Page 1075 – RTO Insider

February 11, 2019

NERC Board of Trustees Briefs: Feb. 7, 2019

By Tom Kleckner

Florida RE’s Delegated Agreement to be Terminated

MANHATTAN BEACH, Calif. — The number of NERC Regional Entities will soon dwindle to six following last week’s unanimous approval by the organization’s Board of Trustees to enter into a termination agreement with the Florida Reliability Coordinating Council (FRCC).

The NERC Board of Trustees holds its quarterly meeting. | © *RTO Insider*

During the board’s Feb. 7 meeting and without discussion, trustees authorized NERC management to terminate the amended and restated delegation agreement between the organization and FRCC and to approve transfer of its registered entities to SERC Reliability.

FRCC serves as the RE, reliability coordinator (RC) and planning authority for much of the state of Florida, the latter two functions under its member services division. Its only geographic and electrical borders are with SERC.

FRCC announced last year it would dissolve its RE division following a review of its governance structure, set in motion by NERC’s 2017 determination that REs should be separate corporate bodies from NERC-registered entities. A FERC audit in 2010 spurred FRCC to improve the separation between its RE and member services divisions.

NERC will file a petition with FERC seeking its approval of the delegated agreement’s termination and the transfer of FRCC RE’s delegated authority to SERC. It has proposed a transfer deadline of July 1.

The organization will follow much of the same process as last year in approving the dissolution of the SPP RE, which ceased its activities in June. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)

Board Chair Roy Thilly thanked FRCC CEO Stacy Dochoda for moving the process along.

“This is a complex set of arrangements, but it’s working very smoothly,” he said.

As of March 2018, FRCC had 32 registered entities in its RE division and 22 in its member services division, including duplications.

5th RC Provider Enters the Western Grid

The number of RCs in the Western Interconnection could soon number five, said Branden Sudduth, the Western Electricity Coordinating Council’s vice president of reliability planning and performance analysis.

WECC’s Branden Sudduth | © *RTO Insider*

Sudduth told trustees and stakeholders that Gridforce, a Houston-based control center, has notified WECC it intends to offer RC services to its Gridforce Energy Management (GEM) balancing authority in northern Oregon. GEM, the lone undeclared BA in Peak Reliability’s footprint, is a member of the Northwest Power Pool.

Sudduth said WECC and NERC are reviewing the application. Gridforce has an expected go-live date of Dec. 3, when Peak will terminate all its services. Peak last summer decided to close its doors when it became apparent its budget couldn’t withstand the loss of CAISO and other members. (See Peak Reliability to Wind Down Operations.)

CAISO has signed up the bulk of Peak’s membership, but SPP has also made inroads by offering RC services to about 12% of the legacy load, primarily along the Rocky Mountains. BC Hydro will take over for its British Columbia service territory.

WECC will begin its certification visits in March at CAISO, which will go live with RC services for its own territory July 1 and for its non-members Nov. 1. BC Hydro goes live Sept. 2, and SPP will follow Dec. 3.

Peak staff will spend about two months conducting shadow operations with each of the incoming RCs to ensure continuity and shared expertise. Peak is following a detailed project management path until it hands over its RC duties.

“We have a very unique requirement of providing services for a year while closing the organization,” Peak CEO Marie Jordan said. “I haven’t closed too many companies. I’ve closed some power plants, but we always had the mother ship above us. This is truly a territory not too many of us on the leadership have been down, so [we] want to do it right.”

NERC CEO Jim Robb said he found Jordan’s presentation “confidence-inspiring.”

“You’ve made it clear the focus is on reliability, not the closure of Peak,” he said.

Robb said he was concerned about the California-Arizona seam, which was a part of the 2011 Southwest outage that led to Peak’s creation. Jordan said Peak is in the final stages of executing a seams agreement with CAISO but noted that remedial action schemes (RAS) may prove more important.

“I do think RAS schemes need to be as much of a focus as the seams agreements,” she said.

SCE’s Payne: California Prepping for ‘New Abnormal’

Southern California Edison CEO Kevin Payne welcomed NERC to sunny but chilly California, saying, “You’ve picked a pretty interesting time to come” to the state.

Payne said the state is at the forefront of a clean energy future, pointing to its renewables-heavy grid and focus on greenhouse gas reductions.

“Ironically,” he said, “the very thing we’ve worked so hard to mitigate, climate change, is impacting us in real ways. If you’re a skeptic of climate change, I guarantee you would be a believer if you lived through it like we are.”

Payne said 2018 was the “most destructive, damaging and tragic fire year” in the state’s history. Capped by the deadly Camp Fire, the last two years have seen Pacific Gas and Electric rack up $30 billion in potential wildfire liabilities, leading the utility to file for Chapter 11 bankruptcy reorganization. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)

Former Gov. “Jerry Brown referred to the ‘new abnormal,’” Payne said. “We’re quickly preparing ourselves for the new abnormal.”

That includes hardening the grid’s infrastructure, aggressive vegetation management, installing covered conductors on thousands of miles of distribution lines and improving situational awareness by adding weather stations in the utility’s service territory. Like the state’s other investor-owned utilities, SCE filed a wildfire mitigation plan last week. (See Federal Judge to Review PG&E’s Wildfire Plan.)

“We’re working through all of this,” Payne said. “We’re getting the right policies in place, so we can move forward and focus on reliability.”

Robb Honors McIntyre, LaFleur

Robb opened his regular report by asking for a moment of silence in honor of the late FERC Commissioner Kevin McIntyre, who died last month following an 18-month battle with brain cancer. (See FERC’s McIntyre Loses Cancer Battle.)

“I’ll miss his leadership at FERC. He was a rare talent,” Robb said.

He also recognized Commissioner Cheryl LaFleur’s recent announcement that she would not be nominated for another term on the commission. (See LaFleur Announces Departure from FERC.)

“That was a bit of a blow to all of us,” Robb said. “She certainly took reliability as one of the pillars of her work at FERC. She’s been good to us.”

NERC CEO Jim Robb confers with General Counsel Charles Berardesco. | © *RTO Insider*

Robb reviewed his four priority areas with the trustees: the evolution of Western RCs; the pace of change in the resource mix; cyber and physical security; and addressing inverter-based technology. NERC defines inverter-based resources as renewable energy asynchronously connected to the grid through power electronics.

“We have to ensure these resources, which are growing at an extraordinary rate, play nicely with the rest of the grid,” Robb said.

Thilly complimented Robb for his performance since stepping into NERC’s leadership role last year. He noted Robb’s focus on a collaborative culture, “which spreads throughout the leadership at NERC and the whole company.”

“It’s been a great set of changes at the right time,” Thilly said. He then jokingly said, “I should mention, though, the honeymoon is almost over.”

Trustees Elect Case as Vice Chair

The board elected Janice Case as its vice chair, returning her to a position she also held in 2013. Case, a trustee since 2008, serves on the Finance and Audit and Technology and Security committees. She spent 25 years with Florida Progress and its Florida Power subsidiary.

The trustees also approved amendments to Texas Reliability Entity’s bylaws, following a comprehensive review to examine their consistency with the Texas Business Organizations Code, and adopted four standards as part of their quarterly standards review:

TPL-007-3, Transmission System Planned Performance for Geomagnetic Disturbance Events: Adopts Canadian-specific revisions to TPL-007-2, including a new variance for Canadian entities; a method to develop alternative geomagnetic disturbance planning events; and addressing Canadian regulatory approval processes for corrective action plans.

CIP-008-6, Incident Reporting and Response Planning: Modifies CIP-008 Cyber Security Incident to require reporting of cybersecurity incidents that compromise or attempt to compromise the bulk electric system, in response to FERC Order 848. Includes the Department of Homeland Security in the reporting requirements.

February 11, 2019

NERC Board of Trustees Briefs: Feb. 7, 2019

Florida RE’s Delegated Agreement to be Terminated

Board Chair Roy Thilly thanked FRCC CEO Stacy Dochoda for moving the process along.

“This is a complex set of arrangements, but it’s working very smoothly,” he said.

As of March 2018, FRCC had 32 registered entities in its RE division and 22 in its member services division, including duplications.

5th RC Provider Enters the Western Grid

NERC CEO Jim Robb said he found Jordan’s presentation “confidence-inspiring.”

“You’ve made it clear the focus is on reliability, not the closure of Peak,” he said.

“I do think RAS schemes need to be as much of a focus as the seams agreements,” she said.

SCE’s Payne: California Prepping for ‘New Abnormal’

Southern California Edison CEO Kevin Payne welcomed NERC to sunny but chilly California, saying, “You’ve picked a pretty interesting time to come” to the state.

Payne said the state is at the forefront of a clean energy future, pointing to its renewables-heavy grid and focus on greenhouse gas reductions.

Former Gov. “Jerry Brown referred to the ‘new abnormal,’” Payne said. “We’re quickly preparing ourselves for the new abnormal.”

“We’re working through all of this,” Payne said. “We’re getting the right policies in place, so we can move forward and focus on reliability.”

Robb Honors McIntyre, LaFleur

“I’ll miss his leadership at FERC. He was a rare talent,” Robb said.

He also recognized Commissioner Cheryl LaFleur’s recent announcement that she would not be nominated for another term on the commission. (See LaFleur Announces Departure from FERC.)

“That was a bit of a blow to all of us,” Robb said. “She certainly took reliability as one of the pillars of her work at FERC. She’s been good to us.”

“We have to ensure these resources, which are growing at an extraordinary rate, play nicely with the rest of the grid,” Robb said.

“It’s been a great set of changes at the right time,” Thilly said. He then jokingly said, “I should mention, though, the honeymoon is almost over.”

Trustees Elect Case as Vice Chair

— Tom Kleckner

February 10, 2019

Exelon: Need Pa. Action by May to Save TMI

By Rich Heidorn Jr.

Pennsylvania lawmakers must approve nuclear subsidies by May to prevent the retirement of Three Mile Island Unit 1, Exelon CEO Chris Crane told stock analysts Friday.

Crane’s comments came days after a bipartisan group of legislators circulated a proposal to add nuclear energy to Pennsylvania’s Alternative Energy Portfolio Standards Act. (See related story, Nuclear ‘Bailout’ Memo Circulating through P a. Assembly.)

Speaking during the company’s fourth-quarter 2018 earnings call, Crane called the legislative effort “promising,” saying, “We have some strong support.”

But he said the company would need to order a new reactor core by May to refuel the 2,568-MW plant if it is to remain in operation. “We’ve let the stakeholders know that. So, if we can get this through in that period of time, we will be able to save the unit. Short of that, we would be beyond the [point of no] return at the end of May.”

The company announced in May 2017 that it would shutter TMI by about Sept. 30, 2019.

Kathleen Barron, senior vice president of federal regulatory affairs and wholesale market policy, said lawmakers have not decided on the value of the support the state might offer its nuclear plants.

“That is subject to discussions that are ongoing among the lawmakers now. So, we don’t have an estimate for you on how the program will look,” she said.

Crane also said the company continues to seek ways to boost the earnings of its Dresden, Braidwood and Byron nuclear plants in Illinois, all or parts of which did not clear PJM’s 2018 capacity auction.

Exelon CEO Chris Crane | © *RTO Insider*

“We will continue to engage with stakeholders on state policies while advocating broader market reforms at the federal level,” Crane said. “We will support PJM price formation changes like fast-start and reserve market reforms with our states to implement the expected FERC order on PJM capacity reforms and preserve the authority of our states to advance their clean energy policies and continue our efforts to seek fair compensation for zero-emitting nuclear plants.”

In June, FERC ruled that PJM’s Tariff was unjust and unreasonable because it allows resources receiving out-of-market revenues to depress capacity prices. The commission suggested modifications to PJM’s fixed resource requirement (FRR) option could allow the removal of state-subsidized resources and corresponding amounts of load from the capacity market. The first round of filings in FERC’s “paper hearing” on the issue were filed in October (EL18-178). (See Little Common Ground in PJM Capacity Revamp Filings.)

Crane said the company could benefit from “market reforms” underway in PJM, including moving some or all of the Illinois plants into the FRR “so we can get better capacity treatment that matches state’s environmental needs.” He also pointed to the RTO’s effort to improve price formation and revise reserve curves.

“So, that’s why we are keeping more of an open position [and not doing more hedging on future prices]. We believe the market will strengthen,” he said.

The company said its nuclear fleet set an all-time production record for 2018, generating 159 TWh.

In response to an analyst’s question, Barron said it was unclear when FERC would act on changes to PJM’s capacity market.

“Clearly, there has been some delay in the schedule, and I think that’s a function of the transition at FERC,” she said, noting the death of former Chairman Kevin McIntyre, and Commissioner Cheryl LaFleur’s announcement that she won’t be nominated for another term.

“So, while they have been able to get out a number of important orders, others have lagged and the capacity market order [is] among them. … We really have no signal yet from them as to when we will see their final decision in that docket.”

Q4 Results, Investment Opportunities

Exelon’s net income for the fourth quarter of 2018 dropped to 16 cents/share from $1.94 a year earlier, while operating earnings rose slightly to 58 cents/share from 56 cents.

The company said it expects operating earnings of $3 to $3.30/share for 2019, based on growth in utility revenue, the impact of zero-emission credits on its New Jersey nuclear plants and previously announced cost reductions.

Exelon officials also discussed capital investments, the Pacific Gas and Electric bankruptcy and ERCOT’s declining reserve margin during the call.

The company’s Utilities unit expects to make $23 billion in capital expenditures through 2022, boosting its rate base by 7.8% annually.

Anne Pramaggiore, CEO of Exelon Utilities, said the company’s investment opportunities include electric vehicle infrastructure at Baltimore Gas and Electric, distribution automation at Commonwealth Edison and security investments “across the utilities.” It expects to spend about $900 million on cybersecurity, substation security and IT systems.

The company noted its Pepco Holdings Inc. unit could see increased electric load as a result of recently approved legislation in D.C. requiring all public buses and taxis to be zero-emission vehicles by 2045.

Everett LNG Terminal

CFO Joe Nigro said Exelon’s fourth-quarter acquisition of the Distrigas LNG terminal in Everett, Mass., will be “earnings negative” through 2021 because of a need for increased operations and maintenance spending. The company paid $81 million for the import terminal to ensure fuel supplies for its nearby Mystic Units 8 and 9.

Nigro said the terminal is “bundled” with Mystic and will begin to add to earnings when the plant’s cost-of-service contract with FERC Approves Mystic Cost-of-Service Agreement.)

“We are very clear that with any type of asset that is economically viable, we are going to work for solutions and ways to try to make that asset viable,” Nigro said. “But I think you’ve seen with our financial discipline that when we’ve had to, we’ve taken the stance of making the necessary change.”

ERCOT Reserve Margins

Jim McHugh, CEO of Constellation NewEnergy, Exelon’s competitive retail and wholesale supplier, said the company is seeking to profit from the volatility in forward prices in Texas PUC Responds to Shrinking Reserve Margin.)

“I think with the ORDC changes, you are just making the likelihood that scarcity is going to play a bigger role in where the summer prices go,” McHugh said. He said on-peak forward prices for summer 2019 rose by $15/MWh since the end of the third quarter but prices have “been more up and down” in the last month.

“I think what we are going to see the market do is really trade on a pretty volatile range as the assessment of how many scarcity hours there may” be varies, McHugh said.

The company “is keeping a relatively significant open position and capability to extract value as we see volatility occur,” Nigro added.

PG&E Bankruptcy

Nigro said the company is “actively following” the bankruptcy of PG&E, which is the sole off-taker of Exelon’s 242-MW Antelope Valley Solar Ranch. “We will remain diligent in protecting the contractual value of AVSR and the role that assets like ours have in California’s clean energy future,” Nigro said. “AVSR provides 3 cents/share to Exelon in operating earnings and is not significant to our credit metrics.”

Earnings call transcript courtesy of Seeking Alpha.

February 10, 2019

PJM Won’t Act on FTR Order Before Stay Ruling

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM won’t act on FERC’s order to rerun its July 2018 financial transmission rights auction unless the commission denies the RTO’s planned motion for a stay, officials told members Wednesday.

FERC’s Jan. 30 order rejected PJM’s request to waive rules requiring it to quickly liquidate GreenHat Energy’s FTR positions following the company’s default. The RTO liquidated only GreenHat’s FTRs settling in August, saying that selling all the positions immediately would increase members’ losses (ER18-2068).

CFO Suzanne Daugherty told the Market Implementation Committee on Wednesday that unwinding settlements of the company’s FTR portfolio could add $250 million to $300 million to the $186 million the RTO had earlier projected the default would cost members. Daugherty stressed that the calculations are preliminary and might vary significantly after PJM is able to rerun the results of the July auction. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

Deputy General Counsel Chris O’Hara said PJM will ask FERC to stay its order until it rules on the RTO’s request for rehearing or clarification, which will be filed before March 1.

Chris O’Hara, PJM & Suzanne Daugherty, PJM| © *RTO Insider*

“There’s a couple things we unquestionably need clarification from FERC on, assuming the order stands,” O’Hara said, noting members’ approval in January of a new mark-to-auction component for FTR collateral requirements. “Is FERC saying we should go back to the credit rules that existed in July?”

PJM filed the credit rule change with FERC on Jan. 31 (ER19-945). (See “FTR Mark-to-auction Credit Requirements OK’d,” PJM MRC/MC Briefs: Jan. 24, 2019.)

Ex Parte Communications

RTO officials are so alarmed by the impact of the ruling that Craig Glazer, PJM’s D.C.-based vice president of federal government policy, may have violated FERC’s ex parte rules. Commissioners Cheryl LaFleur and Richard Glick and their aides, along with Rachel Marsh, legal adviser to Chairman Neil Chatterjee, said Glazer attempted to speak to them about the issue in separate phone calls on Jan. 30, according to filings the three offices put in the docket.

Marsh and LaFleur aide Jessica Cockrell said Glazer called them for what he initially said was a “procedural update” on the case. “Mr. Glazer explained that PJM intends to file an emergency motion for stay, and also that the order may have significant financial implications for PJM members and require inclusion of relevant amounts on members earnings reports,” Cockrell said.

Glick said Glazer “indicated that PJM was going to issue a press release pointing out that the commission’s order was going to cost its members hundreds of millions of dollars. I told Craig that I was aware of the proceeding and that it remains an outstanding issue and that we should not discuss it. He followed up by noting that PJM was going to file an emergency order with the commission seeking a stay of the Jan. 30 order. I reiterated that we should not discuss this matter until the proceeding is concluded and he agreed. We then ended the conversation.”

PJM spokeswoman Susan Buehler denied that Glazer was attempting to lobby the commissioners.

“As the filed record indicates, Craig contacted commissioners to give them a procedural update on the order which could have a significant impact on PJM members. He wanted to make sure they knew PJM intended to make several filings,” Buehler said in an email. “Regarding the ex parte filing, PJM understands the need for sensitivity when addressing procedural matters with the commission.”

‘Disappointed’ in Delay

O’Hara said the RTO was disappointed that it took FERC six months to rule on the waiver request. “They could have ruled within 30 days. Waiting six months obviously makes [unwinding FTR settlements] more complicated,” he said.

Direct Energy’s Marji Philips asked O’Hara why the RTO did not ask the commission for expedited treatment for the waiver request. “Fair question,” O’Hara responded. “I’ll have to look into that.”

FERC ordered PJM to rerun the auction conducted in July under Tariff rules requiring it to offer all of GreenHat’s FTR positions at a price designed “to maximize the likelihood of liquidation.” That means including liquidation offers for all GreenHat’s FTR positions for August 2018 through May 2019, instead of just the prompt month.

The order also requires PJM to recalculate the default allocation assessments made based on GreenHat FTRs that went to settlement between September and January 2019 if those FTRs get liquidated as a result of the rerun of the July auction.

PJM’s Tim Horger said the RTO, which has never rerun a cleared FTR auction, is still evaluating potential implications of the ruling. “You’re going to have … auctions [after July] where members sold positions they never owned,” he said.

Because the FTR portfolios of participants who traded in the July auction will be revised, the reshuffling is expected to trigger credit collateral calls.

The revised results also will cause FTR auctions from August 2018 through January 2019 “to become infeasible solutions,” violating the simultaneous feasibility test, PJM said.

The RTO will have to make billing adjustments reflecting revised default allocation assessment charges since Aug. 1 — revisions that may cause additional members to default.

There could be additional briefings in the docket regarding how PJM can remedy the violations, O’Hara said. “We’re not entirely sure what to do.”

Suzanne Daugherty, PJM | © *RTO Insider*

Daugherty said the RTO believes the order only requires it to rerun the July 2018 auction for August because the auctions from September forward were under revised rules approved by the commission.

In October, the commission approved PJM’s requests to change its rules so it wouldn’t have to immediately offer any GreenHat positions for liquidation after Aug. 24. (See FERC OKs Key PJM Changes to Address GreenHat Default.)

FERC last week approved PJM’s request to withdraw an earlier petition to allow bilateral counterparties the option to assume indemnified positions (ER19-24). The RTO made the request after FERC issued a deficiency notice seeking more information on its indemnification procedures.

Potential default allocation assessment implications of FERC’s order denying PJM’s waiver request | *PJM*

In asking to withdraw its filing, the RTO said “the proposal does not provide sufficient benefits to the PJM membership to justify PJM continuing to seek approval.” The commission acted over the opposition of Shell Energy, which said the withdrawal would prevent the commission from ruling on its dispute with the RTO over existing indemnification rules. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

The commission also rejected Shell’s request to institute a Section 206 proceeding but said “Shell remains free to file a complaint.”

February 10, 2019

NERC Member Representatives Committee Briefs: Feb. 6, 2019

By Tom Kleckner

Stakeholders Get First Peek at Report on Supply Chain Risks

MANHATTAN BEACH, Calif. — NERC stakeholders last week got a first look at a draft report on supply chain risks as part of a FERC directive to develop a standard addressing risk management of the industry’s vendors.

Roy Thilly, chairman of NERC’s Board of Trustees, called the initiative a “very important undertaking,” but he also cautioned that it is not a “silver bullet.”

Supply chain risk management “requires a practical, effective, measured response,” he said during the NERC Member Representative Committee’s Feb. 6 meeting.

The NERC MRC met Feb. 6. | © *RTO Insider*

NERC staff have been working with the Electric Power Research Institute to assess the bulk electric system’s (BES) product and manufacturer types, analyze BES cyber assets, and gather best practices and standards used by other industries to mitigate supply chain risks.

At the board’s request, the North American Transmission and Generator Forums and other industry groups have developed white papers, which can be found on the initiative’s website.

The report suggests applying industry practices to third-party accreditation processes; ensuring that hardware and software are protected during physical transport; using processes to mitigate risks from unsupported or open-sourced technology components; and using supply chain controls to address common-mode vulnerabilities.

Staff are recommending the standards include electronic access and physical access controls for medium- and high-impact BES cyber systems, and to collect more data on low-impact BES cyber systems. They also plan to monitor emerging technologies for new risks.

Howard Gugel, NERC’s senior director of engineering and standards, said the industry’s reliance on technology and the use of single platforms to host multiple applications has increased the risk of access through “the back door.”

Despite that, he said he would be reluctant to certify particular third parties.

“I’m not sure we as the reliability regulator would want to get into any sort of third-party endorser of people selling in the market,” Gugel said. “However, if there are third-party options for providing that, we’d certainly like to be involved with it.”

FERC ordered NERC in 2016 to draft a “new or modified” standard addressing supply chain risk management for industrial control system hardware, software, and computing and network services associated with the BES. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.)

NERC responded with three supply chain standards — CIP-005-6, CIP-010-3 and CIP-013-1 — which FERC approved in October 2018. (See FERC Finalizes Supply Chain Standards.)

Staff are still accepting comment on the report. A final draft will be presented to the board in May.

Members Elect 4 Trustees to Board

The MRC elected the board’s class of 2022, filling a vacancy created to add a Canadian trustee and re-electing three incumbents to three-year terms.

Colleen Sidford will step into the Canadian vacancy. She spent 10 years with Ontario Power Generation in various financial positions, following a career in international banking.

NERC is required to have two Canadian trustees. It has three with Sidford’s election, but it is expected to reduce the number to two when Fred Gorbet’s term expires next year. That will also leave NERC with 11 trustees.

Re-elected to three-year terms were:

Robert Clarke, who has served on the board since 2013. He chairs the Corporate Governance and Human Resources committees and serves on the Enterprise-wide Risk and Nominating committees.
Ken DeFontes, a trustee since 2016. He is the liaison to the Standards Committee and serves on the Compliance and Technology and Security committees.
David Goulding, who was first elected to the board in 2010. He chairs the Enterprise-wide Risk Committee and serves on the Finance and Audit Committee.

NERC’s trustee succession policy provides that no independent trustee may be re-nominated or re-elected if he or she has served 12 consecutive years.

Ford, Sterling Step into New Leadership Positions

The meeting marked Greg Ford’s first as MRC chair. Ford, CEO of Georgia System Operations Corp., replaces Wabash Valley Power Association’s Jason Marshall, who cycled off the committee.

Jennifer Sterling, vice president of NERC compliance and security for Exelon, is serving as vice chair.

MRC Vice Chair Jennifer Sterling and Chair Greg Ford | © *RTO Insider*

NERC Develops Participant Conduct Policy

NERC General Counsel Charles Berardesco shared with the MRC the organization’s Participant Conduct P ol i cy, which is applicable to participants in all organization activities. The policy was based on similar rules for the NERC Operating Committee and standards development process.

However, the policy doesn’t apply to the MRC itself, Ford said. “The MRC is a creature of the bylaws,” he explained.

Berardesco said the policy will create a professional environment for all participants supporting NERC’s mission, including standing committee members and observers, drafting team members and observers, and other stakeholder volunteers that participate in the organization’s activities or groups.

The policy calls for those it covers to conduct themselves in a professional manner, not to use NERC activities for commercial or private purposes, and not to distribute confidential information or certain work products.

February 10, 2019

Stakeholders Seek Slowdown on MISO RAN Project

By Amanda Durish Cook

CARMEL, Ind. — Stakeholders are urging MISO to slow down on bigger ideas to address its disjointed resource availability and need (RAN) until it can measure the effects of three smaller related filings pending before FERC.

For the remainder of this year and through 2020, MISO’s Market Subcommittee and Resource Adequacy Subcommittee will discuss long-term methods of shoring up resource availability as reserve margins decline.

Speaking at a Feb. 5 RASC meeting, MISO Director of Resource Adequacy Coordination Laura Rauch said most of the discussions will take place independently, though the RTO may schedule joint MSC and RASC meetings on the topic.

MISO recently filed new near-term rules for load-modifying resources (LMRs) and planned outages to buy time for more comprehensive solutions. Up to the filings, stakeholders had also urged a slower approach to developing those rules. (See MISO Files New Planned Outage Rules.)

Nearly a month later, MISO is ready to take on the broader proposals, which may include changes to the annual capacity auction, loss-of-load expectation study and capacity accreditations. It said the second and third phases of the project will address “gaps in the efficient conversion of committed capacity to energy.”

So far, a number of stakeholders maintain that MISO’s timeline on the multifaceted project is too aggressive, with some saying that it should evaluate the effects of its LMR and outage filings before it moves on to long-term remedies.

“A lot of comments focused on that we’re moving too fast; the two phases are being rushed. … We do plan on working through the stakeholder process over the next few months to make sure that any solution is vetted,” MISO planning adviser Davey Lopez told stakeholders at a Feb. 6 RASC meeting.

MISO Executive Director of Market Development Jeff Bladen said the RTO is starting conversations now with an eye on recommending long-term solutions within a year and a half.

“This is a marathon, not a sprint,” Bladen said.

“At what point does MISO declare victory? Is there some point where there’s enough of a buffer that MISO stops making changes?” asked Bill Booth, consultant to the Mississippi Public Service Commission, adding, “We’re moving at warp speed.”

Rauch said the RTO will continue determining whether improvements are enough to maintain reliability by gauging whether increasingly frequent maximum generation events are more accurately predicted and managed.

“The goal is not to eliminate all emergency conditions. That’s part of our normal operations,” Rauch added.

Lopez said MISO plans to analyze the impacts of the LMR and outage filings and compare upcoming capacity auction results with prior year auctions before it proposes any changes to capacity accreditation. MISO has said it will investigate adjusting capacity accreditation “based on the ability to resolve resource risk.”

Seasonal LOLE?

Lopez asked for stakeholders’ written feedback on the usefulness of a seasonal capacity construct, an idea long pondered in MISO. The RTO last proposed a two-season capacity auction in mid-2016 before talks stalled, and stakeholder appetite for a revised proposal resurfaced last year.

Some stakeholders said MISO’s loss-of-load expectation (LOLE) study could use improvement if the RTO moves to a capacity auction structure based on either two or four seasons.

Multiple stakeholders said MISO should first examine possible technical changes to the LOLE study — which is based on an annual summer peak — in light of moving to a one-day-in-10-year reliability standard based on seasons.

“Without basic technical LOLE work, I don’t know if we can start the discussion. … I think that needs to be upfront before we can even start on the policy of this,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “Software can spit out any number you want to. That doesn’t mean you’re getting the right result on your statistical theory.”

Rauch said MISO would have to conduct research to determine which LOLE inputs and calculations would be appropriate.

Jeff Bladen answers stakeholder questions from the audience | © *RTO Insider*

A seasonal construct also raises the question of whether interconnection service should be divided by seasonal availability, Lopez said. He also said stakeholders should consider whether they prefer a single annual action with seasonal offers or multiple separate seasonal auctions.

Independent Market Monitor staff Michael Chiasson said a seasonal auction would satisfy some IMM recommendations, particularly its longstanding recommendation that resources be accredited according to their ability to deliver across varying conditions.

A day later at a Feb. 7 Market Subcommittee meeting, Bladen insisted that MISO doesn’t currently have a load forecasting problem, but an uncertain resource availability problem.

“It’s not the uncertainty itself that’s increasing. It’s the nominal impact of that uncertainty that’s increasing,” Bladen said.

Beyond LMRs

Stakeholders also asked if MISO will begin focusing on other resources besides LMRs, inquiring about possible changes to the modeling or accreditation of baseload or intermittent resources.

MISO staff said a wide array of changes are on the table and that the RTO might also consider incentives for LMRs with shorter lead times.

“We’re going to let the advice from this committee guide us,” Bladen told the RASC. He later added that while stakeholders and MISO may not have the time to examine upwards of 30 solutions, there’s still a “veritable menu” of options.

MISO said stakeholders may want the RTO to further incentivize economic demand response and improve its scarcity price formation. It also said it could reduce capacity accreditation for long-lead resources.

MISO plans to continue the RAN discussion at the March RASC and MSC meetings.

February 10, 2019

MISO Preliminary PRA Data up Slightly from Early Prediction

By Amanda Durish Cook

CARMEL, Ind. — MISO’s recent resource adequacy filings with FERC will affect the timeline of an otherwise unremarkable capacity auction in terms of load forecasts, stakeholders learned last week.

MISO staff confirmed the 2019/20 Planning Resource Auction numbers haven’t moved much from the previous planning year, in line with estimates made last month. (See Early MISO PRA Data Show Little Change.)

The RTO predicted systemwide coincident peak load will be about 122 GW for the period, up from the 121.6-GW prediction made in January for the planning year. The RTO’s total zonal coincident peak now stands at 125.6 GW, up from an earlier 125.3-GW prediction.

MISO now estimates an almost 135-GW planning reserve margin requirement, also up from the earlier 134.4-GW estimate. Similarly, combined local resource requirements are up slightly from 152.6 GW to nearly 153 GW.

“A lot of the data is pretty close to the data we presented in January,” Tim Bachus, MISO capacity market administration analyst, said during a Feb. 6 Resource Adequacy Subcommittee meeting.

Final preliminary data will be presented during the March RASC meeting. MISO will conduct its seventh annual PRA during the second week of April.

In some cases, PRA data deadlines have already passed for resources hoping to participate in the auction — particularly load-modifying resources. Generation owners were also expected to provide the Independent Market Monitor with data to calculate reference levels by Feb. 12, while load-serving entities have until Feb. 15 to request revisions to their coincident peak demand figures.

LMR Registration Confusion

Existing and new LMR registrations, usually due Feb. 1 and Feb. 15 respectively, will be due March 1 only if FERC approves a Tariff filing meant to ensure LMRs are available as promised. MISO said it expects FERC to rule on the matter by Feb. 20, and a more detailed LMR registration survey under the RTO’s proposal is available now.

If the filing is approved, MISO will ask some LMRs with a lead time greater than two hours and that are available fewer than nine months out of the year to submit their monthly megawatt availability and a documented required notification time necessary to begin generating. (See MISO Moves to Examine Long-term Supply Measures.) MISO will allow LMR owners that have already registered their asset according to the current Tariff to amend their registration surveys.

If FERC rejects the filing, MISO will revert to its current LMR registration process, with LMRs not already registered disqualified from auction participation.

Some stakeholders said the competing timelines are creating confusion. Others pointed out that several LMRs have already submitted registration in accordance with MISO’s current Tariff. MISO staff said it would reopen registrations to make sure the new data requirements are met if approved.

Manager of Capacity Market Administration Eric Thoms reassured stakeholders that, should FERC reject the filing, the RTO would not use LMRs’ additional data, and the current process would stand without change.

Stakeholders asked if MISO was satisfied with this year’s load forecast data supplied by LSEs.

“There are always a few numbers that might be outside the curve,” Bachus said, adding that MISO determined there were good reasons for the discrepancies after reaching out to LSEs.

“In the end, there were no concerns about any numbers that may have seemed out of line,” Bachus said.

As in years past, stakeholders continued to question why MISO combines the forecast data for Iowa and Missouri in Local Resource Zones 3 and 5 and all of MISO South. The RTO has long combined PRA data in zones where pivotal suppliers are sparse and their private information could be revealed. Stakeholders again asked MISO to separate the data by zone to provide a clearer picture of resource adequacy.

Meanwhile, MISO will on March 25 send out its annual resource adequacy survey in cooperation with the Organization of MISO States. Completed surveys are due from LSEs and independent power producers by April 15. The RTO will present results in June and July.

February 10, 2019

MISO Details ‘Uncertainty’ Behind Winter Max Gen Event

By Amanda Durish Cook

CARMEL, Ind. — MISO proactively managed its eighth maximum generation event in six years last month despite the difficulty of pulling together the forecast leading up to the episode, RTO staff reported last week.

Ron Arness, MISO director of Central Region operations, said “a significant amount of uncertainty” characterized the Jan. 30-31 event, spurred by a polar vortex bringing record cold conditions.

High load, fuel supply issues and the possibility of equipment failure coupled with substantial voluntary load management, such as school and business closings, made load profiles uncertain over the period, Arness said. MISO called the maximum generation event beginning 2:38 a.m. ET on Jan. 30 and terminated it at 11 a.m. the following day.

“We had some extreme temperatures … and because of the actions of you as members and MISO took, we reliably maintained service. It was essential because public safety was critical at that time,” Arness told stakeholders at a Feb. 7 Market Subcommittee meeting.

MISO originally forecasted a 104-GW peak load on Jan. 30, though the actual peak clocked in at 101 GW as temperatures sunk to -30 degrees Fahrenheit in some parts of the balancing area.

“We thought we were going to be short, and then we weren’t,” Arness said. “Even though temperatures were colder than we predicted, this voluntary load curtailment” scaled down load.

To produce its regional weather forecasts, MISO uses two separate third-party weather forecasters, both of which rely on multiple weather models.

MISO said that for much of the event, it experienced increased imports in response to its emergency conditions pricing. On Jan. 30, spot natural gas prices nearly doubled to $7.42/MMBtu and the average real-time LMP quadrupled to about $108/MWh. By Jan. 31, the real-time LMP dropped to about $49/MWh, still about double the energy price two days prior.

The RTO entered a cold weather alert on Jan. 25, an important and proactive step, Arness said. (See MISO Maintains Reliability Through Arctic Midwest Temps.)

“Really the intent of that cold weather alert is so members can update their offers and unit availability,” Arness said, stressing that MISO is better able to manage the market with the most accurate offer and commitment information.

“Thank you to all your companies that worked so hard to keep the lights on,” Chris Miller, of FERC’s Office of Energy Market Regulation, told members.

Winter Winds, but Few to Harness

MISO operators were further stymied by lower wind generation than expected during the arctic blast.

Wind output during the morning peak Jan. 30 was about 4 GW below forecast as the worst of the cold struck the Midwest. Wind output averaged 4.3 GW and 4.7 GW on Jan. 30 and 31, respectively, compared with about 13 GW for the two days prior to the event.

“It was cold and the wind was blowing, but we suspect that there were significant cold weather cutoffs. We did expect some cutoffs due to the cold — about 1 GW — but we didn’t expect this magnitude,” Arness said.

“This is something we have not seen since MISO has been in existence,” he added.

Arness said MISO staff will continue to investigate the drop in wind output, as well as other factors during the event. The RTO will review wind generator availability during cold temperatures, including maintaining a list of wind generators that have cold weather shutoffs installed, he said.

“What we’re looking for is lessons learned and to enhance our preparedness for future events,” Arness said.

LMR Data Forthcoming

All told, MISO requested about 2,500 MW worth of load-modifying resources during the event. LMR performance reports are expected later.

Stakeholders asked if MISO would consider decoupling its LMR dispatch from its emergency operating procedures so LMRs can be used outside of a declared emergency. Under MISO’s emergency procedures, LMRs are classified as emergency-only resources, requiring the RTO to declare an emergency before dispatching them.

Executive Director of Market Operations Shawn McFarlane said a December Tariff filing would allow MISO to issue scheduling instructions for LMRs as early as 12 hours ahead of a called emergency, allowing the resources to activate and be ready to deploy during an emergency.

Stakeholders questioned whether MISO remains confident about in that approach.

“We can’t deploy emergency resources when it’s not an emergency,” Executive Director of Market Development Jeff Bladen said.

Arness said MISO will continue to dissect the event with stakeholders in public meetings later in February and March.

Customized Energy Solutions’ David Sapper asked for a pricing analysis around the event, given that average energy prices two days before the event hovered around the usual $26/MWh and $27/MWh, even as temperatures ranged from -20 to 2 F.

MISO staff promised to return with more pricing information.

February 10, 2019

CAISO Raises Stakes for Intertie Non-delivery

By Hudson Sangree

FOLSOM, Calif. — CAISO’s Board of Governors unanimously approved a proposal Thursday meant to ensure that bidders from outside the ISO deliver electricity as promised or face more stringent financial penalties.

The Board of Governors met Thursday at CAISO headquarters in Folsom, Calif. | © *RTO Insider*

“The existing charge [for non-delivery] is relatively ineffective,” Brad Cooper, CAISO’s manager of market design policy, told the board in his presen t ation. That’s because participants rarely exceed a 10% monthly threshold when the charge kicks in. The new policy does away with that threshold.

Currently, “if intertie declines are less than 10% of total transactions, no charge applies,” the ISO wrote in an Aug. 15 issu e paper. Anything more than a 10% failure-to-deliver rate can result in a charge of up to $10/MWh.

The lack of a financial incentive to follow through on bids can cause headaches, CAISO said in the paper.

“When an intertie resource receives a market award to import energy into the balancing authority area but does not deliver the awarded energy, the grid operator must maintain system balance by increasing internal supply or finding another intertie resource to import from,” it said.

Brad Cooper, CAISO’s manager of market design policy, briefs governors on a plan to raise the stakes for bidders that don’t deliver on intertie bids. | © *RTO Insider*

Grid reliability and stable pricing depend on expectations being met, Cooper said at Thursday’s board meeting.

“When exports don’t deliver, they can cause intertie congestion,” he said. And “undelivered imports in a critical hour can have a big effect.”

The revised policy is also meant to curb speculative bidding — when a market participant submits a bid and doesn’t deliver because it can’t find the energy it promised or can’t find it at the right price.

When the 10% threshold was enacted in 2007, ISO computers couldn’t distinguish between an intertie “decline” and a reliability curtailment, officials said. That meant that reliability curtailments, which weren’t the fault of the market participant, could still count toward the decline charge.

The bar was set high at 10% to avoid penalizing participants who were unable to deliver because of unforeseeable problems.

Now the ISO’s system can distinguish between curtailments and non-deliveries, meaning the 10% threshold can be eliminated. Instead, non-delivery charges will be assessed in 15-minute intervals and “non-delivery will be subject to a charge equal to 50% of the maximum of the 15-min market or the five-minute real-time dispatch LMP, with a $10/MWh minimum, plus any imbalance energy,” according to the ISO.

Cooper said most stakeholders supported the plan as a way to reduce speculative bidding and to enhance reliability.

Recently appointed CAISO Governors Mary Leslie and Severin Borenstein attended their first board meeting Thursday. | © *RTO Insider*

Severin Borenstein, a University of California Berkeley pro f essor attending his first meeting as a newly appointed CAISO governor, asked planners to clarify why the charge applies to interties but not inside the ISO’s system.

Keith Casey, CAISO’s vice president for market and infrastructure development, explained that if an intertie bid — always scheduled an hour ahead of delivery — doesn’t materialize, the ISO can’t clear additional intertie energy until the next hour, but internally it can resort to the five-minute market to cover the shortfall.

February 10, 2019

NYPSC Approves $32 Million for EV Fast Chargers

By Michael Kuser

The New York Public Service Commission on Thursday authorized utilities to spend $31.6 million to build up to 1,075 fast-charging electric vehicle stations and recover costs from ratepayers over seven years (18-E-0138).

The program is intended to help spur sales of EVs by reducing people’s “range anxiety” — the fear of running out of juice on the road — and to achieve Gov. Andrew Cuomo’s Charge NY goal of 10,000 EV charging stations by the end of 2021 and 800,000 zero-emission vehicles by 2025.

The commission’s Feb. 8 order outlines a flow of actions, including annual reviews, that “are smart and timely steps to enable new and needed infrastructure at sensible budgets and at sensible payment structures,” PSC Chairman John B. Rhodes said. “It puts a wide range of partners in a position to invest their money in our agenda for the benefit of all New Yorkers.”

The PSC last April approved a seven-year tariff for Consolidated Edison’s quick-charging station program (17-E-0814). (See NYPSC OKs Con Ed EV Charging Program, REV Initiatives.)

In a related case (18-E-0206), the PSC in November rejected tariff filings for residential EV charging from all the major utilities in the state and ordered them to file revisions that implement time-of-use rates equal to the traditional residential customer charge. (See NYPSC OKs CCA, Rejects Residential EV Charging Tariffs.)

The new proceeding grew out of a joint petition last April by the New York Power Authority, along with the state’s Department of Environmental Conservation, Department of Transportation and Thruway Authority, seeking rate relief for DC fast-charging (DCFC) facilities for EVs.

The state’s Department of Public Service held a technical conference on the issue last summer, and in November the utilities joined the state agencies in filing a consensus proposal for the program.

Rate Design

Mary Ann Sorrentino, chief of electric rates and tariffs for the DPS, testified that rate design was the PSC’s main concern.

“To capture cost savings from potential technology cost declines, the draft order requires that initial incentive amounts be tied to the year in which the station qualifies for the program,” she said.

Sorrentino said plugs must have a 50-kW minimum charging capability to qualify for the program and that higher incentives will be provided to plugs with a minimum simultaneous charging capability of 75 kW.

Within 90 days of Thursday’s order, the New York State Energy Research and Development Authority must disburse the $31.6 million in unencumbered legacy system benefits charge (SBC) funds to the state’s six regulated utilities in the following amounts: Con Ed ($6.4 million); Orange and Rockland Utilities ($1.66 million); Central Hudson Gas & Electric ($4.4 million); Niagara Mohawk Power ($9 million); New York State Electric and Gas ($5.1 million); and Rochester Gas & Electric ($5 million).

The SBC provides funding for NYSERDA programs targeting energy efficiency, research and development and the low-income sector.

Commissioner Diane Burman brought up the $128 million New York received as its share of Volkswagen’s national settlement for flagrant emissions standards violations, which the state has earmarked for clean transportation measures such as promoting EV use.

“I understand there’s a separate track for that; I’m not looking to get involved in stuff that’s outside our jurisdiction,” Burman said. “To the extent that it complements us … it is extremely important that we are complementing each other in a way that makes sense. Here we’re talking about taking unencumbered legacy funds that seem to never, ever be ending over at NYSERDA, and utilizing them now for part of this.”

The state estimates EV sales were up 50% last year from 2017, with more than 43,000 EVs on the road by October, one-third of them battery electric and the rest plug-in hybrids.

“EVs, as is well known, have a chicken-and-egg problem,” Commissioner Gregg C. Sayre said. “Chargers aren’t being built because there aren’t enough EVs, and EVs aren’t being bought because there aren’t enough chargers. This item helps us get out of that cycle.”

Notable Differences

The PSC decided to minimize some of the “notable differences” contained in the consensus proposal.

“For example, pursuant to the consensus proposal, the Con Ed and Orange and Rockland per-plug incentives were to provide a combined benefit in conjunction with delivery rate discounts offered under the Business Incentive Rate [BIR] and Economic Development Rate, respectively, whereas the other utilities’ per-plug incentives were designed assuming that DCFC stations will not receive other delivery rate discounts,” Sorrentino said.

The Con Ed and O&R proposals were also unique in that they contained a separate load-factor incentive whereby station owners would earn a $500 incentive annually for achieving a 5% load factor, and $1,500 annually for achieving a 10% load factor, she said.

The commission found “the load-factor incentive to be unnecessary at this time, as station owners have a natural incentive to maximize station utilization,” Sorrentino said.

Under Con Ed’s tariff, the BIR was available to owners of EV quick-charging stations with a minimum aggregate charging capacity of 100 kW and a maximum aggregate demand of 2,000 kW in New York City and Westchester County.

“This BIR has been open to electric vehicle quick-charging station developers since April, and that market has not materialized,” testified Bridget Woebbe, assistant counsel for the DPS. “Removing the restrictions really allows site hosts that are providing a direct capital investment by building the critical infrastructure to receive the appropriate incentive to deliver the public good of the DCFC.”