CARMEL, Ind. — MISO will require its managers to undergo training on handling harassment complaints amid heightened awareness over sexual misconduct in the workplace.
MISO Vice President of Human Resources Greg Powell announced the new training during a Dec. 5 Human Resources Committee of the Board of Directors meeting.
In response to a question from Director Mark Johnson, Powell also said HR and management will have additional discussions on sexual misconduct awareness in the first quarter of 2018. “What are we doing from an overall standpoint to make sure all employees feel safe?” Johnson asked.
The HR Committee also decided to reserve time during first-quarter meetings to take up the topic.
“News headlines in recent weeks remind all organizations of the importance of ensuring a respectful and professional workplace,” Powell said, referring to the spate of sexual harassment and assault accusations that have roiled the media, politics and other industries. “Even some in our energy industry have fallen to this very bad situation in the headlines.”
NERC CEO Gerry Cauley resigned last month after his arrest for assaulting his estranged wife after she allegedly discovered his relationship with a female subordinate. (See Cauley Resigns; NERC Launches Search for Replacement.)
Powell said MISO will initiate a longer, more intense training for managers that will cover “all workplace harassment issues” in addition to the existing annual springtime sexual harassment training required of all employees.
Director Barbara Krumsiek has also been tapped to advise leadership and the MISO board on preventing sexual harassment and addressing accusations. Krumsiek has served as senior industry fellow of Georgetown University’s Women’s Leadership Institute and has given a TED Talk on women making their way to C-suites in “toxic” cultures.
MISO urges employees to contact managers, HR and its legal department with complaints. The RTO also maintains an anonymous hotline.
Powell said MISO will continue to concentrate on training and increasing awareness among its HR ranks and management.
“In addition to a strong, comprehensive sexual harassment policy and regular training required annually for all employees, we are working to extend beyond the expected actions to involve employees at every level to support a strong, open and inclusive way of life,” Powell said. “This includes the recent launch of our Diversity and Inclusion Council and Women’s Resource Group, which were created to ensure we continue our steadfast focus on diverse viewpoints in the organization and our communities.”
The RTO currently has a 3.1 approval rating out of 5 on Glassdoor with a 36% CEO approval rating. Among more than 100 reviews by present and former employees are multiple references to MISO as an “old boys’ club” with “top-heavy” management.
“Creating a Women’s Resource Group and then promoting men who mistreat women (you know who I’m talking about) won’t fix MISO,” one anonymous reviewer identifying as a current MISO engineer said in a review posted in May.
MISO declined to say whether it has disciplined any employees for harassment or sexual misconduct, saying it considers all personnel-related information confidential.
SALT LAKE CITY — The Western Electricity Coordinating Council’s board of directors last week endorsed a new three-year operating plan for the organization, part of a larger reinvention intended to more precisely define the organization’s role in protecting electric grid reliability.
The Regional Entity is undergoing a transformation that began with its 2014 restructuring and bifurcation into WECC and Vancouver, Wash.-based Peak Reliability. WECC is the largest and most diverse of NERC’s REs responsible for monitoring and enforcing compliance with reliability standards.
WECC Board of Directors (Left-Right): Joe McArthur, Richard Woodward, Shelley Longmuir, CEO Jim Robb, Chair Kris Hafner, Vice-Chair Ian McKay, Gary Leidich, Mike Core, Richard Campbell (not pictured) | Kirha Quick for WECC
Peak Reliability, which counts utilities, transmission owners and CAISO among its six classes of members, now serves as reliability coordinator for the Western Interconnection, except the Canadian province of Alberta. The organization last week said it is exploring developing a new market structure with a division of PJM. (See PJM Unit to Help Develop Western Markets.)
WECC CEO Jim Robb | Kirha Quick for WECC
“Really, [WECC] got kind of refocused on its core reliability assurance mission,” WECC CEO Jim Robb told RTO Insider. The 2018-2020 operating plan endorsed by the board “is really just building a process that wasn’t in place before, recognizing that we have a new kind of board, new management and a new relationship with the members.”
WECC develops and implements reliability standards and regional criteria across 14 Western U.S. states, Alberta, the Canadian province British Columbia and a small, northern portion of Baja California, Mexico. It is a 501(c)(4) “Social Welfare organization” with a current annual budget of $27 million.
Last week Robb detailed the company’s many ongoing initiatives to the board at WECC headquarters, in a modernized former hardware store in downtown Salt Lake City. The discussion illustrated the many complexities in monitoring reliability on an electric grid that is rapidly changing in resource mix and market structure.
A year ago, the WECC board approved five areas of strategic focus for the next three to five years, including focusing on the reliability impacts of new and changing market structures, such as the Western Energy Imbalance Market (EIM) and Mountain West Transmission Group’s effort to join SPP.
Other areas of focus include the reliability impact of changing load and energy resources, identifying and mitigating key vulnerabilities, and analysis of future events that could affect grid reliability that encompassed “high impact, low frequency” events.
What’s in a Name?
WECC has recently revived a proposal to change its name to “Reliability West,” which officials contend would complete the bifurcation efforts begun in 2014 and position the organization as “mission-driven” and “create separation from its history as a Registered Entity,” according to a WECC white paper published last month to tackle issues around the name change, which has been under discussion for three years. The change has many implications regarding implementation costs, perceptions of what the organization does and possible confusion with other entities that share the WECC acronym, the document shows.
The WECC Board and Committees met on December 4 – 5 in Salt Lake City, Utah | Kirha Quick for WECC
“Some folks think this is just a branding effort,” Robb said at the meeting, adding that the proposed name is more reflective of the company’s mission and easier for employees to engage with.
WECC is also drawing up a three-way memorandum of understanding with NERC and the British Columbia Utilities Commission to better define the roles and responsibilities of each organization, and developing a reliability agreement with the Mexico’s Energy Regulatory Commission (CRE). It is also taking comment through Feb. 5 on proposed changes to the operating rules for its Western Renewable Energy Generation Information System (WREGIS).
WECC is funded through allocations to end users in its footprint based on net energy for load, as described in its delegation agreement with NERC. It is not a resource planner, but assesses the reliability implications of resource decisions and identifies concerns to address.
The organization also produces reliability reports on the Western grid. Its June 2017 State of the Interconnection Report showed that, between 2015 and 2016, loss of generation or transmission in the U.S portion of the Western Interconnection increased by 50% to 24 events. (See WECC Generation, Transmission Loss Events Spike.)
In the area of assuring reliability, WECC said its second-quarter index score of reliability outcomes in the Western Interconnection was at or above the average of the past eight quarters, as was the score of indicators of entities building better compliance programs.
CARMEL, Ind. — MISO’s Board of Directors on Thursday unanimously approved the RTO’s annual Transmission Expansion Plan, including 353 new transmission projects valued at $2.6 billion.
But a Texas project subject to shifting cost allocation was benched for at least two months before approval.
MTEP 17 contains $1.4 billion of projects driven by transmission owners’ local needs, including reliability, replacement of aging equipment and upgrades for environmental requirements. Almost $1 billion will be spent on baseline reliability projects, while nearly $240 million will go to generator interconnection projects. The proposed projects have expected in-service dates through 2024.
“The bulk of the dollars are being driven by local needs,” MISO Vice President of System Planning Jennifer Curran said.
MISO South represents 41% of spending under the new plan, in keeping with a trend that increasingly allocates more spending to the southern portion of the RTO’s footprint, which is experiencing load growth — unlike the Midwest region.
Texas Project Delay
The board postponed approval of the $130 million Hartburg-Sabine 500-kV line market efficiency project (MEP) in eastern Texas for two months because of a late change to cost allocation for the projects. Last month, regulators from both Texas and Louisiana asked MISO to create separate zones for the two states to allow for a more specific cost allocation.
Hartburg to Sabine Junction project | MISO
MISO has since filed with FERC to rename Local Resource Zones as “Cost Allocation Zones” for the purposes of allocating MEP costs only, with Louisiana becoming Zone 9 and Texas becoming Zone 11 (ER18-364). The proposal does not eliminate LRZs, which are used to determine resource adequacy needs, nor does it change their boundaries.
“Out of an abundance of caution, MISO does believe that a short delay would be prudent,” Curran said. A board vote on the project has been put off until Feb. 5, allowing FERC time to respond to MISO’s filing.
“The change to the zonal requirement makes sense,” Curran said. “Most of our other cost allocation zones are based on state lines.”
MISO policy requires that 80% of the costs for MEPs be allocated to local resource zones based on their relative share of adjusted benefits.
Curran said the delay would not affect MISO’s timeline for issuing a request for proposals for the project.
The Hartburg-Sabine project will be MISO’s second-ever competitively bid transmission project and the first such project to include a substation, and the RTO plans to add two new staff members to oversee the competitive process behind the project. The line is intended to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area straddling Texas and Louisiana.
“There’s a significant amount of aging infrastructure in this area,” MISO interregional adviser Adam Solomon said.
The Texas project has already frustrated some stakeholders, who last month considered requesting a longer delay over concerns about the project’s cost estimates. (See MTEP 17 Advances with Disputed Texas Project.)
TMEP project locations | MISO
MTEP 17 also includes five targeted market efficiency projects, smaller interregional projects meant to relieve historical congestion on seams shared with PJM, whose Board of Managers also approved the TMEP portfolio on Monday. (See related story, New Wave of PJM Transmission Upgrades Rankles AMP.)
All five TMEP projects this year are upgrades to existing systems. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined.
TMEP project costs will on average be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million within four years of going into service.
TMEPs are designed to address cost-effective and congestion-relieving seams projects that might otherwise be overlooked because of their low cost and small size. To qualify, projects must cost less than $20 million, be in service within three years of approval and provide historical congestion relief that is equal to or greater than construction costs within the first four years of operation.
CARMEL, Ind. — The MISO Board of Directors last week learned about the recent discovery that PJM had been committing two market-to-market errors that have likely cost MISO millions of dollars over a period of years.
They also heard that MISO may have little recourse to recover those losses.
At issue was PJM’s longtime practice of overstating its own transmission loading relief (TLR) because of a calculation error and its failure to order mandated tests required to define M2M constraints between the two RTOs. (See MISO Monitor Blames PJM for Market-to-Market Errors.)
During a Dec. 5 meeting of the board’s Markets Committee, Independent Market Monitor David Patton said MISO has anted up millions in unnecessary congestion costs stemming from PJM’s mistakes.
The untested M2M constraints led to $84 million worth of congestion in 2016 and $187 million in 2017, Patton said, adding a disclaimer that his firm probably couldn’t perfectly duplicate the constraint test that the RTOs perform, and that they may show different congestion values. Delays in defining constraints resulted in $44 million worth of congestion last year and $25 million this year.
“If they don’t define the constraint, they basically get to a free pass to use the transmission system,” Patton told the board.
Patton said one flowgate that wasn’t tested or defined as M2M led to $43 million in congestion in September alone.
“A unit was running, overloading the constraint, and we did not tell PJM to back it down,” Patton said. “We need to be vigilant. … We don’t always ask our neighbors to test the constraints.”
Willful Neglect?
Patton said PJM’s failure to order these tests was deliberate: “In our mind, this is a pretty gross violation of the Tariff, particularly since they knew they weren’t doing the test.”
Director Baljit Dail asked how Patton could be sure PJM knowingly neglected the test.
Patton said at the beginning of the RTOs’ M2M process nearly a decade ago, PJM was aware it needed to devise a new constraint model that included an actual representation of MISO system outages with shift factors, but it failed to create such a model. “They never did it, and they knew they didn’t do it.” Patton said.
“I’ll hold the rest of my questions for closed session,” Dail replied, referring to a closed session on the matter following the board’s open meeting.
“What is it that we can do as a board?” Director Thomas Rainwater asked.
Patton said there weren’t many options available to the board. It could urge enforcement by FERC, “which to be honest, hasn’t been very active in enforcement on violations of RTOs.”
“I don’t think there’s a lot you can do other than telling PJM how serious you think this is,” Patton said. He also said MISO stakeholders could pursue resettlement of prices related to the TLR miscalculations, although no precedent exists for such resettlements. PJM has been overstating its TLR response since 2009, “inappropriately” raising the relief obligation of MISO and other balancing authorities, Patton said.
Patton said it’s up to stakeholders to decide whether to pursue TLR resettlement at FERC.
“We’ve certainly resettled for less,” Patton said.
“These are serious issues with big dollar amounts,” Director Barbara Krumsiek said.
MISO Executive Vice President of Operations Richard Doying said strategies for resettlement would “certainly be a closed discussion item.”
PJM Responds
PJM Chief Communications Officer Susan Buehler told RTO Insider that PJM acknowledges it had “an internal process issue regarding the flowgate tests as well as a calculation error with respect to relief obligations,” but it disagreed that the issues amounted to a Tariff violation. She also said the MISO Monitor is possibly overstating the monetary impacts.
“PJM has corrected both issues and is evaluating the potential impacts, but at this time we do not believe the impacts are what the MISO IMM has indicated,” Buehler said.
She also said the congestion impacts and monetary values the Monitor has disclosed are projections and not solely a consequence of PJM’s “internal process issues” and “potential M2M inefficiencies” with constraints. PJM cannot confirm Patton’s numbers, she said.
JOA with TVA
Patton also urged the board to consider entering a joint operating agreement with the Tennessee Valley Authority over the TLR issue. MISO discovered PJM’s incorrect TLR values while investigating a northeastern Tennessee constraint, and Patton said TVA often calls TLRs on its 500-kV Volunteer-Phipps Bend line, which leads to price increases in the Midwest and corresponding reductions in the South. The TLR constraint contributed to higher prices during a late September emergency event, Patton said.
He said MISO has incurred 100 dispatch violations of its own constraints in responding to the competing dispatch effects of the Volunteer-Phipps Bend constraint.
“We’ll violate our own constraints in order to provide TLR to TVA,” Patton said. He also said TVA’s generation is almost always more effective and economic for managing a TVA constraint than MISO’s.
Patton originally complained about the excessive amount of relief MISO is asked to provide the Volunteer-Phipps Bend more than two years ago. (See External Constraint Vexing MISO, Market Monitor Says.) Now he thinks the RTO could lower its transmission constraint demand curve for TLR requests to avoid incurring costs to provide “very small amounts of relief.” He said MISO should instead pay TVA for economic relief on constraints pursuant to a JOA.
Doying said MISO is not in 100% agreement with the Monitor’s suggestions. “We value the reliability of our neighbor’s systems as much as we value the reliability of our own,” Doying said.
However, Doying said MISO is currently drafting a narrow JOA with TVA that would govern certain flowgates. He said MISO has had similar agreement with TVA in the past.
Patton also noted that TVA at times orders TLRs on Volunteer-Phipps Bend as a proxy to obtain relief on a nearby 161-kV constraint, and he questioned the efficiency of TVA’s process.
Director Paul Bonavia asked MISO executives if it was appropriate under NERC rules to use the 500-kV line as a proxy for a 161-kV line. Doying said the practice doesn’t violate NERC policies.
MISO General Counsel Andre Porter then reminded the board that further discussion was best left for a closed session.
“We’re not going to solve all of this today, but we’ll grapple with it, get it on the table,” Bonavia said. “How do we approach the resettlement issue. … How do we help our neighbors without being overzealous?”
“I do think we have a lot of issues to untangle with PJM and TVA,” Doying said.
CARMEL, Ind. —The MISO Board of Directors last week stepped in to order a plan of succession for the RTO’s executive leadership, while also approving its requested 2018 budget.
As part of the plan, the board immediately promoted Executive Vice President of Operations Clair Moeller to president, a permanent appointment. In the event of unforeseen circumstances related to CEO John Bear, Moeller would act as CEO, the board decided.
The RTO’s board usually takes a “nose in, fingers out” approach except when it comes to matters of personnel succession and strategic planning, Chair Michael Curran explained during a Dec. 7 meeting. He said the appointment will ensure that MISO is spared uncertainty in the event that Bear leaves his post.
For example, Curran joked, “if John gets hit by a truck, wins the lottery [or] beamed up by a spaceship.”
The board also approved a $321.7 million total operating budget and $29.6 million in capital spending for 2018.
As part of the budget, MISO will spend $21.7 million to begin replacing its aging market platform with a more adaptable modular market platform, a project it expects to complete by 2024. (See Winter Launch for MISO Website, Market System Project.) The RTO’s existing market platform relies on technology from the late 1990s, while its day-ahead and real-time market systems were added around 2005. The age of the system is limiting the new market products MISO can pursue.
“It’s approaching its teen years — God help us all,” Dynegy’s Mark Volpe joked during a Dec. 6 Advisory Committee meeting.
Alliant Energy’s Mitch Myhre, chair of the MISO Finance Subcommittee, said his group will track spending on the project.
“This is a big deal. $130 million is half of MISO’s annual budget,” Volpe said.
To date, MISO is under its 2017 base operating budget by about $1.8 million and predicts it will end the year having spent $240.8 million instead of the budgeted $241.7 million.
Chief Financial Officer Melissa Brown said the savings will result from not implementing a previously planned forward capacity market for the RTO’s deregulated areas, as well as lower-then-expected spending on building maintenance and employee travel.
MISO is $500,000 overbudget on this year’s capital spending but is poised to shrink the overage to $200,000 by year-end. The increase was mainly driven by the RTO’s effort to replace its market settlements software.
Last week also marked Director Paul Bonavia’s final meeting on the board, with his term expiring Dec. 31. In parting remarks, Bonavia called MISO a “civics lesson” and said the RTO was proof that decorum and cooperation could exist in an industry with several competing interests. “It’s positively breathtaking, with how you come together representing different interests but still have goodwill and move billions of dollars in investment,” he said.
Newly revealed photographs show Energy Secretary Rick Perry and Murray Energy CEO Robert Murray meeting in late March to discuss the coal mining company’s “action plan” — the apparent basis for Perry’s controversial call for price supports for coal generating plants.
The photos, obtained by magazine In These Times and The Washington Post, appear to contradict Murray’s statement to Greenwire in November that “I had nothing to do with” the DOE Notice of Proposed Rulemaking.
One photo shows the action plan’s cover letter, printed on Murray Energy letterhead. Another shows Perry embracing Murray.
Cover letter of Murray Energy’s “action plan” | Photograph obtained by In These Times
In These Times reporter Kate Aronoff said a confidential source provided the magazine with the photos, as well as additional, unpublished photos showing pages in the document, which propose, among other things, cutting EPA’s staff by half and replacing members of FERC, the Tennessee Valley Authority’s Board of Directors and the National Labor Relations Board.
Murray and Perry embrace. | Photograph obtained by In These Times
Aronoff said her magazine had only obtained photographs of the meeting and of the document, not the document itself.
The action plan contains language regarding the need for “immediate action” to support struggling coal plants like that in the DOE NOPR issued to FERC on Sept. 28 (RM18-1).
One section of the plan calls for “immediate action … to require organized power markets to value fuel security, fuel diversity and ancillary services that only baseload generating assets, especially coal plants, can provide,” according to In These Times.
The DOE NOPR says “immediate action is necessary to ensure fair compensation in order to stop the imminent loss of generators with on-site fuel supplies, and thereby preserve the benefits of generation diversity.”
Murray had referenced the document in an Oct. 11 episode of PBS’s “Frontline,” “War on the EPA.”
“I gave Mr. Trump what I called an ‘action plan’ very early,” said Murray, whose company’s political action committee donated $100,000 to President Trump’s campaign last year, according to the Federal Election Commission. “It’s about three-and-a-half pages … of what he needed to do in his administration. He’s wiped out page 1,” which apparently included repealing the Clean Power Plan.
Several other officials are portrayed in the photos: Perry’s chief of staff, former Edison Electric Institute Vice President for External Affairs Brian McCormack, is pictured shaking hands with Murray. Also seen is Andrew Wheeler, at the time a registered lobbyist for Murray Energy, now Trump’s nominee for EPA deputy administrator.
Murray Energy CEO Robert Murray (right) shakes hands with DOE Chief of Staff Brian McCormack (left) as Energy Secretary Rick Perry (center) looks on. | Photograph obtained by In These Times
At his confirmation hearing in early November, Wheeler testified to the Senate Environment and Public Works Committee that he had only briefly seen the document. Sen. Sheldon Whitehouse (D-R.I.) has called for its release. Wheeler has cleared the committee, and his nomination is pending a vote by the full Senate.
DOE did not dispute the authenticity of the photos. “Industry stakeholders visit the Department of Energy on a daily basis,” a department spokeswoman told Politico.
The March 29 meeting at DOE headquarters occurred just weeks after Perry was sworn in as secretary, and weeks before he would order a study on the effect of federal policies on the reliability of the grid.
Later in July, according to a letter from Murray to Trump obtained by the Associated Press, Murray met with the president and Perry in Youngstown, Ohio, where he asked that the secretary declare an emergency on the grid under Section 202(c) of the Federal Power Act in order to protect coal-fired plants owned by FirstEnergy, Murray’s biggest customer.
Andrew Wheeler, President Trump’s nominee for EPA deputy administrator, is seen on the far right, as Murray speaks with Perry. | Photograph obtained by In These Times
Trump was receptive to the proposal and, according to Murray, told Perry three times that “I want this done.” On Aug. 3, Murray again met with the president, along with FirstEnergy CEO Charles Jones, in Huntington, W.Va., where Trump told personal aide John D. McEntee III to tell Gary Cohn, director of the White House’s National Economic Council, “to do whatever these two want him to do.”
Perry, however, rejected the emergency order, the AP reported on Aug. 22. The next day, the department released its grid study. And a month later, Perry issued his NOPR, ordering FERC to consider fully compensating plants with a 90-day supply of on-site fuel their operating costs. (See Perry Orders FERC Rescue of Nukes, Coal.)
The PJM Board of Managers last week authorized $348 million in transmission projects. Coming two months after it greenlit $1 billion in projects, the approvals irked American Municipal Power, the RTO’s biggest critic when it comes to its Regional Transmission Expansion Plan.
“There was another $186 million of supplemental projects that will move forward in the PJM process. In other words, over a third of the transmission projects reviewed in this time frame were not approved by the PJM board,” American Municipal Power’s Ed Tatum said in an email. “These projects were not subjected to the same level of rigorous review afforded baseline projects, yet the cost of these facilities will ultimately be borne by the consumers in the constructing transmission owners’ zone.”
Tatum was referring to the separation within PJM’s RTEP between different types of projects: baseline projects requested to address reliability issues that receive significant RTO scrutiny; and “supplemental” projects proposed by TOs to address their own internal criteria that aren’t subject to the same level of analysis.
PJM must make recommendations and receive board authorization before assigning baseline projects, but TOs do not need RTO approval for supplementals.
“Another half-billion dollars of more supplemental projects are waiting in the wings. The sheer volume of projects moving forward absent adequate review for need and alternatives should be a grave concern to the PJM board,” Tatum said.
Last week’s decision by the board authorized 26 projects, most of which were reliability upgrades or replacements. There were three market efficiency proposals PJM staff recommended for authorization, though they accounted for less than $10 million. Twelve of them are in the Mid-Atlantic region of PJM’s footprint; 10 are in the Western area and four are in the Southern area.
The board also approved PJM’s installed reserve margin (IRM) of 15.8% for 2021/22. The IRM dropped from 16.6% thanks to an anticipated fleet-wide equivalent forced outage rate (EFORd) reduction from 6.59% to 5.89%. (See “IRM Results Approved,” PJM Planning/TEAC Briefs Oct. 12, 2017.) An IRM study earlier this year also created updated margins for other delivery years, which the board also approved: 16.1% for 2018/19 and 15.9% for 2019/20 and 2020/21.
The board also approved five targeted market efficiency projects (TMEPs) in conjunction with MISO that traverse the grid operators’ borders. The smaller, congestion-relieving interregional projects were also approved last week by MISO’s board. (See related story, MISO Board Approves $2.6B Transmission Spending Package.)
The portfolio of system upgrades has a combined cost of $20 million. On average, project costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million.
FERC last week approved several changes to MISO’s competitive transmission developer selection process under Order 1000, which the RTO says will greatly improve its efficiency.
The most substantial of these changes eliminates MISO’s facility-by-facility evaluation when considering a developer’s bid, allowing the RTO to evaluate the project as a whole (ER18-44). Previously, the RTO had to individually assess a project’s facilities, such as lines and substations, even if they were all part of the same project. MISO called this approach both “inefficient” and “analytically flawed.”
MISO will now evaluate mixed-facility projects (those consisting of both competitive lines and substations) using the following weights:
35% for cost and facility design quality;
30% for project implementation capabilities;
30% for operations, maintenance, repair and replacement capabilities; and
5% for MISO transmission planning process participation.
Previously, the RTO used separate weighting for lines and substations.
Developers Midcontinent MCN and LS Power protested the new weighting. Both said the cost and description criterion, though increased by 5% for both types of facilities, should have significantly greater weight.
FERC rejected this, saying it agreed with MISO “that providing greater weight (35%) for cost and reasonably descriptive facility design quality appropriately accounts for the evaluation criterion that MISO anticipates will result in the greatest challenges for these types of projects, which include different types of facilities.”
“Indeed, MISO’s proposal to provide greater weight for the cost and reasonably descriptive facility design quality evaluation criterion for mixed-facility projects is consistent with LS Power’s and Midcontinent MCN’s general view that this evaluation criteria should play a greater role in the competitive developer selection process,” the commission said.
Additionally, FERC accepted other noncontroversial changes to the selection process. One of these allows MISO to stagger its requests for proposals for competitive projects. The RTO had explained that, as its Board of Directors approves projects for bidding in packages, drafting RFPs for the projects at the same time created significant staffing crunches (ER18-41).
The commission also approved several revisions to MISO’s governing documents to update terms and definitions related to the competitive process, as well as to improve their clarity, grammar and formatting (ER18-39).
Public Service Enterprise Group CEO Ralph Izzo last week asked New Jersey legislators to approve subsidies for the company’s three in-state nuclear facilities, warning they may otherwise be shuttered.
Testifying at a joint session of the General Assembly’s Telecommunications and Utilities Committee and the Senate Environment and Energy Committee on Dec. 4, Izzo said PSEG’s three nuclear units at the Salem and Hope Creek facilities remain profitable but are threatened by low natural gas prices and could become uneconomic within two years. He said the plants’ finances have been propped up by hedging over the past three years, but most of those contracts are set to expire by the end of next year.
“Unless market prices change, we will no longer be covering our costs within the next two years. Without intervention — without a thoughtful economic safety net — PSEG will be forced to close its New Jersey nuclear plants,” he said. “It would be an extraordinarily painful decision because of how much we value the importance to New Jersey, but it is a cut-and-dry decision.”
A Brattle Group study produced for PSEG and Exelon found that allowing the facilities to close would increase New Jersey power bills by $400 million annually over the next decade while reducing state tax receipts by $37 million, eliminating 1,400 jobs and increasing carbon dioxide emissions by 13.8 million metric tons annually.
Izzo requested state subsidies like the zero-emission credits approved in Illinois and New York for units owned by Exelon, which also owns 43% of the two Salem units.
Opposition Coalescing
Opponents questioned Izzo’s prediction that the plants will become unprofitable.
“It is not enough to simply accept PSEG’s assertions regarding the plants’ profitability, and that even if the plants are shown to be at risk of losing money in the future, the solutions must be found within the federally administered markets and not through out-of-market payments for plants that are already profitable,” said Stefanie Brand, the director of New Jersey’s Division of Rate Counsel. “Just because nuclear plants in other parts of the country are not profitable, doesn’t mean that plants in New Jersey — the state with the highest prices in PJM — are also unprofitable.”
PSEG’s units benefit from constraints in New Jersey’s EMAAC locational deliverability area (LDA) that traditionally put its clearing prices near the top in PJM. Capacity prices for delivery year 2020/21 during May’s Base Residual Auction fell to $76.53/MW-day in most of the RTO, while EMAAC jumped to $187.87 from less than $120 for 2019/20. (See Analysts See End to New Builds in PJM Capacity Results.)
PJM sent identical letters to Sen. Bob Smith, chair of the Senate committee, and Wayne DeAngelo, chairman of the Assembly committee, urging lawmakers to consider a regional approach rather than having the state act on its own. “As a state within PJM, New Jersey need not address these challenges alone or in a vacuum. Being located within PJM — a regional organization with a multistate market — allows for solutions and alternatives that can augment, enhance and amplify the means by which you meet your state policy priorities.”
“There is no evidence that PSEG’s nuclear plants are uneconomic and facing a retirement signal from the PJM markets,” said Joe Bowring, PJM’s Independent Market Monitor. “Neither plant is defined as at risk according to the criteria that the IMM applies to all units in the IMM’s annual PJM State of the Market Report.”
He argued that subsidizing the units would also deter investment in newer technology.
“Subsidies suppress energy and capacity market prices and therefore suppress … investment incentives for innovation in the next generation of energy supply technologies and energy efficiency technologies. These impacts are large and long lasting,” he said. “If subsidies are provided to one generating plant, this will suppress prices for all generating plants and create a need for additional subsidies for the remaining units. Competition in the markets will be replaced by competition to receive subsidies.”
Other Opponents
Also opposing PSEG’s proposal are AARP, which launched an anti-subsidy ad campaign, and the New Jersey Coalition for Fair Energy — whose members include Calpine, Dynegy, NRG Energy and the Electric Power Supply Association — which released a TV spot.
The New Jersey Coalition Against Nuclear Taxes includes AARP, environmental groups, the New Jersey Petroleum Council and other groups. Over the summer, one of its members — Dennis Hart, executive director of the Chemistry Council of New Jersey — criticized PSEG for “trying to build support in the New Jersey Legislature for another government handout that may cost all New Jersey ratepayers about $350 million annually over a 10-year period, or $3.5 billion.”
In a press release announcing its formation about a week before last Monday’s hearing, the Coalition for Fair Energy upped that estimate to “the range of $475 million a year or more, or in excess of $4 billion total” based on analysis of the New York and Illinois initiatives.
“There is no need for the Legislature to rush to pass a bill of such magnitude in a lame duck session without a full and thoughtful examination of a subsidy and its implications on the cost of electricity and its impact on a fair, level and competitive electric marketplace,” coalition spokesman Matt Fossen said in the release. “The public deserves complete transparency and a review of PSEG’s finances to see if there is any basis for a ratepayer-financed subsidy.” In his testimony, Izzo promised to open his company’s financial books for an independent examination.
After the Dec. 4 hearing, Smith said that legislation supporting the plants could be enacted during the lame-duck session, which ends early in January. “I learned enough today to begin the discussion,” he told NJ Spotlight.
Outgoing Gov. Chris Christie said he would sign a bill to save the nuclear plants, but only if it does not include incentives sought by environmentalists.
FERC last week again rejected PJM’s 2012 compromise on the minimum offer price rule (MOPR), saying that eliminating unit-specific exemptions and subjecting generators to the offer floor for three years is unreasonable (ER13-535-004).
The commission originally rejected PJM’s proposal in 2013, saying it discouraged new entry because the exemptions were too narrow and the mitigation period was too long. However, it indicated it would accept the proposal if the unit-specific review were retained and the mitigation period remained unchanged. PJM agreed in a compliance filing adopting FERC’s changes, but a handful of stakeholders petitioned the D.C. Circuit Court of Appeals to review the order.
PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | PSEG
In July, the D.C. Circuit said the commission had overstepped its authority in undoing the compromise. The court determined that FERC exceeded its “passive and reactive role” under Section 205 of the Federal Power Act, which requires it to accept proposed rate changes if they are just and reasonable and suggest only “minor” changes. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
PJM’s proposal would have replaced the unit-specific MOPR exemption with two new categorical exemptions and extended the mitigation period from one to three years before a unit could bid below the price floor. The change was prompted by generators’ concerns that the unit-specific review, which allowed units to prove confidentially to PJM that its costs were below the required minimum offer, lacked transparency and allowed below-cost bids.
In exchange for eliminating the exemption, load-serving entities won an agreement for two new exemptions: a competitive-entry exemption for units that are unsubsidized or subsidized through a nondiscriminatory, state-sponsored procurement process; and a self-supply exemption for units intended to meet a portion of an LSE’s needs.
The compromise proposal was widely supported by PJM stakeholders — the first time that a significant MOPR revision had won a two-thirds sector-weighted vote, the court noted.
Although the commission’s membership has changed since 2012, its opinion of the PJM proposal did not.
“We continue to find that PJM has failed to show that its proposed categorical exemptions, standing alone, are just and reasonable … because there would be no means for nonexempted resources with lower costs than the MOPR offer floor to have a competitive bid considered in the auction,” Commissioners Cheryl LaFleur, Neil Chatterjee and Richard Glick wrote in the 3-0 order. “We also continue to find that PJM failed to show that extending the mitigation period from one year to three years is just and reasonable. … Accordingly, we reject PJM’s December 2012 filing in its entirety and reinstate its previously approved market design, i.e., a MOPR without categorical exemptions but with a unit-specific review process and a one-year MOPR mitigation period.”
Chairman Kevin McIntyre and Commissioner Robert Powelson did not participate in the ruling.
The commission said a unit-specific exemption was necessary because “the benchmark price that is used to set the MOPR is an estimate of the net [cost of new entry]. This derived price may exceed the actual costs of individual generators and such generators should have an opportunity to demonstrate as much.”
The fact that unit-specific reviews are more complicated than categorical exemptions did not justify their elimination, the commission said. “We concur with the [Independent Market Monitor], and we disagree with the notion that the unit-specific review is an unworkable method to prevent buyer-side market power, as evidenced by its effective use in ISO-New England Inc. and NYISO.”
It said the three-year mitigation period was improper because it would prevent resources from bidding based on their going-forward costs.
“Before a resource is built, its incremental cost would reflect the unit-specific net CONE, but once the resource has cleared in one auction, its developer would need to begin construction to meet its obligation three years later in the delivery year. At that point, the construction costs incurred prior to subsequent auctions become sunk costs, and they are not part of the resource’s incremental costs going forward,” the commissioners said. “But under a three-year mitigation period, developers whose offers are mitigated and clear in the auction would be prevented from offering at their going-forward costs for at least two years beyond the first auction in which they clear and would instead have to offer at … an artificially inflated price.”
The commission said, however, that it would not order PJM to rerun its capacity auctions under the rules in effect before the 2012 filing, saying it “would cause significant disruption and burdens that are not warranted.”
The situation may soon become moot as PJM completes its yearlong examination of its capacity construct. A proposal from the Monitor to extend the current MOPR process — the only plan to receive endorsement by the task force investigating the issue — is set for a vote at the Dec. 21 meeting of the Markets and Reliability Committee.
The proposal would expand the MOPR to all units indefinitely but would include exemptions for self supply, competitive entry, public power and state renewable portfolio standards programs.
The Monitor is holding a question-and-answer session following Tuesday’s Operating Committee meeting to address stakeholder questions ahead of the vote.
PJM has not confirmed it would file the proposal for FERC approval should it win endorsement, but Monitor Joe Bowring confirmed he would file it himself if the RTO refuses. (See related story “Stakeholders Have Questions Before Approving MOPR-Ex,” Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
