Page 1112 – RTO Insider

October 1, 2018

PJM MRC/MC Briefs: Sept. 27, 2018

PJM, Monitor Come to Agreement on Opportunity Cost Calculator

VALLEY FORGE, Pa. — Stu Bresler, PJM senior vice president of operations and markets, announced at the Members Committee that he and Independent Market Monitor Joe Bowring had signed an agreement regarding the use of the Monitor’s opportunity cost calculator.

pjm mrc mc vrr — Adam Keech, PJM executive director of market operations, addresses stakeholders. | © *RTO Insider*

Under the agreement, Monitoring Analytics will continue to use its calculator to calculate the opportunity costs for market participants and will explain its inputs and logic to PJM to demonstrate that the unit-specific opportunity costs are compliant with the OA.

In return, PJM acknowledged that the calculator is the Monitor’s intellectual property, that the agreement is not a license for PJM to use the calculator and that the RTO will not attempt to reverse engineer it.

In response to stakeholder questions, Bresler said he was not sure how long it would take for PJM to get the Monitor’s data, but he estimated it would take two weeks.

The agreement is the culmination of a yearlong dispute between PJM and the Monitor over opportunity cost calculations, which came to a head in August when the Markets and Reliability Committee approved Tariff revisions, proposed by Bob O’Connell of Panda Power Funds, allowing participants to use the Monitor’s calculator. The RTO said it would be willing to allow its use but needed to understand the details of how it worked, something at which the Monitor balked. (See PJM Monitor Holding Firm on Opportunity Cost Calculator.)

The Monitor has repeatedly criticized PJM’s calculator as inaccurate and the RTO’s process for verifying inputs as flawed.

Calpine’s David “Scarp” Scarpignato asked what would happen to a generator if the calculators gave different results, and the generator used the one that gave it a higher price. Bowring answered: “It is still our responsibility to calculate opportunity costs, and if you propose to use an opportunity cost that is too high, we will let you know and refer you to FERC as necessary.”

O’Connell, who had originally been scheduled to speak before Bresler on the topic and had deferred, moved to postpone the vote on his proposed revisions to the next meeting to give PJM and the Monitor time to put the new process in effect. The motion was approved by acclimation with no objections or abstentions.

Quadrennial Review

The MRC voted on four packages of revisions as part of PJM’s quadrennial review of the variable resource requirement (VRR) curve, but none of the proposals received majority support.

The committee’s sector-weighted votes were advisory to the Board of Managers, which has ultimate approval of what is filed with FERC.

The PJM MRC and MC meetings were held Thursday, Sept. 27. | © *RTO Insider*

The MRC voted on proposals by PJM, the Monitor, Calpine and the D.C. Office of the People’s Counsel. Several stakeholders noted that their support hinged on the reference unit used in the calculations. PJM and the Monitor have proposed changing it from General Electric’s 7FA combustion turbine to the new 7HA, while the OPC proposed using an F- and H-class combined cycle. Calpine’s proposal maintains use of the 7FA.

Exelon’s Jason Barker said his company was against the HA being used, noting that GE has had trouble with its newest turbine class.

Reports of problems with the H-class began coming in last year, and Exelon recently had to shut down two power plants in Texas after GE identified a flaw in the design.

PJM’s proposal came in first with 2.32 in favor, followed by Calpine’s with 2.14, the Monitor’s with 1.96 and the OPC’s with 1.42.

At the MC, Carl Johnson, representing the PJM Public Power Coalition, moved to adopt the MRC’s votes for the sake of efficiency. This was quickly approved by acclimation, with only one objection.

VOM Proposal Rejected by MC

A revised proposal by PJM to include certain variable operations and maintenance (VOM) costs in cost-based energy offers failed to win supermajority endorsement from the MC, garnering only 2.92 of a sector-weighted vote.

At last week’s MRC, PJM’s Melissa Pilong presented several revisions to an RTO proposal that had been rejected, along with four others, by the MRC in July. (See PJM Ponders Advancing VOM Effort over Objections.) The changes included removing the ability for resources that did not clear the capacity auction to recover their fixed costs in their energy offers.

Originally, the proposal included only changes in Manual 15, which would only require MC endorsement and approval by the Board of Managers. As part of the new proposal, PJM would also add clarifying language to the Tariff and OA, meaning it would have to be approved by FERC.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said that while he appreciated the additional FERC provision, he was frustrated that the VOM proposal kept coming up with little change. In a sector-weighted vote motioned for by Poulos, the MRC advanced PJM’s new proposal, with 3.4 in favor.

Later at the MC, Poulos motioned to delay a vote on the proposal, which Chairman Borgatti set for a sector-weighted vote. Before members voted on whether to vote, however, Bresler noted that because of the Oct. 12 deadline for filing changes stemming from the quadrennial review, PJM had set both matters for that day. CEO Andy Ott also urged members to vote, saying “it would be helpful to the board if you resolved this today.”

PJM’s proposal would allow major maintenance costs to be included in the VOM costs in energy offers. That would mean that they would be not included in the cost of new entry, which is set as part of the quadrennial review. Without the vote, Deputy General Counsel Chris O’Hara said that it would be difficult for PJM to justify the quadrennial review. “We would have to tell FERC we lack sufficient information to ensure the quadrennial review is just and reasonable,” he said.

With only a simple majority needed, members resolved to vote that day, with 3.1 in favor, before the actual proposal failed in a subsequent vote. Bresler later told RTO Insider that PJM will discuss with the board whether it should file the proposal under Federal Power Act Section 206, which is done when a proposal lacks member support. The RTO would have to show that its existing OA language regarding VOM costs is unjust and unreasonable, rather than just show that its proposal is just and reasonable.

Liaison Committee Meeting to be Closed to Nonmembers

Near the end of the MC meeting, a motion by Poulos for a temporary waiver to the Liaison Committee’s charter to allow some nonmembers to attend its upcoming Oct. 3 meeting as listening-only participants failed in a sector-weighted vote, with only 2.43 in favor.

According to PJM’s Dave Anders, it has been accepted practice to allow nonmembers — such as state regulators and their staff, FERC staff, PJM management and staff, and the Monitor — to attend since an LC meeting in D.C. one year coincided with a meeting of the National Association of Utility Regulatory Commissioners several years ago. State regulators and FERC staff had asked to be allowed to attend the LC, and “how could we say ‘no’ to that?” Anders said.

In an email to RTO Insider after the meeting, Poulos said his motion was prompted by a member’s request to enforce the charter during a “prep call” for the upcoming meeting. Poulos declined to name the individual who made the request.

“It was not the first time I’ve heard this request, but this time the request was gathering support from the others on the call,” he said. “I thought the decision was important enough to be heard by the entire stakeholder body.”

At Thursday’s meeting, Barker said he was disappointed that PJM had been lax in its enforcement of the charter. “This is our private discussion with the board,” he said. “This is our one opportunity.”

Alex Stern of Public Service Electric and Gas, who participated in the formation of the Liaison Committee and its charter several years ago, echoed the statements of other stakeholders. He said the charter should be respected and that it had been thoroughly developed to allow members direct and unfettered access to the board.

Before voting on Poulos’ motion, O’Connell moved to keep individual members’ votes private, only allowing the board to view them. This passed with 3.42 in favor.

Ott said PJM would notify members of the charter’s stricter enforcement going forward.

“Member actions at PJM’s September Members Committee reduced transparency in PJM governance,” said Illinois Commerce Commissioner John Rosales, president of the Organization of PJM States Inc., in a statement provided to RTO Insider. “This is an issue which needs examination going forward.”

PJM Debuts Web-based Governing Documents

PJM has converted its OA, Tariff and Reliability Assurance Agreement into user-friendly webpages.

On the left side of each page is a sidebar with links to each section in a document, and each page contains hyperlinks to referenced sections and attachments. Every term on a page has a clickable pop-up containing its definition.

There’s even a search bar.

The web versions are technically unofficial versions, as PJM changed the formatting and removed redundancies from the official, FERC-approved PDFs to make them more readable.

PJM staff presenting the new pages at the MRC were enthusiastic, and stakeholders expressed gratitude.

The Tariff PDF is a 3,554-page, 58-MB file. Its Table of Contents alone runs for 29 pages.

The PDFs for the OA and RAA are a bit more manageable at 630 and 251 pages, respectively.

— Michael Brooks

October 1, 2018

NYISO Management Committee Briefs: Sept. 26, 2018

RENSSELAER, N.Y. — NYISO experienced six days with peak loads of more than 31,000 MW this summer, compared with last summer’s actual peak of 29,677 MW, the ISO’s Management Committee learned last week.

New York ambient temperatures were above the 20-year average in May, July and August, and near average in June. Albany registered 19 days over 90 degrees Fahrenheit this summer, which has occurred only 10 times since 1874, Wes Yeomans, vice president of operations, said as he delivered the Summer 2018 Hot Weather Operations report.

“Fuel supplies for electric generation worked very well this summer,” he said. (See “Adequate Summer Capacity Forecast,” NYISO Management Committee Briefs: June 12, 2018.)

nyiso peak loads tcc — Total load (GWh) was above 50/50 projections this summer, while peak load was below the 50/50 projection for the 5th consecutive summer. | *NYISO*

Total New York Control Area load was above 50/50 projections this summer, while peak load was below the 50/50 projection for the fifth consecutive summer. The summer 2018 50/50 forecast was 32,904 MW, while actual peak load hit 31,861 MW on Aug. 29. The all-time peak of 33,956 MW occurred on July 19, 2013.

NYISO on Aug. 29 activated 481 MW of demand response for Zone J to support New York City transmission security from noon to 6 p.m., while utilities in the state also activated their DR programs. The ISO will report scarcity pricing outcomes at the Market Issues Working Group meeting in October.

Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said the ISO called DR in Zone J for the two largest contingencies, not just the single largest.

“So, these DR resources are needed to meet the reserve requirements for Zone J — which is a real reliability requirement, but it’s not reflected in the market,” LeeVanSchaick said. “It’s really a failure of the market to procure reserves for this requirement, not an operational issue of activating excessive demand response.”

Yeomans replied that the ISO is engaged in a project to review reliability criteria.

Significant summer transmission outages were the 345-kV Hudson-Farragut B and C Lines, the 230-kV St Lawrence-Moses L33P and the 345-kV Dunwoodie-Mott Haven 71, which was forced out on July 1 in New York City near the beginning of a six-day heatwave and remains out of service.

Many more outages occurred, but the ISO only reports those that were out for a long time and impacted power availability during a heatwave, Yeomans said.

NYISO’s behind-the-meter solar installations have increased six-fold since 2013, with total registered nameplate capacity around 1,200 MW, Yeomans said. “But you’d need all of the panels aimed south and working in full sun to achieve that.”

Yeomans said pop-up showers on a hot day can reduce load by around 500 MW, prompting Mark Younger of Hudson Energy Economics to suggest that the weather normalization program at the ISO should try to account for this effect on net load.

Weather normalization refers to smoothing chaotic weather data from several years in order to provide a useful model for load forecasting.

AC Transmission Project on Hold

NYISO CEO Brad Jones informed the MC about why the ISO’s Board of Directors had not yet voted on the AC Public Policy Transmission Project approved by the committee in June.

“The board has looked at this and asked for additional data,” Jones said. “We hope to get as much as we can to them for the October board meeting but are not sure we’ll have all of it.” (See NYISO MC Supports AC Transmission Projects.)

The MC in June approved joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects that could cost $900 million to $1.1 billion.

NYISO Proposes 8.5% Budget Increase

The ISO’s draft 2019 budget totals $168.2 million, including an 8.03% increase in revenue requirement from this year’s budget and a 0.45% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 8.51%.

Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the review of a budget allocated across a forecast of 157.1 million MWh, for a Rate Schedule 1 charge/MWh of $1.071, compared to $155.7 million allocated across 157.81 million MWh for a Rate Schedule 1 charge/MWh of 98.7 cents this year.

The ISO has held the budget to an approximately 1% average increase in revenue requirement for the past four years, “but this trend is not sustainable for the 2019 budget,” Ackerman said.

One big factor driving up spending is repayment of a $30 million loan to finance an Energy Management System/Business Management System upgrade project, Ackerman said. Other factors include debt service, new software needs, professional consultant fees, and salaries and benefits. The ISO plans to add 15 new positions over the coming year.

The board will review the draft budget Oct. 15, the MC will vote on a new budget Oct. 31, and the board will consider the final proposal on Nov. 13, 2018.

MC Approves 2018 Reliability Needs Assessment

The committee approved the ISO’s 2018 Reliability Needs Assessment (RNA), which identified no reliability needs on the state’s bulk power system over the coming decade. The board will consider the RNA in October.

Resource Planning Manager Laura Popa reported that the 2018 RNA is based on information from the 2018 Gold Book (the annual transmission planning and evaluation report filed with FERC), historical data and market participant data.

For transmission security, planners evaluated Year 1 (2019), Year 5 (2023) and Year 10 (2028) for summer peak baseline power flow cases, and found no reliability needs for Years 1 and 5. However, for Year 10 they identified one preliminary reliability need: a 3-MW deficiency in Eastern Long Island.

The deficiency would stem from a 1% overload on the 138-kV Brookhaven-Edwards Avenue line (Line 864), the contingency being the loss of the 138-kV Wildwood-Riverhead line (Line 890) and returning the system to normal criteria. PSEG Long Island presented an updated and firm long-range transmission plan at the June 28 Electric System Planning Working Group/Transmission Planning Advisory Subcommittee that involved scheduling terminal upgrades at the Brookhaven 138-kV substation to be in service in June 2019. With these upgrades the overload is resolved, according to NYISO.

LeeVanSchaick elaborated on MMU comments filed with the ISO that markets are generally well designed, noting an inconsistency between the assumed value of certain resources needed for reliability transmission planning purposes and how NYISO’s capacity market compensates those resources.

The MMU recommends the ISO periodically reassess the assumed relief from land-based wind generators and special case resources (SCRs) in transmission security planning assessments to ensure levels are commensurate with their expected performance and availability. It also asked the ISO consider using different assumptions for offshore wind generators than for land-based wind units, and possibly further discount the capacity ascribed to wind generators and SCRs, which represent load capable of being interrupted upon demand or a distributed generator rated 100 kW or higher.

Failure to maintain consistency between planning reliability criteria and capacity market requirements may increase the need for regulated transmission solutions and reliability-must-run contracts to satisfy reliability needs, which becomes particularly important as more wind generation is built in import-constrained areas over the coming decade, the MMU said.

“It’s important to think about this as the resource mix is turning over,” LeeVanSchaick said.

ISO Customers Mostly Satisfied with Query Response

Customers and market participants continue to be pleased with how NYISO interacts with them and are nearly 100% satisfied with how the ISO answers their questions, according to a biannual customer satisfaction survey conducted by the Siena College Research Institute (SRI).

SRI Director Don Levy told the MC his group recorded a 98% “customer inquiry satisfaction” score on the survey, which combined a market participant satisfaction score (89.9%) with assessment of performance (76.8%) for an overall approval rating of 84.7%.

Levy said the surveys identified several areas for improvement, including tariff, legal and regulatory webpages; ISO manuals, technical bulletins and user’s guides; market mitigation and analysis interactions; transparency of operations; and increasing the consideration of stakeholder input.

MC Approves Revisions to OATT Attachment L

The MC approved revisions to Attachment L of NYISO’s Open Access Transmission Tariff updating terms regarding transmission congestion contracts (TCCs).

Gregory R. Williams, manager of TCC market operations, said the updates to Section 18.1.1 (Table 1A) of Attachment L followed an annual review. Among the changes were revising contract expiration dates from Dec. 31, 2017, to Dec. 31, 2027, for two specified agreements.

If authorized by the board at its meeting in October, the ISO will file the revisions with FERC.

MC Approves Change to Unsecured Credit Scoring Model

The MC approved changes to the ISO’s unsecured credit scoring model following its first review of the methodology since 2009.

John Jucha, senior credit analyst for corporate credit, said that under the new model, the 12.7% weighting for revenue/market capitalization in predicting a default will be replaced with a measure of total assets. The review found that asset size variables were not represented in the model despite their “strong predictive power.”

Rating all market participants — including corporations, financial institutions and government entities — on the same scorecard may mask differences between them, the analysis found.

If authorized by the board in October, the ISO will file the revisions to Attachment K of the Market Administration and Control Area Services Tariff with FERC.

— Michael Kuser

October 1, 2018

FERC OKs Discounted Tx for Maine Biomass Plants

FERC on Thursday approved Emera Maine’s proposal to provide discounted transmission service to two ReEnergy biomass plants in northern Maine (ER18-2123, ER18-2124).

The commission’s Sept. 27 order also found that a protest from Maine Gov. Paul LePage lay outside its jurisdiction. LePage alleged that Emera would recover the cost of the discounts from the state’s retail customers, but FERC said retail rates are regulated by the Maine Public Utilities Commission. “Our findings here are limited to whether Emera Maine’s proposed commission-jurisdictional wholesale rates are just and reasonable,” FERC said.

ReEnergy employee leads tour of Fort Fairfield biomass generator. | *Biomass Power Association*

ReEnergy owns a 39-MW biomass-fueled power plant in Ashland and a 37-MW biomass plant in Fort Fairfield. Both facilities have market-based rates and are allowed to sell their output into ISO-NE’s energy, capacity and ancillary services markets.

Under the agreements, Emera will provide non-firm transmission service from the two ReEnergy facilities to ISO-NE for $0/MW-month for Oct. 1, 2018, through Dec. 31, 2019, and $1,132/MW-month for Jan. 1, 2020, through Dec. 31, 2020.

ReEnergy said the discounts were needed to remain in business because of the pancaked transmission charges they pay to move energy to the ISO-NE market.

Emera would provide service to the plants through the Maine Public District transmission system, which is not directly interconnected with any portion of the U.S. transmission grid. Entities interconnected with it can only access the New England grid over transmission facilities in New Brunswick, Canada, which NB Power owns and operates.

Emera said it agreed to the discounts because ReEnergy provides jobs in northern Maine.

— Michael Kuser

October 1, 2018November 13, 2023

PUCT Urges 2nd Look at Freeport Project Costs

By Tom Kleckner

Texas regulators last week signaled their discomfort with the rising costs of CenterPoint Energy’s planned 345-kV transmission line to serve load in the industrial Freeport area south of Houston.

The Public Utility Commission has asked ERCOT to provide further input on CenterPoint’s project, which is part of the “Freeport Master Plan Project” addressing load growth around the Gulf Coast seaport.

“I’m not going to trust these huge shifts in costs without having ERCOT weigh in,” Chair DeAnn Walker said during the commission’s Sept. 27 open meeting.

CenterPoint’s application for a certificate of convenience and necessity presented 30 alternative routes, ranging in length from 54 to 84 miles, and in estimated costs from $481.7 million to $695.2 million. The costs at the lower end are almost double ERCOT’s estimate of $246.7 million when it approved the Freeport project in December. (See “Board Approves $246.7M Freeport Transmission Project,” ERCOT Board of Directors/Annual Meeting Briefs.)

“Some of these numbers are approaching those of a nuclear plant,” Commissioner Arthur D’Andrea said.

Warren Lasher, ERCOT’s senior director of system planning, didn’t argue that point. He explained that the grid operator made its recommendation based on “specific electrical reasons,” but it has taken a second look after CenterPoint notified it of the cost increase.

“From our very preliminary analysis, neither the need nor the timing for the need for the project has changed,” Lasher said. “When we looked at this project electrically, there were just not that many options to get to that part of the state and serve the increasing customer demand. I’m not sure we couldn’t have found another option, but it’s unlikely.”

ERCOT has projected a 92% increase in the Freeport area’s load to 1,979 MW by 2019, with a large chemical plant accounting for much of the growth. The region is expected to see an additional 300 MW of load by the end of 2022.

PUC staff agreed to prepare a preliminary order for the commission’s Oct. 12 open meeting. The order would incorporate ERCOT’s input on whether there are other alternatives for meeting the area’s demand.

“I am going to need that,” Walker said.

Rio Grande Electric, AEP Texas Reach Agreement

The commission canceled an Oct. 31 procedural hearing in the dispute between Rio Grande Electric Cooperative and AEP Texas over which utility will serve certain customers in a Uvalde subdivision after the companies said they had reached a settlement (Docket 47186). (See “Hearings Set for AEP Texas Legal Cases,” PUCT Reduces Rates for AEP, Others on Income Tax Cut.)

Rio Grande and AEP Texas told the commission they will resolve the dispute through requests for service area changes. They said they are finalizing maps and preparing the necessary documents to reflect “definitive boundary changes.”

The PUC gave the parties until Oct. 22 to file an agreement or a status update.

Commission Accepts IOU Earnings Review; OKs Interventions

The commissioners accepted staff’s review of the state’s 14 investor-owned utilities’ earnings reports. Staff said none of the IOUs “warrant[ed] a more detailed analysis” (Project 48158).

Following a closed session, the PUC agreed to allow Walker, who represents the PUC on SPP’s Regional State Committee, to work with outside counsel on FERC dockets involving SPP. The PUC also said it would intervene in two FERC dockets:

- The Louisiana Public Service Commission’s complaint against Entergy Services and the corporation’s five operating companies alleging they failed to include 100% of the costs of Entergy’s transmission control centers in MISO’s Attachment O formula rate (EL18-201). The PSC said Entergy’s failure to bill MISO for all of the costs would force “native load customers to cross-subsidize the use of the Entergy transmission system by third party wholesale customers.”
- East Texas Electric Cooperative’s complaint against American Electric Power subsidiaries Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission and AEP Southwestern Transmission. The co-op alleges the 10.7% base return on common equity in the AEP West companies’ formula transmission rates is unjust and should be reduced (EL18-199).

October 1, 2018

FERC Approves New Hampshire Capacity Settlement

By Michael Kuser

A 4.5-MW biomass power generator in Claremont, N.H., will refund ISO-NE capacity payments it wrongly accepted for nine months following the plant’s closure in September 2013 and pay a $250,000 civil penalty under a settlement approved by FERC on Friday (IN18-10).

The commission accepted a stipulation and consent agreement between its Office of Enforcement and Wheelabrator Technologies under which the company will disgorge $107,231.34 in capacity payments and interest.

Claremont energy-from-waste facility | *Stuart B. Millner & Associates (SBMA)*

Enforcement began its investigation in March 2015 following a referral from the RTO. “Claremont subsequently responded to data requests and requests for investigative testimony, and demonstrated cooperation during the investigation,” the commission said.

Following the Claremont facility’s closure, ISO-NE continued to issue monthly capacity payments for a year in exchange for Claremont’s continuing obligation to supply capacity while the facility was inoperable. The RTO later clawed back the July to October 2014 payments through its Tariff-based reconciliation process.

Public Service New Hampshire (now part of Eversource Energy) previously purchased Claremont’s generation and operated as its lead market participant and asset owner, managing Claremont’s participation in the Forward Capacity Auctions (FCAs) and receiving the payments issued by ISO-NE. On Dec. 1, 2013, PSNH transferred Claremont’s market participant status to Wheelabrator North Andover, which operates a generation facility in North Andover, Mass., and, as of that date, began receiving capacity payments on Claremont’s behalf.

At the time, Wheelabrator management did not fully understand its obligation to shed its capacity supply obligations for FCA 4 (June 2013 to May 2014) and FCA 5 (June 2014 to May 2015) and continued to collect capacity payments for the closed Claremont facility, the commission said.

“Accordingly, Claremont did not successfully shed those obligations. Claremont did shed its obligation for FCA 9 through a non-price retirement request. Claremont’s obligations in FCA 8 were eventually unwound by ISO-NE after it discovered Claremont’s permanent closure,” the commission said.

Wheelabrator’s compliance measures were insufficient to identify the violation, the commission said. The company also agreed to submit annual reports for two years on the progress of its recently implemented compliance measures and any new incidents of noncompliance.

October 1, 2018

New NERC Chief Not ‘Smartest Guy in the Room’

By Rich Heidorn Jr.

nerc jim robb e isac — Jim Robb, NERC CEO | *© RTO Insider*

WASHINGTON — NERC CEO Jim Robb is a chemical engineer who learned the electric industry as a McKinsey consultant in California in the 1990s.

“So I learned the industry much more from a business and strategic angle than coming up through technology, operations and planning,” he said Thursday during an hourlong press conference scheduled to mark six months on the job for Robb, who was previously CEO of the Western Electric Coordinating Council. (See NERC Names WECC Chief to Top Post.)

“I’m … not an electrical engineer. … I’m never going to present myself as the smartest guy in the room on any technical topic,” he said. “I think the reason the NERC trustees chose me for this job was my ability to put the right set of people together to work on the right set of issues at the right time.”

Robb, who was tapped to replace long-time CEO Gerry Cauley, met with the press at NERC’s D.C. office, which houses about 30% of the organization’s employees, including its legal, enforcement and communications staffs and the Electricity Information Sharing and Analysis Center (E-ISAC). Robb said he spends most of his time at NERC’s Atlanta headquarters but visits D.C. about three or four times a month. (See related story, NERC Chief Sees Need for Inverter, Fuel Assurance Standards.)

Robb said NERC has a good foundation, citing the long-term strategic plan developed over the last 18 months and its four-year effort to transition to a risk-based approach, the Reliability Assurance Initiative (RAI).

The RAI initiative moved NERC away from the “one size fits all, check the box” approach of the past, Robb said.

Instead of auditing all registered entities on a three-year cycle, NERC and its Regional Entities are focusing on the most critical standards. NERC also has identified about 20% of its requirements as candidates for retirement.

NERC is also narrowing its focus on the entities that present the biggest risks to the system, based on their scale, location and the neighbors with whom they are connected. The organization’s staff now has power to change their audit scope on site if they encounter unexpected issues.

“It’s much more tailored to the individual company, its risk posture and its historical performance,” Robb said. “I think when we first rolled this out, industry thought, ‘This is great. This is going to be much less [regulation].’ And in fact, the experience has been all over the board. There’s some entities that would say, ‘Boy, we’re seeing a lot more of you than we’d like.’ And there are a few that we have had a much lighter touch on.

“We have to maintain rigor at all times. While we’ll disproportionally focus our time on and attention on the key risks and issues of the moment, we can’t lose sight of all the other stuff that goes on,” he added, mentioning criticism the Federal Aviation Administration received over its inspection practices in April following a fatal Southwest Airlines engine failure caused by cracked fan blades. “I don’t want to go through that,” he said.

Among Robb’s priorities are improving the consistency in how standards are implemented across regions, long a source of industry complaints, and improving the work of the ISAC.

The ISAC effort is being led by Bill Lawrence, a NERC veteran who led the GridEx IV exercise in 2017. Lawrence was appointed in August as chief security officer, replacing Marcus Sachs, who resigned last December. RTO Insider reported that Sachs was forced out because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the ISAC’s planned expansion. (See NERC Parts Ways with Chief Security Officer.)

“The ISAC really has not performed up to expectations,” Robb said. “Over the last couple years we, and the Electricity Subsector Coordinating Council’s Member Executive Committee, worked with Bill and others to put real rigor around the strategic role of the ISAC. … The ISAC is really designed to [provide] a service function for the industry. It’s not meant to be an idea lab.”

Robb said the ISAC faced challenges in “sanitizing” confidential information it receives and converting it to actionable intelligence.

The ISAC will double its staffing to “build [a] very strong analytical capability” and create a 24/7 watch operation, Robb said. The ISAC is now staffed only during normal business hours, although there is a NERC officer on duty around the clock.

The Cybersecurity Risk Information Sharing Program (CRISP), which is funded by industry and the Department of Energy and managed by the ISAC, is now monitoring utilities representing about 75% of electric meters to identify hackers seeking to penetrate the companies.

“The risk of a major outage as a result of one of these [attacks] is very low — but not zero,” Robb said. “And given the havoc that would result, we need to always be vigilant and staying way ahead of the curve, and I think we are. I think our system is designed with so much security built in, through the standards, through the isolation of operating systems from enterprise systems, that it would be very, very unlikely that a foreign entity or a malicious actor of any type would be able to create a catastrophic kind of cascading issue on the grid. Not zero, but very unlikely.”

October 1, 2018

PJM Price Formation Group Talks Reserves

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM’s initiative to revise how its energy market is constructed continued down the rabbit hole last week with a complex discussion about the timing of procuring reserves.

pjm ordc price formation — Catherine Tyler | *© RTO Insider*

At Wednesday’s meeting of the Energy Price Formation Senior Task Force, the Independent Market Monitor’s Catherine Tyler suggested revising the operating reserve demand curve (ORDC) to compare the value of purchasing reserves now to fill potential shortages later versus purchasing them later during the peak hours of the day.

Tyler explained that this level of analysis could determine the value of reducing the probability of a reserve. Hung-po Chao, PJM’s chief economist, agreed the idea merits consideration and that “the PJM team has been struggling with that” idea.

FirstEnergy’s Jim Benchek questioned the Monitor’s assumption that the relationship between the price for reserves now and the price for reserves later would be linear.

“That seems like a pretty big leap of faith,” he said.

PJM’s Patricio Rocha-Garrido explained the RTO’s justification for its recommendation of a 30-minute reserve product, which he said would account for all the time necessary to dispatch a resource and have it be ready to operate if necessary. Security-constrained economic dispatch (SCED) cases are solved 10 minutes prior to being implemented, and units that are assigned reserves have 10 minutes after a case is implemented to be online, so that accounts for 20 minutes, Rocha-Garrido said. The additional 10 minutes would cover SCED cases that are completed up to 14 minutes ahead and the additional output assigned units could provide past their assignments, if not for their ramping constraints.

The justification didn’t satisfy Tyler.

“It kind of sounds like fudging the numbers more than it’s based on anything,” she said. “You are increasing the looking forward time span such that there is more forecast uncertainty, increasing the probability of a shortage and therefore the price.”

“Obviously, I wouldn’t describe it in those terms,” Rocha-Garrido said. “We’re trying to capture the mathematical value … and not dismiss it completely.”

PJM’s Anthony Giacomoni provided market simulations using the RTO’s proposed revisions, which would consolidate Tier 1 and Tier 2 synchronized reserves and implement a downward-sloping ORDC. The simulations found that a net annual increase of $250 million to $800 million in load costs would be shifted from other areas, such as uplift, into the energy market, creating a $1 billion annual increase in energy market revenues.

October 1, 2018

New NERC Chief Not ‘Smartest Guy in the Room’

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb is a chemical engineer who learned the electric industry as a McKinsey consultant in California in the 1990s.

The RAI initiative moved NERC away from the “one size fits all, check the box” approach of the past, Robb said.

Among Robb’s priorities are improving the consistency in how standards are implemented across regions, long a source of industry complaints, and improving the work of the ISAC.

The ISAC effort is being led by Bill Lawrence, a NERC veteran who led the GridEx IV exercise in 2017. Lawrence was appointed in August as chief security officer, replacing Marcus Sachs, who resigned last December. RTO Insider reported that Sachs was forced out because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the ISAC’s planned expansion. (See NERC Parts Ways with Chief Security Officer.)

Robb said the ISAC faced challenges in “sanitizing” confidential information it receives and converting it to actionable intelligence.

September 30, 2018February 12, 2024

ERCOT Technical Advisory Briefs: Sept. 27, 2018

AUSTIN, Texas — ERCOT stakeholders last week granted Southern Cross Transmission’s (SCT) request to create a new market participant category for DC tie operators after months of inaction.

The Technical Advisory Committee on Sept. 26 unanimously endorsed a Nodal Protocol revision request (NPRR857) and an accompanying change to the Nodal Operating Guide (NOGRR177). Together, the changes create a “direct current tie operator” role that will clarify “obligations specific to those entities that operate DC ties” as distinct from those of transmission service providers (TSPs), who currently own all DC ties in ERCOT.

SCT was unable to qualify as a TSP because it will not own transmission facilities under the Texas Public Utility Commission’s jurisdiction. Pattern Development is pushing the proposed HVDC transmission project in East Texas that would be capable of shipping more than 2 GW of energy between the Texas grid and Southeastern markets. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

The revision also requires any TSP that operates a DC tie to secure additional registration as a DC tie operator.

Before the change can be implemented, NPRR857 requires SCT to issue Oncor a notice to proceed with construction of the facilities and provide the financial security required to fund the interconnection facilities. SCT has already signed an interconnection agreement with Oncor.

Under a separate memorandum of understanding with ERCOT, SCT agreed to cover all Protocol revision costs and any system change costs necessary to implement NPRR857. Staff have estimated a budgetary impact of up to $700,000.

The NPRR had been tabled since May’s TAC meeting, when SCT requested a delay in an attempt to increase the market’s understanding of the revision. (See “Staff Again Delays Vote on Amendment, Bylaw Revisions,” ERCOT Technical Advisory Committee Briefs: May 24, 2018.)

Cratylus Advisors’ Mark Bruce, who represents Pattern Development before the TAC, said SCT was ready to move forward with the change requests, but it was waiting for ERCOT’s determination of which market segment a DC tie operator should be placed in for governance purposes. That question is yet to be resolved.

Bruce said ERCOT comments filed Sept. 19 “address everything that was raised previously at TAC.”

ERCOT built on NPRR857 to make it clear SCT will bear the cost of implementing the change and added the criteria necessary to begin its implementation. The grid operator will issue a market notice before beginning the project, and another before NPRR875’s implementation.

The change addresses one of 14 directives the PUC set for ERCOT before energizing the SCT project (Project No. 46304).

TAC Approves First PUC Directive Related to DC Ties

Stakeholders also approved the first ERCOT determination in response to the PUC’s directives, but not before editing ISO staff’s language.

In directive 10, the commission ordered ERCOT to decide whether pricing changes are necessary within the market during emergencies to avoid DC tie flows “adversely affecting price formation … or otherwise causing outcomes inconsistent with a properly functioning energy market.”

TAC changed ERCOT’s original determination (“No market changes are needed to address pricing issues.”) to: “Although ERCOT staff recognizes potential price formation issues, ERCOT staff has identified no need for additional market changes at this time.”

Members argued staff’s original determination did not accurately reflect discussions within the Wholesale Market Subcommittee (WMS) and the Qualified Scheduling Entity Managers Working Group (QMWG). Both groups eventually endorsed ERCOT’s determination, which noted that stakeholders had previously considered pricing issues.

WMS Chair David Kee of CPS Energy said a staff white paper approved by stakeholders did not capture the history of the issues.

Staff said it determined that actions related to DC ties could “adversely affect” price formation during both emergency and normal conditions. They noted stakeholders have considered these issues while developing NPRRs related to the operating reserve demand curve’s (ORDC) price adder and the real-time online reliability deployment price adders.

Staff said there is no need to revise the NPRRs with another change request but said they will engage in stakeholder discussions should an NPRR be submitted or the PUC issues another directive.

QMWG Chair Eric Goff of Citigroup Energy said a market participant he did not identify plans to file an NPRR making changes to price adders and the ORDC. Goff’s abstention was the only vote the determination did not receive.

Staff’s white paper explained its determination.

“That view may not jibe with the stakeholders’ view, but we think it’s important for the board to evaluate those opinions,” ERCOT’s Nathan Bigbee said. “We view this as an ERCOT staff artifact, but we want to give you a chance to see our input.”

The white paper and determination will be presented for the Board of Directors’ approval at its Oct. 9 meeting.

TAC Endorses $53.3M Economic Project in West Texas

The committee endorsed Wind Energy Transmission Texas’ (WETT) Bearkat area transmission project in West Texas, which could become ERCOT’s first economic project in three years.

The project, which will be up for board approval in October, addresses congestion on a 138-kV line near Odessa, which is burdened with 1.5 GW of operational and planned wind generation. It consists of two new 345-kV bays and a 27-mile, 345-kV single-circuit line on double-circuit-capable structures.

The Bearkat project had a $69.9 million price tag when WETT submitted it to the Regional Planning Group last year. ERCOT staff’s independent review whittled the cost down to $53.3 million by recommending one of the least-cost 345-kV options, saying it provides a high transfer limit and “relatively good overall net societal benefits.”

The review evaluated nine upgrade alternatives, all of which passed the grid operator’s economic-planning criteria: Annual production cost savings must be equal to or greater than the project’s first year annual revenue requirement, assumed to be 15% of the capital cost.

Bearkat has a savings-to-cost ratio of 60% and is projected to produce $400 million in 30-year net savings.

The review took into consideration Lubbock Power & Light’s pending integration into ERCOT and the recently approved Far West Transmission Project. (See ERCOT Board Approves West Texas Transmission Project.)

TAC to Move 2019 Meetings to Wednesday

The TAC will likely move its 2019 meetings from Thursdays to Wednesdays to avoid conflicts with the PUC’s open meetings. TAC Chair Bob Helton said the change will also allow committee members to devote more attention to several PUC dockets that will “create issues in the wholesale market.”

Just Energy’s Blakey Confirmed as RMS Chair

Committee members unanimously confirmed Just Energy’s Eric Blakey as chair of the Retail Market Subcommittee, which serves as a forum to resolve retail market issues.

The committee’s Reliability and Operations Subcommittee (ROS) will choose its new chair on Oct. 11. The ROS develops, reviews and maintains operating guides and planning criteria.

Other Approvals

The TAC also approved five NPRRs, two revisions to the Nodal Operating Guide (NOGRR), two Other Binding Document revision requests (OBDRR) and two changes to the Planning Guide (PGRRs):

- - NPRR845: Incorporates numerous revisions to the reliability-must-run process, including standardizing the standby cost in terms of dollars per hour instead of dollars per megawatt; adjusting availability metrics used in settlements to the current operating plan rather than the availability plan; clarifying a resource’s post-RMR status and requiring an entity to submit a resource-notification change no later than 60 days before an agreement’s conclusion; allowing ERCOT to retain a mutually agreeable third party to help evaluate submitted RMR budgets; and modifying the RMR agreement to require detailed budgeted costs with or without capital expenditures.
  - NPRR869: Requires generators over 1 MW within a private use network (PUN) to provide modeling information to ERCOT if they are not: registered with the PUC as a power generation company; part of a PUN with more than one connection to the ERCOT grid; or registered to provide ancillary services. The change includes a netting exemption for a qualifying facility that is a small power production facility and provides energy to a customer behind a single point of interconnection. It also deletes a reference to the now-expired System Benefit Fund.
  - NPRR880: Requires ERCOT to publish shift factors for PUN settlement points for the real-time market, as is currently done in the day-ahead market.
  - NPRR883: Removes the real-time reliability deployment price adder from the real-time settlement point price to avoid double payment when resources have received an ancillary services assignment.
  - NPRR888: Clarifies the four-coincident-peak (4-CP) adjustment methodology that was implemented in conjunction with NPRR830.
  - NOGRR180: Removes “governor dead-band” and “governor droop settings” requirements for combined cycle steam turbines.
  - NOGRR181: Ensures consistency between the ERCOT and NERC requirements regarding black start plans. Because ERCOT has to review each transmission owner’s plan within 30 days of receipt, it must receive the plans for each year by Nov. 1 of the preceding year to complete its annual study.
  - OBDRR007: Changes the ORDC methodology to account for the curtailment of solar PV resources. Solar generation had been excluded since the ORDC was implemented in 2014.
  - OBDR008: Makes ERCOT’s procedure for identifying resource nodes consistent with NPRR890, which aligns price-calculation formulas with ERCOT systems calculation of the real-time LMP at a logical resource node for an online combined cycle generation resource. NPRR890 has cleared the Protocol Revisions Subcommittee.
  - PGRR063: Outlines the process for evaluating the reliability impact of transmission projects of 100-kV or above that are expected to be in service before the next Regional Transmission Plan’s completion but that were not included in the current plan, a Regional Planning Group project submission, or a generation interconnection or change-request study.
  - PGRR064: Requires resource entities to verify that dynamic devices used for reliability reflect their operating characteristics.

September 30, 2018

MISO to Create NOLA Cost Allocation Zone

By Amanda Durish Cook

MISO said last week it will approve New Orleans’ request to make the city a cost allocation zone but is deferring action on an interregional cost-sharing plan advanced by transmission owners.

In a letter signed by City Councilmember Helena Moreno, New Orleans asked MISO to create a standalone cost allocation zone for the city, pointing to FERC’s policy that project costs be allocated “roughly commensurate” with estimated benefits and that non-beneficiaries not be required to pay for them.

“MISO’s analysis has demonstrated that cost allocation on a more granular level within the state of Louisiana will improve the alignment of benefits and costs, consistent with MISO’s objectives for cost allocation reforms,” the city said.

miso nola cost allocation zone — Jesse Moser | *© RTO Insider*

The request involves creating an Entergy New Orleans transmission pricing zone. Director of Strategy Jesse Moser said the zone will not contain overlapping regulatory jurisdictions.

MISO conducted analyses to determine whether a New Orleans zone would contain enough generation and load to calculate benefits and result in better alignment of the costs and benefits for economic projects under the Transmission Expansion Plan.

“The short answer is ‘yes,’” Moser said during a Sept. 27 Regional Expansion Criteria and Benefits Working Group meeting. He said example calculations show MISO can isolate benefits and costs for New Orleans.

“We do plan to make a filing some time in the middle of October … to effectuate this change,” he said.

How Small?

Stakeholders asked MISO how small it’s willing to make cost allocation zones, with some saying they thought the RTO favored larger cost allocation zones.

MISO hasn’t established how small is too small, Moser responded.

“We could have something that’s too small. I don’t think we’ve put any definition around that yet,” Moser said. “It’s going to be incremental steps, and I think this [New Orleans] zone is a step in that direction.”

The current 11 cost allocation zones, based on the historic grouping of transmission pricing zones by state jurisdiction, resemble the 10 local resource zones used in the annual capacity auction. MISO earlier this year separated its Texas territory into a distinct cost allocation zone at the request of regulators.

Moser said MISO’s smallest cost allocation zone currently contains about 300 to 400 MW of generation. He added that while the RTO will not create any new cost allocation zones beyond New Orleans ahead of its planned cost allocation filing with FERC, it may revisit the possibility of creating new, smaller zones in the future.

“I think it’s something we’re going to come back to. I don’t think we’re done with this level of granularity,” Moser said.

As part of its cost allocation overhaul, MISO said it would look into the possibility of more specific zones. The RTO has proposed eliminating a footprint-wide postage stamp rate and lowering its current threshold for market efficiency projects from 345 kV to 230 kV. It will also add new benefit metrics to judge a project’s eligibility for cost allocation, including consideration for projects that defer or avoid other reliability transmission projects and a benefit for projects that reduce flows on the contract path on SPP transmission linking MISO’s North and South regions. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)

Speaking before the Board of Directors in September, MISO Vice President of System Planning Jennifer Curran said the RTO’s cost allocation proposal had determined a good way to estimate regional benefits considering the “various interests of stakeholders.”

“This is a very thorny issue here. You’re talking about money,” Director Mark Johnson said. “The entire MISO team needs to be commended for this effort.”

Alternate Interregional Proposal

However, most members of MISO’s Transmission Owners sector are seeking an alternative to the RTO’s plans for interregional project cost allocation.

A majority of TOs, including those with Section 205 filing rights, have formally requested that MISO consider their alternative approach for projects developed jointly with SPP and PJM.

The proposal stipulates that for interregional projects located in both RTOs through tie lines — or wholly within MISO — MISO would allocate costs to each RTO based on adjusted production cost benefits outlined in joint operating agreements. To allocate interregional costs within MISO, benefiting cost allocation zones would share costs for projects 230 kV and above, and the transmission pricing zone where the project is located would take on costs of projects below 230 kV down to 100 kV.

For interregional projects located wholly outside of MISO in either SPP or PJM, RTO costs would be divvied up according to adjusted production cost, with MISO’s allocation spread across benefiting cost allocation zones for projects 230 kV and above. However, for 100- to 229-kV projects, costs would be divided based on a line outage distribution factor (LODF) to determine the local transmission prizing zone beneficiaries. A LODF measures the change in flow on a facility stemming from the outage of a new project facility.

The RTO has said it wants consistency in project requirements along its seams with SPP and PJM, citing that reason in June when it proposed cost sharing 100-kV and above interregional projects along both the PJM and SPP seams. At the time, more than 20 MISO TOs said they opposed the 100-kV cost sharing threshold on SPP interregional projects because the MISO-SPP seam is lengthier with sparser load density than PJM. They also argued the seam is a better fit for higher-voltage projects, which can carry electricity farther. (See MISO to Lower SPP Interregional Project Thresholds.)

Moser said MISO is not yet taking a stance on the TOs’ proposal, waiting until it can work out numerical examples for hypothetical projects under the proposal. He said the RTO might not take an official position until early November.

“We appreciate the work of the owners,” Moser said. “It’s not everyone in the TO community, but it does represent a [Section] 205 filing majority, notwithstanding other filing rights that could be exercised in that community.”

Speaking for the TOs, attorney Wendy Reed thanked MISO for considering their proposal and said members hope they can negotiate with the RTO to avoid filing a competing cost allocation proposal with FERC.

Stakeholders at the meeting appeared divided on the proposal. LS Power’s Pat Hayes and Northern Indiana Public Service Co.’s Clark Gloyeske said they still supported MISO cost sharing down to 100 kV on interregional projects, though Mississippi Public Service Commission Counsel David Carr expressed support for the TO proposal. MISO asked for written stakeholder feedback on the proposal through Oct. 16.