Page 1115 – RTO Insider

August 17, 2018

CAISO Regionalization Bill Cast on Uncertain Course

By Hudson Sangree

SACRAMENTO, Calif. — Gov. Jerry Brown’s controversial plan to transform CAISO into an RTO took an unexpected turn Thursday in the State Senate’s Appropriations Committee.

CAISO regionalization western energy imbalance market — Brown | © *RTO Insider*

The committee’s members were set to vote on the plan’s first step, AB 813, either killing it or sending it to the Senate floor. Instead, the bill was withdrawn from Appropriations and sent back to the upper house’s Rules Committee.

The move likely was intended to give proponents time to work out a deal to allow the state-chartered CAISO to transform itself into an independent organization positioned to expand into the vast Western energy market.

“The Senate is taking the time needed to get this right, which is so important because full integration of the western electricity grid is vital to California’s clean energy future,” the Natural Resources Defense Council, a supporter of the measure, said in an email immediately after the move was announced.

The measure now could languish in Rules or be sent directly to the Senate floor as the legislature nears the end of its two-year session Aug. 31. Previous efforts to authorize CAISO’s expansion have stalled during the past two years in the face of strong opposition both inside and outside of California. (See Governor Delays CAISO Regionalization Effort.)

Regionalization Risks

AB 813 would authorize CAISO’s Board of Governors to submit a plan to the California Energy Commission to change the ISO’s governance structure to include transmission owners from outside California. If adopted, it would be the first step in a multiyear process to make CAISO an RTO for the West.

Those who’ve opposed AB 813 include the Sierra Club, municipal utilities and ratepayer advocates. They contend the measure would lump California in with coal-producing states such as Wyoming and put California at risk of greater interference from federal regulators under the Trump administration.

“I don’t buy the argument that we have to regionalize to take advantage of opportunities elsewhere,” said Barry Moline, executive director of the California Municipal Utilities Association, which represents publicly owned utilities throughout the state.

Moline told RTO Insider that the Western Energy Imbalance Market is already doing a good job at allowing energy to be bought and sold as needed among Western states, without building new transmission lines from wind farms in Wyoming to consumers in California.

Creating more renewable energy sources in California and using in-state transmission lines would further the state’s aims without adding risk, he said.

Moreover, he said, AB 813 would benefit wealthy out-of-state investors and conglomerates that want California ratepayers to pay for infrastructure from which they’d profit.

“There’s a lot of transmission companies and a lot of renewable resource developers that want to deliver kilowatt-hours into California,” Moline said. “These folks want to make money off of California.”

The proposal’s champions include Brown, CAISO, some environmental nonprofits and companies that stand to profit. It was introduced by Assemblyman Chris Holden, chairman of the Assembly Utilities and Energy Committee.

Those arguing for the bill said it would further California’s ambitious renewable energy goals by tapping into Wyoming windmills and Arizona solar arrays, while spreading sustainable energy throughout the West.

“This is the direction the grid is heading in,” said Carl Zichella, NRDC’s Western transmission director. “We need to be able to operate the system as a congruent whole.”

A set of amendments adopted Aug. 7 was meant to ease the concerns of those who worried about linking deep-blue California with the red states of the interior West.

“The purpose of the amendments is to reassure people that the progress California’s been making on renewable energy and climate change are not likely to be interfered with,” Zichella said.

The new language included a requirement that a California TO, retail seller or publicly owned electric utility not join or remain a member of an RTO with a centralized capacity market.

The amendments also insisted the state not undermine its ambitious scheme for achieving reductions in greenhouse gases and for purchasing electricity from renewable energy and zero-carbon sources.

The Aug. 7 changes, however, were apparently insufficient to ensure the measure’s passage through the Appropriations Committee before Friday, the last day for fiscal committees to meet and report out bills.

AB 813 can now be amended in the Rules Committee and sent to a vote of the full Senate before the last day of August, bypassing Appropriations. The bill passed the Assembly last year.

If it clears the legislature, Brown would then have until Sept. 30 to sign the measure into law. If it proves too complex and divisive for quick resolution, Brown could call a special session of the legislature this fall.

August 17, 2018

New SPP Member Walmart Eyes ‘Everyday Low Costs’

By Tom Kleckner

OMAHA, Neb. — When SPP CEO Nick Brown welcomed Walmart as one of the organization’s newest members last month, he made a point of noting the company was the first in the RTO’s large retail customer sector, which has been vacant since 2003.

A big deal for SPP, maybe, but old hat for Walmart. The retail giant is a member of every U.S. grid operator except CAISO, though that could eventually change.

Walmart Chris Hendrix SPP — Hendrix | © *RTO Insider*

“It depends on the regulatory environment there,” Chris Hendrix, Walmart’s director of markets and compliance, told RTO Insider.

As it is, Walmart is involved in most states that are open to retail competition, along with markets in Canada and the U.K., the latter through its Asda affiliate. Other markets, national and international, could follow “depending on how they’re structured,” Hendrix said.

“It’ll be easier for me to tell you what markets we aren’t in,” he said, ticking off Delaware, Michigan, Rhode Island and D.C.

Walmart’s foray into electricity markets began simply enough in 2003, when it joined ERCOT as a retail electric provider (REP) through its Texas Retail Energy entity. The wholly owned company has a customer of one, procuring power for Walmart, Sam’s Club and other subsidiaries and their many stores and distribution centers.

“Initially, it was all about lowering our costs,” Hendrix said. “We’re like other REPs [in Texas], only we don’t have sales people or customer service reps.”

Hendrix, who brought 15 years of energy experience in both the gas and electricity sectors when he joined Walmart in 2003, is part of a team of 15 former energy insiders and company associates “doing all types of things.”

Everything, that is, except sales. There’s no need to market outside the Walmart family of companies.

“We can be in control of our own destiny,” Hendrix said. “We can buy power how and when we want to, as opposed to being beholden to somebody else’s buying schedule at the utility, or the market products they can come up with. We access the wholesale market when and how we see fit.”

No Middleman

Hendrix said Walmart benefits from its membership in SPP and other grid operators by gaining access to hourly pricing and managing it for the company’s needs.

“We cut out the middleman, and we leverage our credit as Walmart,” he said. “The cost savings come from leveraging our credit, as well as operational efficiencies from having less people and services that we have to offer.”

Asked to quantify Walmart’s energy savings, Hendrix demurred.

“Cutting out the middleman’s margin is basically the savings,” he said. “Our goal is everyday low prices, and along with that, everyday low costs. Anything we can do to lower the cost helps the business opportunities of Walmart.”

At the same time, Walmart’s involvement with RTOs and ISOs has been instrumental in the company’s sustainability program. The retailer has been working toward a goal of operating with 100% renewable energy since 2005.

Walmart has been the eighth largest corporate purchaser of wind and solar power globally since 2008 with 781 MW, according to Bloomberg New Energy Finance, and it gets about 28% of its electricity from renewables. Just before the presidential election in 2016, the company announced it intended to get half its power from wind and solar energy by 2025, passing Google as the world’s top buyer of renewable power.

Nothing has changed, despite the Trump administration’s lack of support for renewables.

“Our goals and objectives have not changed at all since they were first introduced … and more specifically, in November before the election,” Hendrix said. “By the time it’s all finished, 35% of our load in Texas will come from wind. That’s a significant number, but it’s still not a 50% number. We’re looking to do a lot more, because we can’t get there with on-site solar. It has to be large-scale solar and large-scale wind.”

Hendrix said one of the side benefits of participating in energy markets is purchasing renewables on a wholesale basis. To participate in most of the markets it’s in, Walmart had to become a member of the grid operators. SPP doesn’t have that same requirement, but its 18 GW of installed wind capacity was too enticing to pass up.

“As we do a lot more renewables, a lot of that … is in the SPP territory,” he said.

Walmart’s annual $6,000 membership fee is a small price to pay. As the executive responsible for regulatory and legislative matters for the company’s retail and wholesale energy businesses, Hendrix also gets to have a vote in SPP’s stakeholder process.

“We decided, as we have been in all those other markets and we have seen the benefits of being on those committees, it made sense to join SPP,” he said. “We try to understand what’s happening with the ISO’s policies and try to steer them in the direction that we think is best. We’ll always advocate for competition and free markets.”

SPP’s hefty exit fee — about $673,000 for non-transmission owners, the RTO estimates — has scared away some potential members, but not Walmart.

“We don’t intend to go anywhere,” Hendrix said. “It works out to $6,000 a year. We think we get the benefit of being involved in the market.”

August 17, 2018

Line Opponents Set Sights on PJM in Public Campaign

By Rory D. Sweeney

PJM may soon have to choose between continuing to greenlight its “largest-ever” congestion-reducing transmission project or risking a public relations war with opponents of the project who live in its proposed pathway and have gained influential allies in their fight to have it shelved.

The $340.6 million project proposed by Transource Energy would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border — one between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; and another between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.

PJM and regulatory filings refer to the project as “9a,” while Transource has dubbed it the Independence Energy Connection.

PJM Transource Independence Energy Connection — 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*

“Until now, landowners have considered Transource to be their opponent, but unless PJM soon exercises its right to withdraw the project, we will hold PJM responsible,” wrote the opponents — consisting of three landowner groups in Harford, York and Franklin counties — in a June 30 letter to the RTO’s Board of Managers.

“PJM will become the target of our media outreach, our legislative efforts and, potentially, our legal efforts as we hold PJM responsible for the tremendous costs incurred by landowners who will ultimately emerge victorious,” the letter warned. “Further PJM support of this project will be viewed as an abuse of process.”

Project 9a

PJM selected Transource’s market efficiency proposal in August 2016 to reduce congestion along the RTO’s AP South interface. As part of PJM’s implementation of FERC Order 1000, the congested interface was included in its inaugural window for proposing such projects and received the most attention, attracting seven of the 17 total proposals submitted. (See AP South, Cleveland Draw Congestion Relief Proposals.)

At the time, PJM CEO Andy Ott called it “PJM’s largest-ever market efficiency project,” projecting it would save ratepayers $622 million in congestion costs over 15 years. The eastern portion would relieve the Graceton-Conastone 230-kV line, which was the most congested line in PJM’s 2016 long-term analysis. Its congestion costs in 2017 were $51.8 million and were expected to rise over the next 10 years to $68.88 million in 2027.

Another line leading into Graceton, the 230-kV Bagley-Graceton, was third on the list with $23.59 million in 2017 congestion costs and estimates of $59.57 million in 2027. A third line in the area, the 500-kV Peach Bottom-Conastone, was second on the current list with $32.78 million in congestion costs, which are expected to drop precipitously to $1.9 million in 2027.

FERC approved a formula rate for the project in January 2017 and a settlement this January on Transource’s return on equity, but it refused to reconsider whether the company should be allowed to make single-issue rate filings or recover all costs if the project is canceled through no fault of the company.

Transource received permission, starting on Jan. 31, 2017, to recover all “prudently incurred costs” if it must abandon the project for reasons “beyond Transource’s control.” All costs prior to that are subject to a cost-sharing policy FERC ordered in Opinion 295, through which Transource could recover 50% (ER17-419).

‘Do the Right Thing’

But opposition has developed among residents who live around the proposed paths, and they have orchestrated an awareness campaign that netted support from high-level elected officials on both sides of the state border. U.S. Rep. Scott Perry (R-Pa.) wrote a letter to FERC in March, calling on the commission to reconsider whether Order 1000 “puts impacted private citizens at a distinct disadvantage” in opposing projects. FERC Chairman Kevin McIntyre responded in April, outlining how projects are selected through Order 1000’s competitive solicitation process and assuring Perry that PJM re-evaluates its decisions annually.

Maryland Gov. Larry Hogan wrote to PJM’s Board of Managers on July 10 to “express concerns” that “the project will take prime agricultural land out of production, including land that is in permanent agricultural easements.” He sympathized with “the need to reduce power congestion in Maryland” but requested that the project be halted pending a re-evaluation or rerouting using existing rights of way, along with greater engagement with residents and state agricultural and energy agencies.

PJM says it never received Hogan’s letter.

“We have no record of receiving it,” PJM spokesperson Susan Buehler told RTO Insider in an email.

But the PJM board did receive the letter from opponents, who mentioned McIntyre’s “favorable response” and called for the project to be removed from the Regional Transmission Expansion Plan because the benefits have dropped substantially since the RTO last analyzed it.

“While we understand that PJM feels a responsibility to Transource to allow them to fail gracefully at the state level after a protracted review, the facts demand that PJM cancel this project immediately,” they wrote.

The opponents argued that near-universal local opposition and unknown environmental impacts should induce staff “to use your professional and moral judgment to do the right thing.”

Citing testimony from PJM’s Paul McGlynn to the Maryland Office of People’s Counsel (OPC), they argued system changes since last year’s annual analysis have reduced the potential benefits while costs have likely risen. The reference was to a data request from the OPC to PJM as part of the Maryland Public Service Commission’s review of Transource’s application for a certificate of public convenience and necessity for the project. In a portion of the data request provided to RTO Insider by the opposition, McGlynn appears to indicate that the congestion savings have fallen from the $620 million expected when the project was approved to $245.75 million in the most recent analysis.

However, that number is not a direct input in PJM’s analysis of such projects. That analysis, which was performed last September and posted in January, still produced a benefit-to-cost ratio of 1.32, exceeding PJM’s 1.25 threshold for considering a proposal. PJM was unable to independently verify the document cited by the opposition but confirmed that the information McGlynn would have used came from the analysis that resulted in the 1.32 benefit-cost ratio. Any changes in the variables will be included in the next analysis coming in September.

“PJM is currently conducting a third evaluation of the project, and we are using up-to-date data in doing so,” PJM spokesperson Jeff Shields said in an emailed statement. “In the past, the PJM board has canceled several major transmission projects in the region — including the [Mid-Atlantic Power Pathway] and [Potomac-Appalachian Transmission Highline] projects in 2012 — as a result of such re-evaluations.”

Impact on the Ground

The opposition argues that PJM does not give enough consideration to utilizing existing infrastructure. They point out that PPL’s existing Conastone-Otter Creek 230-kV line, which largely mirrors the proposal’s eastern path, has capacity to run another line.

PJM confirmed that PPL offered a proposal among the 41 submitted to address the AP South interface congestion, but its benefit-cost ratio did not meet the 1.25 threshold. A PPL representative said the company’s proposal “involved adding equipment to an existing substation.”

[Editor’s Note: An earlier version of this article incorrectly reported, based on information provided by PJM, that PPL had not submitted a proposal.]

Because it’s PJM’s largest market-efficiency project, “they want it to go through at any cost to land owners and local communities,” said Patti Hankins of Harford County, who joined the opposition in 2017 after learning property belonging to her husband’s cousin would be impacted.

Opponents are also concerned about the safety of high-voltage lines and the potential impact on destination agriculture, such as Shaw’s Orchard Farm Market in White Hall, Md., and other farm-to-table operations. New construction should be the last resort, they argue.

“The impact on the ground is so significant that there should be no new construction until it’s absolutely necessary,” said Aimee O’Neill, a Maryland resident and president of grassroots group Stop Transource Powerlines MD, a signatory to the opposition letter.

Political Action

O’Neill has been lobbying state legislators to pass five bills that would require developers to use existing transmission infrastructure where possible before building new. Opponents of the bills, which O’Neill hopes will be reintroduced in the legislature’s 2019 session following mid-term elections, argue that state regulatory oversight is satisfactory and that such laws would significantly upset plans to replace much of the regional grid that is nearing the end of its usable life.

“Maryland is not prepared to protect the interests of the people in the face of a changing energy environment,” O’Neill said. “There’s really nothing wrong with requiring those upgrades to be completed in existing easements with existing equipment, and what we’ve learned is that unless there is legislation requiring that … people [opposing new projects] are doomed to go through this time and again.”

Every property owner along the proposed routes has objected to the project, so Transource will need eminent domain authority to take them, O’Neill said. The company is currently working through permitting and eminent domain proceedings with regulators in both states.

A Transource representative said the company would not a comment on the opponents’ letter because it is directed to PJM.

August 16, 2018

FERC OKs MISO Storage Filing; Rejects IPL Rehearing

By Rich Heidorn Jr.

FERC on Wednesday accepted MISO’s compliance filing spelling out rules for its new energy storage category, rejecting a protest and rehearing request by Indianapolis Power & Light (ER17-1376-002, ER17-1376-003).

MISO was responding to FERC’s March 23 ruling approving the creation of a Stored Energy Resource Type II that ordered the RTO to flesh out the concept further. MISO proposed the new storage category last year following IPL’s complaint against the RTO’s existing storage participation rules. (See FERC OKs MISO Plan to Expand Storage.)

SER–Type II FERC MISO energy storage IPL — IPL Harding Street Station battery interior | *IPL*

In its compliance filing, MISO revised the definition of SER-Type II resources to clarify that they are eligible for up/down ramp capability if technically capable.

It also said that SER-Type II resources will be subject to the same must-offer obligation that applies to other capacity resources. MISO said it would be expensive and time-consuming to redesign its day-ahead market software to exclude such resources from the must-offer obligation. However, MISO also revised its Tariff to allow the storage facilities to derate their capacity to limit their supply to four hours.

The filing also revised the definition of station power to exclude the energy used to charge an SER-Type II resource.

In Wednesday’s ruling, FERC said MISO’s filing was largely responsive to the March order, although it agreed with IPL that Tariff changes regarding up/down ramp capability are incomplete and ordered the RTO to add additional Tariff language.

The commission rejected IPL’s protest of MISO’s proposal to apply the must-offer rules to SER–Type II resources that provide capacity. But it noted that Order 841 required each RTO/ISO to demonstrate that its existing market rules allow storage resources to provide capacity in a way that acknowledges their limitations.

“Therefore, while we accept MISO’s clarification that its must-offer rules apply to SER–Type II resources, we note that MISO still has a compliance obligation under Order No. 841 to demonstrate how its capacity market acknowledges the energy limitations of electric storage resources,” the commission said.

The commission also rejected IPL’s request for rehearing, saying it had addressed the company’s arguments in both the March 2018 order and a February 2017 ruling. “Indianapolis Power does not raise any issues in its rehearing request challenging the commission’s conditional acceptance of MISO’s compliance filing that are new to this proceeding or that Indianapolis Power had not raised earlier,” FERC said.

August 15, 2018

NEPOOL Files Press Ban with FERC

The New England Power Pool filed a proposal with FERC on Monday to codify its unwritten ban on press attendance at stakeholder meetings (ER18-2208).

The proposed amendments to the NEPOOL Agreement add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant.

NEPOOL ISO-NE FERC stakeholder meetings — NEPOOL’s 2017 Annual Report included a photo of a stakeholder meeting. Of the seven RTOs and ISOs in the U.S., only New England’s bars the press and public from attending. | *NEPOOL*

New England is the only one of the seven U.S. regions served by RTOs or ISOs that prevents press coverage of stakeholder meetings.

NEPOOL’s Participants Committee approved the press ban June 26 with 79% in favor in a sector-weighted vote. An alternative proposal that would have made the press eligible for a non-voting membership failed with only 27% in support, with only the end-user sector strongly in support. (See NEPOOL Votes for Press Ban, Discusses Fuel Security.)

RTO Insider prompted the vote by having reporter Michael Kuser, who lives in Vermont, apply for committee membership as an end-user customer in March. NEPOOL has not acted on the application.

NEPOOL’s filing says that permitting press to become a participant or to represent a participant “would adversely impact NEPOOL’s ability to continue to foster candid discussions and negotiations in its stakeholder meetings. Without such discussions and negotiations among its members, ISO New England Inc. and state officials, NEPOOL would be limited in its ability to narrow or resolve complex issues within the NEPOOL stakeholder process. This could have the effect of increasing the issues and scope of litigation at the commission on ISO-NE Tariff changes and related matters before it.”

It cited concerns that press attendance at meetings “could encourage public posturing, pre-scripted statements and reduced willingness or ability by members to freely explore ideas or solutions.”

The filing notes that FERC ruled in a 2001 order that the NEPOOL Agreement is not a FERC tariff but “a supporting document … [and the] equivalent of a utility’s Articles of Incorporation.”

While it relieved NEPOOL of filing the agreement in tariff form, the commission said the organization must continue to file proposed changes to the agreement with the commission. “The commission will continue to review the proposed changes that fall within its authority under the [Federal Power Act],” the commission said.

NEPOOL said the commission is in “‘an essentially passive and reactive’ role’” and can only reject the filing if it finds the changes not “just and reasonable.”

“Thus, if the commission determines that a provision that precludes press from becoming a NEPOOL participant or participant representative falls within its authority, it can only reject that provision if it concludes that the changes are unlawful,” it said. “The commission’s review does not extend to the question of whether there are other reasonable approaches to the press membership issue.”

NEPOOL requested the change take effect Nov. 1.

RTO Insider began covering PJM stakeholder meetings in early 2013 and expanded coverage to stakeholder meetings of MISO and NYISO in late 2014, SPP in early 2015, and ERCOT and CAISO in 2016. RTO Insider also began covering ISO-NE in late 2014 but has been barred from all stakeholder meetings except for the Planning Advisory Committee, which is run by the RTO.

— Rich Heidorn Jr.

August 15, 2018

NYISO Business Issues Committee Briefs: Aug. 13, 2018

RENSSELAER, N.Y. — NYISO’s Business Issues Committee voted Monday to approve a revised charter for the state’s Integrating Public Policy Task Force (IPPTF), the group exploring how to incorporate the cost of CO₂ emissions into the ISO’s markets.

business issues committee nyiso bic carbon dioxide emissions ipptf — DeSocio | © *RTO Insider*

Michael DeSocio, NYISO senior manager for market design, highlighted a single sentence added to clarify the task force’s mission: “Incorporating the cost of carbon dioxide into the wholesale energy markets is intended to provide the most efficient means to incentivize carbon abatement from a broad set of electric suppliers, supporting the state’s clean energy policies to reduce electric sector carbon dioxide emissions while continuing to leverage market forces to provide affordable, reliable electricity.”

The IPPTF is being run by NYISO after initially being set up in collaboration with the state’s Department of Public Service. The group next meets at ISO headquarters Aug. 20.

Broader Regional Markets Report

Staff continue work on clarifying the minimum deliverability requirements for external capacity from PJM into NYISO’s Installed Capacity (ICAP) market, Nicole Bouchez, ISO principal economist, highlighted from the monthly Broader Regional Markets report.

At the July 31 Installed Capacity/Market Issues Working Group meeting, the ISO presented its proposed market design to improve the supplemental resource evaluation process for external capacity resources. It will communicate next steps after evaluating stakeholder feedback.

In related matters, Bouchez highlighted that the Independent Power Producers of New York last month filed a complaint asking FERC to direct the ISO to disallow PJM resources from selling ICAP into New York City (Zone J) using certain unforced capacity deliverability rights (UDR) facilities.

Public Service Electric and Gas in May had filed a complaint against Consolidated Edison concerning two transmission lines, B3402 Hudson-to-Farragut (B line) and C3403 Marion-to-Farragut (C line). PSE&G alleged that underwater portions of the lines may have been permanently damaged and should be removed.

On June 6, the ISO filed a protest with FERC indicating that removal of the B and C lines would undermine resilience in both New Jersey and New York and requested that PSE&G’s complaint be denied.

Sub-20-MW Constraint Reliability Margin Values

The BIC approved the ISO’s proposal to apply a sub-20-MW constraint reliability margin (CRM) value to certain facilities where warranted. A CRM is a portion of a transmission facility’s capacity kept in reserve to help meet NERC and other reliability standards. A few facilities use the normal 20-MW CRM under most conditions but also use a larger CRM during periods of higher load, such as the Gowanus Substation in Brooklyn.

David Edelson, manager for operations performance and analysis, said the ISO would base its determination to use a sub-20-MW CRM mainly on the desire to keep CRM values at a level representing no more than 10% of a facility’s rating.

NYISO’s Tariff currently requires use of a minimum value of at least 20 MW for any non-zero CRM value employed in the day-ahead and real-time markets. As the ISO continues to consider inclusion of certain 115-kV facilities with lower thermal ratings (relative to 230-kV and higher facilities) into its dispatch, a 20-MW CRM can often represent a significant percentage of the facility limits.

For instance, many 115-kV facilities have post-contingency limits of 150 MW or lower. A 20-MW CRM represents 13% of the rating for a 150-MW facility.

In megawatt terms, a facility with a 150-MW rating and a 20-MW CRM would be secured in the dispatch using a 130-MW limit. By comparison, a typical 345-kV circuit has a 1,550-MW post-contingency rating with a 20-MW CRM representing only about 1% of the rating.

The ISO will seek Management Committee approval at its next meeting Aug. 29, and by the ISO’s Board of Directors during a special call on the issue in early September, with a FERC filing targeted for the middle of next month.

T&D Manual Revisions

The BIC voted to approve incorporating into the ISO’s Transmission and Dispatching Operations Manual (T&D Manual) an existing technical bulletin on the procedures transmission owners must use to secure their facilities into the Business Management System (BMS) day-ahead and real-time market models.

The information would be located in a new section in the manual and would not substantively differ from the existing guidelines, said Ethan D. Avallone, senior market design specialist.

The committee also approved proposed revisions to Section 3.1.3 of the T&D Manual, specifying that the New York Control Area reserve is monitored through the use of the Reserve Monitor Program; and to Section 4.2.11, regarding procedures when a transmission owner or the Northeast Power Coordinating Council observes or reports significant geomagnetically induced currents.

Distillate Prices Up 40% Y-o-Y

NYISO locational based marginal prices (LBMP) averaged $39.58/MWh in July, up nearly 18% from June and 10% higher than the same month a year ago, Bouchez told the BIC.

Year-to-date monthly energy prices averaged $46.64/MWh in July, a 28% increase a year ago. July’s average sendout was 529 GWh/day, higher than 445 GWh/day in May and 454 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.87/MMBtu, up about 17% from both June and a year earlier. Distillate prices dropped slightly compared to the previous month but were up 40% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.05/MMBtu and $14.81/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour dropped from June, but the ISO’s 44-cent/MWh local reliability share in June came in higher than the previous month’s 18 cents/MWh, while the statewide share dropped from 12cents /MWh to -57 cents/MWh. Thunderstorm alerts (TSAs) accounted for 21 cents/MWh for the month, down from 39 cents/MWh in June. TSAs occur when actual or anticipated severe weather conditions lead the ISO to reduce transmission transfer limits on the UPNY-SENY interface, which often leads to severe congestion.

— Michael Kuser

August 14, 2018

PJM Seeks to Delay 2019 Capacity Auction to August

PJM last week asked FERC to delay next year’s Base Residual Auction to Aug. 14 to provide the RTO more time to respond to the commission’s June 29 order requiring changes to capacity market rules.

The commission ordered PJM to expand its minimum offer price rule (MOPR), which now covers only new gas-fired units, to all new and existing capacity receiving out-of-market payments. The commission’s ruling, which rejected PJM’s April “jump ball” capacity filing (ER18-1314) and partially granted a 2016 complaint led by Calpine (EL16-49), initiated a Section 206 proceeding in a new docket (EL18-178). (See FERC Orders PJM Capacity Market Revamp.)

PJM FERC BRA Base Residual Auction Capacity Market — | *123RF*

PJM requested the delay in an Aug. 9 filing supporting the Organization of PJM States Inc.’s (OPSI) motion to extend to Oct. 11 the deadline for filing testimony, evidence or arguments in response to the FERC order (EL16-49, et al.).

The RTO asked the commission to issue an initial order directing a compliance filing by Jan. 15 and a final order on compliance by March 15. “This proposed schedule will provide PJM and capacity market sellers with approximately five months to undertake the Tariff imposed obligations in advance of the delayed BRA,” PJM said.

PJM, OPSI and more than a dozen other parties also have requested rehearing of the commission’s ruling, including industrial customers, the American Public Power Association, Exelon, Old Dominion Electric Cooperative, Dominion Energy, FirstEnergy Services, and regulators from Illinois, New Jersey and Maryland.

— Rich Heidorn Jr.

August 13, 2018

PJM Reeling from Major FTR Default

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM staff are still working on how to respond to GreenHat Energy’s default in the financial transmission rights market, CFO Suzanne Daugherty told stakeholders at last week’s Market Implementation Committee meeting.

Daugherty announced at the June meeting of the Markets and Reliability Committee that GreenHat was likely to default on payments for a sizable FTR portfolio that was proving unprofitable. After the company defaulted, PJM staff realized that their current rules for attempting to mitigate the financial burden to members might instead exacerbate the situation and requested a waiver from FERC to find a more effective solution (ER18-2068).

PJM GreenHat Energy FTR Financial transmission rights — PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | *PJM*

The Tariff requires PJM to liquidate the FTRs of a defaulted member by offering for sale “all” current planning period FTR positions in the next monthly balance of planning period FTR auction “at an offer price designed to maximize the likelihood of liquidation of those positions.”

PJM said a waiver is required “given the market impact by the liquidation of GreenHat’s large FTR portfolio and observed low levels of market liquidity more than one month forward (i.e., non-prompt months).” Staff found that the bids offered to take the portfolio’s positions would have been approximately four times the pre-default auction clearing prices on the affected paths. Instead of being forced to liquidate the entire portfolio at once and potentially suppress the holdings’ return in an illiquid market, PJM asked FERC on July 26 to allow it to not liquidate each FTR position until the month it becomes due in the market. FERC has not yet responded. (See “ Default Details,” PJM MRC/MC Briefs: July 26, 2018.)

At the same time, PJM also requested a waiver of its requirement to return collateral posted by Orange Avenue, another FTR market participant that is affiliated with GreenHat (ER18-1972). Orange has challenged that request, but PJM argued that it may become necessary to sue Andrew Kittell, who oversees both firms, and that Orange’s collateral would be included among Kittell’s assets.

When GreenHat acquired most of its positions starting in 2015 long-term FTR auctions, both historical congestion and the FTR auction clearing prices indicated that the portfolio would be profitable, so it had a low credit requirement. However, by April 2017, PJM staff realized the portfolio, consisting primarily of prevailing-flow FTRs, were on paths where transmission upgrades were expected to reduce future congestion.

According to PJM, GreenHat’s portfolio was estimated at $57 million based on the auction clearing prices when the positions were taken. In the 2015-16 planning year, the same portfolio would have netted $548 million. It dropped slightly in the next planning year to $481 million. However, the following year the value dropped precipitously to $126 million and continued falling in subsequent auctions. By June 2018’s auction, the portfolio would have lost $110 million.

After realizing GreenHat’s exposure, staff approached Kittell, who offered to mitigate some of the potential risk by signing over what he told PJM were the rights to receive $62 million in proceeds from several bilateral FTR contracts. PJM accepted the agreement in June 2017 and opened a bank account for the expected proceeds, but the other company in the contract, whose name was redacted from the public filings in the docket, says it paid what it owed to GreenHat well before Kittell signed the agreement with PJM. The RTO wants FERC to allow it to keep the collateral from Orange while it investigates “whether Mr. Kittell and GreenHat fraudulently induced PJM to enter into the pledge agreement.” FERC hasn’t responded to that request yet either. Kittell did not respond to a request for comment.

His attorney, David Gerger, also declined to comment but pointed to Orange’s July 27 protest, in which it told PJM it “was not making any representations or warranties about the value of the additional collateral … and that PJM must make its own valuation.”

Orange said “PJM was uniquely poised to [establish the value of the collateral] because the [$62 million] number came from applying the PJM Tariff to amounts entered into PJM’s FTRCenter System.”

In the wake of the GreenHat default, PJM received stakeholder endorsement to enhance its credit policy for FTR traders. The new rules, to be implemented on Sept. 3, will institute a 10-cent/MWh minimum monthly credit requirement for FTR bids submitted in auctions and cleared positions held in FTR portfolios. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)

However, Daugherty confirmed at the MIC meeting that GreenHat remained compliant with the credit requirements existing at the time until it failed to post a collateral call in April. Stakeholders grilled her on why PJM hadn’t previously attempted any regulatory action or policy changes if it knew about the concern nearly a year and a half ago.

“There was nothing specific in the credit policy that would have allowed PJM to make a collateral call” sooner, she said, noting that the agreement with Kittell was signed in June 2017.

Additionally, staff said that FERC lacked a quorum of commissioners at the time and that stakeholders had not yet agreed on revisions on how to analyze predicted congestion. Daugherty said staff made a “good faith effort” to bring GreenHat and Kittell to heel.

Several stakeholders pushed PJM to provide even a rough estimate of the expected losses. One, Vitol’s Joe Wadsworth, said he used recent market results to determine that it could be upward of $145 million.

“It is getting worse,” he said.

If accurate, the result would be almost triple the $52 million credit default by Tower Research Capital’s Power Edge hedge fund in 2007, which also triggered credit policy revisions. (See PJM Credit Adder Fails upon Heightened Review.)

Daugherty resisted the requests, saying that it would be impossible to accurately predict.

“We will not know the dollars until they play out or they are liquidated because we may have to pay to liquidate them,” Daugherty said.

“There’s urgency here. We can’t just let this ride on the market,” Wadsworth said. He said engaging with GreenHat once the risk was identified was “clearly the right thing to do,” but he asked why the company was allowed to continue participating in the auctions.

“These numbers are kind of scary. We’re trying to find out … how big this is going to be,” Old Dominion Electric Cooperative’s Adrien Ford said. “I’d appreciate some sort of take on it so I can go back to the home office and say ‘roughly we think it’s about this size.’”

“I don’t think you should expect that PJM’s going to project a number,” Daugherty said.

Stakeholders also debated the best strategy for how to liquidate the portfolio if FERC approves PJM’s waiver request. Some, including Wadsworth, called for immediate action, as auction results have shown a continuing downward trend. Others, including Direct Energy’s Marji Philips, argued it might be better to wait to see if something materializes that’s better than the current guaranteed loss.

“Do you liquidate today and have a fixed number, or do you want to not liquidate today, and the number might come in lower,” she said.

PJM is working with its members to agree upon a strategy at the August MRC meeting and targeting a final approval vote at the September MRC meeting.

According to PJM’s rules, all members will be on the hook for at least some of the losses. Of the final amount, 10% will be allocated on a per capita basis to the 992 members, including affiliates, as of June 21. The per capita assessments are capped at $10,000 per year, though Daugherty confirmed the rule’s intention was for the cap to count per default event and that the language may need to be clarified.

The remaining losses will be allocated according to each member’s gross PJM activity over the three months preceding the default. The RTO said the total activity for the period was $24 billion.

So far, PJM has sent, or plans to send, bills for $42.5 million, about 18% of GreenHat’s portfolio.

Daugherty confirmed “there is no other situation like [GreenHat’s exposure] related to credit requirements.” She said PJM is working with external consultants from trading exchanges, clearing houses, other consultants and its Independent Market Monitor “to review factors that can affect future congestion levels and [perform a] gap analysis against how FTR credit requirements would address those factors.” The talks are excluding members to avoid potential conflicts of interest.

DC Energy’s Bruce Bleiweis said the incident was not a failure of the FTR market or structure but “clearly a significant failure of the credit policy.”

However, he expressed concern that PJM’s presentation indicated staff might agree with the IMM’s position that the benefits of long-term FTRs are outweighed by their risks.

In June, stakeholders endorsed changes to the long-term FTR auction construct to prohibit participants from obtaining the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. The Monitor has said the revisions are improvements but don’t go far enough. (See “Long-term FTRs Undercut Annual FTRs,” PJM Market Implementation Committee Briefs: June 6, 2018.)

Kittell worked as an energy trader for JPMorgan Venture Energy Corp. when FERC fined the company $285 million and ordered it to disgorge $125 million for “manipulative bidding strategies” from September 2010 through November 2012. Kittell and two other employees named by the commission were not charged.

August 13, 2018

PJM Market Implementation Committee Briefs: Aug. 8, 2018

VALLEY FORGE, Pa. — Stakeholders at last week’s Market Implementation Committee meeting overwhelmingly endorsed PJM’s proposal for revising how it calculates balancing ratios while also rejecting several competing proposals.

PJM’s proposal received 0.88 in favor, surpassing a 0.5 threshold in the sector-weighted vote. Stakeholders also preferred it to the status quo, voting 0.69 in favor of the new proposal.

pjm balancing ratio — The PJM Market Implementation Committee met on August 8, 2018 | © *RTO Insider*

The proposal, known as Package A, would calculate the balancing ratio used in the default market seller offer cap (MSOC) and nonperformance charge rate (PPR) formulas by averaging the balancing ratios from the three delivery years that immediately preceded the capacity auction. For years that don’t have at least 30 hours of performance assessment intervals (PAIs), the actual number of PAIs would be supplemented with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI. PAIs are five minutes apiece.

Some stakeholders like the proposal because it is straightforward and maintains the same number of PAIs used in either the MSOC or the PPR. However, others argue the calculation overestimates the likely number of PAIs, which leads to an artificially high MSOC. Such conditions led Independent Market Monitor Joe Bowring to conclude last week that the clearing prices in May’s Base Residual Auction were higher than they should have been. (See related story, IMM: PJM 2018 Capacity Auction was ‘Not Competitive’.)

“This all turns on your belief that 30 hours is a reasonable number [for PAIs]. I don’t believe that. … I would say it’s pretty clearly not a reasonable number,” Bowring said.

“We don’t have any technology that can solve that problem [of accurately predicting the number of PAIs], so we’re left with what is a reasonable number to put in there,” PJM’s Adam Keech said.

“The 30 hours is definitely an issue for the consumer advocate offices I’ve talked to,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States.

Stakeholders have been debating the issue for months. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: July 11, 2018.)

PJM’s Pat Bruno announced that staff planned to abandon a second proposal, Package B, unless a stakeholder offered to sponsor it. Dave Mabry, representing the PJM Industrial Customer Coalition, agreed to do so. The proposal would calculate the balancing ratio in the same manner as Package A but would also estimate an expected number of PAIs for the delivery year using data from the prior three years. That estimate would be inserted into the MSOC and PPR formulas.

Each formula would include a floor of PAIs, but they would differ: five hours for the MSOC and 15 hours for the PPR. That difference concerns stakeholders, who argue the numbers need to be the same for the formulas to maintain their mathematical relationship.

“We don’t share PJM’s thoughts that they have some problems at FERC with the” formulas, Mabry said in sponsoring the proposal. American Municipal Power’s Steve Lieberman seconded it, and it received 0.09 in favor.

Additional proposals from Exelon and Calpine differed with PJM on the PAI calculations for the formulas. Calpine’s would floor both at 10 hours and calculate a number based on the past 10 years of data. Exelon’s would use a probabilistic model to look forward. Both would keep constant the number of PAIs used in the two formulas.

“We think it’s illogical to have different assumptions for those calculations,” Exelon’s Jason Barker said.

“The heart of our proposal was to get the expected amount of performance assessment [intervals] to match. It didn’t make sense to us [to have them not match], and I don’t think it would make sense to FERC,” Calpine’s David “Scarp” Scarpignato said.

Scarp withdrew his proposal in favor of PJM’s Package A. Exelon’s received 0.36 in favor.

“I am more in favor of fixing the immediate problem of the” balancing ratio, Scarp said.

“You can’t fix [the balancing ratio] without addressing the problem on a consistent basis,” Bowring said.

A proposal from the Monitor, which mirrored Package B except that it had floors of just five hours for either formula, received 0.02 in favor.

Quadrennial Review of VRR Curve

Stakeholders endorsed a proposal from Scarp on revisions for PJM’s quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct. Several other proposals, including one endorsed by PJM, were rejected by stakeholders.

Despite the result, all four proposals will be up for consideration at the August meeting of the Markets and Reliability Committee meeting. Stakeholders had made that request long before the vote in an attempt to overcome the influence of companies with multiple affiliates, which can each vote separately at lower committees.

Scarp’s proposal largely mirrored PJM’s, except that it maintains the current combustion turbine configuration as the curve’s reference technology; the RTO had planned to change it to a newer model. It also maintained the curve’s current calculation, while PJM and the other two proposals would have shifted it 1% left. The shift was part of revisions recommended by the Brattle Group, who were hired by PJM to analyze the curve. (See “VRR Curve Update,” PJM Market Implementation Committee Briefs: July 11, 2018.)

PJM’s proposal received 0.39 in favor.

A proposal from the Monitor agreed with PJM on updating the reference technology, but it differed on several other factors. That proposal received 0.1 in favor.

A proposal from the D.C. Office of the People’s Counsel sought to use a combined cycle unit for the reference technology and otherwise largely mirrored the Monitor’s proposal. It received 0.1 in favor, as well.

Fuel Cost Policy

John Rohrbach of ACES, representing the Southern Maryland Electric Cooperative, presented a proposed problem statement and issue charge to review the first year’s performance of the new fuel-cost policy rules and determine if any improvements can be made.

The proposal was also endorsed by Old Dominion Electric Cooperative and Panda Power Funds. The group hopes to have any potential revisions to the current policy identified by April 19 to target a June filing at FERC. Any potential alternatives to the current policy that are identified would need to be ready for consideration by the fall to target a FERC filing in the fourth quarter.

Transmission Constraint Penalty Factor

PJM and its Monitor have developed a joint proposal to revise how the transmission constraint penalty factor is utilized. PJM’s Angelo Marcino explained that the current process uses “constraint relaxation” so that the penalty factor doesn’t set shadow prices. This “masks” transmission shortages in the market. The proposal would remove constraint relaxation and allow the $2,000/MWh penalty factor to set prices as appropriate.

The proposal received so little reaction that PJM suggested canceling the next meeting of the group overseeing the issue, which stakeholders approved.

After the meeting, PJM posted online an analysis from the Monitor on the potential impact of the proposed revisions. The Monitor found that in 2017 the revisions would have increased the balancing market in the aggregate by $10 million.

— Rory D. Sweeney

August 13, 2018

PUCT Continues Review of Potential Market Improvements

Texas regulators last week issued requests for comments on real-time co-optimization (RTC) and incorporating marginal losses into dispatch decisions, proposals that have varying levels of stakeholder support.

On June 29, ERCOT’s Independent Market Monitor filed a report at the Public Utility Commission indicating RTC could have saved as much as $257 million in reduced congestion costs and $155 million in reduced ancillary service costs during the 2017 test year.

IMM Director Beth Garza told ERCOT’s Board of Directors on Aug. 7 that a significant cost of providing operating reserves is the lost opportunity cost of providing energy.

“The cost of containing those reserves, setting them aside, is the lost opportunity of selling that energy,” Garza said. “When initially selected in the day-ahead market, the costs of providing both energy and reserves are minimized. That is, co-optimized.”

During their Aug. 9 open meeting, the commissioners approved a set of questions as part of its review of RTC (Project No. 48540). They also approved a second group of questions related to incorporating marginal losses’ costs into dispatch (Project No. 48539).

erccot puct real time co optimization rtc — Commissioners (left to right) Shelly Botkin, DeAnn Walker and Arthur D’Andrea discuss market improvements during the PUCT open meeting. | *Admin Monitor*

A second report, filed by ERCOT, found the grid operator would benefit from RTC through its more efficient procurement of ancillary services and congestion management, and reduced reliability unit commitments.

The IMM and ERCOT will host a technical workshop on the two filed reports Sept. 6.

The PUC held a pair of workshops last year following a report coauthored by Harvard University’s William Hogan and FTI Consulting’s Susan Pope that recommended rule changes to address intermittent renewables and add incentives for generators. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)

The PUC also published a list of questions on the review and approval of substations. It has scheduled an Oct. 4 workshop on the subject (Project No. 48251).

Commissioners Approve Tweaks to Retail Website

The commissioners approved staff’s suggested recommended changes to the PUC’s Power to Choose website, where consumers in Texas’ competitive areas can shop for electricity providers. The website has drawn the commission’s attention following consumer complaints of pricing gimmicks that result in unexpectedly high costs.

“We’ve been here before,” Commissioner Arthur D’Andrea said. “The commission thought we fixed this website, and now here we are again. I don’t want to be back here in two years doing the same thing.”

“Unfortunately, I think we may be because REPs [retail electric providers] adjust,” Chair DeAnn Walker said. She had reason to be pessimistic, saying she had recently met with a retail representative.

“People are already trying to figure out how to get around these” rule changes, Walker said.

Staff’s proposal adds a filter to weed out plans that offer low average prices at the 1,000-kWh usage level, when they cost significantly more for customers who average more than 1,000 kWh/month. The recommendations will also limit the number of offers a REP can list on the website to prevent them from “flooding” a page.

“Doing so will encourage REPs to use [their] available postings wisely, rather than repeating very similar offers to strategically dominate search results,” staff said.

PUC to Intervene in FERC Entergy Dockets

Following an executive session, the commissioners agreed to intervene in five dockets at FERC involving Entergy Services and cost-reimbursement agreements with its five operating companies (ER18-2079, et al.).

Entergy proposed last year to recover $5.9 million from Texas retail rates for Entergy Texas’ portion of construction costs for a pair of transmission control centers it built in Arkansas and Mississippi.

FERC set the agreements for settlement proceedings in February, but the company said the negotiations between Entergy Service its operating companies, commission staff and other parties were not “fruitful” and further discussions “would not resolve the issues in these proceedings.” The company filed cancellation notices for the reimbursement agreements with the commission in July. Entergy said no payments were made and no benefits received under the agreements.

— Tom Kleckner