Page 1091 – RTO Insider

December 9, 2018

SPP Stakeholders: Stick with Dec. 2019 Date for Western RC

By Tom Kleckner

The Western Reliability Executive Committee, which is overseeing SPP’s effort to provide reliability coordination (RC) services to more than a dozen Western Interconnection entities, pushed back last week against the Western Electricity Coordinating Council’s suggestion that the RTO coordinate its go-live date with that of CAISO.

SPP, CAISO and Canada’s BC Hydro have agreed to provide RC services in the West in response to Peak Reliability’s surprise move this summer to wind down its operations by the end of 2019. (See CAISO RC Wins Most of the West.)

CAISO will become the RC for its existing territory on July 1, 2019, and take over RC services for many areas outside of California on Nov. 1. SPP will take responsibility for about 12% of the region on Dec. 3.

BC Hydro will become the RC for most of British Columbia on Sept. 2.

SPP Vice President of Operations Bruce Rew told the committee during its Dec. 7 meeting that Peak is concerned that staff attrition may hinder its ability to continue providing RC services as it approaches its wind-down date.

At a WECC meeting last week, Jim Shetler, chair of Peak’s Member Advisory Committee, also said the staggered go-live dates do not afford the organization any room for error. (See related story, RC Transition Fraught with Pitfalls, WECC Hears.)

Rew said that during a recent Western RC-to-RC meeting, WECC said it may offer a streamlined recertification process to Peak and the new Western RC providers during footprint modifications. He said WECC’s actions should mitigate some of the concerns.

“Peak will have already gone through July 1 and Sept. 2 transitions,” Rew said. “As for [Peak] staff, they should have financial incentives to stay until January 2020. I don’t see a significant difference in risk between Nov. 1 and Dec. 3 … but I’m not in Peak’s shoes, either.”

Committee members pointed out that by Dec. 3, Peak will only be handling RC services for a small portion of its footprint. Committee Chair Keith Carman, with Tri-State Generation & Transmission Association, urged SPP to “hold fast and steady” on the Dec. 3 date.

“I’m struggling with what the issue is,” Carman said. “As the footprint gets smaller, they have less to worry about.”

December 9, 2018

Calif., Ill. Top Grid Modernization Index

By Rich Heidorn Jr.

WASHINGTON — California and Illinois won the top spots on the GridWise Alliance’s fifth annual Grid Modernization Index, standing out for their initiatives on energy storage, distributed generation, non-wires alternatives and ratemaking innovations.

Minnesota jumped to 10th place from 21st, and Colorado also jumped several spots to No. 11 in the index, which ranks states and D.C. on policies, customer engagement (rate structures, customer outreach and data collection practices) and grid operations (deployment of technologies such as sensors and smart meters).

GridWise announced the results at the gridConnext 2018 conference, where attendees heard about some of the projects exciting grid technology advocates.

‘Trailblazer’

GridWise CEO Steve Hauser said California “continues to be the grid modernization trailblazer,” citing its distribution system planning requirements and “multi-pronged approach to support distributed energy resources, including competitive solicitations, multiple DER demo projects, a self-generation incentive program, a net metering tariff, and an energy storage target and default time-of-use rates.”

Speaking at the conference, Courtney Prideaux Smith, chief deputy director of the California Energy Commission, noted that the CEC had just received approval to implement a requirement that new homes include solar panels beginning in 2020.

The new standards require that the solar systems be sized to meet each home’s energy usage and encourage battery storage and heat pump water heaters. The CEC says the new rules and other energy-efficiency initiatives will reduce energy use in new homes by more than 50%.

“It is going to save Californians money starting on day one,” Smith said.

Smith also touted the microgrid developments in the state, citing Borrego Springs, a desert community 90 miles east of San Diego that sits at the end of a transmission line, where frequent outages can leave elderly residents without air conditioning.

After a wildfire knocked out the line in 2007, San Diego Gas & Electric applied for a grant to create what Smith said is one of the world’s largest utility-owned microgrids, which integrates generation and storage and has reduced the community’s greenhouse gas emissions by 20%.

When lightning and flooding knocked out the transmission line again in 2013, Smith said, “the microgrid did exactly what we wanted it to. It islanded, and it directed power to critical infrastructure” — a gas station, a library that served as a cooling center for those who couldn’t relocate, and an elderly community.

Smith also cited a tenant-owned mobile home park in Bakersfield where the state helped add solar power with storage, reducing the low-income community’s net energy consumption by 30%.

Cluster of Microgrids

Anne Pramaggiore, who oversees Exelon’s six utilities, told the conference about a pilot to build “the world’s first microgrid cluster,” which will connect a solar-powered microgrid in the Bronzeville neighborhood of Chicago to an existing microgrid at the Illinois Institute of Technology. The project was approved by the Illinois Commerce Committee in February.

Solar panels located on a Chicago Housing Authority building will provide power to both the building residents and the microgrid. The plan also includes a “first-mile, last-mile” electric vehicle rideshare program for senior citizens and solar- and battery-powered lighting in areas without streetlights, a STEM education program at local schools, and an energy-efficiency program.

Pramaggiore said Exelon’s utilities also are “beginning to make investments to accelerate the conversion of distribution circuits from 4 kV to 12 kV to accommodate more distributed generation; build[ing] out smart inverters to better integrate diverse resources into the grid; … [and] standing up hosting capacity maps to help customers and developers see where the grid has capacity for solar.”

GridWise also cited the ICC’s approval of an order allowing utilities to recover the costs of cloud-based computing services “seen by many observers as a key pathway to move toward a service orientation (versus the traditional infrastructure focus core to most regulatory regimes).”

Ohio and Rhode Island Cited

GridWise gave Outstanding Progress Awards to Ohio and Rhode Island for recent initiatives.

The Public Utilities Commission of Ohio is pursuing regulatory changes “to support innovation while envisioning the distribution grid as an open-access platform enabling various levels of customer engagement,” GridWise said.

The group said Rhode Island regulators addressed their changing distribution system with new rate design principles and a benefit-cost framework.

December 9, 2018

MISO Board OKs Full MTEP 18 over Stakeholder Complaints

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Board of Directors voted unanimously last week to approve the $3.3 billion, 442-project 2018 Transmission Expansion Plan in its entirety despite stakeholder objections to three projects.

Last month, the Planning Advisory Committee withheld endorsement of two MTEP 18 projects: the rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota, and American Transmission Co.’s proposal to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas in the Straits of Mackinac. (See MTEP 18 Advancing with 2 Contentious Projects.)

MISO executives report to the Board of Directors. | © *RTO Insider*

At the board’s System Planning Committee meeting on Dec. 4, and again at the Dec. 6 board meeting, Xcel Energy’s Carolyn Wetterlin insisted that the Wabaco-Rochester area is “not ripe for a project yet,” asking directors to delay the project for a year so planners can find a better solution to ease congestion in the area. Dairyland Power Cooperative representatives also reiterated their concern that the co-op’s customers would have to pay for an unnecessary line, complaining that MISO staff and board were ignoring stakeholder voices.

MISO’s 10 most expensive projects range from the Mount Pleasant Tech Interconnection ($140 million) to the Natchez SES-Red Gum 115-kV Rebuild ($46 million). | *MISO*

Meanwhile, Consumers Energy challenged a third project, a $21 million, 138-kV interconnection near the Michigan-Ohio border.

Consumers’ Donald Lynd said Michigan Electric Transmission Co.’s (METC’s) Morenci line is a distribution line under the seven-factor test of FERC Order 888 because the line would be radial in nature.

“If MISO approves the project, Consumers Energy does intend to seek a determination from FERC,” Lynd announced during a public comment period.

The RTO responded that it had no authority to address Consumers’ request.

“MISO legal staff has reviewed this objection and has determined that under the terms of the Transmission Owners Agreement, asset classification is a matter to be determined between the transmission owner (METC) and FERC,” it said.

“Clearly, we’re at an impasse for at least a few of the projects,” Director Mark Johnson acknowledged before the SPC approved the full MTEP 18.

But he noted that the committee ensured that RTO leadership responded to the stakeholders and followed the MTEP procedure as outlined in the Tariff and Business Practices Manuals.

“I don’t think we should ever have grand illusions that we will have 100% consensus with the size and scope of the projects in Appendix A,” Johnson said.

Director Phyllis Currie said stakeholders should not view the board’s approval of the projects as brushing aside member concerns. “We acknowledge there’s going to be times when there’s disagreement,” she said.

December 9, 2018October 30, 2023

Fuel Security the Focus at ISO-NE Consumer Liaison Meeting

By Michael Kuser

BOSTON — Fuel security topped the agenda at the quarterly meeting of ISO-NE’s Consumer Liaison Group on Thursday.

“While the calendar might not say winter yet, the cold season starts Dec. 1” for the RTO, said Anne George, ISO-NE vice president for external affairs. She highlighted three new ways the RTO is dealing with winter this year, including new measures on fuel security that were approved by FERC earlier in the week. (See ISO-NE Fuel Security Measures Approved.)

First, the Winter Reliability Program was discontinued as Pay-for-Performance incentives took effect June 1. Second, a new energy availability forecasting and reporting framework has been added to the operating procedures to improve situational awareness and encourage proactive measures to avoid energy shortages.

“The third one is a way for resources to price in their opportunity costs for having fuel,” George said. “It was not fully available to do that in the energy market last winter, and we hope that by doing this it gives resources the opportunity to value their fuel and … that the energy market will reflect that value.”

“The wholesale energy markets were not designed to deal with fuel security at all,” said Mark Karl, the RTO’s vice president for market development. “We need to look at where we’ve come from. … The world has changed and so the design objectives need to change.”

In a concurrence on the commission’s Dec. 3 fuel security order, Commissioner Richard Glick wrote that “ISO-NE’s apparent need to retain units for fuel security is the result of a market failure” and that the RTO’s “ultimate approach to fuel security will need to be more sophisticated than the interim approach we approve today.”

Karl said the long-term solution the RTO is considering has three components: multiple day-ahead markets, a new ancillary service that’s integrated into that, and a new, voluntary, forward seasonal auction.

The RTO plans to launch a quantitative and qualitative analysis on its proposal, including potential cost impacts, next year and file a proposal with FERC by July 1, 2019, he said.

The new ancillary service would seek “to maintain an inventory — what we call a buffer stock in economics — of fuel that can be converted into electricity.”

While current markets optimize over a single day, the new design will optimize fuel supplies and stored energy over five or six days, Karl said. The voluntary auction is intended to provide an incentive for resource owners to procure fuel inventory for the next winter.

FERC’s ruling, which approved an out-of-market agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022, endorsed the ISO-NE proposal and rejected all of the New England Power Pool’s suggestions, said Paul Peterson of Synapse Energy Economics, which serves numerous NEPOOL participants, mostly in the End User and Alternative Resources sectors.

The NEPOOL alternative proposals approved by stakeholders and filed with FERC would limit the retention of resources for fuel security to Forward Capacity Auction 14, covering 2024-2025, and add FCA 15 only if necessary. NEPOOL also recommended requiring generators to report fuel status for winter; raising the threshold for triggering a fuel security reliability contract; and allocating reliability costs to the transmission portion of bill to reduce risk premiums from suppliers.

“Time will tell,” Peterson said. “We’ll have an opportunity four or five years from now to see whether or not the levels of fuel security that the [RTO] used to justify retention of Mystic really were true.

“And that’s one of the concerns on the ongoing back-and-forth between NEPOOL stakeholders and ISO-NE: What level of risk? What level of reliability? What level of cost? How are those things balanced out in a way that makes the region reasonably secure in the delivery of electricity?” Peterson said.

“How do we get an adequate supply of natural gas? How long is it going to take to build the offshore wind projects?” asked Massachusetts Rep. Thomas Golden, House chair of the state legislature’s Joint Committee on Telecommunications, Utilities and Energy.

“There’s a misperception that New England is seeing a continually increasing demand for natural gas to generate electricity,” Peterson said.

“Since 2010, the share of power generated by natural gas has grown, but overall consumption of gas has declined and will continue to do so,” Peterson said. “By our projections, demand for natural gas in 2030 will have declined 41% from 2015 figures.” Peterson’s projection assumes the operation of a Massachusetts “clean hydro” transmission line by 2023 and the addition of 1,600 MW of offshore wind in 2027.

Millstone

Eric Annes, a technology analyst with Connecticut’s Department of Energy and Environmental Protection (DEEP), said that both DEEP and the state’s Public Utilities Regulatory Authority have found Dominion Energy’s Millstone nuclear plant to be at risk and that the 2,111-MW plant “is critical to our carbon goals and to winter fuel security.” (See Connecticut Likely to OK Millstone for Zero-carbon RFP.)

“No one has had experience with the winter we’re about to experience this year or will experience the next couple of years,” Peterson said. “Suppliers don’t know what kind of costs they’re going to be facing. When they go to customers to offer them a bid for energy supply for 18 months or two years in the future, they’re going to put a risk premium on that because of the costs they don’t know whether they can take care of or not — they don’t even know how big they’re going to be.”

The CLG on Thursday elected a new coordinating committee for the 2019-2020 term. The new members and their respective states are: Deena Frankel (Vt.); August Fromuth (N.H.); Douglas Gablinske (R.I.); D. Maurice Kreis (N.H.); Erika Niedowski (R.I.); Guy Page (Vt.); Robert Rio (Mass.); Joseph Rosenthal (Conn.); Mary Smith (Mass.); Rebecca Tepper (Mass.); Mary Usovicz (Mass.); and Liz Wyman (Maine).

December 9, 2018January 30, 2024

MISO Board of Directors Briefs: Dec. 6, 2018

By Amanda Durish Cook

Market Platform Replacement Enters Year 3

CARMEL, Ind. — The MISO Board of Directors last week approved the RTO’s 2019 capital and operating budgets, allocating $20.5 million for another year of the RTO’s ongoing effort to replace its market platform.

MISO sought a $312.6 million operating budget, a 3% decrease from 2018, and a $27.2 million capital budget, an 8.3% decrease. The RTO’s administrative fee will continue to be 40 cents/MWh in 2019, the same as 2018’s rate.

Kevin Caringer, executive director of MISO’s technology team, praised early-phase vendor General Electric for attracting the usual levels of talent to the company despite its publicized troubles.

During a meeting of the board’s Technology Committee on Dec. 4, Caringer said MISO is currently “withholding judgment but having healthy skepticism” about GE’s ability to deliver software needed to clear the day-ahead market until future platform deliveries are evaluated by the RTO. GE is supposed to have an updated delivery schedule to MISO by the year-end.

Further talk on GE’s schedule was held for closed session of the board at the advice of MISO General Counsel Andre Porter.

The RTO will not announce a recommended platform vendor until the fourth quarter of 2019, when it finishes evaluating alternatives.

Director Michael Curran asked MISO to create milestones to gauge GE’s progress throughout 2019. “I’m struck by the fact that it’s going to be 2019 fourth quarter before we have a sense of the performance,” he said.

Caringer said that executives will provide quarterly updates.

MISO executives also confirmed that they have deliverable expectations for GE’s work but did not reveal dates.

Director Baljit Dail said he felt more positive about GE’s plan and new employees. He said the platform replacement schedule was on a “dark” trajectory earlier in 2018. (See MISO Platform Replacement Risks Delay, Budget Overrun.)

By the first quarter of 2019, MISO will upgrade its web service to support modern browsers.

“It’s a marathon, and we’re into the first 5 miles of it. We’ve hit a really, really good pace,” Dail told MISO executives, while commending the RTO’s work on the project so far.

DART Outages

During an IT scorecard presentation, MISO staff disclosed it suffered an outage of its day-ahead and real-time (DART) application on the afternoon of Sept. 11. The RTO said a process within the program was unresponsive, causing its unit dispatch system and look-ahead commitment tool to miss the targeted solve time of five minutes. MISO said the unit dispatch system, look-ahead commitment tool and its coordinated transaction scheduler were not solving, leading the RTO to perform manual workarounds during the 40-minute outage and restart.

MISO said it experiences DART outages occasionally and the problem requires a solution from GE. RTO staff said it provided operator logs to GE detailing the outage.

Curran, Kozey Get MISO Send-off

Porter will take over as board secretary in 2019, replacing outgoing Senior Vice President Stephen Kozey, board members have decided.

The board voted in closed session on the succession decision. As a rule, all MISO personnel matters are taken up privately.

“I won’t say you have you have big shoes to fill … I would say you have a big head to fill,” Curran told Porter, and after a beat and audience laughter, he said, “That probably didn’t come out right.”

Kozey is retiring at the end of the year after more than 18 years of service in MISO. Curran said Kozey helped build the RTO’s legal team and commemorated him with some of the first written words about Kozey in the MISO record: “The candidate has been recruited without the expense of an outside recruiting firm.”

The audience laughed then gave Kozey a standing ovation.

Curran, also departing MISO at the end of the year, likewise got a standing ovation. Curran has served on the board for 12 years.

Outside board counsel Karl Zobrist lauded Curran’s insistence on “plain language and transparency” during his board tenure.

“I’ve only known you for two years, but it feels like 20. You are the most generous mentor I’ve had,” Director Barbara Krumsiek told Curran.

Director Thomas Rainwater praised Curran’s “directness” and took a benevolent jab at him for now having to deal with ISO-NE’s sloped capacity demand curve. Curran, who will join ISO-NE’s Board of Directors in 2019, has long sparred with Independent Market Monitor David Patton over his appeals to adopt a downward-sloping demand curve in the MISO capacity market.

“I actually like you,” Director Mark Johnson joked. MISO CEO John Bear borrowed a Curran phrase and called him “wicked smart.”

Curran signed off saying, “I refuse to say ‘goodbye’; it’s ‘see you later.’”

Director Phyllis Currie will take over as board chair in 2019. (See MISO Board Selects Currie as New Chair.)

6 Added to MISO Membership

The board approved into MISO membership non-transmission-owning businesses Cleco Cajun, Nuclear Development, TransCanada Energy Sales, Xcel Energy Acorn Transmission and Xcel Energy Birch Transmission. The board also approved the transmission-owning membership application of the city of Henderson. The western Kentucky municipality owns Henderson Municipal Power and Light.

December 9, 2018

MISO Stakeholders: New Blueprint Needed for Tx Planning

By Amanda Durish Cook

CARMEL, Ind. — MISO stakeholders debating whether the RTO should embark on another regional transmission package said impact to customers and solid business cases should factor prominently.

MISO is asking whether it needs another long-term regional transmission plan like 2011’s multi-value project (MVP) portfolio as it experiences a changing fleet and an increasing need to access new resources. The topic was the focus of the Dec. 5 Advisory Committee’s quarterly hot topic discussion.

Aubrey Johnson, MISO executive director of system planning and competitive transmission, said the approximately 37 GW of wind projects under study in the queue cannot be supported by the RTO’s current system, even considering under-construction projects in the MVP portfolio. The majority of MISO’s 17-project portfolio will be online by the end of 2019.

MISO’s transmission queue contains 483 projects totaling about 80 GW. Executive Director of Resource Planning Patrick Brown said MISO may be reaching an economic “break point” where the costs of network upgrades render projects uneconomic, especially in the wind-heavy western portion of its footprint. “The general cost of network upgrades is going to drive them out,” Brown said.

Historically, 17% of proposed generators that enter MISO’s interconnection enter the generator interconnection agreement phase.

‘Stand by Me’

Per tradition, moderator Julia Johnson began the hot topic conversation with a song selection, this time Ben E. King’s “Stand by Me.”

“Blackout!” Johnson jokingly interjected while the lyrics “when the night has come, and the land is dark, and the moon is the only light we’ll see” played in the room. More seriously, she said the takeaway from the song was for industry players to remain unafraid and working together on regional planning.

Alliant Energy’s Mitchell Myhre said he didn’t think MISO would need an entirely new transmission planning playbook but that it should analyze transmission project alternatives and engage in conversations about them. He said more analysis on transmission project alternatives may have lessened the late-stage disagreements over at least two projects in this year’s Transmission Expansion Plan. (See related story, MISO Board OKs Full MTEP 18 Over Stakeholder Complaints.)

“We ask that those conversations [about alternatives] happen at the front end of the process so they don’t come up in the back end of the process,” Myhre said.

Dec. 5 MISO Advisory Committee meeting | © *RTO Insider*

Multiple stakeholders said another possible crop of MVPs, if any, will need a new business case process, especially considering the fleet change that has occurred in the intervening years and the transmission cost allocation plan MISO will file at the end of the year.

“What if customers have had enough of transmission expansion? What if they’re tired of having transmission lines going across their farms, yards. … They have more options to bypass us completely. You can talk about MISO’s value until you’re blue in the face. What customers see is rising bills,” Madison Gas and Electric’s Megan Wisersky said.

She said customers might be better served by a reinforced distribution system than more transmission projects.

“We have to remember that these transmission lines do impose on communities,” said Coalition of Midwest Transmission Customers attorney Jim Dauphinais, who agreed that overbuilding transmission will result in more expensive bills.

Dauphinais said strong business cases are a must for new regional transmission.

“We think there needs to be a study; we think there needs to be a process” to see if a long-term regional transmission plan makes sense, Missouri Public Service Commissioner Daniel Hall agreed.

However, Kevin Murray, representing the Coalition of Midwest Transmission Customers, said a strong business case can’t be built on a speculative information about where resources might be constructed.

“We need to avoid the ‘build it and they will come’ sentiment. And we’ve seen hints of that in the past,” Murray said. He said some transmission projects might be more appropriately funded by interconnection customers for planned generation.

Clean Grid Alliance’s Beth Soholt said her company will continue to support the Cardinal Hickory Creek line project in Wisconsin, which she said had a “solid as ever” business case. She urged the MISO community no to get too hung up on the infeasibility of the entirety of the projects in the queue.

“We’re always going to have a queue. We’re always going to have projects entering because of economics,” Soholt said.

NRG Energy’s Tia Elliott, a representative of the Independent Power Producers sector, said grid buildout makes sense for a growing base of customers that prefer different resource options.

Soholt suggested that MTEP 15-year future scenarios should account for sustainability goals beyond renewable portfolio standards. Other stakeholders said MISO’s “limited fleet change” future scenario, which doesn’t anticipate widespread renewable use, is outdated and too improbable to be used in transmission planning. Although MISO staff said this year’s four future scenarios were developed for reuse over multiple planning cycles, some stakeholders said all of them should be revised. (See MISO to Recycle Tx Planning Scenarios for 2019.)

Others said accessing diverse resources may require the RTO’s own transmission pathway to connect MISO Midwest and MISO South. Dauphinais said the RTO should make “deeper dives” into chronic transmission constraints that don’t always show up in its annual market congestion planning study.

December 7, 2018

PJM SHs Seek End to Frequency Response Debate

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM will have to determine whether it wants to move forward without stakeholder endorsement on its plan to enforce primary frequency response (PFR) requirements beyond the standards of FERC Order 842 after members roundly rejected three proposals to revise the requirement.

RTO staff announced the results of a recent poll on the proposals at the Dec. 5 meeting of the Primary Frequency Response Senior Task Force (PFRSTF). None received more than 0.34 support; 0.5 was required to be advanced for consideration at the Markets and Reliability Committee. A question on whether PJM should make any change showed 0.73 in support of maintaining the status quo.

PJM stakeholders roundly rejected proposals to revise the RTO’s primary frequency response requirements beyond FERC Order 842 in a recent poll. | *PJM*

New units that enter the interconnection queue after Oct. 1 and existing units that request an uprate — including facilities that add units — will have to provide PFR, but there would be no new requirements for existing units that don’t make any changes. Generators have opposed proposals to require existing units to provide PFR. (See Primary Frequency Proposals Set for Vote in PJM.)

Stakeholders’ comments at the meeting reiterated the view that the proposals were, as FirstEnergy’s Jim Benchek put it, “a solution looking for a problem.”

“The thing about this is … it’s really an Eastern Interconnection thing … because each balancing authority has the obligation. Things are working,” Benchek said. “I would suggest that PJM … continue to monitor the situation, and if primary frequency response continues to degrade and needs to be addressed, then we restart this task force.”

American Electric Power’s Brock Ondayko agreed that the RTO should give Order 842 time to see if it corrects a trend PJM has noticed of reduced fleetwide PFR performance.

“In the meantime, I think PJM should probably explore the impacts of their own dispatch on the capabilities of units to provide [PFR],” he said. “The capability is so dependent on how PJM loads the assets, whether or not they have them moving prior to the [PFR event].”

Old Dominion Electric Cooperative’s Adrien Ford echoed the remarks, saying the poll results are “clear guidance” that the status quo is preferable.

“At this point, I think our work here is done,” she said.

Wider Concern

“Based on the latest webinar NERC held, I think there is indication that frequency response is declining in general. Is there someone jumping up and down saying, ‘The sky is falling’? I don’t think so. However, I think all the trends show we’re heading in that direction,” PJM’s Vince Stefanowicz said, noting that further delay risks NERC promulgating additional standards.

PJM’s Danielle Croop said that the overall trend is reflected within the PJM footprint.

“We have seen trending down in our frequency response … year over year for the past few years,” she said. “I definitely don’t think it’s PJM in a bubble that’s concerned about frequency response.”

Benchek assured that FirstEnergy’s units will continue to provide PFR and saw the potential for NERC to revise its standards as beneficial rather than a risk.

“We’re not going to take the governor controls off our units or anything,” he said. “We want to comply. We want to have a reliable system. It’s just not clear what we should do, so it’s maybe prudent to wait for better guidance.”

Other stakeholders asked PJM to continue to provide reports on unit performance and overall fleet response.

PJM’s Glen Boyle agreed to doing so.

December 7, 2018

SPP Board of Directors/Members Committee Briefs: Dec. 4, 2018

By Tom Kleckner

Board Approves Reduced Admin Fee for 2019

DFW AIRPORT, Texas — SPP’s Board of Directors on Tuesday approved a more than 8% reduction in the RTO’s administrative fee for 2019, although the fee is projected to rise again in 2020.

December’s Board of Directors/Members Committee meeting | © *RTO Insider*

The RTO’s Finance Committee based its recommendation for a 39.4 cents/MWh fee on a net revenue requirement (NRR) of $157.5 million next year, a $21.3 million reduction from prior estimates for 2019 and just $3.2 million more than 2018’s forecast. SPP is projecting a 4.4% increase next year in the billing determinants used to calculate the administrative fee and is also benefiting from a recent $10.7 million over-recovery.

The administrative fee, which is collected under Schedule 1A of SPP’s Tariff on transmission contracts between transmission providers and customers, was 42.9 cents/MWh for 2018.

“There’s no promise that the fee can stay [low],” said Director Bruce Scherr, the committee’s chair.

SPP Board Chair Larry Altenbaumer discusses the 2019 schedule as CEO Nick Brown listens. | © *RTO Insider*

Scherr said future affordability will be addressed as SPP moves into its next budgeting cycle. Board Chair Larry Altenbaumer said several times he would like to see an affordability task force created during the RTO’s January meeting.

There was little discussion as the Finance Committee presented its recommendations for both the fee and SPP’s 2019 budget. The budget, also approved without opposition, includes $196.3 million in expenses, a 5.2% increase over 2018’s forecast but 2.9% below 2019’s prior estimates.

SPP allocates the NRR to transmission customers based on their purchase of point-to-point (PtP) transmission service and/or network integrated transmission service (NITS). NITS customers are billed based on the prior year’s average monthly peak demand and represent approximately 90% of total annual billing determinants. PtP service is billed based on reserved hourly transmission capacity and represents about 8% of annual billing determinants.

Monthly true-up assessments cover any unreported load not covered by NITS or PtP service.

The NRR is expected to climb into the $180 million range by 2021, when a major computer system upgrade is planned. That would require an administrative fee of 45.2 cents/MWh.

Board Approves Group Chairs, Reliability Project

New Director Susan Certoma attends her first full board meeting. | © *RTO Insider*

The board’s consent agenda reaffirmed chairs for nine stakeholder groups; approved an $8.9 million short-term reliability project; accepted the Oversight Committee’s recommended 2019 Industry Expert Pool (IEP) that will evaluate any competitive upgrade projects; and passed scope changes for various working groups, primarily removing references to the dissolved SPP Regional Entity and ensuring equal representation among transmission owners and transmission users.

SPP said the following chairs were nominated with the unanimous support of their respective groups and will begin their two-year terms on Jan. 1:

Balancing Authority Operating Committee: Bryan Taggart, Evergy
Change Working Group: Carrie Dixon, Xcel Energy
Credit Practices Working Group: Mark Holler, Tenaska Power Services
Economic Studies Working Group: Alan Myers, ITC Great Plains
Market Working Group: Richard Ross, American Electric Power
Model Development Working Group: Nate Morris, Liberty Utilities
Operations Training Working Group: Russell Moore, City Utilities of Springfield
Project Cost Working Group: Tom Hestermann, Sunflower Electric Power
System Protection and Control Working Group: Steve Wadas, Nebraska Public Power District

The reliability project includes a 5.6-mile, 161-kV line in the Kansas City, Mo., area that will address thermal overloads following several Kansas City Power & Light generation retirements.

The 2019 IEP pool will include 13 holdovers from last year and adds two new members: SPP retiree John Mills and consultant Tip Goodwin. Mills is the first former SPP employee to serve on the panel. The panel did not consider any competitive projects in 2018.

The consent agenda also included a board policy statement that will allow Markets and Operations Policy Committee-endorsed actions destined for FERC filings and not appealed by members to go through the regulatory process without further board approval.

December 7, 2018

PJM Stakeholders Seek More Flexible Fuel Cost Rules

By Rory D. Sweeney

VALLEY FORGE, Pa. — After a year under new fuel-cost policy (FCP) rules, PJM stakeholders want to make some tweaks.

Discussions on the revisions commenced Tuesday at a special session of the Market Implementation Committee. The special sessions are the result of a problem statement and issue charge approved by the MIC in September. (See “Review of Fuel Cost Policy Rules,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)

Attendees at last week’s special session of the Market Implementation Committee discuss potential changes to fuel-cost policy rules. | © *RTO Insider*

PJM staff and stakeholders alike agreed the process could use some revisions to reduce its administrative burden. The rules went into effect in May 2017 after months of debate. In June 2017, the Independent Market Monitor announced that it had rejected fewer than 5% of FCPs during its annual review, but that those rejections accounted for roughly 11% of the units requiring FCPs. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)

John Rohrbach of ACES highlighted a specific concern that “innocuous” operator errors representing less than half a penny can create tens of thousands of dollars in penalties.

“It seems reasonable to ask whether that is a reasonable system to have” such potential for penalties, he said.

The Monitor’s Joel Romero Luna clarified that PJM’s online information-submission portal rounds to the penny and that no penalty would be assessed if the error does not make it to the portal.

Rohrbach, however, pointed out that the Tariff and Operating Agreement give staff no leeway in assessing penalties for such FCP violations.

PJM attorney Chenchao Lu agreed that the current OA language doesn’t provide the RTO any discretion in assigning penalties for violations, though it does have some discretion in determining whether the FCP was violated in the first place.

Calpine’s David “Scarp” Scarpignato said the lenience should be expanded to include additional types of errors, including those “not intentional.”

“It’s very difficult to be able to determine intent just by looking at the data,” PJM’s Glen Boyle said. “If I move a decimal place on a number, is it intentional? How do I prove that?”

Additional Changes

PJM staff provided education on how the current FCP procedures work for developing cost-based offers. Stakeholders then listed a dozen areas of interest for revising the rules, including removing the administrative burdens for both the RTO and unit owners and adjusting potential penalties to be proportional to violations.

PJM’s Bhavana Keshavamurthy, secretary of the MIC, said she would add the topic to the agenda for the MIC’s Dec. 12 meeting for further discussion.

December 7, 2018

PJM Board Demands Action on Energy Price Formation

By Rory D. Sweeney

WILMINGTON, Del. — PJM’s Board of Managers has signaled that it is done waiting for stakeholders to make progress on a nearly yearlong initiative to improve energy price formation.

In a letter dated Dec. 5, the board gave stakeholders until Jan. 31 to reach any consensus they can on six energy price formation issues. After that, the board threatened, it will direct PJM to seek FERC approval for the changes without member endorsement under Section 206 of the Federal Power Act.

The six areas for changes include:

Consolidation of Tier 1 and Tier 2 synchronized reserve products;
Improved utilization of existing capability for locational reserve needs;
Alignment of market-based reserve products in day-ahead and real-time energy markets;
Operating reserve demand curves (ORDCs) for all reserve products;
Increased penalty factors to ORDCs to ensure utilization of all supply prior to a reserve shortage; and
A transitional mechanism for the Reliability Pricing Model energy and ancillary services revenue offset to reflect expected changes in revenues in the determination of the net cost of new entry.

“The board has reviewed evidence that demonstrates that when the system is experiencing stressed conditions, energy and reserve prices do not accurately reflect PJM operator reliability actions and, as a result, out-of-market payments increase substantially during those periods,” the letter, signed by Board Chair Ake Almgren said. “Further, PJM’s current reserve market rules do not accurately align the procurement of reserves with their reliability value or incentivize consistent response when deployed. The lack of alignment in the reserve markets mutes price transparency, shifts costs unfairly to consumers who have prudently hedged and limits competition to secure reserves at the least cost to consumers.”

The board said stakeholder discussions have shown “widespread agreement that improvements to reserve markets are necessary” and that PJM has proposed to stakeholders elements from other regions that have “successfully implemented … more robust designs [that] more effectively value reserves and price operator actions.”

The Energy Price Formation Senior Task Force last month delayed a vote on competing proposals from PJM and its Independent Market Monitor for revising the RTO’s ORDC. Stakeholders had expressed reservations about both plans. (See PJM, Monitor Remain at Odds over Energy Market Proposals.)

MRC Response

PJM CEO Andy Ott opened Thursday’s meeting of the Markets and Reliability Committee by saying the changes are “critical to the ongoing evolution of our market” and that, “frankly, we think [the market rules] fall short today.” He noted price spikes during extreme weather, first highlighted by the polar vortex in 2016, and thought some of the proposals, such as locational reserves, were “low-hanging fruit” that stakeholders would endorse “in the time period that’s necessary.”

“We really believe a comprehensive solution to this is necessary. I wish that stakeholders would have come to consensus,” he said.

The forced deadline irritated some stakeholders and found support from others.

“We think that stakeholders have been working assiduously on this, and we’re disappointed that PJM and the board think differently,” said Carl Johnson, who represents the PJM Public Power Coalition. He noted that newly proposed ORDCs were introduced last week and said setting up an Enhanced Liaison Committee, used once before to implement the Capacity Performance construct, is the tool available to the board for expediting the stakeholder process, not making threats.

Susan Bruce, who represents the PJM Industrial Customer Coalition, said stakeholders have not addressed some of the topics the board has asked for agreement on, such as alignment between day-ahead and real-time markets and aligning penalty factors.

“Those are issues that we haven’t really tackled and we don’t really have any information about,” she said, asking PJM staff to provide information for stakeholders to analyze because “the calendar is creeping” up to the deadline.

“That will happen. Where’s [PJM Senior Vice President of Operations and Markets Stu] Bresler? Make that happen,” Ott said, assuring stakeholders that the board wants member input “so when we do present a package to FERC, it is as vetted as possible.”

NRG Energy’s Neal Fitch said many of the topics are “evergreen,” and “we could as stakeholders talk about this for a very long time.” He said the Enhanced Liaison Committee might not be the right plan.

“Perhaps calling the question in the very near future is the right thing to do,” he said. “We’ve been working on this for a very long time. … I think it’s time for us to move on.”

“From my perspective, the stakeholder group is actually moving in a negative direction,” Calpine’s David “Scarp” Scarpignato said. He questioned whether stakeholders should have Section 205 rights in the FPA over market rules in PJM’s Operating Agreement because of how the stakeholder process gets bogged down. He said he doesn’t agree with everything in PJM’s proposal, like the transition plan, “but eventually you have to make a decision.”