FERC declined to hear a complaint brought by a wind developer against the New Mexico Public Regulation Commission that sought to clarify when the Public Utility Regulatory Policies Act kicks in as a generation project moves forward in the development process (EL19-25).
Great Divide Wind Farm filed a petition for an enforcement action against the PRC pursuant to PURPA. The generator argued that Part 570 of the New Mexico Administrative Code, as interpreted by the commission, violated PURPA by requiring that a qualifying facility be built and ready to connect before a utility has a legally enforceable obligation to buy its power.
Great Divide said it could be difficult to obtain financing to build a project without assurances of future power purchases.
“Great Divide asserts that the effect of the New Mexico commission’s requirement is to deny Great Divide the right to the legally enforceable obligation needed to provide the certainty required to obtain the financing to construct the QFs,” FERC said.
Great Divide Wind Farm, a subisdiary of Scout Clean Energy in Boulder, Colo., is developing a wind energy project in southwestern New Mexico. | Scout Clean Energy
FERC declined to initiate an enforcement action — legally freeing Great Divide to bring a case in federal court under PURPA.
Great Divide, a subsidiary of Scout Clean Energy in Boulder, Colo., is developing two 80-MW wind projects in southern New Mexico that will eventually connect with the El Paso Electric’s grid in 2020, it said.
After self-certifying the projects as QFs in August 2018, Great Divide filed a complaint before the PRC requesting it find El Paso Electric had a legally enforceable obligation to purchase the output of Great Divide’s QFs starting in 2020.
The state commission issued a final order on Nov. 7, 2018, dismissing Great Divide’s complaint without prejudice. It found that “a legally enforceable obligation is not created in New Mexico until the QF is ready to interconnect to the utility.”
The PRC had decided a similar case, Western Water and Power Production, Limited, LLC v. Public Service Company of New Mexico, in which it had dismissed Western Water’s complaint. In that case, the PRC also said its administrative code requires a QF to show it is ready to interconnect and deliver energy before a legally enforceable obligation is created.
FERC had declined to hear that case (EL17-17), letting the PRC’s decision stand.
“The New Mexico commission … noted that its ruling was not declared by this commission to be contrary to PURPA and this commission’s regulations,” FERC said.
Regulators Grant Preliminary Approval to Sharyland-LP&L Projects
The Texas Public Utility Commission last week issued preliminary orders approving certificates of convenience and necessity (CCNs) related to integrating a portion of Lubbock Power & Light’s SPP load into the ERCOT system.
The commission consented to a request by the city of Lubbock and Sharyland Utilities to build a single-circuit 345-kV transmission line and associated facilities, which include an expanded LP&L switchyard. Sharyland will take care of the construction, while LP&L will own and operate the line upon its completion (Docket 48668).
The project has a total estimated cost of $65.3 million to $90.4 million. The 18 proposed routes range between 30 and 50 miles.
During its Feb. 7 open meeting, the commission also conditionally approved LP&L and Sharyland’s joint application to build a 345-kV transmission line and a 115-kV line that will eventually interconnect (Docket 48909).
Sharyland will own the 115-kV line but will share ownership of part of the 345-kV line with LP&L. The former is expected to cost $49.7 million to $61.4 million and has 14 potential routes ranging between 14 and 26 miles. The latter project has an estimated cost of $88.4 million to $103.9 million and 22 possible routes ranging in length from 42 to 53 miles.
In a memo, PUC Chair DeAnn Walker said it was inappropriate for two separate transmission lines to be filed in a single CCN application because “it raises concerns of efficient administrative processing of the cases.”
But Walker said she was willing to make an exception in LP&L’s case because severance might be too difficult at this point and the project is time-sensitive. She recommended the State Office of Administrative Hearings issue separate proposals for decisions for each line and said that future CCN applications should be split apart if more than one transmission line is included.
Sharyland had proposed a $247.5 million, 345-kV project in the Texas Panhandle that overlapped with the facilities needed to integrate LP&L into ERCOT, but predated LP&L’s move. ERCOT was unable to find the project as meeting economic needs.
The PUC must issue a final decision in both dockets by Sept. 20.
LP&L announced in 2015 that it intended to move about 70% of its load, currently provided through two long-term contracts with Southwestern Public Service (one of the contracts expires in 2021). The PUC approved the migration in March 2018. (See “LP&L Welcomed into ERCOT,” Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
PUC Puts off Final Decision on Rayburn Country
The commission debated but put off two decisions related to Rayburn Country Electric Cooperative’s proposal to move 96 MW, or about 12% of its load, from SPP into ERCOT.
At issue is Rayburn’s request that the load being transferred to the Texas grid be included in the co-op’s existing non-opt-in entity load zone (an area without retail choice), and that it be granted a good-cause exception from a four-year notice requirement for ERCOT Board of Directors approval. The commission also expressed concern that congestion revenue rights holders in the area might not have been properly notified (Docket 48400).
Following the open meeting, the PUC filed a briefing order requesting briefs from the settlement’s signatories by Feb. 26. The commission expects to file a completed order at its March 13 meeting.
Rayburn signaled its intentions to transfer the load in 2016, and late last year it reached an unopposed settlement with commission staff, Oncor and the Texas Industrial Energy Consumers that approved the transfer of the load and associated facilities into ERCOT. The agreement denied the sale of transmission facilities and associated CCN rights to Lone Star Transmission.
ERCOT and SPP did not join in the agreement, but they did not oppose it either.
Separately, the commission held off on an order approving Rayburn’s sale of a 30-mile, 138-kV line in its territory to NextEra Energy Transmission Southwest (NETS). Southwestern Electric Power Co. owns the substations at both ends of the line, and NETS plans to transfer functional control of the line to SPP when the transaction is completed (Docket 48071).
NETS has applied to become a transmission-owning member of SPP.
“I see a lot of inefficiencies,” Walker said.
Commissioner Arthur D’Andrea supports Walker’s decision, but Commissioner Shelly Botkin said she had not yet formed an opinion on the “broader issues.”
The PUC’s final order is clouded by its 2017 ruling under different commissioners that SPS does not possess an exclusive right to construct and operate transmission facilities, including new regionally funded transmission facilities, within its service area. Former Commissioners Ken Anderson and Brandy Marty Marquez had also determined the commission had the authority to grant a certificate to an entity that will provide only transmission service outside of ERCOT (Docket 46901).
“I don’t believe we have the authority to grant this,” Walker said. “I read everything in 46901. I would not have come down that way.”
“We might need time to think creatively about the best way to do this and change course,” D’Andrea said.
SPS appealed the decision in November 2017 to the 459th District Court (D-1-GN-18-000208).
Staff to Study ERS Load Resources
In other actions, the PUC:
Directed staff to open a project on emergency response service (ERS) and the potential for daily offers into the market. Walker noted some load resources are currently excluded from offering ERS because of unavailability for particular contract periods.
Delegated authority to Executive Director John Paul Urban to sign joint comments with the Texas Commission on Environmental Quality and the Railroad Commission of Texas in response to EPA’s proposal to eliminate the requirement that new coal-fired generation incorporate carbon-capture technology (EPA-HQ-OAR-2013-0495). The three agencies have joined together before to provide comments on similar legislation. (See EPA Eases Rules for New Coal Generation.)
Approved CCNs for Electric Transmission Texas’ 345-kV project in South Texas. The commission found the $44.8 million cost for 5 miles of 345-kV double-circuit line and a substation expansion to be reasonable. The area has incurred overloading since the 524-MW Frontera combined cycle generation facility began exporting its capacity to Mexico in 2016 (Docket 47973).
VALLEY FORGE, Pa. — PJM’s Planning Committee on Thursday unanimously approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind.
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore, PJM’s Sue Glatz said.
The vote came after PJM officials resisted calls to broaden the initiative to also consider rules for non-controllable AC transmission facilities onshore.
“My concern is that in essence what we are doing is that we are going to prioritize the transmission facilities built out into the ocean, but we are not giving a path for the same thing to occur for facilities with future plans to connect to renewable resources,” said Ryan Dolan, director of transmission planning for American Municipal Power. “We are mitigating risk for offshore and not doing the same thing for AC onshore.”
Offshore transmission developers want to acquire CIRs so PJM can identify the necessary network upgrades.
The key difference from the normal procedure is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses. (See “PJM Ponders Rules for Offshore Wind Transmission,” PJM PC/TEAC Briefs: Jan. 10, 2019.)
PJM said the narrow scope of the problem statement addresses an immediate need from pending interconnection requests.
The RTO hopes to develop a FERC filing on Phase 1, focusing on rules for a single offshore generator lead line, by July.
Steve Herling, PJM vice president of planning, said the RTO could discuss extending similar rights to onshore developers in Phase 2 of the initiative, when it will consider networked offshore transmission for connecting multiple wind sites.
“We don’t have a fundamental issue with doing the same thing onshore … but because of the immediacy of the need, we would prefer to develop this with respect to offshore and then it would probably be a fairly straightforward extension of it in Phase 2 if there’s value of doing it onshore,” Herling said. “We do feel a sense of urgency offshore.”
PJM has targeted Phase 2 for a September 2020 FERC filing.
Quick Fix for Queue Filing Errors Endorsed
The PC approved a problem statement and solution to prevent transmission customers from falling out of the interconnection queue because of minor errors.
The one-sentence rule change allows customers 10 days to fix any deficiencies in their requests — whether they submit their application on the first or the last day of the new services request window.
PJM’s Susan McGill first presented the problem statement to the committee in January, suggesting the RTO reverse rules implemented in 2016 by the Earlier Queue Submission Task Force that didn’t allow requesters adequate time to clear errors found in their submissions. (See “PJM Seeks Fix on Queue Filing Errors,” PJM PC/TEAC Briefs: Jan. 10, 2019.) The change — intended to encourage generation customers to submit requests earlier in the six-month window — led to a 6% increase in terminated or withdrawn applications filed in the last month.
PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”
The problem statement is scheduled for endorsement at the March 21 Markets and Reliability Committee meeting. It would be effective with queue AF1, which opens April 1.
PJM Pushes Change in Wind, Solar Capacity Measurements
PJM has decided to use effective load carrying capability (ELCC) to calculate wind and solar capacity credits, calling it a “superior alternative” to current rules using average values. ELCC measures the additional load that a group of generators can supply without a reduction in reliability.
The new methodology combines wind and solar capacities in one calculation that is later prorated. Tom Falin, PJM’s director of resource adequacy planning, said this process sets wind and solar factors to 12.3% and 41%, respectively.
“I think all along we should have done this in a composite manner,” he said. “Why? Because both wind and solar are going to be around to serve PJM load. It’s a model of the entire system.”
Falin said considering the total amount of intermittent generation is crucial to the process, noting the “point of ELCC is to really figure what’s the incremental value of a new type of unit when you add it to the existing fleet.”
Some stakeholders disagreed with PJM’s decision to calculate solar and wind capacities together, citing their different characteristics.
“I agree they are both going to be here, barring some disaster,” said John Brodbeck of EDP Renewables. “We’ve been working them as separate numbers. … I haven’t noodled through what this does here. It just seems to mix apples and oranges.”
The new rules will be included in Manual 21 changes that will be presented to members in March. PJM wants to request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. They would not affect UCAP values from prior auctions.
Holistic Review of RTEP Removal Suggested
PJM said Thursday it’s considering drafting a problem statement regarding how projects get removed from the Regional Transmission Expansion Plan, suggesting the process needs a “holistic” review.
PJM’s Aaron Berner said because of differing regulatory requirements in its 13 states, the RTO has dealt with cancellations on a case-by-case basis. Cancellations can result from a reduction in load forecasts — eliminating the need for a project — or because developers are unable to get state siting approval.
“In the past there have been changes to the load profile or the actual load forecast that’s resulted in a reduction for a need for reinforcement on the system, and we have pulled some baseline upgrades based on that,” he said. “Primarily, it’s our need that drives our decision around the various insertions and removals of the project.”
The issue arose after Sharon Segner, vice president of LS Power, proposed an amendment to Manual 14B: PJM Region Transmission Planning Process specifying that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project.
“It’s very important that the rules be very clear with how projects are added to the RTEP and how they are removed,” Segner said. “We stand behind the viewpoint that PJM should be a strong regional planner and have complete authority over the regional and supplemental process.”
Segner first presented the new manual language during the Jan. 24 MRC meeting as a friendly amendment to a proposal from American Municipal Power to increase transparency of supplemental project planning. AMP accepted the amendment as friendly. Despite winning a majority of stakeholder approval, PJM declined to implement the entirety of the AMP proposal, calling it an overreach of the RTEP. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
PJM said it will discuss the issue further with stakeholders after identifying requirements in the Operating Agreement, Tariff and manuals that spell out when projects should be removed from or added to the RTEP.
Segner declined to say whether she will seek a vote on her language at the MRC. “I’m still getting feedback; the purpose of this discussion was to talk through substance. It’s not a procedural discussion today,” she said. “PJM said they’re taking this [PC discussion] under advisement. That’s what LS Power is doing as well.”
Dominion, ATSI Present Supplemental Projects at TEAC
TOs presented two supplemental projects to the Transmission Expansion Advisory Committee.
American Transmission Systems Inc. plans upgrades to a 345-kV line between Erie, Pa., and the Perry nuclear plant in Ohio. The three-terminal line is prone to misoperations and subject to longer restoration efforts, and its relay transmission communication equipment is nearing its end of life, ATSI said. No cost was listed.
Dominion Energy Virginia presented seven supplemental project needs and one solution, a second distribution transformer at the Greenwich substation to address growing load. The $1.4 million project is expected to be complete by Oct. 15.
Dominion listed the following needs:
A third distribution transformer at the Winterpock substation;
A second distribution transformer at the Rockville substation in Goochland County;
A second 84-MVA distribution transformer at the Cumulus substation in Loudoun County;
A new Lockridge substation to support a new data center campus in Loudoun County with a total load exceeding 100 MW;
A third 84-MVA distribution transformer at the Pacific substation in Loudoun County;
A new Perimeter substation to support a new data center campus in Loudoun County; and
A new Relocation Road substation to support a new data center campus in Loudoun County with a load exceeding 100 MW.
VALLEY FORGE, Pa. — The PJM Demand Response Subcommittee would be tasked with updating the testing rules for rarely dispatched DR resources under a problem statement and issue charge presented to members Wednesday.
PJM’s Jack O’Neill told the Market Implementation Committee that the RTO’s current testing rules are based on limited demand response (LDR) requirements made obsolete by Capacity Performance.
LDR applied only to summers, non-holidays and weekends, while CP requires the resource on demand year-round. Likewise, CP events can now last up to 15 hours — versus just six under LDR — and lack LDR’s cap of 10 reductions a year.
PJM says it is concerned because load management events are “low frequency, high impact” incidents. The last recorded event, in 2013, required reductions totaling 6,000 MW across 15 transmission zones. In years when there are no events, there is only a one-hour summer test of performance.
“Testing is our fallback position when there isn’t anything to measure against,” O’Neill said.
PJM noted that DR has averaged about 123% performance in tests versus about 97% in actual events. “This indicates that testing may not reflect performance during actual events,” the problem statement says.
The RTO hopes to bring the revisions to the MIC for a first read in August, a schedule it said would allow for a FERC filing by February 2020 and a commission ruling in time for next year’s Base Residual Auction.
The daily load management test failure charge rate will not be affected by the review.
Utilities Question Primary Frequency Response Calculation
VALLEY FORGE, Pa. — PJM’s Operating Committee last week endorsed revisions to Manual 12: Balancing Operations over the opposition of FirstEnergy, which challenged the manual’s formula for judging primary frequency response performance.
Under the formula included in a newly added Section 3.6 of the manual, PJM will evaluate generators’ performance during events in which the system frequency goes outside a +/-40-MHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz.
PJM’s Danielle Croop, senior engineer of operation analysis and compliance, said the formula was vetted by the Primary Frequency Response Task Force based on NERC criteria.
“We opened up our criteria to be more lenient … and we are catching as much performance as we can,” she said. “We are open to changing the formula.”
Jim Benchek, FERC and RTO market technical support at FirstEnergy, said the formula is too sensitive and could result in false failures. “We prefer not to have the formula memorialized in the manual at this time.”
He added that his company remains committed to providing PFR.
The manual changes were endorsed despite 24 objections by FirstEnergy and Duke Energy and 20 abstentions.
At the January OC meeting, American Electric Power noted that FERC’s order did not require scoring of PFR and said PJM had little stakeholder support for it. (See “The Right Metric on Frequency Response?” PJM Operating Committee Briefs: Jan. 8, 2019.)
PJM Continues Review of Non-retail BTM Generation Business Rules
PJM provided stakeholders additional background on a proposed problem statement and issue charge that could result in revised rules for non-retail behind-the-meter generation (NRBTMG).
Terri Esterly, PJM’s senior lead engineer for capacity market operations, said business rules in the RTO’s governing documents need modifications to address the growth of distributed generation. NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load; they do not participate in PJM markets but can be netted against load to reduce certain charges.
Esterly said it’s been nearly 15 years since a settlement agreement established rules for NRBTMG — long before the RTO implemented the Reliability Pricing Model and Capacity Performance and took on several utility companies as members, including American Transmission Systems Inc., East Kentucky Power Cooperative and Duke Energy’s Ohio and Kentucky divisions.
Under existing rules, NRBTMG must operate at full output during the first 10 instances of maximum emergency generation conditions between Nov. 1 and Oct. 31. However, it’s not clear in Manual 13: Emergency Operations what procedures trigger this requirement.
Likewise, the RTO doesn’t know how close the grid is to exceeding the 3,000-MW NRBTMG cap set in 2005. PJM estimates put this value closer to 4,600 MW, but incomplete public records make it difficult to determine an exact figure.
PJM first proposed reviewing NRBTMG rules during a Jan. 8 Operating Committee meeting and faced suspicion from several municipal utilities and cooperatives. (See Munis Wary of PJM Rules on Non-Retail BTM Generation.) Stakeholders at last week’s meeting requested more firm data surrounding megawatt estimates before moving forward in the process.
Committee Endorses Updates to TO/TOP Matrix
Stakeholders unanimously endorsed changes to the Transmission Owners/Transmission Operator Matrix to document their responsibilities under new NERC reliability standards.
The matrix is an index between the PJM manuals and NERC reliability standards that spells out which responsibilities are PJM’s as the TOP and which are assigned to member TOs.
Version 13 of the matrix adds references for reliability standards:
TOP-001-4 R20 and R21, which took effect in July 2018;
VAR-001-5, which took effect Jan. 1;
EOP-004-4, EOP-005-3 and EOP-008-2, which take effect April 1; and
PER-003-2, which takes effect July 1.
The endorsed changes head to the Transmission Owners Agreement Administrative Committee for approval.
Incremental RFP Window for New Black Start Resources Closes May 1
PJM opened a window for new black start resources in the Baltimore Gas and Electric and Potomac Electric Power Co. (PEPCO) zones on Feb. 1.
PJM initiated the new request for proposals — separate from the five-year process completed in November 2018 — after receiving notice late last year of generator deactivations in BG&E’s territory not included in the original scope of projects. The RFP seeks service beginning by April 1, 2021.
“We have included the PEPCO zone and also some surrounding adjacent TO zones in this RFP in the event there are cross-zonal black start options that may be considered,” said David Schweizer, PJM’s manager of power system coordination. “We did not specify megawatts in the RFP because we want to be able to consider any size black start unit that’s proposed.”
Expressions of interest are due by Feb. 25, with detailed proposals due May 1.
Lisle RAS Scheduled for Retirement
A reinforcement project will trigger the retirement of two remedial action schemes designed to prevent thermal overloads at the Commonwealth Edison’s Lisle substation.
The project will add breakers to the four existing 345-kV lines and reconfigure the 345-kV bus into a ring-bus. ComEd said the schemes will be removed as they become unnecessary. The work is scheduled to begin in March and be complete by June 1, 2020.
WASHINGTON — Having regained control of the House of Representatives after eight years in the minority, Democrats have put a lot on their plate, including investigating President Trump’s finances and Russian interference in the 2016 presidential election.
But last week, House Democrats added climate change to their agenda, with two committees holding hearings on the topic simultaneously Wednesday, and Rep. Alexandria Ocasio-Cortez (N.Y.) and Sen. Ed Markey (Mass.) introducing the “Green New Deal” on Thursday.
The hearings came the same day that NASA’s Goddard Institute for Space Studies and the National Oceanic and Atmospheric Administration reported that 2018 was the fourth hottest year on record, with the average global surface temperature for the year coming in only behind those of the previous three.
Since the 1880s, the average temperature has risen about 1 degree Celsius (1.8 degrees Fahrenheit), according to climate scientists. A report released in October by the U.N.’s Intergovernmental Panel on Climate Change said that catastrophic effects from climate change could occur as soon as 2040, when warming is expected to reach 1.5 C if the current rate continues. International efforts, such as the 2015 Paris Agreement, have so far focused on preventing only a 2-degree C increase. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
The IPCC report said the impacts of climate change are already being felt in increased storm intensity, precipitation, wildfires and heat waves; rising sea levels from melting polar ice; and the nearing extinction of several species, including coral.
It was these effects that the hearings by the House Natural Resources Committee and the Energy and Commerce Committee, and their witnesses, focused on during Wednesday’s hearings.
“Our communities are paying the price for years of inaction on this issue,” said Rep. Raul Grijalva (D-Ariz.), chair of the Natural Resources Committee. “The massive and unprecedented storms, heat waves, fires and droughts we are experiencing are not normal. They are being made worse by climate change, and if we don’t take action now, we’re only at the beginning.”
Climate change “goes by many different names: Sandy, Harvey, Maria, Katrina, Camp Fire,” said Rep. Paul Tonko (D-N.Y.), chair of the E&C Committee’s newly renamed Subcommittee on Environment and Climate Change.
Many of the Democratic committee members used their allotted time to talk about the natural disasters unique to their states; Californians especially focused on the wildfires of the past few years.
Similarly, North Carolina Gov. Roy Cooper (D) and Massachusetts Gov. Charlie Baker (R) told the Natural Resources Committee about the challenges their states have faced.
“We’ve weathered two so-called 500-year floods in two years and three in fewer than 20 years,” Cooper said. “In the Western North Carolina mountains, volatile weather has caused mudslides, damaged infrastructure, cost apple growers valuable crops and forced ski areas to close mid-season, hurting local businesses and putting jobs in jeopardy.”
“Shortly after taking office in January of 2015, the snow started falling, hard, and it didn’t end until well into April,” Baker said. “What was different about those storms was the sheer volume of snowfall, with record-breaking amounts in Worcester and Boston.”
Most of the Natural Resources Committee’s witnesses after the governors were environmental and social activists, who spoke of how climate change would hit poor and minority communities the hardest.
“As a poor and working-class community, housing displacement and disruption of services due to storms and other severe weather affect our people much more acutely compared to resident of affluent communities with more resources,” said Elizabeth Yeampierre, executive director of UPROSE, an organization representing the Latino community in Brooklyn’s Sunset Park neighborhood.
Only two scientists appeared on the panel, one of whom, Judith Curry, was invited by Republicans and downplayed the severity of the threat. “Both the problem and its solution have been vastly oversimplified,” said Curry, president of the Climate Forecast Applications Network and former chair of the School of Earth and Atmospheric Sciences at the Georgia Institute of Technology.
Republicans Resistant
Some Republicans at the hearings questioned the science of climate change, asking questions such as whether this was the hottest the planet has been, or whether extreme heat or extreme cold kills more people.
One GOP member of the Natural Resources Committee, Louis Gohmert (Texas), asked Curry, “Do you think we’re causing the polar ice caps on Mars to melt? … That’s probably the sun.”
The Republicans that did not question the science criticized the economic costs and job losses associated with closing down fossil fuel plants, said renewable resources are less reliable than baseload plants and rejected proposed solutions as infeasible.
“We want a healthy environment for our children, grandchildren and their children,” said Rep. Greg Walden (R-Ore.), ranking member of the E&C Committee. “But we also want the people who live in our districts and in this country today, right now, to have jobs and to be able to provide for their families. These are not mutually exclusive principles. Working together, we can develop the public policies to achieve these goals.”
Rep. Rob Bishop (R-Utah), ranking member of the Natural Resources Committee, criticized Grijalva for even holding a hearing on climate change, saying it wasn’t in the committee’s jurisdiction. Instead, he said he wanted the committee to focus on issues such as wildfire management and National Parks maintenance.
“Are these hearings simply for those of us around the horseshoe who are going to be making legislation, or are these hearings simply for those who sit around that table in the corner so they can write cute stories?” Bishop asked, pointing to the table of reporters seated next to the witness table.
He noted that Grijalva had dubbed February “climate change month.”
“I appreciate the fact you picked the shortest month of the year to do that,” Bishop said.
Ironically, between the two governors at the hearing, Baker received most of the Republicans’ criticism. Rep. Tom McClintock (R-Calif.) cited the failure of two wind turbines in Falmouth, Mass. The town spent about $10 million to build the turbines in 2009 and 2011. Last month, the town’s Board of Selectmen voted to shut down the turbines and potentially spend millions more dismantling them after residents continually complained of noise.
Baker responded by saying, “My father always used to say that there’s two things: There’s doing the right thing, and then there’s doing the thing right. And doing the right thing but doing it wrong doesn’t necessarily solve the problem. There were a whole series of issues with a well-intended effort in Falmouth that in many respects failed because they didn’t make a lot of the decisions with respect to where they sited them and how they sited them that would have made sense. …
“I think sometimes when something doesn’t go the way it should go, everybody blames the concept. Well sometimes we actually just screw up the way we implement it, and it makes the concept looks bad.”
Rep. Garret Graves (R-La.) noted that his state was one of the top oil and gas producers in the country, while Massachusetts was one of the top oil and gas consumers. “How do you reconcile what you’re able to do based on your economy versus the challenges in Louisiana based on what our economy is founded on?” he asked Baker.
The governor began to explain how despite productivity and population growth, the state has reduced its emissions. Graves interrupted him, saying, “I do appreciate that you all have taken steps, I do. But I also think it’s important to recognize that states in some cases are fundamentally different.” He pointed out that Massachusetts’ electricity prices are among the highest in the U.S.
Green New Deal
Republicans at the hearings also criticized the so-called “Green New Deal,” a set of goals floated by the progressive wing of the Democratic Party after last year’s midterm elections.
On Thursday, Rep. Ocasio-Cortez, with 60 co-sponsors, formally introduced the idea in the House as a nonbinding resolution, with Sen. Markey introducing an identical resolution in the Senate.
The 14-page document calls for “a 10-year national mobilization… to achieve net-zero greenhouse gas emissions.”
The resolution also contains a hodge-podge of goals, including achieving “maximum energy efficiency” from all existing buildings and “spurring massive growth in clean manufacturing in the United States and removing pollution and greenhouse gas emissions from manufacturing and industry.”
“A new national, social, industrial and economic mobilization on a scale not seen since World War II and the New Deal era is a historic opportunity to create millions of good, high-wage jobs in the United States; to provide unprecedented levels of prosperity and economic security for all people of the United States; and to counteract systemic injustices,” the resolution says.
Specific policy proposals to achieve these goals, however, are absent from the document. And with Republicans still in control of the Senate and the White House, any legislation attempting to codify them is almost guaranteed to fail for the next two years.
Rather, many analysts last week saw the document — and the focus on climate change among Democrats this month in general — as more of a political rallying cry for the party ahead of the 2020 elections.
“It actually will be impossible to enact a Green New Deal while Trump is in the White House, but the resolution still has two useful purposes,” Michael Grunwald wrote in Politico Magazine last week. “It’s primarily a political manifesto, a messaging device designed to commit the Democratic Party to treating the climate crisis like a real crisis, pressuring its presidential candidates to support radical transformation of the fossil-fueled economy. At the same time, the Green New Deal is a policy proposal — or at least a sketch of one, a way to launch a substantive debate over how Democrats will attack the crisis if they do regain the White House.”
“In an increasingly social-media-driven political culture, the bill’s sponsors may be looking to generate ‘likes’ … rather than votes,” ClearView Energy Partners said.
Several major contenders to be the Democratic nominee in the 2020 presidential election endorsed the Green New Deal last week.
Republicans predictably lambasted the document.
“It’s a socialist manifesto that lays out a laundry list of government giveaways, including guaranteed food, housing, college, and economic security even for those who refuse to work,” Sen. John Barrasso (R-Wyo.), chairman of the Environment and Public Works Committee, said in a statement. “As Democrats take a hard left turn, this radical proposal would take our growing economy off the cliff and our nation into bankruptcy. It’s the first step down a dark path to socialism.”
MANHATTAN BEACH, Calif. — The number of NERC Regional Entities will soon dwindle to six following last week’s unanimous approval by the organization’s Board of Trustees to enter into a termination agreement with the Florida Reliability Coordinating Council (FRCC).
During the board’s Feb. 7 meeting and without discussion, trustees authorized NERC management to terminate the amended and restated delegation agreement between the organization and FRCC and to approve transfer of its registered entities to SERC Reliability.
FRCC serves as the RE, reliability coordinator (RC) and planning authority for much of the state of Florida, the latter two functions under its member services division. Its only geographic and electrical borders are with SERC.
FRCC announced last year it would dissolve its RE division following a review of its governance structure, set in motion by NERC’s 2017 determination that REs should be separate corporate bodies from NERC-registered entities. A FERC audit in 2010 spurred FRCC to improve the separation between its RE and member services divisions.
NERC will file a petition with FERC seeking its approval of the delegated agreement’s termination and the transfer of FRCC RE’s delegated authority to SERC. It has proposed a transfer deadline of July 1.
Board Chair Roy Thilly thanked FRCC CEO Stacy Dochoda for moving the process along.
“This is a complex set of arrangements, but it’s working very smoothly,” he said.
As of March 2018, FRCC had 32 registered entities in its RE division and 22 in its member services division, including duplications.
5th RC Provider Enters the Western Grid
The number of RCs in the Western Interconnection could soon number five, said Branden Sudduth, the Western Electricity Coordinating Council’s vice president of reliability planning and performance analysis.
Sudduth told trustees and stakeholders that Gridforce, a Houston-based control center, has notified WECC it intends to offer RC services to its Gridforce Energy Management (GEM) balancing authority in northern Oregon. GEM, the lone undeclared BA in Peak Reliability’s footprint, is a member of the Northwest Power Pool.
Sudduth said WECC and NERC are reviewing the application. Gridforce has an expected go-live date of Dec. 3, when Peak will terminate all its services. Peak last summer decided to close its doors when it became apparent its budget couldn’t withstand the loss of CAISO and other members. (See Peak Reliability to Wind Down Operations.)
CAISO has signed up the bulk of Peak’s membership, but SPP has also made inroads by offering RC services to about 12% of the legacy load, primarily along the Rocky Mountains. BC Hydro will take over for its British Columbia service territory.
WECC will begin its certification visits in March at CAISO, which will go live with RC services for its own territory July 1 and for its non-members Nov. 1. BC Hydro goes live Sept. 2, and SPP will follow Dec. 3.
Peak staff will spend about two months conducting shadow operations with each of the incoming RCs to ensure continuity and shared expertise. Peak is following a detailed project management path until it hands over its RC duties.
“We have a very unique requirement of providing services for a year while closing the organization,” Peak CEO Marie Jordan said. “I haven’t closed too many companies. I’ve closed some power plants, but we always had the mother ship above us. This is truly a territory not too many of us on the leadership have been down, so [we] want to do it right.”
NERC CEO Jim Robb said he found Jordan’s presentation “confidence-inspiring.”
“You’ve made it clear the focus is on reliability, not the closure of Peak,” he said.
Robb said he was concerned about the California-Arizona seam, which was a part of the 2011 Southwest outage that led to Peak’s creation. Jordan said Peak is in the final stages of executing a seams agreement with CAISO but noted that remedial action schemes (RAS) may prove more important.
“I do think RAS schemes need to be as much of a focus as the seams agreements,” she said.
WECC RC/BA footprint | WECC
SCE’s Payne: California Prepping for ‘New Abnormal’
Southern California Edison CEO Kevin Payne welcomed NERC to sunny but chilly California, saying, “You’ve picked a pretty interesting time to come” to the state.
Payne said the state is at the forefront of a clean energy future, pointing to its renewables-heavy grid and focus on greenhouse gas reductions.
“Ironically,” he said, “the very thing we’ve worked so hard to mitigate, climate change, is impacting us in real ways. If you’re a skeptic of climate change, I guarantee you would be a believer if you lived through it like we are.”
Payne said 2018 was the “most destructive, damaging and tragic fire year” in the state’s history. Capped by the deadly Camp Fire, the last two years have seen Pacific Gas and Electric rack up $30 billion in potential wildfire liabilities, leading the utility to file for Chapter 11 bankruptcy reorganization. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Former Gov. “Jerry Brown referred to the ‘new abnormal,’” Payne said. “We’re quickly preparing ourselves for the new abnormal.”
That includes hardening the grid’s infrastructure, aggressive vegetation management, installing covered conductors on thousands of miles of distribution lines and improving situational awareness by adding weather stations in the utility’s service territory. Like the state’s other investor-owned utilities, SCE filed a wildfire mitigation plan last week. (See Federal Judge to Review PG&E’s Wildfire Plan.)
“We’re working through all of this,” Payne said. “We’re getting the right policies in place, so we can move forward and focus on reliability.”
Robb Honors McIntyre, LaFleur
Robb opened his regular report by asking for a moment of silence in honor of the late FERC Commissioner Kevin McIntyre, who died last month following an 18-month battle with brain cancer. (See FERC’s McIntyre Loses Cancer Battle.)
“I’ll miss his leadership at FERC. He was a rare talent,” Robb said.
He also recognized Commissioner Cheryl LaFleur’s recent announcement that she would not be nominated for another term on the commission. (See LaFleur Announces Departure from FERC.)
“That was a bit of a blow to all of us,” Robb said. “She certainly took reliability as one of the pillars of her work at FERC. She’s been good to us.”
Robb reviewed his four priority areas with the trustees: the evolution of Western RCs; the pace of change in the resource mix; cyber and physical security; and addressing inverter-based technology. NERC defines inverter-based resources as renewable energy asynchronously connected to the grid through power electronics.
“We have to ensure these resources, which are growing at an extraordinary rate, play nicely with the rest of the grid,” Robb said.
Thilly complimented Robb for his performance since stepping into NERC’s leadership role last year. He noted Robb’s focus on a collaborative culture, “which spreads throughout the leadership at NERC and the whole company.”
“It’s been a great set of changes at the right time,” Thilly said. He then jokingly said, “I should mention, though, the honeymoon is almost over.”
Trustees Elect Case as Vice Chair
The board elected Janice Case as its vice chair, returning her to a position she also held in 2013. Case, a trustee since 2008, serves on the Finance and Audit and Technology and Security committees. She spent 25 years with Florida Progress and its Florida Power subsidiary.
The trustees also approved amendments to Texas Reliability Entity’s bylaws, following a comprehensive review to examine their consistency with the Texas Business Organizations Code, and adopted four standards as part of their quarterly standards review:
CIP-008-6, Incident Reporting and Response Planning: Modifies CIP-008 Cyber Security Incident to require reporting of cybersecurity incidents that compromise or attempt to compromise the bulk electric system, in response to FERC Order 848. Includes the Department of Homeland Security in the reporting requirements.
MANHATTAN BEACH, Calif. — The number of NERC Regional Entities will soon dwindle to six following last week’s unanimous approval by the organization’s Board of Trustees to enter into a termination agreement with the Florida Reliability Coordinating Council (FRCC).
During the board’s Feb. 7 meeting and without discussion, trustees authorized NERC management to terminate the amended and restated delegation agreement between the organization and FRCC and to approve transfer of its registered entities to SERC Reliability.
FRCC serves as the RE, reliability coordinator (RC) and planning authority for much of the state of Florida, the latter two functions under its member services division. Its only geographic and electrical borders are with SERC.
FRCC announced last year it would dissolve its RE division following a review of its governance structure, set in motion by NERC’s 2017 determination that REs should be separate corporate bodies from NERC-registered entities. A FERC audit in 2010 spurred FRCC to improve the separation between its RE and member services divisions.
NERC will file a petition with FERC seeking its approval of the delegated agreement’s termination and the transfer of FRCC RE’s delegated authority to SERC. It has proposed a transfer deadline of July 1.
Board Chair Roy Thilly thanked FRCC CEO Stacy Dochoda for moving the process along.
“This is a complex set of arrangements, but it’s working very smoothly,” he said.
As of March 2018, FRCC had 32 registered entities in its RE division and 22 in its member services division, including duplications.
5th RC Provider Enters the Western Grid
The number of RCs in the Western Interconnection could soon number five, said Branden Sudduth, the Western Electricity Coordinating Council’s vice president of reliability planning and performance analysis.
Sudduth told trustees and stakeholders that Gridforce, a Houston-based control center, has notified WECC it intends to offer RC services to its Gridforce Energy Management (GEM) balancing authority in northern Oregon. GEM, the lone undeclared BA in Peak Reliability’s footprint, is a member of the Northwest Power Pool.
Sudduth said WECC and NERC are reviewing the application. Gridforce has an expected go-live date of Dec. 3, when Peak will terminate all its services. Peak last summer decided to close its doors when it became apparent its budget couldn’t withstand the loss of CAISO and other members. (See Peak Reliability to Wind Down Operations.)
CAISO has signed up the bulk of Peak’s membership, but SPP has also made inroads by offering RC services to about 12% of the legacy load, primarily along the Rocky Mountains. BC Hydro will take over for its British Columbia service territory.
WECC will begin its certification visits in March at CAISO, which will go live with RC services for its own territory July 1 and for its non-members Nov. 1. BC Hydro goes live Sept. 2, and SPP will follow Dec. 3.
Peak staff will spend about two months conducting shadow operations with each of the incoming RCs to ensure continuity and shared expertise. Peak is following a detailed project management path until it hands over its RC duties.
“We have a very unique requirement of providing services for a year while closing the organization,” Peak CEO Marie Jordan said. “I haven’t closed too many companies. I’ve closed some power plants, but we always had the mother ship above us. This is truly a territory not too many of us on the leadership have been down, so [we] want to do it right.”
NERC CEO Jim Robb said he found Jordan’s presentation “confidence-inspiring.”
“You’ve made it clear the focus is on reliability, not the closure of Peak,” he said.
Robb said he was concerned about the California-Arizona seam, which was a part of the 2011 Southwest outage that led to Peak’s creation. Jordan said Peak is in the final stages of executing a seams agreement with CAISO but noted that remedial action schemes (RAS) may prove more important.
“I do think RAS schemes need to be as much of a focus as the seams agreements,” she said.
SCE’s Payne: California Prepping for ‘New Abnormal’
Southern California Edison CEO Kevin Payne welcomed NERC to sunny but chilly California, saying, “You’ve picked a pretty interesting time to come” to the state.
Payne said the state is at the forefront of a clean energy future, pointing to its renewables-heavy grid and focus on greenhouse gas reductions.
“Ironically,” he said, “the very thing we’ve worked so hard to mitigate, climate change, is impacting us in real ways. If you’re a skeptic of climate change, I guarantee you would be a believer if you lived through it like we are.”
Payne said 2018 was the “most destructive, damaging and tragic fire year” in the state’s history. Capped by the deadly Camp Fire, the last two years have seen Pacific Gas and Electric rack up $30 billion in potential wildfire liabilities, leading the utility to file for Chapter 11 bankruptcy reorganization. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Former Gov. “Jerry Brown referred to the ‘new abnormal,’” Payne said. “We’re quickly preparing ourselves for the new abnormal.”
That includes hardening the grid’s infrastructure, aggressive vegetation management, installing covered conductors on thousands of miles of distribution lines and improving situational awareness by adding weather stations in the utility’s service territory. Like the state’s other investor-owned utilities, SCE filed a wildfire mitigation plan last week. (See Federal Judge to Review PG&E’s Wildfire Plan.)
“We’re working through all of this,” Payne said. “We’re getting the right policies in place, so we can move forward and focus on reliability.”
Robb Honors McIntyre, LaFleur
Robb opened his regular report by asking for a moment of silence in honor of the late FERC Commissioner Kevin McIntyre, who died last month following an 18-month battle with brain cancer. (See FERC’s McIntyre Loses Cancer Battle.)
“I’ll miss his leadership at FERC. He was a rare talent,” Robb said.
He also recognized Commissioner Cheryl LaFleur’s recent announcement that she would not be nominated for another term on the commission. (See LaFleur Announces Departure from FERC.)
“That was a bit of a blow to all of us,” Robb said. “She certainly took reliability as one of the pillars of her work at FERC. She’s been good to us.”
Robb reviewed his four priority areas with the trustees: the evolution of Western RCs; the pace of change in the resource mix; cyber and physical security; and addressing inverter-based technology. NERC defines inverter-based resources as renewable energy asynchronously connected to the grid through power electronics.
“We have to ensure these resources, which are growing at an extraordinary rate, play nicely with the rest of the grid,” Robb said.
Thilly complimented Robb for his performance since stepping into NERC’s leadership role last year. He noted Robb’s focus on a collaborative culture, “which spreads throughout the leadership at NERC and the whole company.”
“It’s been a great set of changes at the right time,” Thilly said. He then jokingly said, “I should mention, though, the honeymoon is almost over.”
Trustees Elect Case as Vice Chair
The board elected Janice Case as its vice chair, returning her to a position she also held in 2013. Case, a trustee since 2008, serves on the Finance and Audit and Technology and Security committees. She spent 25 years with Florida Progress and its Florida Power subsidiary.
The trustees also approved amendments to Texas Reliability Entity’s bylaws, following a comprehensive review to examine their consistency with the Texas Business Organizations Code, and adopted four standards as part of their quarterly standards review:
TPL-007-3, Transmission System Planned Performance for Geomagnetic Disturbance Events: Adopts Canadian-specific revisions to TPL-007-2, including a new variance for Canadian entities; a method to develop alternative geomagnetic disturbance planning events; and addressing Canadian regulatory approval processes for corrective action plans.
CIP-008-6, Incident Reporting and Response Planning: Modifies CIP-008 Cyber Security Incident to require reporting of cybersecurity incidents that compromise or attempt to compromise the bulk electric system, in response to FERC Order 848. Includes the Department of Homeland Security in the reporting requirements.
Pennsylvania lawmakers must approve nuclear subsidies by May to prevent the retirement of Three Mile Island Unit 1, Exelon CEO Chris Crane told stock analysts Friday.
Crane’s comments came days after a bipartisan group of legislators circulated a proposal to add nuclear energy to Pennsylvania’s Alternative Energy Portfolio Standards Act. (See related story, Nuclear ‘Bailout’ Memo Circulating through Pa. Assembly.)
Three Mile Island | 123rf
Speaking during the company’s fourth-quarter 2018 earnings call, Crane called the legislative effort “promising,” saying, “We have some strong support.”
But he said the company would need to order a new reactor core by May to refuel the 2,568-MW plant if it is to remain in operation. “We’ve let the stakeholders know that. So, if we can get this through in that period of time, we will be able to save the unit. Short of that, we would be beyond the [point of no] return at the end of May.”
The company announced in May 2017 that it would shutter TMI by about Sept. 30, 2019.
Kathleen Barron, senior vice president of federal regulatory affairs and wholesale market policy, said lawmakers have not decided on the value of the support the state might offer its nuclear plants.
“That is subject to discussions that are ongoing among the lawmakers now. So, we don’t have an estimate for you on how the program will look,” she said.
Crane also said the company continues to seek ways to boost the earnings of its Dresden, Braidwood and Byron nuclear plants in Illinois, all or parts of which did not clear PJM’s 2018 capacity auction.
“We will continue to engage with stakeholders on state policies while advocating broader market reforms at the federal level,” Crane said. “We will support PJM price formation changes like fast-start and reserve market reforms with our states to implement the expected FERC order on PJM capacity reforms and preserve the authority of our states to advance their clean energy policies and continue our efforts to seek fair compensation for zero-emitting nuclear plants.”
In June, FERC ruled that PJM’s Tariff was unjust and unreasonable because it allows resources receiving out-of-market revenues to depress capacity prices. The commission suggested modifications to PJM’s fixed resource requirement (FRR) option could allow the removal of state-subsidized resources and corresponding amounts of load from the capacity market. The first round of filings in FERC’s “paper hearing” on the issue were filed in October (EL18-178). (See Little Common Ground in PJM Capacity Revamp Filings.)
Crane said the company could benefit from “market reforms” underway in PJM, including moving some or all of the Illinois plants into the FRR “so we can get better capacity treatment that matches state’s environmental needs.” He also pointed to the RTO’s effort to improve price formation and revise reserve curves.
“So, that’s why we are keeping more of an open position [and not doing more hedging on future prices]. We believe the market will strengthen,” he said.
The company said its nuclear fleet set an all-time production record for 2018, generating 159 TWh.
In response to an analyst’s question, Barron said it was unclear when FERC would act on changes to PJM’s capacity market.
“Clearly, there has been some delay in the schedule, and I think that’s a function of the transition at FERC,” she said, noting the death of former Chairman Kevin McIntyre, and Commissioner Cheryl LaFleur’s announcement that she won’t be nominated for another term.
“So, while they have been able to get out a number of important orders, others have lagged and the capacity market order [is] among them. … We really have no signal yet from them as to when we will see their final decision in that docket.”
Q4 Results, Investment Opportunities
Exelon’s net income for the fourth quarter of 2018 dropped to 16 cents/share from $1.94 a year earlier, while operating earnings rose slightly to 58 cents/share from 56 cents.
The company said it expects operating earnings of $3 to $3.30/share for 2019, based on growth in utility revenue, the impact of zero-emission credits on its New Jersey nuclear plants and previously announced cost reductions.
Exelon officials also discussed capital investments, the Pacific Gas and Electric bankruptcy and ERCOT’s declining reserve margin during the call.
The company’s Utilities unit expects to make $23 billion in capital expenditures through 2022, boosting its rate base by 7.8% annually.
Anne Pramaggiore, CEO of Exelon Utilities, said the company’s investment opportunities include electric vehicle infrastructure at Baltimore Gas and Electric, distribution automation at Commonwealth Edison and security investments “across the utilities.” It expects to spend about $900 million on cybersecurity, substation security and IT systems.
The company noted its Pepco Holdings Inc. unit could see increased electric load as a result of recently approved legislation in D.C. requiring all public buses and taxis to be zero-emission vehicles by 2045.
Everett LNG Terminal
CFO Joe Nigro said Exelon’s fourth-quarter acquisition of the Distrigas LNG terminal in Everett, Mass., will be “earnings negative” through 2021 because of a need for increased operations and maintenance spending. The company paid $81 million for the import terminal to ensure fuel supplies for its nearby Mystic Units 8 and 9.
“We are very clear that with any type of asset that is economically viable, we are going to work for solutions and ways to try to make that asset viable,” Nigro said. “But I think you’ve seen with our financial discipline that when we’ve had to, we’ve taken the stance of making the necessary change.”
ERCOT Reserve Margins
Jim McHugh, CEO of Constellation NewEnergy, Exelon’s competitive retail and wholesale supplier, said the company is seeking to profit from the volatility in forward prices in Texas PUC Responds to Shrinking Reserve Margin.)
“I think with the ORDC changes, you are just making the likelihood that scarcity is going to play a bigger role in where the summer prices go,” McHugh said. He said on-peak forward prices for summer 2019 rose by $15/MWh since the end of the third quarter but prices have “been more up and down” in the last month.
“I think what we are going to see the market do is really trade on a pretty volatile range as the assessment of how many scarcity hours there may” be varies, McHugh said.
The company “is keeping a relatively significant open position and capability to extract value as we see volatility occur,” Nigro added.
PG&E Bankruptcy
Nigro said the company is “actively following” the bankruptcy of PG&E, which is the sole off-taker of Exelon’s 242-MW Antelope Valley Solar Ranch. “We will remain diligent in protecting the contractual value of AVSR and the role that assets like ours have in California’s clean energy future,” Nigro said. “AVSR provides 3 cents/share to Exelon in operating earnings and is not significant to our credit metrics.”
Earnings call transcript courtesy of Seeking Alpha.
VALLEY FORGE, Pa. — PJM won’t act on FERC’s order to rerun its July 2018 financial transmission rights auction unless the commission denies the RTO’s planned motion for a stay, officials told members Wednesday.
FERC’s Jan. 30 order rejected PJM’s request to waive rules requiring it to quickly liquidate GreenHat Energy’s FTR positions following the company’s default. The RTO liquidated only GreenHat’s FTRs settling in August, saying that selling all the positions immediately would increase members’ losses (ER18-2068).
CFO Suzanne Daugherty told the Market Implementation Committee on Wednesday that unwinding settlements of the company’s FTR portfolio could add $250 million to $300 million to the $186 million the RTO had earlier projected the default would cost members. Daugherty stressed that the calculations are preliminary and might vary significantly after PJM is able to rerun the results of the July auction. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
Deputy General Counsel Chris O’Hara said PJM will ask FERC to stay its order until it rules on the RTO’s request for rehearing or clarification, which will be filed before March 1.
“There’s a couple things we unquestionably need clarification from FERC on, assuming the order stands,” O’Hara said, noting members’ approval in January of a new mark-to-auction component for FTR collateral requirements. “Is FERC saying we should go back to the credit rules that existed in July?”
RTO officials are so alarmed by the impact of the ruling that Craig Glazer, PJM’s D.C.-based vice president of federal government policy, may have violated FERC’s ex parte rules. Commissioners Cheryl LaFleur and Richard Glick and their aides, along with Rachel Marsh, legal adviser to Chairman Neil Chatterjee, said Glazer attempted to speak to them about the issue in separate phone calls on Jan. 30, according to filings the three offices put in the docket.
Marsh and LaFleur aide Jessica Cockrell said Glazer called them for what he initially said was a “procedural update” on the case. “Mr. Glazer explained that PJM intends to file an emergency motion for stay, and also that the order may have significant financial implications for PJM members and require inclusion of relevant amounts on members earnings reports,” Cockrell said.
Glick said Glazer “indicated that PJM was going to issue a press release pointing out that the commission’s order was going to cost its members hundreds of millions of dollars. I told Craig that I was aware of the proceeding and that it remains an outstanding issue and that we should not discuss it. He followed up by noting that PJM was going to file an emergency order with the commission seeking a stay of the Jan. 30 order. I reiterated that we should not discuss this matter until the proceeding is concluded and he agreed. We then ended the conversation.”
PJM spokeswoman Susan Buehler denied that Glazer was attempting to lobby the commissioners.
“As the filed record indicates, Craig contacted commissioners to give them a procedural update on the order which could have a significant impact on PJM members. He wanted to make sure they knew PJM intended to make several filings,” Buehler said in an email. “Regarding the ex parte filing, PJM understands the need for sensitivity when addressing procedural matters with the commission.”
‘Disappointed’ in Delay
O’Hara said the RTO was disappointed that it took FERC six months to rule on the waiver request. “They could have ruled within 30 days. Waiting six months obviously makes [unwinding FTR settlements] more complicated,” he said.
Direct Energy’s Marji Philips asked O’Hara why the RTO did not ask the commission for expedited treatment for the waiver request. “Fair question,” O’Hara responded. “I’ll have to look into that.”
FERC ordered PJM to rerun the auction conducted in July under Tariff rules requiring it to offer all of GreenHat’s FTR positions at a price designed “to maximize the likelihood of liquidation.” That means including liquidation offers for all GreenHat’s FTR positions for August 2018 through May 2019, instead of just the prompt month.
The order also requires PJM to recalculate the default allocation assessments made based on GreenHat FTRs that went to settlement between September and January 2019 if those FTRs get liquidated as a result of the rerun of the July auction.
PJM’s Tim Horger said the RTO, which has never rerun a cleared FTR auction, is still evaluating potential implications of the ruling. “You’re going to have … auctions [after July] where members sold positions they never owned,” he said.
Because the FTR portfolios of participants who traded in the July auction will be revised, the reshuffling is expected to trigger credit collateral calls.
The revised results also will cause FTR auctions from August 2018 through January 2019 “to become infeasible solutions,” violating the simultaneous feasibility test, PJM said.
The RTO will have to make billing adjustments reflecting revised default allocation assessment charges since Aug. 1 — revisions that may cause additional members to default.
There could be additional briefings in the docket regarding how PJM can remedy the violations, O’Hara said. “We’re not entirely sure what to do.”
Daugherty said the RTO believes the order only requires it to rerun the July 2018 auction for August because the auctions from September forward were under revised rules approved by the commission.
In October, the commission approved PJM’s requests to change its rules so it wouldn’t have to immediately offer any GreenHat positions for liquidation after Aug. 24. (See FERC OKs Key PJM Changes to Address GreenHat Default.)
FERC last week approved PJM’s request to withdraw an earlier petition to allow bilateral counterparties the option to assume indemnified positions (ER19-24). The RTO made the request after FERC issued a deficiency notice seeking more information on its indemnification procedures.
Potential default allocation assessment implications of FERC’s order denying PJM’s waiver request | PJM
In asking to withdraw its filing, the RTO said “the proposal does not provide sufficient benefits to the PJM membership to justify PJM continuing to seek approval.” The commission acted over the opposition of Shell Energy, which said the withdrawal would prevent the commission from ruling on its dispute with the RTO over existing indemnification rules. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
The commission also rejected Shell’s request to institute a Section 206 proceeding but said “Shell remains free to file a complaint.”
