee, a member of the MMU staff will be designated as a staff secretary for MMU purposes.”
It adds, however, that “RTO staff may attend such executive sessions at the mutual consent of the Oversight Committee and the MMU director.”
The statement also makes the committee responsible for determining salary and bonus compensation for McQueen and his unit.
The committee shared its statement with the Board of Directors at the board’s Jan. 26 meeting. “It’s a step beyond where we’ve been in the past,” Martin said. “We wanted to be as clear as we can that the MMU is an independent entity.”
Mooney said the revised policy statement “reflects changes that are being put in place as a result of our concerns, concerns that the MMU leadership was unwilling to raise. … These changes notwithstanding, the MMU will not be independent as long it is subject to a member-driven RTO culture, instead of its own independent, market-driven principles.”
Hyatt says that the MMU should be the voice of the market. “If no one says what a true, efficient market is, then no one is going to get that market.”
Retirement Unrelated
Martin also announced at the January board meeting that McQueen would be retiring by the end of the year. McQueen said his decision to retire was driven by a desire to spend more time with his grandchildren in northern Michigan and had nothing to do with the conflicts in the MMU. No date has been set for his departure.
“I have never been limited in any of my positions or felt any pressure to do anything other than what my department has decided to do,” he said.
Are Mooney and Hyatt lying when they say otherwise?
“I’m not going to get into that,” he responded. “You know, that’s something for them to decide, not me.”
Mooney and Hyatt say they believe McQueen was conflicted.
McQueen “could have quieted us more than he did,” Mooney added. “He seemed uncomfortable, but I believe he felt that we were generally right.”
Mooney and Hyatt are happy to have landed new positions at Monitoring Analytics. The job change, however, meant Mooney’s and Hyatt’s children won’t often get to see their extended families in Arkansas. The firing was “heartbreaking for my family,” she said.
[Editor’s Note: SPP/ERCOT Correspondent Tom Kleckner worked as an SPP spokesman from 2011 to 2015; Editor-in-chief Rich Heidorn Jr. participated in the 2008 audit of SPP as a member of FERC’s Office of Enforcement.]
PJM members approved a charter for the Seasonal Capacity Resource Senior Task Force last week, but not before a long discussion in which some voiced concern over its potential to undermine the new Capacity Performance product.
The Markets and Reliability Committee passed the motion with 68% of a sector-weighted vote.
The charter stemmed from a problem statement and issue charge that also passed with 68% approval in February to study how seasonal resources could be incorporated into Capacity Performance. (See “Seasonal Resources in the Capacity Market to be Studied,” PJM Markets and Reliability Briefs.)
Katie Guerry of EnerNOC introduced the issue after no aggregated seasonal resources offered into the first Base Residual Auction involving Capacity Performance last August. One aggregated resource offered into this month’s BRA, but Stu Bresler, PJM senior vice president of markets, said he did not know whether it cleared.
In the last two auctions, PJM required 80% of the capacity procured to meet Capacity Performance standards. The market goes to 100% Capacity Performance resources in the next BRA, for the 2020/21 delivery year.
Since the endorsement of the problem statement and issue charge, the task force has added a work activity: to analyze alternatives to requiring 100% Capacity Performance resources, including the development of stand-alone sub-annual products.
Contrary to FERC Order?
Those opposed to the charter worried that the task force’s deliverables might run afoul of FERC’s ruling allowing Capacity Performance.
David “Scarp” Scarpignato of Calpine said his company did not want to move forward with the effort.
“We understand that PJM wants to give people the ability to truly offer aggregated resources,” Scarp said. “We do appreciate that anyone who can meet the CP requirements should be able to bid in. But this goes contrary to a very recent FERC order.”
Jason Barker of Exelon said the desired timeline to study the issue and recommend changes “seems strained at best.” Any modifications to planning parameters would have to approved by the first week of February for next year’s BRA.
Bresler echoed Barker’s concern. “I recommend restricting the talk to things that might be attainable,” he said. “You’re really going to have to focus your discussion on something that’s manageable.”
Aggregation not an Option
Dan Griffiths, executive director of the Consumer Advocates of the PJM States, said that when FERC ruled, it didn’t know that aggregated products would not be offering into the BRA or subsequent transitional auctions.
“The longer we go, the clearer we will see that’s not an option that works for seasonal capacity resources,” he said. “The notion that we shouldn’t do something because we’re changing the model I think is inconsistent in that we’ve been changing the model since it was created.”
Gregory Carmean, executive director of the Organization of PJM States, said that the challenges to seasonal resources participating in the market is an unintended consequence from the “rushed” Capacity Performance model.
Capacity Performance, he said, “was designed only to meet one objective: reliability. There are other aspects of competitive markets that can be affected. … It behooves PJM to at least study these options. If we move forward, and these things fall by the wayside, I don’t think PJM will be doing its part to foster competitive markets that meet the needs of the public.”
The MRC also approved a problem statement and issue charge to study the challenges associated with capacity resources subject to pseudo-tie requirements. (See “Study of Pseudo-Tie Standards for External CP Deferred,” PJM Markets and Reliability Committee Briefs.)
The issue had been postponed a month after members asked staff to narrow the scope of the proposal.
The work will be assigned to the Underperformance Risk Management Senior Task Force, which will be asked to devise recommendations addressing “equal opportunity based on deliverability” and “existing or new challenges to currently approved pseudo-tie resources.”
The task force will be expected to present their findings to the MRC in August or September for implementation in the 2017 BRA.
The motion passed with one “no” vote and zero abstentions.
