FERC on Thursday ordered hearing and settlement procedures on a complaint by the Louisiana Public Service Commission alleging that its ratepayers are being overcharged by an Entergy subsidiary that sells power from the Grand Gulf nuclear plant (EL18-204).
The ruling effectively reinstates a portion of a complaint FERC had earlier dismissed for lack of evidence over System Energy Resources Inc. (SERI), an Entergy subsidiary that sells Grand Gulf’s output to four Entergy operating companies: Entergy Arkansas, Entergy Louisiana, Entergy New Orleans and Entergy Mississippi.
Grand Gulf Nuclear Station | Entergy
In August, FERC set for hearing and settlement the PSC’s complaint that SERI’s return on equity of 10.94% was based on outdated data that did not reflect current capital markets (EL18-142). (See FERC Sets La. Entergy Complaint for Settlement.)
But the commission rejected the PSC’s complaint over SERI’s capital structure, saying the regulators had not demonstrated that it was unjust and unreasonable.
The PSC had contended that SERI’s equity ratio of 64.9% was “unusually rich” and that it was cross-subsidizing more highly leveraged activities while transferring most of its risk to the four operating companies.
FERC said the PSC had not presented any evidence that SERI does not meet the requirements of the federal commission’s three-part test for determining whether to use an operating company’s actual capital structure: whether the operating company issues its own debt without guarantees, has its own bond rating and has a capital structure within the range of structures approved by the commission.
The PSC responded to the Aug. 24 order a month later with a new complaint that offered evidence that SERI did not meet the three-part test.
It provided records that it said showed SERI’s debt is guaranteed by its parent and the operating companies. It also contended that SERI is a shell company with no employees and that each of its corporate officers is an executive officer of Entergy. It said SERI’s equity ratio should be reduced to 35.8%, or at least no higher than 49%, the equity ratio of SERI combined with the operating companies.
FERC rejected Entergy’s contention that it had already decided the merits of the capital structure allegations.
“The language in the Aug. 24 order indicated that the allegations in the complaint in docket No. EL18-142-000 concerning capital structure did not establish a prima facie case to justify setting that issue for hearing. Thus, there was no hearing litigating SERI’s capital structure … and the Aug. 24 order cannot be considered an ‘on the merits’ judgment on SERI’s capital structure,” the commission said.
FERC said it will let the chief administrative law judge decide whether to consolidate this proceeding with docket EL18-142.
Rehearing Denied
Separately, FERC on Thursday also rejected the PSC’s request for rehearing of its May 17 order regarding Entergy’s “bandwidth” calculation for a seven-month period in 2005 (EL01-88-020). (See FERC Affirms Rulings in Entergy Bandwidth Dispute.)
The calculations were used to equalize production costs among Entergy’s operating companies.
WASHINGTON — Senate Democrats pressed acting EPA Administrator Andrew Wheeler on the agency’s efforts to reverse Obama administration policies on vehicle and power plant emissions Wednesday, complaining he failed to demonstrate a sense of urgency to address climate change.
Wheeler was nominated by President Trump on Jan. 9 to replace Scott Pruitt, who resigned as administrator in July.
In a two-and-a-half-hour confirmation hearing before the Environment and Public Works Committee, Wheeler was repeatedly challenged by Democrats over EPA’s dismantling of the Clean Power Plan and its plan to weaken fuel economy standards for vehicles. But with only 47 votes, Democrats and the two independents who caucus with them will be unable to block Wheeler’s confirmation.
About a quarter of the audience in the small hearing room wore the red T-shirts of the Moms Clean Air Force and Wheeler’s opening statement was difficult to hear over the shouts of “Shut down Wheeler, not the EPA!” from protestors outside the room. The shouts began after two protestors inside the room were ejected.
Republicans praised Wheeler’s nearly two decades of experience at EPA and at the Senate committee, which oversees the agency. Wheeler began his EPA career during the George H.W. Bush administration and later served as staff director and chief counsel to Republicans on the committee.
“I think that’s really strong qualifications for this job,” Sen. Dan Sullivan (R-Alaska) said. “You come highly, highly qualified.”
Republicans also praised EPA’s efforts under Wheeler and Pruitt to clean up long neglected toxic waste dumps and to tighten regulations to protect children from lead. Wheeler called himself a “conservationist,” saying, “I am an Eagle Scout. I’m an avid camper [and] hiker.”
But the nominee found little support among Democrats. Although several praised him for being more responsive to their offices than Pruitt, Sen. Tom Carper (D-Del.) said “his policies are almost as extreme.”
Sen. Sheldon Whitehouse (D-R.I.), pressed Wheeler on his work as a lobbyist for coal magnate Robert Murray, suggesting he had been disingenuous when he previously minimized his role in Murray’s “action plan” to save coal-fired electric generation. Aides displayed blow-ups of photos of a meeting at which Murray and Wheeler discussed the plan with Energy Secretary Rick Perry. (See Photos Show Murray’s Role in Perry Coal NOPR.)
In August, Wheeler announced EPA would replace the Obama Clean Power Plan with the Affordable Clean Energy (ACE) Rule, which defines the “best system of emission reductions” as heat-rate efficiency improvements that can be achieved at individual coal plants. The CPP set state emissions limits and encouraged switching to natural gas and renewables. Wheeler cited EPA projections that ACE will reduce U.S. power sector CO2 emissions up to 34% below 2005 levels, but Democrats said it will allow higher emissions than the CPP. (See EPA: CPP Replacement Could Boost Coal-Fired Power by 6%.)
In December, EPA proposed changing its cost-benefit calculations to eliminate the “co-benefits” of reducing pollutants other than those being targeted. Had the proposed methodology been in place in 2011, EPA said, it would have prevented the Mercury and Air Toxics Standards (MATS), which pushed many coal generators into retirement.
Sen. Ben Cardin (D-Md.) said he didn’t understand why EPA was seeking to change its cost-benefit methodology, saying “it seems to me the mercury standards have worked.”
Wheeler said EPA had to re-evaluate the rules in response to a Supreme Court ruling but said he didn’t expect the change to affect mercury emissions.
“Under our preferred option, I do not believe there would be a weakening of the mercury standards at all as far as the equipment that has already been deployed and implemented across the board,” Wheeler said. “I get accused of rolling back the Clean Power Plan. I don’t think you can roll back a regulation that never took effect. And on MATS, I don’t think you can roll back a regulation that’s been fully implemented. I honestly don’t believe that equipment will be turned off or removed under our proposal.”
Carper was skeptical. He said Delaware would be in noncompliance for nitrogen oxide even if it eliminated all pollution from vehicles and businesses because it is downwind from several coal-fired generators in Pennsylvania and West Virginia. “The cruel irony is each of those plants had installed the technology to stop the pollution. … They turned it off. They still have it turned off. And when we [asked] EPA to do something about it, you declined. So, forgive me for being concerned and cautious on this front.”
In response to questioning by Sen. Bernie Sanders (I-Vt.), Wheeler agreed that the climate is changing and that humans have an impact on it, saying “I wouldn’t use the ‘hoax’ word” as Trump has used to dismiss climate change.
“Do you agree with the scientific community that climate change is a global crisis that must be addressed aggressively?” Sanders pressed.
“I believe that climate change is a global issue that must be addressed globally,” Wheeler responded. “I would not call it the greatest crisis. … I consider it a huge issue that has to be addressed globally.”
Wheeler also conceded the forest fires that have charred parts of California had “some relation” to climate change but said “the biggest issue is forest management.”
Sen. Jeff Merkley (D-Ore.) rejected Wheeler’s contention, saying “the reason these fires are so much longer [is] because the summer season is so much hotter and longer.”
“Our entire ecosystem … our fishing, our farming, our forests, are at grave risk.”
RENSSELAER, N.Y. — The NYISO working group charged with shepherding carbon pricing into New York’s wholesale electricity market kicked off its efforts Tuesday by taking up the issue of how import and export transactions would be handled under the pricing scheme.
A task force created in October 2017 by NYISO and the New York State Public Service Commission worked for more than a year developing a proposal to price carbon into wholesale markets. Last month, it turned the proposal and final details over to the ISO’s stakeholder process. (See IPPTF Hands off Carbon Pricing Proposal to NYISO.)
Ethan D. Avallone, NYISO senior energy market design specialist, showed the Market Issues Working Group (MIWG) several hypothetical transactions, pointing out that his examples “had to be extreme to show the effects of under- or overestimating the real-time carbon charge.”
A carbon charge or credit would apply only to transactions that actually flow in real time, and to external transactions such that they compete with internal resources and each other as if the ISO was not applying a carbon charge to internal suppliers — that is, on a status quo basis, Avallone said. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)
A market participant intending to import into the New York Control Area (NYCA) will sell power at the proxy generator bus for the applicable control area in the NYISO market. | NYISO
To calculate locational-based marginal prices, the examples in the presentation focused on prices at one NYISO proxy generator bus located outside the New York Control Area to represent a typical bus in an adjacent control area. There may be more than one proxy generator bus at a particular interface with a neighboring control area to enable the ISO to distinguish the bidding, treatment and pricing of products and services at the interface.
Imports into the NYISO market are paid the proxy generator bus price for the applicable external control area. For example, an import with costs of $40/MWh in the PJM market could sell at the $50 PJM Keystone Proxy Generator Bus price in the NYISO market for a potential net revenue of $10/MWh.
Several stakeholders at the meeting said they wanted better real-time data from the ISO, possibly using a unit-specific, rather than aggregated, approach.
“The reason we landed on this more aggregated approach is because we wouldn’t be able to tell whether a unit-specific one is representative,” Avallone said, adding that the fundamental question about what approach to take had been fully aired in the stakeholder process last year.
Seth Kaplan of EDP Renewables, the largest wind generator in the state, said his company had no position on the matter but suggested the ISO ask for market proposals for a unit-specific approach from those who were advocating one.
Howard Fromer, director of market policy for PSEG Power New York, offered that the ISO could provide day-ahead carbon data to help traders to better ascertain the right carbon adder in order to plan their bids.
“We would settle on the real-time LBMP,” Avallone said in explaining the ISO’s choice not to provide day-ahead data. “We have discussed recalculating LBMPs for a historical time period as if there were a carbon component [c] included [in order] to get an approximation of LBMPc in real time.”
Michael DeSocio, the ISO’s senior manager for market design, said energy traders were already “using some model, some heat rate model. Now you just have to add in a carbon adder, so it’s not much different from what you do today.”
Fromer said it would take some time to digest the detailed examples, and that his company wants to see carbon pricing move ahead, but it’s “likely to have some impact on scheduling” as traders are “being forced into guesstimating on the day-ahead LBMPc.”
Scott Leuthauser, manager of regulatory affairs and business development for H.Q. Energy Services (U.S.), read a prepared statement saying his company opposes applying the carbon charge, as proposed, to external transactions because it creates additional risks for them. External resources have no control over NYISO carbon emissions and no way of physically hedging against the risk, he said.
“As we have said before, it is better for traders to assess and bear the risk,” Avallone said.
The MIWG next meets Jan. 22 to review Tariff sections impacted by a carbon adder.
New Zone J Operating Reserves
NYISO is speeding up the stakeholder process in order to implement by June a Zone J (New York City) reserve requirement and procure 500 MW of 10-minute reserves and 1,000 MW of 30-minute reserves, the MIWG learned Tuesday.
Ashley Ferrer, NYISO energy market design specialist, told the working group that creating a Zone J reserve region and associated reserve requirements can provide more efficient scheduling and procurement of resources, as well as location-specific market price signals.
The ISO is considering the appropriate operating reserve demand curve for the zone’s reserves and will present its proposed pricing as part of further discussions regarding the proposal, Ferrer said.
NYCA operating reserves with Zone J | NYISO
Establishing a separate Zone J operating reserves requirement was originally recommended in the 2017 State of the Market report and later in the 2018 Management Response to an assessment by Analysis Group of wholesale market options regarding performance assurance.
The ISO will present market design and associated Tariff revisions to stakeholders this month and next, with the Business Issues and Management committees slated to vote on the proposal in March. Assuming stakeholder approval, the ISO would submit the proposal to the Board of Directors in April and file Tariff revisions with FERC seeking approval to implement in June.
CAISO said Monday it had finalized agreements to provide reliability coordinator services, starting later this year, with 32 transmission operators and balancing authorities in the West.
The ISO expects to eventually have a total of 39 RC clients. Those that have finalized agreements include the Bonneville Power Administration, Arizona Public Service and PacifiCorp. (For a complete list, see CAISO’s website.)
“We are pleased with the progress made this past year to offer Reliability Coordinator services, and welcome our new participants,” CAISO President Steve Berberich said in a news release. “After a year of intensive planning and coordination, the ISO will now focus on developing technology and integrating systems to meet our July 1 implementation date.”
CAISO said it is moving forward to complete the NERC certification process led by the Western Electricity Coordinating Council (WECC).
CAISO won the majority of Western clients for its RC services after Peak Reliability decided last year to wind down its reliability coordinator services by the end of 2019. Peak is currently the RC for nearly all of the Western United States and parts of Canada and Mexico. (See RC Transition, California Wildfires Will Occupy 2019.)
Peak stunned the electricity sector in July when it announced it would end its RC role and withdraw from its effort to develop a regional electricity market competing with CAISO. (See Peak Reliability to Wind Down Operations.) The Vancouver, Wash.-based company said it would shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs.
Several months before the announcement, CAISO, a Peak RC customer, said it would “reluctantly” leave Peak, develop its own RC services and offer them to others at reduced costs. CAISO’s move was seen as a reaction to Peak entering a partnership with PJM to form a Western RTO to compete with the ISO’s expansion.
CAISO, SPP and BC Hydro decided to fill the role left behind by Peak. Most of the Western Interconnection signed nonbinding letters of intent to take advantage of CAISO’s RC services. (See CAISO RC Wins Most of the West.)
In November, FERC approved a set of Tariff revisions covering CAISO’s new RC services, clearing the way for about 72% of the region’s load to sign on with the RTO, compared with 12% for SPP. BC Hydro is proceeding with plans to provide RC services for its own territory in British Columbia, representing about 7% of load in the region overseen by the Western Electricity Coordinating Council.
The transition of RC services is scheduled to be phased in this year, with CAISO assuming responsibility for California and part of northern Mexico on July 1. BC Hydro will become the RC for a large swath of western Canada on Sept. 2. CAISO will then take over RC services for many areas outside of California on Nov. 1, while SPP will take responsibility for other regions of the West on Dec. 3.
NEW ORLEANS — For a historic moment for SPP, the ascension of two women to the RTO’s Markets and Operations Policy Committee leadership was fairly low-key.
NextEra Energy Resources’ Holly Carias began her term as MOPC chair Tuesday by simply saying, “Thank you for letting me be the MOPC chair.”
Then it was down to business for NextEra’s director of regulatory affairs. She ran the meeting efficiently, wasting no time in moving from agenda item to agenda item. She conducted the votes quickly and brought the committee back on time from breaks.
“I’m glad to see you in a leadership position,” Jim Eckelberger, SPP’s chairman emeritus, told Carias during the lunch break.
Board Chair Larry Altenbaumer offered his own unsolicited comments during the opening introductions. “I think it’s a good leadership team,” he said.
Serving as MOPC’s vice chair is Denise Buffington, director of federal regulatory affairs for Kansas City Power & Light. She and Carias are only the second and third women to take a leadership position at MOPC.
Asked if two women leading a male-dominated group — as is typical in the electric industry — is a good sign for women, Buffington replied unequivocally, “Yes!”
“Obviously, I’m excited for the opportunity to take a leadership role at the board level,” she said.
Diversity and Balance
Whereas SPP made a concerted effort to increase the diversity of its Board of Directors by adding two women as members last year, SPP Vice President of Engineering Lanny Nickell said that was not the case with the MOPC appointments.
“I don’t think the Corporate Governance Committee recommended Holly and Denise to serve as MOPC chair and vice-chair, and the board approved that recommendation, to increase diversity,” said Nickell, himself a new addition to MOPC as staff secretary. “The recommendation was made because these were the two best candidates for the positions.”
Both positions opened up late last year when Chair Paul Malone cycled off and Vice Chair Jason Atwood left Northeast Texas Electric Cooperative. Having already sent out one solicitation for vice chair, SPP sent out a second for chair or vice-chair.
If anything, the board and CGC followed an unwritten rule in ensuring the MOPC chairs represented either a transmission user (Carias) or transmission owner (Buffington). As an added measure, Carias is also the first independent power producer representative to chair MOPC since Dogwood Energy’s Rob Janssen.
“Certainly, diversity of thought and skill sets and experience is important,” Nickell said. “If you look at the history of chairs and vice chairs of MOPC, you’ll note there has been an attempt to have a balance of perspectives.”
Nickell said Carias is a collaborator who tries to find creative solutions “that tend to serve the interests of a broad group of parties.”
“She seems to have SPP’s regional interests in mind when she participates in our stakeholder discussions,” he said.
And Buffington?
“She’s very passionate,” said Nickell. “She’s very good at asking the right question to get [to] the root cause of an issue. She makes us think about what we can do and what we can do better. I think they will work together to be effective leaders for the MOPC.”
Nickell has his own large shoes to fill, those of COO Carl Monroe, who served as MOPC’s staff secretary for 18 years. Claiming he won’t be as smart as Monroe, the self-deprecatory Nickell did admit, “I’ve got good people around me, so we’ll be fine.”
‘All About Process’
Carias became an MOPC member just last year, though she had previously attended the committee’s meetings in her role as director of wind development for NextEra Energy Resources. She has been with NextEra for more than 11 years, following her discharge as a captain from the Air Force.
Buffington has been a steady presence on MOPC for several years and recently chaired the Z2 Task Force. She joined KCP&L in 2010 after 13 years with the law firm Skadden Arps Slate Meagher & Flom, and she holds a law degree from American University’s College of Law and an MBA from the University of Missouri-Kansas City.
Buffington said she will focus on ensuring stakeholders receive meeting materials on time, a common complaint in annual stakeholder surveys.
“I’m a lawyer. I’m all about process,” she said. “If you’re trying to elevate the conversation at MOPC, people have to get the materials on time. I don’t like getting materials the day of the meeting and the continual updates to the meeting materials.”
That will be the least of the changes for MOPC in 2019. Under Altenbaumer’s leadership, the board has delegated additional authority to the committee, relinquishing its approval of changes to SPP’s Tariff or criteria. Unless there’s a dispute requiring an appeal to the board, MOPC will now have final authority for those changes.
“That’s a huge change,” Carias told stakeholders. “These are exciting times in SPP.”
Nickell said he and Carias plan to adhere to Robert’s Rules of Order, which was evident during Tuesday’s meeting.
“The result of [some] debate won’t go to the board anymore,” he said. “If that puts more emphasis on MOPC resolving those issues at MOPC, we’ll have to get better at following those rules. I think motions need to be clearly understood, and the best way is seeing those in writing on the screen before a vote is taken.”
The Maryland Public Service Commission extended the schedule for its review of Transource Energy’s controversial Independence Energy Connection for 30 days to allow parties to provide additional evidence on proposed alternatives.
The PSC rejected a motion by the Power Plant Research Program (PPRP) of the Maryland Department of Natural Resources to dismiss Transource’s application for a certificate of public convenience and necessity (CPCN) or suspend the schedule.
But the commission’s Jan. 15 ruling set a new deadline of Feb. 25 for the PPRP, PSC staff, the Office of People’s Counsel (OPC) and local residents opposing the line to file direct testimony (Case #9471).
PSC staff and OPC supported PPRP’s argument that the PSC should reject the project because Transource failed to examine alternative solutions as required by state law. Staff recommended the commission grant the motion, suspend the procedural schedule and direct Transource to supplement its application.
The $372 million project would add two 230-kV double-circuit lines, totaling about 42 miles across the Maryland-Pennsylvania border.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource
The PPRP said Transource had failed to meet requirements to examine alternatives if an existing transmission line “is convenient to the service area; or the use of the transmission line will best promote economic and efficient service to the public.”
The agency said the need for the eastern segment of the project could be met by the existing Furnace Run-Conastone and Furnace Run-Graceton 230-kV double-circuit transmission tower lines, each of which has only one 230-kV circuit and could carry a second. (See Cancel Transource Line, Md. Panel Says.)
Transource responded it was not required to study PPRP’s proposed alternative and said it met the requirements of state law by analyzing “over 30 study segments.”
“Disputes over whether the commission should consider an alternative are properly the subject of competing testimony at the evidentiary hearing,” Transource said.
The commission said it was modifying the procedural schedule to allow the parties to conduct additional analysis or discovery regarding the use of PPRP’s alternative.
“In response to PPRP’s motion, Transource acknowledges that as the CPCN applicant — the party with the burden of proof — it should be prepared to present evidence at the hearing to address any suggestions by other parties that the proposed project should be denied because there exists a clearly superior alternative,” the commission said. “This criteria includes the existing transmission line evaluation requirements set forth in [section 7-209 of the Public Utilities Article, Maryland Annotated Code].”
Rebuttal testimony will be due by March 18, with surrebuttal testimony and any PPRP response to public comments due April 1. The commission said it will allow live rejoinder testimony if needed during the evidentiary hearings.
Mary Urban, community affairs representative for Transource, issued a statement reiterating it has met all filing requirements under Maryland law.
“Transource has presented a substantial amount of information regarding alternatives,” Urban added. “As the case proceeds, the company will respond as is appropriate under commission rules.”
PJM said in November the project would reduce load costs by $707.3 million in net present value over 15 years, producing a benefit-cost ratio of 1.4. PJM declined to comment Tuesday.
Assistant Attorney General Sondra Simpson McLemore, who filed the motion to dismiss for PPRP, did not immediately respond to a request for comment.
VALLEY FORGE, Pa. — PJM’s proposed revisions to how it prices reserves in its energy market necessitates changes in the RTO’s capacity market to prevent substantial overpayment by customers for electricity and the exercise of market power by generators, Independent Market Monitor Joe Bowring said Friday.
Without a true-up, PJM’s package of changes, being developed under a Jan. 31 deadline imposed by the RTO’s Board of Managers, would result in the overpayment of at least $6 billion to generators over four years after its implementation, Bowring told the Energy Price Formation Senior Task Force (EPFSTF), as well as significantly higher overpayment after that without specific market design changes in the capacity market.
“PJM’s apparent goal is to shift revenue from the capacity market to the energy and reserve markets,” Bowring said in a presentation. If so, he said, “there must be a clear and verifiable mechanism to ensure that the shift occurs effectively, equitably and efficiently.”
The RTO has proposed raising the maximum price in the operating reserve demand curve (ORDC), used to set prices for reserve products, from $850 to $2,000. The proposed ORDC would raise both energy and reserve prices significantly. PJM would also use the same ORDC in the day-ahead and real-time markets for reserves, introducing the ability to procure primary reserves in the day-ahead and secondary reserves in the real-time. (See Section 206 Filing on PJM Reserve Pricing Likely.)
Bowring said increased energy market revenues won’t result in lower capacity prices without changes to the variable resource requirement (VRR) demand curve. The curve is based on the net cost of new entry (CONE), which considers all generator revenues from energy and ancillary services markets.
The Monitor proposed setting net CONE as the maximum price on the curve. As a result, Bowring said, capacity prices could be $0 under some circumstances when energy market revenues are high.
“You can’t have it both ways,” Bowring said. “If you shift this high level of revenue from the capacity market to the energy market, you’re effectively eliminating the capacity market.”
The Monitor first raised its concerns at the task force’s previous meeting Jan. 4, but Friday’s meeting marked the first time it made explicit its proposals for why the VRR curve needs to change in response to PJM’s proposal.
Capacity markets serve the same function as scarcity pricing, he said: to provide enough revenue to ensure there is adequate supply to meet demand. “I’m not arguing that we should get rid of the capacity market, but if PJM’s changes to increase energy and reserve prices are implemented, we have to make sure people are not paying twice for the same product.”
Bowring said PJM’s logic for the package of revisions “escapes me.” But, he said, if that was what the RTO wanted to do, his concerns would need to be addressed to prevent overpayments.
“I am not sure why PJM believes that there is urgency to this,” Bowring said in an email. “It is not a simple matter, and PJM’s approach has not been adopted by other RTO/ISOs.”
Bowring also said an increased reliance on the energy market will reduce PJM’s ability to “pick the reserve margin quite so precisely.”
“It’s the same lesson ERCOT learned,” he said of the Texas grid operator, which does not have a capacity market.
Adam Keech, PJM executive director of market operations, did not directly dispute Bowring’s arguments. But he did take exception to the idea that the RTO was trying to eliminate the capacity market. “The goal [of PJM’s proposal] is not to shift revenue,” he said at the meeting. “The goal is to price energy and reserves correctly.”
Keech told RTO Insider after the meeting that PJM was waiting for information from the Monitor, “because we have thought about it and not been able to identify what the issues are that they see.”
Bowring said that PJM has explicitly ignored the potential revenue impact on the capacity market during the transition period. “In other words, PJM is proposing that customers pay twice for the same product during the transition period.”
The RTO proposes to use simulations to estimate the increase in energy revenue in defining the VRR curve in the capacity market auctions after the transition period. “PJM clearly has thought about the issues,” he said, “but they have a very different proposal than the IMM’s proposal.”
RTO VRR curve comparison | Monitoring Analytics
Stakeholder reaction to Bowring’s presentation was mixed. Brock Ondayko of American Electric Power said that, without further modifications to the VRR curve, he expected capacity to clear at lower prices under the proposed rules because of the increased energy and reserve revenues. Bowring’s predictions “just seem counterintuitive,” he said.
But consultants James Wilson and Roy Shanker, and Susan Bruce, attorney for the PJM Industrial Customers Coalition, agreed the IMM had identified a problem that needed to be addressed.
With the PJM board’s deadline looming, however, it may not matter.
“We’re in an interesting spot, both from a timing and scope perspective,” said Dave Anders, PJM director of stakeholder affairs and chair of the task force, explaining that the capacity market curve is out of scope under the issue charge the Markets and Reliability Committee approved. The MRC’s next meeting is Jan. 24, when the committee is expected to vote on PJM’s proposal.
Anders said stakeholders offering alternatives to PJM’s proposals should include any measures to address the capacity curve issue as an addendum, not as part of the packages to be voted on by task force members Jan. 17. “I don’t want to use the process to ignore what may be a significant issue,” he said.
Bowring said PJM would be foolish to ignore the impact of such a “radical change” to the energy market on the capacity market. “It is going to be part of the scope in front of FERC,” he said.
Transparency Proposal
Wilson, a consultant to consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C., ended the session with a brief presentation in which he said PJM should make public appeals for conservation when administrative shortage prices reach a threshold so that customers know they are facing high prices and have an opportunity to reduce their consumption. He said the trigger could be the shortage price component hitting $300/MWh.
“It shouldn’t be just a quiet little press release on the PJM website,” Wilson said. “It ought to be on the nightly news.”
PJM’s current rules call for such appeals only when reliability is at risk.
Concern about the ripple effects of Pacific Gas and Electric’s financial meltdown had already spread last week as CAISO addressed worries about the utility’s potential to default on its payments to the ISO, and a solar farm owned by Warren Buffett’s Berkshire Hathaway saw its credit rating cut to junk status because of its dependence on PG&E.
Those worries will grow after PG&E announced Monday it would file for Chapter 11 bankruptcy protection by Jan. 29 because it faces $30 billion in liability for the catastrophic wildfires of 2017 and 2018. (See related story, PG&E Says It Will File Bankruptcy, as CEO Steps Down.)
On Friday, CAISO issued a market notice aimed at easing concerns about how PG&E’s problems could affect the ISO and its participants.
“The California ISO has received inquiries relating to the financial status of Pacific Gas & Electric Co. in light of recent media reports,” the notice said. “The ISO wants to assure market participants that PG&E has posted collateral with the ISO to cover its outstanding and upcoming obligations.”
Should PG&E default, however, the ISO’s other members would have to pick up the tab. CAISO rules require each market participant to cover default losses “in proportion to the benefits it receives from its activity” in the market. When GreenHat Energy spectacularly defaulted in June in PJM’s financial transmission rights market, other members were angry that they had to cover tens of millions of dollars in payments. (See Greenhat FTR Default a ‘Pig’s Ear’ for PJM Members.)
GreenHat was a relatively small player in PJM, whereas PG&E, California’s largest utility, is a huge part of CAISO. The total volume of energy delivered in CAISO in 2017 was 228,191 GWh, according to the ISO’s annual Market Issues and Performance Report. PG&E’s total deliveries that year were 82,226 GWh, the utility said in its Annual Report to Shareholders.
Bankruptcy Imminent
The question of PG&E’s default isn’t academic. The company’s circumstances have been quickly worsening, raising questions about its ability to continue making ISO payments.
Hours before Monday’s bankruptcy announcement, PG&E said CEO Geisha Williams was stepping down amid the growing turmoil.
Both Moody’s Investors Service and S&P Global Ratings cut PG&E’s credit rating to “junk status” last week, citing the utility’s financial exposure for two years of massive, deadly wildfires along with the waning will of politicians to bail out the state’s largest utility. (See PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status.)
PG&E’s stock price plummeted after November’s Camp Fire and continued plunging this week amid talk of the company declaring bankruptcy and selling off its gas division. | Google
“The downgrade reflected our assessment of a weakening of the company’s governance, the souring political environment that we expect will lead to a weakening of the regulatory construct, what we see as the company’s limited capital market access, and the possibility of a voluntary bankruptcy filing given the immense pressures and uncertainties still facing the company,” S&P said in an update posted on its website Friday.
As of Monday afternoon, PG&E had lost about $32 billion, or nearly 78% of its market value, over 15 months starting in October 2017, when 21 major fires swept Northern California’s famed wine country. Those fires killed 44 people and destroyed thousands of homes, including a substantial part of the city of Santa Rosa.
State fire investigators blamed PG&E for at least 17 of those blazes, and its stock price sunk from more than $70/share to about $38/share. For months, the utility’s stock price hovered in the range of $40 to $50/share, then the Camp Fire struck Nov. 8. The deadliest fire in state history killed 86 people and wiped out the town of Paradise in the Sierra Nevada foothills of Butte County.
PG&E’s equipment quickly fell under suspicion after the company reported to the Public Utilities Commission that it had experienced a problem with a transmission line, and that employees saw flames near the Camp Fire’s point of origin on the morning it started.
The company saw its stock price drop to less than $18/share last week as S&P downgraded its credit rating from investment grade to junk status.
News reports, quoting unnamed sources, suggested the utility might be getting ready to file for bankruptcy — or to put its downtown San Francisco headquarters on the market or sell off its gas division.
By Monday afternoon, PG&E shares were selling for about $8 on the New York Stock Exchange.
‘Negative Implications’
The uneasiness about PG&E’s future has started to spread to companies with which it does business
On Friday, S&P slashed the credit rating of the 550-MW Topaz Solar Farms in San Luis Obispo County to junk, citing its reliance on PG&E, with which it has a 25-year sales contract. Topaz is owned by BHE Renewables, a subsidiary of Buffet’s Berkshire Hathaway Energy. The solar farm was completed at a cost of $2.4 billion in 2015.
The 550-MW Topaz Solar Farms in central California, one of the largest photovoltaic power plants in the world, has been caught up in PG&E’s financial meltdown. | NASA Earth Observatory
“Topaz Solar Farms receives all of its revenue from PG&E under a long-term power purchase and sale agreement,” S&P said. “Our rating on the solar project is currently capped by our view of the credit quality of PG&E, its utility offtaker.”
S&P put Topaz on its credit watchlist with “negative implications.”
“The CreditWatch negative listing reflects the increasing risk that we will downgrade PG&E by one or more notches over the next few months. If we lower our ratings on PG&E again, it could lead us to take an equivalent action on our ratings on Topaz Solar Farms.
“If PG&E files for Chapter 11, this could, subject to it being a material adverse effect, trigger a cross default under Topaz Solar’s financing documents unless the power contract is replaced within 90 days of the bankruptcy event,” S&P added.
In a separate post on its website Friday, S&P explained why it had downgraded PG&E’s credit rating from BBB- to B Jan. 7.
“A number of events, over several weeks, contributed to our … multinotch downgrade,” it said.
Immediately after the Camp Fire, it appeared that state lawmakers and regulators would try to keep PG&E afloat to protect ratepayers and to achieve the state’s ambitious renewable portfolio standards, S&P said. A new law, SB 100, requires the state to obtain 60% of its energy from renewable sources by 2030.
But public anger intensified, with protests at PUC hearings and PG&E headquarters. That anger has undermined the will of state regulators and politicians to protect PG&E, S&P said.
An allegation by the PUC in December that PG&E had falsified natural gas safety records made things worse. Politicians who had supported the utility expressed distrust.
On Jan. 4, PG&E issued a press release saying it was planning to shuffle its board of directors and reviewing “structural options,” including in its operations, finances and management. Speculation quickly followed that PG&E might file for bankruptcy.
“It was the totality of these events that led to S&P Global Ratings’ downgrade of PG&E into speculative grade,” the credit rating firm said.
VALLEY FORGE, Pa. — PJM is considering changing interconnection rules to accommodate transmission serving offshore wind generation.
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.
PJM’s Sue Glatz presented the Planning Committee a problem statement to consider allowing merchant transmission developers to request capacity interconnection rights, or equivalents, for non-controllable AC transmission facilities.
Glatz said transmission developers have expressed interest in building AC transmission to accommodate future generation interconnection requests. The developers want to acquire capacity interconnection rights so PJM can identify the necessary network upgrades, she said.
The key difference 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, Glatz said.
PJM hopes to develop a FERC filing on Phase 1 of the initiative — focusing on rules for a single offshore generator lead line — by July.
Phase 2 will consider networked offshore transmission for connecting multiple wind sites. A FERC filing is targeted for September 2020. “We view this as much further down the road,” Glatz said.
John Brodbeck of EDP Renewables N.A. asked PJM to offer education on what open-access rights generators will have to the lines.
Theodore Paradise, ISO-NE’s former assistant general counsel for operations and planning, who has joined transmission developer Anbaric as special counsel, asked for a discussion on how HVDC facilities are modeled in PJM.
The committee will be asked to approve the problem statement at its next meeting.
PJM Seeks Fix on Queue Filing Errors
PJM is proposing a one-sentence rule change to help developers avoid being removed from interconnection queues because of minor errors or omissions.
Interconnection customers are generally granted up to 10 business days to resolve deficiencies found by the RTO. But under changes initiated in 2016, requesters must clear all deficiencies by the last day.
The changes were intended to dissuade developers from late submissions. But PJM said requests are not being submitted any earlier and the changes were undermined by FERC rulings reinstating applicants removed for minor errors.
PJM’s Susan McGill presented the PC a proposed problem statement to ensure that all applicants have up to 10 business days to correct deficiencies, whether they enter on Day 1 or the last day of the six-month queue.
“We can’t have another queue where people get bumped out … they go to FERC and get waivers [to return]. It’s very disruptive,” Vice President of Planning Steve Herling said.
Since the AA1 queue opened in May 2014, 50 to 60% of interconnection requests were submitted in the last month of the queue.
Prior to the 2016 changes, which resulted from the Earlier Queue Submission Task Force, about 18% of projects submitted in the last month of the queue were withdrawn for deficiencies. After the EQSTF changes, that withdrawal rate increased to 24%.
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.”
“We’re not looking for reasons to get rid of you,” McGill explained.
PJM’s Dave Anders said Manual 34 allows the first discussion of a problem statement to include a proposed solution if the committee chair determines “the problem presented is sufficiently simple.”
Herling said, “We do have more changes we think need to be made [to interconnection queue rules]. But that will require a more robust conversation.”
PJM Pondering Wind Capacity Measures
Wind generators could see lower capacity credits under rule changes being considered by the RTO.
PJM’s Tom Falin presented the PC with the updated results of the RTO’s analysis of wind and solar resources’ effective load carrying capability (ELCC) — a measure of the additional load that a group of generators can supply without a reduction in reliability.
Effective load carrying capability is a measure of the additional load that a group of generators can supply without a reduction in reliability. | PJM Renewable Integration Study (2014), General Electric
The new results use the 2018 reserve requirement study (RRS) capacity model, which shows nameplate capacities for 2022/23 of 14,620 MW of wind and 5,290 MW of solar.
PJM found the average wind ELCC between delivery year 2009/10 and 2017/18 was 11.5%. That suggests the RTO’s current practice of using wind’s average capacity factor of 17.1% overstates wind’s value, Falin said. The median capacity factor over that period was 8%.
“We feel [the median is] a much, much better indicator of the reliability value” of the resources than the average, Falin said.
PJM found the average solar ELCC since 2012/13 is 42.3%, close to the average capacity factor of 42.1% and median capacity factor of 40.9%.
Falin posed two questions to stakeholders: Should PJM continue with its original proposal to change the intermittent resource capacity credit calculation from an average value to a median value? Or should it base the calculation on the ELCC methodology?
He said the advantage of changing from average to median capacity factor is “it’s much less of a black box” than ELCC.
Although the figures represent ELCC values RTO-wide, PJM said the ELCC must be allocated to individual generating units based on individual unit performance.
PJM calculates capacity credits for existing wind resources by multiplying the ELCC by the total nameplate. The RTO has three options for prorating the total capacity credit for existing units:
The average output of an individual unit during a specified number of daily peak hours in each year for which the unit was in-service;
The average output of an individual unit during the daily peak hours in which the loss-of-load expectation (LOLE) is non-zero in each year for which the unit was in-service; or
The average output of an individual unit during hours ending 3, 4, 5 and 6 p.m. during the summer season in each year for which the unit was in service.
Falin said the second option could involve as few as three hours or as many as 12 per year. The last option — PJM’s current method — has the advantage of being based on a lot of data, making it more stable than the other choices. But Falin said it also includes many hours with no LOLE risk.
For new resources, the credit can be calculated by:
multiplying the systemwide ELCC by the nameplate of the new unit (as MISO does);
multiplying an estimated zonal ELCC by the nameplate of the new unit; or
multiplying an estimated unit-type ELCC by the nameplate of the new unit.
RTO-wide ELCC values will be updated each year as part of the installed reserve margin study.
New units will continue to have the option to provide data justifying capacity credits greater than the ELCC value. As under current rules, new units’ actual performance will be rolled in over a three-year period.
PJM wants to develop manual language and 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.
The changes would be effective June 1, 2022; thus, they would not affect UCAP values from prior auctions.
Transmission Expansion Advisory Committee
Dominion Plans $7.5M Substation Project
Dominion Energy plans to spend $7.5 million on a new substation to accommodate a new data center campus in Fauquier County, Va., with a total load of more than 100 MW.
The company will interconnect a new Lucky Hill substation between the Remington and Gordonsville substations on line #2199, a 230-kV circuit.
The requested in-service date is Sept. 15, 2020.
Supplemental Projects More than Double Baseline Additions in 2018
Transmission owners proposed $5.7 billion in supplemental projects in 2018, more than double the $2.065 billion in baseline projects included in the 2018 Regional Transmission Expansion Plan, PJM’s Aaron Berner told Transmission Expansion Advisory Committee members Thursday.
Most of the supplemental projects were presented by American Electric Power ($2.4 billion) and Public Service Electric and Gas ($1.46 billion).
More than half of the baseline projects were attributed to aging infrastructure.
Transmission owners’ supplemental projects have outpaced baseline projects in all but one year since 2015, totaling almost $15 billion. Baseline projects totaled only $8.1 billion over the same period. | PJM
Reliability Window Likely in June
In an update on the assumptions for the 2019 RTEP, Berner said the RTO expects to open a reliability window for proposals in June.
The 2010 RTEP will include 27 locational deliverability areas and Ohio Valley Electric Corp. FERC approved OVEC’s integration into PJM last February.
Generation with executed facilities study agreements (FSAs) will be modeled offline along with associated network upgrades, which will be analyzed separately. Berner said PJM could “turn on” FSA generation and their upgrades if there are many generation retirements but said the RTO does not expect to do so.
Travis Stewart of Gabel Associates said the American Wind Energy Association would like PJM to analyze the consumer benefits of states sharing the costs of transmission to accommodate their renewable portfolio standards. Stewart said AWEA wants more information on projects that could relieve congestion and allow PJM to access higher quality wind in the Midwest. The group may request PJM consider an RPS build-out as an RTEP future, he said.
PJM to Sunset Regional Planning Process Task Force
PJM notified stakeholders Friday that it plans to sunset the Regional Planning Process Task Force on Feb. 1 unless it receives objections from stakeholders within the task force, PC or the Markets and Reliability Committee.
The MRC voted in April 2015 to place the task force on hiatus in case it needed to be reconvened to address FERC Order 1000 or other issues. (See “Regional Planning Process Senior Task Force Placed on Hiatus,” PJM Markets and Reliability Committee & Members Committee Briefs.)
VALLEY FORGE, Pa. — It was one of the shortest Market Implementation Committee meetings in memory Wednesday as stakeholders clocked out in only two and a half hours following discussions of the must-offer exception process, FERC’s energy storage order and PJM’s indemnification rules on bilateral trades of financial transmission rights. (See related story, Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
PJM May Split Rule Changes on Must-offer Exceptions
PJM may seek approval of widely supported changes to the must-offer exception process while having further discussions on revisions that lack consensus, RTO officials told the MIC.
The process behind the rule changes was initiated by Exelon to investigate issues including the process for existing capacity resources with a must-offer requirement to become energy-only resources.
The changes with widest support would allow market participants to voluntarily remove a generator from its capacity resource status by making a request to PJM and the Independent Market Monitor. It would also permit participants to request exemptions from multiple auctions in a single exception request. It would allow such changes for new resources that cannot be completed by the start of the delivery year for which it cleared.
There is less consensus on a rule that would require generators to forfeit their capacity injection rights (CIRs) if they are repeatedly approved for CP must-offer exceptions and not offered in capacity auctions for three consecutive delivery years.
Monitor Joe Bowring said the proposed changes failed to strike the right balance.
Bowring said PJM should discourage generators from holding on to CIRs for a long period of time because “they can’t make up their mind” about being a capacity resource.
“If someone has a clear plan, and they’re following it, that’s fine,” Bowring said. “We think this [proposal] allows more than that.”
Carl Johnson, representing the PJM Public Power Coalition, was also critical. “I’m struggling to find anything I like about any of this,” he said. “This doesn’t hang together to me as an effective set of rules.”
Sharon Midgley of Exelon asked PJM to move forward on the parts of the package with wide support, saying the only issue in dispute was over the RTO involuntarily seizing CIRs from generators after three years of successive must-offer exception requests.
PJM stakeholders are still debating a rule change that would require capacity resources to become energy-only after three consecutive years of exemptions from must-offer rules. | PJM
But Marji Philips of Direct Energy said her company would not support a “quick fix” based on what has been proposed to date. “The process as proposed is a little bit loose yet,” she said, adding that CIRs are “a very serious barrier to new entry.”
A few stakeholders rekindled an earlier debate over whether CIRs are generators’ “property rights.”
Gary Greiner of Public Service Enterprise Group said stakeholders need PJM’s opinion on the issue. “We’ve kind of danced on the periphery, but we’ve never come at it head on,” he said.
PJM’s Pat Bruno said the RTO may split the issue so it can seek approval of its non-controversial elements. He said the RTO will conduct additional discussions with stakeholders before the next MIC.
Electric Storage Rules Require Manual Changes
PJM’s Laura Walter gave stakeholders an update on the RTO’s implementation of rules opening its markets to electric storage, saying as many as 15 manuals may require revisions.
PJM made two filings to comply with FERC Order 841 on Dec. 3, one covering markets and operations (ER19-469) for which comments are due Feb. 7, and a second governing accounting (ER19-462), for which the comment period closed on Jan. 4. The RTO plans to implement the changes by Dec. 3.
Walter said stakeholders will be asked for feedback on energy storage cost offers at the February MIC meeting. Among the items to be discussed will be whether cost offers should be based on inventory cost (historical weighted average cost of stored energy available for discharge, adjusted for round-trip efficiency); opportunity costs (expected lost net revenue from operating in a given hour); or replacement cost (estimated future weighted average cost of charging energy over the next available operating period).
First drafts of manual revisions will be presented before July, Walter said.
