Page 1168 – RTO Insider

May 3, 2018

Powelson: ‘Erosion of Confidence’ in Stakeholder Process

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — FERC Commissioner Robert Powelson on Wednesday reiterated his defense of organized markets but said he sees an “erosion of confidence” in RTO stakeholder processes.

Robert Powelson Stakeholder Process — Powelson | © *RTO Insider*

Powelson, who made the observation in a speech at a PJM issues workshop sponsored by the Great Plains Institute and Duke University’s Nicholas Institute for Environmental Policy Solutions, elaborated afterward in an interview with reporters.

He cited concerns over escalating transmission rates and PJM’s February “jump ball” filing of two competing proposals for insulating its capacity market from state-subsidized generation. (See PJM Board Punts Capacity Market Proposals to FERC.)

“You talk to certain state commissioners; you talk to consumer advocates; there’s a concern that voices are not being heard,” he said. “I think PJM — [CEO] Andy [Ott] has heard me say this — has to do a better job with their state outreach. … A lot of states right now are not happy.”

Illinois Commerce Commissioner John Rosales, and Pennsylvania Public Utility Commission Vice Chairman Andrew Place, who also spoke at the workshop, agreed with Powelson’s characterization. “PJM is swimming and drowning in capacity. … And capacity repricing only worsens that,” Place said.

PJM spokeswoman Susan Buehler said Powelson’s “concern about our stakeholder process … is valid and has been recently discussed with members.”

Regarding complaints about the “jump ball” filing, Buehler said: “PJM believes this is a policy question and that FERC should make policy calls. Based on the recent New England ruling, it appears evident that commissioners are divided.” (See Split FERC Approves ISO-NE CASPR Plan.)

‘Awkward Position’

Powelson said PJM’s decision to file both the two-tier capacity repricing proposal RTO staff prefer and the Independent Market Monitor’s proposal to extend the minimum offer price rule (MOPR) to all units indefinitely “puts us in an awkward position.”

The former Pennsylvania regulator contrasted the filing with the RTO’s Capacity Performance proposal, which was supported by his state as a response to the 22% generator forced outage rate during the 2014 polar vortex. “I want to see more of that synchronization as these constructs come down [to FERC]. It makes the commission’s job a lot easier if there’s those kind of alignments.

“It’s hard to build consensus, and that’s a concern too,” he added. “I don’t know how to change that, but I’d like to see us at least look at it more.”

Adam Keech, PJM executive director of market operations, who spoke after Powelson, also addressed his comments.

“I think the stakeholder process is a great process for getting feedback and vetting proposals and understanding the interests,” Keech said. But he acknowledged the RTO has difficulty advancing “big ticket items” and navigating some “larger issues.”

“And so, are there are ways we can make the process more efficient? I’m sure there are, but there’s value to the process nonetheless. … We need to not throw the baby out with the bath water,” he said.

The challenge of reaching stakeholder consensus was highlighted in a May 2017 paper on PJM’s governance by Christina Simeone, director of policy and external affairs at the University of Pennsylvania’s Kleinman Center for Energy Policy.

“For these high controversy issues, it seems the stakeholder process is falling short at exactly the time when stakeholder collaboration and joint problem solving is critical to informing profound questions about market design and the future of competitive markets,” Simeone wrote.

`Very Disappointing’

Rosales, who is president of the Organization of PJM States Inc. (OPSI), said he agreed that state regulators don’t feel PJM is sufficiently responsive. “Absolutely. 100%. Unqualified yes,” said Rosales, who called PJM’s jump ball filing “very disappointing.”

“We were very clear,” he told RTO Insider in a brief interview. “We thought that the status quo was better than these two really poor options that they put to be filed at FERC.”

Rosales elaborated in a panel of state regulators. PJM is “trying to resolve an issue that hasn’t become an issue yet. It’s a solution to a problem that we don’t have.”

OPSI sent the PJM Board of Managers a letter in February urging it to take no action on any repricing proposal, saying that if the RTO thought rule changes are necessary, “it should reinitiate a more holistic stakeholder process.” The organization said it was not convinced that state policies undermine the RTO’s markets and that PJM’s proposal does not respect state jurisdiction and may raise capacity prices.

But Rosales said OPSI’s concerns have gone unheeded and that PJM has recently adopted a practice of effectively covering its ears and saying, “We hear you.”

“It becomes very frustrating for us because they’ll say they listen, they’ll tell us about the stakeholder process, they’ll tell us everything that they’ve done … and then they’ll just throw it out the door and say, ‘We’re going to go with this anyway.’”

OPSI is not a PJM member, so it has no means of trying to change the stakeholder process at FERC. “We as a group have decided not to be stakeholders,” Rosales said. “We try to have a relationship with PJM … [and] play nice in the sandbox. … But for the most part they’ve not had an open dialogue. … They listen, but the changes aren’t there.”

Monitor Contract

Rosales also cited the renewal of PJM’s contract with its Monitor, Monitoring Analytics. The IMM’s current contract expires in December 2019. “We have problems with getting the Market Monitor contract — again. They seem to be going not the right way,” he told RTO Insider. He did not elaborate on his concerns, which he repeated on the panel.

Monitoring Analytics President Joe Bowring, a Ph.D. economist, has served as PJM’s Monitor since 1999. In 2013, the PJM board came under fire over its proposed request for proposals for monitoring services, which OPSI and other critics said contained language that would undermine the independence and quality of the monitoring function. The board dropped the proposal and signed a contract renewal with Monitoring Analytics later that year. (See Board, OPSI Bury the Hatchet over Monitor Contract.)

OPSI Executive Director Gregory Carmean did not respond to a request for comment Wednesday on the current contract negotiations. Bowring declined to comment in detail but said he was confident in reaching agreement with the RTO.

PJM’s Buehler acknowledged PJM has received questions from OPSI about the contract negotiations. “PJM believes the discussions are productive and ongoing and we are frankly confused by any other characterization,” she said.

Not Just PJM

Powelson said his concerns over the stakeholder process are not limited to PJM, saying all RTO/ISO boards should operate under term limits and ensure diversity among their members. “I’m looking at this … from general business practices as a regulator overseeing those boards and what these RTOs do; making sure they’re synchronizing with what’s going on in the corporate world.

“In my view, you can’t have enough transparency in this [stakeholder] process,” he continued. “We’re making all these changes. People should have the ability to see it, understand it and feel comfortable with the final outcome.”

Powelson also commented on PJM’s initiative, announced Monday, to seek a market-based response to potential fuel security concerns. (See PJM Seeks to Have Market Value Fuel Security.)

Based on “the briefing I received from Andy Ott and his team, I think [PJM] is exactly where we need to be,” he said.

Powelson said “people should not read into” PJM’s announcement that it will end up paying coal and nuclear operators to provide backup for gas-fired generators subject to fuel delivery interruptions. “I think what PJM is saying is ‘we’re going to look at it and we’re going to do it in a market-based approach.’ There might be other technologies out there that have the same [fuel security] characteristics. It could be an oxidized fuel cell. It could be storage. It’s going to be a level playing field discussion. … It’s going to be done in a fuel-neutral, technology-neutral way.”

Powelson said it would be a mistake for the Trump administration to use the 68-year-old Defense Production Act to keep financially struggling coal and nuclear power plants operating, as is being considered, according to published reports. The act was used by President Harry Truman to control steel prices during the Korean War.

“I think it would lead to the unwinding of competitive markets in this country,” Powelson said. “It would be the wrong direction for us to venture down.”

May 3, 2018January 3, 2024

WEC Delivers Strong Q1 Despite Leadership Uncertainties

By Amanda Durish Cook

Cold weather and a stronger regional economy helped boost WEC Energy Group’s first-quarter earnings above expectations, the company reported Tuesday.

The company also addressed uncertainty in its executive suite and described its near-term plans for more renewable investment.

WEC’s profits totaled $390.1 million ($1.23/share) during the quarter, compared with $356.6 million ($1.12/share) for the same period last year.

CEO Gale Klappa said the “solid results” were driven by a stronger-than-expected demand for electricity and natural gas. “Colder winter temperatures, a strengthening economy and efficiency gains across our system were all positive factors that lifted our earnings above year-ago levels,” Klappa said.

The company’s operating revenue for the quarter slipped from $2.3 billion to $2.29 billion this year.

During a May 1 earnings conference call, Klappa praised the company’s performance and said it has a plan readied in the event that company President Allen Leverett does not return to his post as CEO after being placed on medical leave in October 2017 when he suffered a stroke. Klappa said Leverett is currently undergoing intensive speech therapy and is in “good physical condition.” Should Leverett choose not to resume the role of CEO, WEC will employ a succession plan that would “involve a number of internal promotions,” Klappa said.

“I can assure you that we have a solid Plan B in place if Allen does not assume his previous role. … We would have great continuity going forward, and the board and I are very comfortable with [that],” Klappa said, adding that he and WEC’s board of directors will continue to monitor the situation.

Klappa also said WEC is making multiple renewable energy investments throughout 2018. The company on April 30 signed a $280 million agreement to acquire an 80% ownership interest in the 200-MW Upstream Wind Energy Center, currently being built by Invenergy in Antelope County, Neb. Klappa said he expects the wind farm deal to close in early 2019, pending FERC approval — just as Upstream begins commercial operation.

Early last month, WEC closed on its $80 million partial purchase of the 129-MW Forward Wind Energy Center near Brownsville, Wis. Klappa said WEC now owns 44.6% of the wind farm, which is expected to generate savings for customers.

WEC also plans to file construction requests with Wisconsin regulators by the end of the second quarter to build its first solar farm, Klappa said.

“Over the past few years … utility-scale solar has increased in efficiency, and prices have dropped by nearly 70%, making it a cost-effective option for our customers, an option that also fits very well with our summer peak demand curve and with our plan to significantly reduce carbon dioxide emissions,” Klappa said.

He also said WEC is developing plans to provide natural gas and electric infrastructure to “Wisconn Valley,” the moniker for the future site of electronics manufacturer Foxconn’s $10 billion plant. In February, MISO Fast-Tracks ATC Foxconn Project Review.)

May 3, 2018

CAISO, PacifiCorp Gain Most EIM Q1 Benefits

By Robert Mullin

CAISO and PacifiCorp reaped the majority of the Western Energy Imbalance Market’s (EIM) $42.1 million in gross benefits during the first quarter, according to a report released by market operator CAISO.

The ISO earned $14.85 million in EIM benefits over the quarter, followed by PacifiCorp at $10.5 million. Trailing those two market players were Arizona Public Service ($5.9 million), NV Energy ($4.2 million), Portland General Electric ($3.6 million) and Puget Sound Energy ($3 million).

Total quarterly benefits were up nearly 26% from the fourth quarter of 2017 and 31% from the same period a year ago — before Portland General Electric began transacting in the EIM last October. The market has yielded $330.5 million in benefits since it was launched with PacifiCorp in November 2014, the ISO estimates.

EIM CAISO PacifiCorp Western RTO — | *CAISO*

The report again illustrated an established pattern with the arrival of spring: that CAISO becomes a net exporter of energy as increasing output from solar resources coincides with modest electricity demand during mild weather in California. (See CAISO EIM Exports Rise with Spring, Report Shows.)

The ISO’s EIM exports surged from 94,769 MWh in January to 325,664 MWh in March, with imports falling from 299,586 MWh to 185,008 MWh, the report showed. First-quarter exports totaled 608,416 MWh, compared with 362,774 MWh the previous quarter.

CAISO said the energy transfers facilitated by the EIM allowed it to avoid curtailment of 65,680 MWh of renewable output during the quarter, up 24% from the same period last year. That was still down sharply from the nearly 113,000 MWh of avoided curtailments in the second quarter of 2016, which the ISO attributed to improved hydroelectric conditions and advancements in how EIM participants are deploying their resources.

The avoided renewable curtailments translated into the displacement of 28,188 metric tons of carbon dioxide, based on an assumed default emissions rate of 0.428 metric tons CO₂/MWh from other sources of generation. By avoiding curtailments, the EIM has helped to displace 250,845 metrics tons of CO₂ since 2014, the ISO said.

The report also showed that APS and NV Energy functioned heavily as “wheel through” areas during the first quarter, meaning their transmission networks facilitated many transactions for which the utilities received no financial benefits because they were neither source nor sink. (See graph). During February and March, energy volumes wheeled through APS’ territory exceeded the utility’s combined EIM net imports and exports, as significant amounts of energy flowed between the CAISO and PacifiCorp-East balancing authority areas during what is typically a period of low demand in Arizona.

The ISO has “committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits,” the report said.

A CAISO proposal to provide transmission revenue to EIM participants that wheel energy through their BAAs last summer drew stiff opposition from current and future stakeholders concerned about the impact of new charges on the economic dispatch of generating resources. (See EIM Member Wary of Need for Wheeling Charge.)

May 3, 2018

Edison Hopeful for State Action on Wildfire Liability

By Jason Fordney

Edison International CEO Pedro Pizarro said the company is hopeful that several bills working their way through the California State Legislature will ease the financial pressure stemming from hundreds of millions of dollars in wildfire costs.

The company’s main subsidiary, Southern California Edison, is the target of civil lawsuits stemming from the Thomas Fire that began in December 2017 in Ventura County, Calif., burning about 440 square miles and causing two deaths. While the California Department of Forestry and Fire Protection, the Ventura County Fire Department and the California Public Utilities Commission’s Safety and Enforcement Division look into the causes of the fire, the utility is conducting it own investigation, Pizarro said.

During an earnings call Tuesday, Pizarro called for the state to implement wildfire mitigation operating standards to help determine whether a utility properly ran its transmission system prior to a fire.

“An updated standard of liability that considers degree of fault rather than the current standard of strict liability would ensure that there is a fair sharing of the increasing risk of climate change impacts across society,” Pizarro said. He said he was “heartened” by Gov. Jerry Brown’s comments in March about updating utility liability rules for wildfires. Three related bills have been introduced into the legislature: SB 819, SB 901 and SB 1088.

Edison International California Wildfire costs — Edison International reported its first quarter earnings this week

The third bill, set for a May 7 hearing at the Senate Committee on Appropriations, would allow utilities to recover wildfire costs if they conform to state-regulated safety plans, but it faces heavy opposition from critics who say it lets utilities off the hook for their contribution to wildfires. (See Calif. Legislation Shields Utilities from Wildfire Costs.)

Wildfire costs and the financial health of the state’s investor-owned utilities have sparked concerns in the capitol about the impact on utility stock prices and the potential for bankruptcies — shades of the electricity crisis of the early 2000s. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)

Edison reported first-quarter net income from continuing operations of $242 million, compared with $392 million in the same quarter last year. Operating revenue was $2.5 billion in the first quarter, and total operating expenses were $2.2 billion. SCE is a waiting for a CPUC decision on its 2018 retail general rate case.

SCE on April 3 filed an application at the CPUC for a Wildfire Expense Memorandum Account to track incremental wildfire costs. The company is in the process of renewing its wildfire insurance for 2018 and 2019 and said the cost of additional insurance may substantially exceed the amount authorized in rates or in the pending 2018 rate case. The utility has proposed a schedule that would see a decision on the account issued by August.

The state’s three utilities have banded together on the wildfire issue after the CPUC last year denied San Diego Gas & Electric’s request to recover $379 million in wildfire-related costs. (See Besieged CPUC Denies SDG&E Wildfire Recovery.)

May 2, 2018

FERC Accepts Southeast Transmission Import Limits

By Amanda Durish Cook

FERC on Tuesday approved simultaneous transmission import limits for several balancing authority areas in the Southeast, stretching from Kentucky to Florida.

The 16 simultaneous import limits (SILs) were submitted with non-public market power analyses by several transmission-owning companies, including eight subsidiaries each of Southern Co. and Duke Energy; seven NextEra Energy affiliates (including Florida Power & Light); PPL affiliates Louisville Gas & Electric and Kentucky Utilities; Tampa Electric Co.; and South Carolina Electric & Gas. (ER10-1325 –008, et al.).

FERC SILS — South Carolina Electric & Gas Co. linemen at work | *SCE&G*

FERC will use the SIL values to evaluate market power analyses submitted by the region’s transmission owners (TOs) and non-transmission-owning sellers.

The limits range from a 10.7-GW import capability during winter in the Tennessee Valley Authority balancing area down to a zero-megawatt year-round import limit in the Florida Power & Light balancing area. The limits were created based on a study period extending from December 2014 to November 2015.

While FERC accepted most of the transmission owners’ own SILs, it said it selected Tampa Electric’s calculated values for a few Florida balancing areas where various TO SIL values conflicted with one another.

The commission commended the TOs for coordinating to create the SIL values but said in the future SIL calculations must follow a commission-ordered procedure.

“The southeast transmission owners generally performed their SIL studies correctly. However, the review of these filings, as well as the review of filings for other regions, leads the commission to conclude that it is appropriate to remind sellers of its expectations, and provide clarification, with respect to the calculation of SIL values,” FERC said.

FERC said TOs should abide by the tariff-approved methodologies to calculate SIL capability and should take into account voltage and stability limits, capacity benefit margins and transmission reserve margins.

“The commission emphasizes here that each transmission owner’s SIL values must reflect [transmission reserve margins] and [capacity benefit margins] in the same manner as utilized to calculate and post [available transfer capability] and to evaluate requests for firm transmission service,” FERC said.

May 2, 2018

FERC Approves CAISO-Calpine RMR Settlements

By Jason Fordney

FERC on Monday approved settlement agreements among CAISO, Pacific Gas and Electric and Calpine covering reliability-must-run (RMR) contracts for three Northern California gas-fired plants, reducing the revenue they will receive and making them subject to a must-offer requirement.

FERC’s orders covered two proceedings, one for Calpine’s Metcalf plant (ER18-2 40) and another for the company’s Feather River and Yuba City plants (ER18-2 30). A FERC Administrative Law Judge last month recommended the commission approve the agreements. (See FERC ALJ Certifies Calpine R M R Settlements; PG&E, CAISO Protest Calpine RMR Terms.)

RMR CAISO PG&E Calpine reliability-must-run — Calpine’s Yuba City Energy Center in Northern California | © *RTO Insider*

While the commission said the agreements resolved all issues in dispute in the proceedings and appeared to be “fair and reasonable and in the public interest,” the out-of-market RMR payments are not popular with many CAISO stakeholders and were opposed by the California Public Utilities Commission (CPUC) after the ISO’s Board of Governors reluctantly approved them in November. (See Board Decisions Highlight CAISO Market P roblems.) The CPUC in January voted to require PG&E to hold solicitations to replace the agreements with energy storage. (See CPUC Retires Di a blo Canyon , Replaces Calpine RMRs.)

The Metcalf settlement reduces the plant’s annual fixed revenue requirement from about $72 million to $43 million through 2020 if it retains its RMR status and makes the plant operator responsible for routine repairs and capital expenses. Under the agreement, the plant will recover $8 million in 2018 capital items in 12 installments of $675,000 beginning on Jan. 1, 2018. If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement also grants the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.

The Feather River and Yuba City settlements would reduce each plant’s 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020, if the RMRs are renewed.

The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Re v isions.)

CAISO Tariff Waivers

In a separate order, FERC also granted CAISO a limited Tariff waiver to permit nine scheduling coordinators (SCs) to submit out-of-time requests to recertify 18 resources for the 2018 resource adequacy compliance year (ER18-85 7). CAISO said the SCs had failed to renew an exemption related to its Resource Adequacy Availability Incentive Mechanism (RAAIM) program by the Nov. 15, 2017, deadline because of confusion about the recertification process for acquired resources within the program.

FERC said the waiver grants certainty to those resources that they their RAAIM exemption will not be unwound. CAISO replaced its Standard Capacity Product with RAAIM in November 2016. SCs must present an affidavit for each resource adequacy year testifying that each resource meets eligibility for exemption from certain performance incentives.

Energy Crisis Settlement

The Commission also approved an uncontested settlement filed Feb. 6 among CAISO, Wayzata Opportunities, PG&E, Southern California Edison and San Diego Gas and Electric related to the 2000/01 California energy crisis (EL02 –18). The agreement ensures the payment of interest to the resource owners who had received delayed compensation for certain power supply contracts because of the default of the California Power Exchange. The filing parties said approval of the settlement would avoid further litigation, eliminate regulatory uncertainty and enhance financial certainty.

May 2, 2018

ERCOT Gains Additional Capacity to Meet Summer Demand

By Tom Kleckner

ERCOT will have more breathing room as it prepares for record demand this summer after an additional 525 MW of generation recently came online in Texas.

The ISO said Monday it now has 78.2 GW of capacity available to meet an expected peak demand of 72.8 GW, which would break the 2016 record of 71.1 GW. The additional capacity has boosted ERCOT’s planning reserve margin from 9.3% to 11% since the previous seasonal assessment of resource adequacy (SARA) report.

“That definitely improves the situation,” said Pete Warnken, ERCOT’s manager of resource adequacy, during a media call Monday.

The additional generation comes from the 225-MW, gas-fired Denton Energy Center that recently went into service in North Texas and the return of the mothballed 300-MW gas unit at Barney Davis in Corpus Christi.

ERCOT summer peak demand planning reserve margin — South Texas Nuclear Generating Station

Warnken said rotating outages are still possible under extreme scenarios, “but that risk has been reduced a little bit with those resources.”

ERCOT has approximately 2.3 GW of capacity available through load-control measures with transmission or distribution service providers. Tight reserves could also trigger the need for the ISO to deploy ancillary services and contracted emergency response service capacity to maintain sufficient operating reserves.

Staff also expects industrial facilities to make voluntary load reductions and increase the power they sell into the market during peak demand.

“We expect the market to respond to scarcity conditions,” Warnken said. “It’s a good bet to expect they’ll be looking at summer conditions and making decisions appropriately before they bring their resources on.”

ERCOT summer peak — ERCOT’s Dan Woodfin | © *RTO Insider*

Dan Woodfin, the ISO’s senior director of system operations, said the grid will also benefit with the completion of the Houston Import Project, a $590 million effort that will allow more power to be imported from the north.

“All the pieces are in service at this point,” Woodfin said. “That will help reduce congestion into the Houston area because it improves the transfer capability.”

ERCOT also released its latest Capacity, Demand and Reserves (CDR) report, which includes planning reserve margins for the next five years. The reserve margin peaks at 12.3% in 2020, before dropping to 8.9% in 2023.

The CDR report adjusts the 2019 summer demand forecast down to 74.2 GW, reflecting a delay in a new industrial facility on the Texas coast. Staff expects the load forecast to eclipse 77 GW in 2023. That number includes the planned integration of Lubbock Power & Light’s customers, which is scheduled to take place in 2021.

The ISO’s target planning reserve margin is 13.75%. Warnken said staff is studying an economically optimal reserve margin, which would balance the amount of generation needed to maintain reliability with its cost.

The next CDR report will be released in early December.

May 1, 2018

Izzo: Nukes Outside NJ Likely Eligible for State ZECs

By Peter Key

A recently passed New Jersey law could lead to the state subsidizing nuclear plants outside its borders, Public Service Enterprise Group (PSEG) CEO Ralph Izzo said during his company’s first-quarter earnings call Monday.

“The bill simply says that New Jersey wants 40% of its power supplied by nuclear energy and it does not limit it geographically,” Izzo said.

Izzo made the statement in response to a question from Morningstar’s Director of Energy Research Travis Miller, who said he thought nuclear plants outside New Jersey could be eligible for the zero emission credits (ZECs) authorized by the legislation.

PSEG ZECs earnings Ralph Izzo Q1 2018 — PSEG head Ralph Izzo says NJ Gov. Phil Murphy supports the jobs at the Hope Creek nuclear plant. | *NRC*

In addition to the Salem and Hope Creek nuclear plants that PSEG operates in Salem County, N.J., Izzo said the Peach Bottom nuclear plant in Pennsylvania, of which PSEG is half owner, could compete for ZECs. So, he added, could two other Pennsylvania nukes: Talen’s Susquehanna and Exelon’s Limerick.

The ranking system the legislation encourages the New Jersey Board of Public Utilities (BPU) to use in determining which plants get ZECs is driven by their impact on the state’s air quality, Izzo said.

Gov. Phil Murphy has not signed the legislation, which was passed April 12. He has 45 days from then to sign it into law; veto it, which both houses of the legislature could override with two-thirds majorities; conditionally veto it, which amounts to sending it back to the legislature with changes requiring majority approval; or not sign it, in which case it would become law after the 45 days pass. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)

PSEG ZECs earnings Ralph Izzo — PSEG head Ralph Izzo says nuclear plants outside New Jersey could be eligible for ZECs from the state. | © *RTO Insider*

Izzo declined to opine on what he thinks Murphy will do — “You never, ever want to pretend to be constraining your governor,” he said — but he also said the governor has been outspoken about nuclear power being a bridge to a future with much more renewable generation capacity and supportive of the jobs at PSEG’s two nuclear plants in the state.

As for PJM’s efforts to improve its capacity market, Izzo said PSEG supports the RTO’s two-stage capacity repricing proposal over the Independent Market Monitor’s plan to expand the minimum offer price rule. PJM earlier this month filed both plans with FERC, asking it to choose one and outline what aspects of it should be revised. (See PJM Capacity Proposals to Duel at FERC.)

Izzo said PSEG prefers the status quo to either option because it doesn’t interfere with the ability of states to price attributes that markets aren’t currently pricing, which, in PSEG’s case, are the emissions-free generating capabilities of its nuclear fleet.

PJM’s two-stage approach would at least continue to allow states to value carbon-free generation,

but what’s really needed is a price on carbon, he said.

“The market’s just got these inherent inconsistencies built into it,” he said. “If we could get a price on carbon … capacity markets could do what they’re supposed to do.”

PSEG CFO Dan Cregg addressed the company’s recent agreement to pay $39.4 million to settle an investigation into violations of PJM’s energy market bidding rules over 9 years. (See PSEG to Pay $39.4M to Settle FERC Investigation.) He said PSEG’s Power unit recorded an incremental $5 million pretax charge to income in the first quarter that will conclude the issue.

“We do not believe the order will have any ongoing impact” on PSEG Power, he said.

PSEG earned $558 million and $1.10/share in the first quarter, up from $114 million and $0.22/share in the first quarter of last year. Last year’s results included costs related to the early retirement of the Hudson and Mercer generating stations and a reserve for the impairment of leveraged leases.

As part of his effort to promote renewables, Gov. Murphy issued an executive order that began moving the state towards a solicitation of 1,100 MW of offshore wind capacity.

Izzo said PSEG has a lease and a partner, which he didn’t name, for offshore wind development, but said since his company has no experience in that area, it “would be interested in the transmission component as much as, if not more than, the actual wind farms.”

May 1, 2018

PJM Seeks to Have Market Value Fuel Security

By Rory D. Sweeney

PJM wants to take a more holistic look at how the grid’s supply chain works and factor the findings into its markets.

The RTO announced a plan Monday it thinks will help ensure the reliable delivery of both electricity and the fuel necessary to generate the electricity. The three-phased approach will analyze fuel security throughout PJM’s footprint to identify vulnerabilities, develop criteria to address them and include those criteria in the models used for capacity auctions.

The result would be constraints on the grid that trigger clearing price differences in affected locational deliverability areas (LDAs) in the same way deliverability constraints already trigger price separation in base residual auctions (BRAs). Those price differences would signal opportunities for developers to build new infrastructure.

PJM hopes to have the process in place for the 2022/23 BRA in May 2019.

The RTO will brief stakeholders on the plan and discuss the study scoping document at a special Markets and Reliability Committee meeting from 9:00-12:00 EDT on May 8. The RTO apologized for scheduling it on a “no meeting day,” saying there were no other available times on the committee meeting calendar in May.

Avoiding Problems

PJM fuel security — Ott | © *RTO Insider*

In announcing the plan, CEO Andy Ott repeatedly reiterated that, while PJM’s grid is currently reliable and has no fuel security issues, problems could materialize if current trends continue for too long. The percentage of gas-fired generation has been growing quickly in PJM’s fleet. The RTO determined last year it wouldn’t have reliability concerns even with a high percentage of gas generation, capping its analysis at 86% of the fuel mix because the current 14% share of demand response and hydro and biomass production is not likely to change, but the analysis didn’t address the security of the gas plants’ fuel supplies. Because they are beholden to gas pipelines, gas plants can have — and pay for — a wide range of contracts, from receiving uninterruptable service to being cut off first if there’s not enough gas in the pipeline. Other plants maintain backup supplies of liquid fuel, such as oil or liquified natural gas (LNG), onsite or are connected directly to Marcellus shale gas wells. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)

Ott called the plan a “narrow” portion of the resiliency initiatives going on at PJM and throughout the nation. He pointed to pipeline constraints in ISO-NE as justification for the plan to get “ahead of those issues in a timely manner.”

“At some point in the future, we may be overdependent on one pipeline or one set of fuel-delivery infrastructure,” he said. “Our approach is to develop these criteria to make sure that we’re monitoring those trends.”

Plan Mechanics

It’s unclear how the mechanics of the plan will work, as the transmission-constraint pricing it would be modeled on raises prices in areas that have issues. That would suggest the price signals would also reward fuel-insecure units within those LDAs.

fuel security PJM — Natural gas pipeline | *Ohio Power Siting Board*

“If we see a fuel security problem, the price would elevate in that area,” Ott confirmed in his Monday morning briefing.

PJM spokespersons said the question is beyond RTO staff’s current analysis, but Robbie Orvis of the clean energy consulting firm Energy Innovation predicted it might be designed as a shadow price that calculates what the price would be without the insecure resources and offers them as an adder for secure ones.

Ott appeared to corroborate that in describing the price separation as an “adder.”

“The increased cost to fix that would be adding more onsite fuel tanks or other types of fuel-secure resources,” he said. “The idea is not to give units more money. The idea is to look at the exposure that we have.”

He noted wind, solar and batteries could qualify as fuel secure, but a renewable resource alone “would probably [qualify at] a much smaller amount than its nameplate capacity” in capacity auctions.

Impact

PJM said part of the study is to determine what, if any, new construction is necessary and where. Orvis added it’s unclear whether it would create demand for new coal and nuclear units, but “it seems rather unlikely” given the net revenues for those technology types calculated by PJM’s Independent Market Monitor in its 2017 State of the Market Report are “well below” their respective costs of new entry calculation.

“Given just how short these units would be on revenue recovery, it would take a very high price from some kind of new market product for fuel security to cause new coal and nuclear builds,” he said. “It’s worth noting that those low revenues are consistent across zones, so it doesn’t look like there are even any specific constrained areas where those plants are especially attractive.”

The adder would make the threshold easier to reach but require significant additional action.

“Over time, with a high enough price, large retirements, and in constrained zones, it is possible that some kind of fuel security price adder could tip the scales and incent new capacity, but it would take a significant deviation from today’s prices,” Orvis said. “PJM’s high reserve margins in the near- and medium-term, based on its cleared capacity in the capacity market, indicate that it’s unlikely there will be a capacity shortfall to push capacity market prices up.”

Orvis noted the modeling parameters PJM plans to use will likely underestimate the generation fleet and therefore might indicate a fuel delivery constraint when there are actually many more resources available.

“It is possible PJM will charge its customers for a service or attribute that is not needed. It would be better if they modeled the system based on what is actually expected to be available rather than their required reserve margin since they have in the past and will in the future continue to come in well above that reserve margin,” he said.

Reaction

Paul Bailey, CEO of the American Coalition for Clean Coal Electricity, praised PJM’s action and urged other grid operators to follow suit. “We are also encouraged that PJM is following a work plan consistent with the urgency necessary to address lack of fuel security,” he said. “Over the next three years, more than 6,000 MW of fuel-secure coal-fueled generating capacity in PJM are expected to retire.”

Meanwhile, NRG Energy spokesman David Gaier noted PJM on Monday also said that FirstEnergy’s announced retirements of its Davis-Besse, Perry and Beaver Valley nuclear plants will not cause reliability problems.

“Units can retire as scheduled” PJM said in a presentation for the May 3 Transmission Expansion Advisory Committee meeting. “Operational flexibility allows [us] to bridge any delays with the transmission upgrades.”

Gaier said the RTO’s analysis undermines FirstEnergy’s request that the Department of Energy declare an emergency to keep the plants running. “Clearly, the attempt by FirstEnergy to keep open its uneconomic nuclear plants on the backs of ratepayers is a subsidy in search of a crisis — one that doesn’t exist,” Gaier said.

May 1, 2018

Texas Commissioners Approve 478-MW SPS Wind Farm

By Tom Kleckner

AUSTIN, Texas — The Public Utility Commission (PUC) of Texas on Friday orally approved Southwestern Public Service Company’s (SPS) request to build a wind farm in West Texas, clearing the way for a 1.23-GW project that will provide renewable energy and economic benefits to SPS customers in the Lone Star State and New Mexico.

SPS ERCOT PUCT Wind Farm — Texas PUC conducts an open meeting. | © *RTO Insider*

“It’s hard for me to look at this and do something different than what” benefits ratepayers, said PUC Chair DeAnn Walker.

Walker and Arthur D’Andrea requested additional information from SPS during the commission’s April 12 meeting, expressing doubts as to whether they had a “legal basis” to grant an application for new generation when the company already has sufficient capacity. (See Texas Regulators Seek More Details on SPS Wind Project.)

“I’m sorry if we kind of freaked out, but it’s a big question, and we don’t have a ton of time to review it,” D’Andrea told SPS representatives and the consumer groups with whom they had reached a unanimous settlement.

“I think you’ve done a nice enough job … for the ratepayers,” D’Andrea said. “You’ve certainly done a great job of getting everyone’s finger on the trigger.”

SPP staff had also previously stamped its approval on the SPS proposal.

Walker instructed staff to reflect Friday’s several minutes of discussion in its draft order. The final order will be approved during the PUC’s May 10 meeting (Docket No. 46936).

“It’s been a very cooperative effort, with both local stakeholders and statewide stakeholders,” SPS President David Hudson told RTO Insider after the April 27 open meeting. “This project will bring tremendous economic value to the region for three decades.”

The commission’s approval allows SPS parent Xcel Energy to proceed with construction of a 478-MW wind farm near Plainview, Texas, and a 522-MW facility near Portales, N.M., both in SPP’s footprint. Xcel will begin construction on the Texas facility in June and in New Mexico next year.

The company, which will own both facilities, will also purchase 230 MW of energy from two NextEra Energy Resources in Texas.

SPS received approval for the New Mexico portion of the project from the state’s Public Regulation Commission in March.

Xcel says the project will save customers hundreds of millions of dollars in production costs over a 30-year period. SPS will receive 100% of the available production tax credits for 10 years, passing the savings directly to its customers.

Xcel also expects the project to generate more than $150 million in local property tax payments over the next 25 years in Texas and New Mexico.

PUC Lowers CenterPoint Energy’s Tx Rates

The commission also approved CenterPoint Energy’s request to revise its wholesale transmission rates to reflect the reduction of the federal income tax corporate rate from 35% to 21%, thanks to the Tax Cut and Jobs Act of 2017 (Docket No. 48065).

The revision reduces CenterPoint’s transmission rate base from $2.11 billion to $2.08 billion and its wholesale transmission revenue requirement from $389.5 million to $347.8 million. Its interim wholesale transmission rate drops from $5,753.91/MW to $5,138.64/MW.