EUCI Panelists: Midwest Tx Plans Must Address Wind, Seams

By Amanda Durish Cook

INDIANAPOLIS — Two topics dominated the discussion this week among industry leaders, RTO officials and transmission planners attending EUCI’s Transmission Expansion in the Midwest conference.

One: The region must focus its transmission expansion efforts on moving wind output from vast resource areas in the west to population centers in the east.

And two: To support that effort, industry participants must overcome ineffective interregional processes among RTOs.

“You’ve got a lot of cheap wind resources where not a lot of people are — Minnesota, the Dakotas, Iowa — and you have to get this clean, affordable energy to where the people are,” Betsy Beck, director of transmission policy for the American Wind Energy Association, said during a Dec. 4 panel discussion. “There’s not enough transmission capacity to move it east where it’s needed.”

Beck said 35 GW of wind capacity is expected to come online in the U.S. by the end of 2020, joining the nearly 85 GW of current wind capacity. She noted that 20-year power purchase agreements are being signed in the Great Plains for less than $20/MWh.

Adam McKinnie, chief economist with the Missouri Public Service Commission, said he has observed a pattern of central states trying to push wind energy toward eastern states where power is more expensive. The eastern states, in turn, claim they can solve their resource adequacy and public policy goals by building new generation and won’t need the imports.

“How do you solve that?” McKinnie asked.

“That’s kind of the million-dollar question,” Beck laughed. “D.C. and the East don’t have a lot of space in their backyards for renewable development, and I think these states are starting to realize that.”

MISO interregional adviser Adam Solomon said the RTO’s 2018 Transmission Expansion Plan will include a new study on the impacts of renewables while also focusing on wind development needs and seeking to predict where future projects are likely to be sited. “We’ll try to find the trend within our footprint and better predict how that’s going to move in the future,” he said.

Seams and Order 1000

An effective wind transmission network in the Midwest will require interregional projects, conference panelists agreed.

Over the past year, MISO has worked with both PJM and SPP to identify large interregional projects, but the two separate efforts failed to produce a viable candidate after identifying just two serious contenders. (See MISO Confident in Tx Process with SPP Despite Lack of Projects.)

“Interregional projects have remained elusive,” Solomon said.

PJM Manager of Interregional Planning Chuck Liebold said MISO and PJM will try again next spring to identify a large interregional project, commencing another two-year coordinated system plan between the RTOs. Officials from both RTOs last week announced that the next Order 1000 project submission window will open in November 2018.

“All that study, hours and hours of analysis, and we have yet to pass a big interregional project,” Liebold said. “We have 200-something joint coordinated flowgates on the MISO-PJM seam. … It seems like there’s a natural area where there could be joint coordination on a project, but that hasn’t happened yet. There are some issues with our process that we keep ironing out over the years.” He also reminded attendees that “there’s no measuring stick that says you have to have an interregional project.”

“I don’t think people understand how jagged the seams are,” McKinnie said.

“I think it’s safe to say that meeting the goals of Order 1000 so far today have been elusive,” said Alan Meyers, ITC Holdings director of regional planning.

Order 1000 has failed to “uniformly encourage” transmission development and may actually be stifling it, he said. “I think there’s a tendency to focus on the competition rather than the planning and cost allocation. The competition is only the sizzle, but the planning and cost allocation is the steak.” ITC has transmission holdings in MISO, PJM, SPP and NYISO.

Meyers criticized RTOs’ past “arbitrary” cost allocations and voltage thresholds on interregional projects but said practices are improving. He said that while RTOs excel at regional transmission planning, they come up short when trying to plan interregional projects. “It may be the biggest area we can improve on,” he said.

Some audience members asked about the next steps for the $2.3 billion Grain Belt Express, a 780-mile HVDC transmission line that would move wind energy from the Midwest to eastern markets. Developer Clean Line Energy Partners last week asked the Missouri Supreme Court to review state regulators’ decision to refuse a development permit. The Grain Belt Express did not result from an RTO process and is not seeking cost allocation.

Mark Lawlor, Clean Line’s vice president of development, said that while SPP and MISO are creating small west-to-east lines, those projects don’t go far enough — literally.

“They’re needed, but they’re not connected. There’s failure to create a process that allows for interregional projects such as the one Clean Line is developing. There’s not a place for us. … Perhaps that’s for Order 1001,” he joked. “I don’t want to say this hasn’t gone right, but there’s no mechanism to facilitate these projects.”

Lawlor added that Order 1000 is still young and “really only created competition for a fraction of the transmission projects out there. There could be more room for competitive projects.”

TMEPs

MISO and PJM are poised to approve a five-project interregional portfolio this year, but it doesn’t contain the extended HVDC lines for which some in the industry had hoped.

This month, the RTOs’ boards of directors are expected to individually approve their targeted market efficiency project (TMEP) portfolio, composed of smaller, congestion-relieving interregional projects. PJM and MISO worked for three years to define the project type before getting FERC approval this year. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)

All five TMEP projects this year are upgrades to existing systems. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined.

On average, project costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million.

“I think what MISO and PJM have done with TMEPs is prove that they can get something done. And I hope they’re not too discouraged that they don’t yet have a large interregional project,” Beck said.

However, Beck maintains that large, public policy interregional projects are going to be vital for the future of the Midwest, but unwieldy seams criteria and differing public policies will hold them back. “By having different rule sets, they create a lot of impediments,” she said.

“A lot of consensus will be needed,” Solomon said.

“As soon as they solve public health care, they’ll start in on public transmission policy,” Liebold joked.

“In the future though, we need to really look at what the Eastern Interconnect looks like and how we can move large amounts of power,” Beck said. She predicted that a handful of new HVDC lines will begin to take shape in the next few years, with others to follow.

“There’s a lot of folks out there that also think that microgrids are the wave of the future, and we don’t need any more transmission projects, and we should begin to take lines down, so I’m not betting just yet,” Liebold said.

McKinnie asked why MISO and SPP haven’t created their own TMEP process to deal with smaller congestion issues along their seam. Solomon said the TMEP process was largely driven by Northern Indiana Public Service Co.’s 2013 complaint against the MISO-PJM interregional planning process, but that MISO would like to implement a similar smaller interregional project type with SPP.

“So if I went back to commission and said the ‘squeaky wheel gets the grease,’ would that be correct?” McKinnie asked.

Solomon said that SPP is a relatively young RTO with less historical data, and while he thinks some SPP stakeholders might not be ready for such a cross-seams project type, he is hopeful they will be convinced of the benefits by observing the progress between MISO and PJM.

“I don’t want there to have to be a FERC complaint for this to get attention. We used to joke that the MISO stakeholder process was a FERC comment period. … We sometimes feel that we’re the kid sibling over on the SPP-MISO seam,” McKinnie said.

Bob Pauley, chief technical adviser with the Indiana Utility Regulatory Commission, urged gentler treatment of RTOs that must plan transmission systems with sometimes limited information.

“I don’t know of any empirical evidence where an RTO developed transmission where there was a better option available.

“I think it behooves us to remember the time before RTOs,” he reminded attendees, before adding jokingly, “When I worked with Thomas Edison and others, each utility had to plan their own needs as if they were an island.”

Pauley said “everyone would be better off” if utilities used the same degree of candor with RTOs as they do with their respective state regulatory bodies. He also said states should take a more active role in forecasting load.

Wind Catcher

American Electric Power’s Raja Sundararajan said his company’s $4.5 billion Wind Catcher project in Oklahoma is also bypassing the RTO transmission planning process in favor of self-funding to ensure it is realized. The project includes what will be the largest wind energy facility in the U.S at 2 GW and a dedicated 350-mile, 765-kV tie-line from the panhandle to Tulsa.

“This is the largest investment AEP has ever made; $4 billion is a massive amount, and we understand that,” Sundararajan said. He pointed out the project circumvented the RTO process because AEP did not have enough time to mount a complex transmission planning process for an expensive 765-kV line before wind production tax credits expire in 2020.

AEP settled on a 765-kV rating because it minimizes transmission line losses and doesn’t require converters, he said. Although AEP has not yet established a preferred route, most of the 350-mile stretch is located on farmland in Oklahoma, Arkansas, Louisiana and Texas. The company is planning to use 25-year extendable land leases with landowners. Regulatory approval is needed in all four states, which AEP hopes to obtain by April.

“Are we the only ones doing this? No. Especially in the Midwest, wind farms are so economical, especially for the ratepayer,” Sundararajan said, pointing to current wind projects by Public Service Company of Colorado, Northern States Power, Southwestern Public Service, MidAmerican Energy, PacifiCorp and Empire District Electric.

One audience member asked how AEP balances the massive wind project with apparently competing support for coal and nuclear subsidies.

“I’m not aware of it. I’m a transmission guy,” Sundararajan replied.

December 7, 2017

DOE: German Energy Struggles Sparked NOPR

By Rory D. Sweeney

PHILADELPHIA — The U.S. Department of Energy’s proposal to save coal and nuclear generating plants is intended to avoid a repeat of Germany’s energy woes, Under Secretary Mark Menezes told a PJM General Session on Wednesday.

DOE NOPR nuclear power German Energy — PJM’s Craig Glazer moderated the first panel at the PJM General Session, featuring FERC Commissioner Rob Powelson, DOE Undersecretary Mark Menezes and Jason Stanek, senior counsel for the House Energy Subcommittee. | © *RTO Insider*

Menezes recounted an international energy meeting this spring, where he said Energy Secretary Rick Perry and Secretary of State Rex Tillerson listened as German officials recounted economic hardships created after the country renounced nuclear power following the 2011 Fukushima nuclear disaster. To mitigate the price spikes, Germany built plants to burn lignite, a lower-quality coal than the traditional anthracite used at most coal-fired facilities.

“They are digging up lignite all over Germany. I have nothing against lignite, but you’ve got to dig up an awful lot of lignite to get the BTU content to produce [power],” Menezes said.

He said German officials told Perry: “If in fact you believe in what you’re saying in [using] ‘all of the above’ [energy resources], please stick to ‘all of the above.’ Try to avoid what happened here.”

FERC Commissioner Robert Powelson, speaking after Menezes, said PJM looms large in his deliberations on DOE’s Notice of Proposed Rulemaking. The NOPR called for additional compensation for “fuel-secure” power stations that sell electricity into organized energy markets and maintain a 90-day fuel supply.

“I think [the commissioners are] working constructively to put forth a potential solution and really work with our RTOs around problem-solving. … We’ll be able to address this issue in a way that, as I said, respects the balance within the organized markets … continues to deliver the value proposition of these organized markets” and maintains a balanced resource portfolio.

He said he discussed the issue with Perry and guaranteed an eloquent solution.

“I said to him, ‘I took high school calculus,’ and he said, ‘I didn’t.’ But, I said, ‘I hopefully can solve this one.’ … I’ve been in this rodeo long enough. I know how to calibrate and make decisions, and those decisions will be defensible.

“We are now seeing what we never thought we’d see, and even Democratic DOE secretaries have admitted it,” Powelson continued. “We’re seeing nuclear plants close, and we’re seeing them close at a rapid pace. And we’ve got to look at those issues. … I agree with the secretary when he says these markets aren’t pure. … As a state commissioner, I didn’t understand that back then until Mark gave me this homework assignment.

“I sat through plant closure announcements; it’s not a fun thing,” he added. “You’re going to see more state interventions. Get ready.”

Jason Stanek, senior counsel for the House Subcommittee on Energy and a former FERC staffer, said the committee isn’t planning a hearing on the issue, but it’s “looking forward to [FERC’s] thoughtful and deliberative process.”

“We have yet to have a hearing on that topic, and it’s one that has split our members not necessarily by party but by region,” he said. “They recognize that the entire industry is in a state of flux right now.”

Powelson also announced that incoming FERC Chairman Kevin McIntyre would be sworn in Thursday at 10 a.m.

“Tomorrow, we’ll have five” commissioners, he said. He added later that he did not know how that would affect FERC’s decision on the NOPR.

“If I knew, I would tell you. I’m usually very candid,” he said.

McIntyre’s arrival beats — by one day — the 120-day deadline before interim Chairman Neil Chatterjee could start appointing FERC staff.

Menezes also suggested that FERC might miss DOE’s requested deadline for a decision by one day.

“I think we have a big deadline you gave us; Dec. 11?” Powelson said to Menezes.

“I understand FERC may have a different date, maybe the 12th,” Menezes replied.

“The 12th? ’Tis the season,” Powelson responded.

December 6, 2017

FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out

By Rich Heidorn Jr.

FERC has waded into yet another state-federal jurisdictional dispute, claiming “exclusive authority” over the participation of energy efficiency in wholesale markets but preserving a carveout it approved earlier for Kentucky utilities.

The commission’s ruling came in response to Advanced Energy Economy’s request for a declaratory order on FERC’s authority over energy efficiency resources (EER). AEE, which represents companies such as General Electric, Nest and Johnson Controls, filed the petition in June after the Kentucky Public Service Commission ruled that retail customers cannot participate in any PJM wholesale market without the state’s permission.

The PSC’s order was in response to a filing by East Kentucky Power Cooperative, which said it was buying more capacity than needed because of providers bidding EER products from its service territory into PJM’s capacity auction.

wholesale markets energy efficiency ferc kentucky utilities — | *Enervee.com*

AEE’s concerns focused on third-party EERs, such as those created when an aggregator contracts with the manufacturer and retailer of high-efficiency appliances, light bulbs or heating and cooling systems.

FERC energy efficiency — | *Enervee.com*

FERC sided with AEE, saying the commission “has exclusive jurisdiction over the participation of EERs in wholesale markets,” and that relevant electric retail regulatory authorities (RERRAs) “may not bar, restrict or otherwise condition the participation of EERs in wholesale electricity markets unless the commission expressly gives RERRAs such authority.” Commissioner Richard Glick, who was sworn in Nov. 29, did not participate in the Dec. 1 order (EL17-75).

PJM Integration

However, FERC said it would honor its 2004 order approving Kentucky Power’s integration into PJM, which granted the utility the right to prevent its customers from participating in the RTO’s demand response or load interruption programs. The opt-out stipulation was later extended to Duke Energy Kentucky and EKPC when they joined PJM.

FERC rejected opponents’ claims that AEE’s petition was premature. “We agree with AEE that the novel issues of federal and state jurisdiction presented here warrant commission guidance,” FERC said, noting that PJM also asked the commission to weigh in.

The commission also said that FERC Order 719 “does not provide for a RERRA to exercise an opt-out and bar or restrict the sale into the wholesale electricity markets of EERs originating in their state or local area.” The 2009 order required RTOs and ISOs to permit aggregators to bid DR on behalf of retail customers directly into the grid operators’ markets unless the RERRA bars participation by retail customers.

“Although in Order No. 719 and Order No. 745 the commission granted RERRAs an opt-out from allowing resources to participate as wholesale demand response, we find that the commission was not obligated to do so,” FERC said, citing the Supreme Court’s 2016 ruling in FERC v. Electric Power Supply Association. The EPSA ruling upheld Order 745, which required RTOs to pay DR the same LMPs as generation. (See Supreme Court Upholds FERC Jurisdiction over DR.)

The commission also said the effects of EER participation on the retail markets “are not substantial.”

“Unlike demand response resources, EERs are not likely to present the same operational and day-to-day planning complexity that might otherwise interfere with [a load-serving entity’s] day-to-day operations. Even if PJM’s add-back mechanism failed to ensure that an LSE’s procurement obligation was unaffected, we agree with AEE that any such impacts should be addressed through PJM’s tariff provisions and not through a broad prohibition on EER participation in wholesale markets.”

But FERC said it was “appropriate” to allow the Kentucky opt-out “as a longstanding agreement relied upon by the parties and entered into prior to the clarification of jurisdiction over wholesale demand-side management in EPSA and this order.”

The commission said although some EERs originating in Kentucky have cleared in PJM capacity auctions, “we find that any necessary market changes should be implemented in a manner that does not require changes to the [auction] results.”

The commissioners declined to state the requirements they would impose in the future if a retail regulator seeks to restrict third-party EER sales.

Back to the Courts?

The Supreme Court has issued three rulings interpreting state-federal jurisdiction under the Federal Power Act since 2015. The commission’s preservation of the carve out would seem to foreclose a court challenge by Kentucky regulators. But it’s no guarantee that other states lacking such agreements won’t seek to overturn the ruling. (See Court’s Reticence Frustrates Energy Bar.)

AEE nevertheless praised FERC’s ruling as a “win for advanced energy innovators and consumers alike.”

FERC’s assertion of jurisdiction “is critical for maintaining free and open competition, with all technologies competing on price and performance,” the group said.

December 5, 2017

NERC Parts Ways with Chief Security Officer

By Rich Heidorn Jr.

Just days after losing its CEO, NERC has seen another senior management departure.

Senior Vice President and Chief Security Officer Marcus Sachs, one of seven direct reports to NERC’s CEO, “resigned” effective Nov. 27, the organization said in a statement.

However, three sources knowledgeable about the matter said Sachs was forced to leave. One former NERC staffer said Sachs was ousted because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the planned expansion of the Electricity Information Sharing and Analysis Center (E-ISAC).

“The ESCC didn’t have confidence in him taking the ISAC forward,” the former staffer said. “I don’t know if it was GridEx-related; I don’t know if it was storm-related or that Marc came from a communications background.”

Sachs joined NERC in May 2015 from Verizon, where he was vice president of national security policy. Prior to Verizon, he was deputy director of the computer science lab at SRI International and the founder of a computer security consultancy. He also worked for several months as cyber program director at the U.S. Department of Homeland Security and served more than 20 years in the U.S. Army. He has degrees in civil engineering and computer science in addition to a Ph.D. in public policy.

A second former NERC official said he was told Sachs was forced out but that he didn’t know the reason. “All I heard was that NERC forced him out,” the ex-staffer said. “My understanding is his departure was very sudden.”

But the first ex-staffer said the resignation “was supposed to be in the works before” Cauley’s Nov. 9 arrest on domestic abuse charges.

NERC did not respond to a request for comment Monday.

Sachs has joined Ridge-Lane LP, a merchant bank co-founded by former Homeland Security Secretary and Pennsylvania Gov. Tom Ridge. In an email, Sachs called his departure from NERC “a strategic move for me, which will allow me to assist other companies and organizations as they grow and develop.”

“I look forward to the next chapter of my career, and to be able to give back to others many of the lessons I have learned,” he added.

The ESCC, which serves as a liaison between industry and the federal government, is dominated by CEOs of investor-owned utilities.

Tim Roxey, a NERC vice president who serves as chief operations officer for the E-ISAC, was named interim chief security officer with responsibility for overseeing the E-ISAC and directing security risk assessment and mitigation activities. Bill Lawrence, a senior director with the E-ISAC who led GridEx IV last month, will assume day-to-day management of the center. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.)

MidAmerican Energy CEO William Fehrman, vice chair of the NERC Members Executive Committee, will provide “strategic counsel and guidance” on the E-ISAC’s expansion during the search for Sachs’ replacement, NERC said. Fehrman referred an interview request to NERC.

The E-ISAC is the primary security communications channel for the electricity sector, helping grid operators and others prepare for and respond to cyber and physical threats.

NERC’s 2018 Business Plan calls for improving the E-ISAC’s “technical and analytical capabilities with a goal of becoming the electricity industry’s leading, trusted source for analysis and sharing of security information.” The E-ISAC’s staffing will increase to 29 full-time equivalent employees from less than 20, funded by a $21.9 million budget, a $3.3 million increase from 2017.

“The long-term strategic plan is to transform the E-ISAC into a world-class intelligence collecting and analytical capability for the electricity industry,” according to the plan.

NERC General Counsel Charles Berardesco, who was appointed interim CEO following the Nov. 20 resignation of former CEO Gerry Cauley, said in a statement that he was “confident the E-ISAC, under Tim and Bill’s leadership, will continue to effectively carry out its responsibilities.” (See Cauley Resigns; NERC Launches Search for Replacement.)

December 5, 2017

MISO Storage Task Force Defines Role, Seeks Plan

By Amanda Durish Cook

After two meetings, MISO’s newly created Energy Storage Task Force has established its charter but not yet developed a plan of action for next year.

While the group spent much of its Nov. 28 meeting finalizing language for its mission statement, it also agreed to schedule an additional conference call in late December to create a 2018 work plan covering storage discussion topics.

During the meeting, stakeholders settled on a sparsely worded charter that stipulates the task force will “engage subject matter experts in the identification of potential issues or topics that are unique to integration of energy storage or challenge the ability to realize benefits of energy storage.”

MISO energy storage task force — Invenergy’s Grand Ridge Battery Storage Facility | *BYD*

The group will also “identify and track issues specific to energy storage that are within the purview of MISO in any of its administrative or functional roles.”

The final version of the mission statement implicitly respects state jurisdiction over storage assets, stakeholders said.

Task force Chair John Fernandes said stakeholders and states were understandably wary of turning over storage assets to MISO’s control. “The 800-pound gorilla in the room is state jurisdiction. There is concern from the states that they don’t want to turn over a piece of hardware, an asset over to MISO,” he said.

Indianapolis Power and Light’s Lin Franks noted that New York has mechanisms in place that allow storage assets to be subject to both state control and ISO regulation, enabling them to participate in wholesale and retail markets “almost simultaneously.”

The charter will now head to the Steering Committee for approval at its Jan. 24 meeting.

A Question of Priorities

Task force leaders have asked stakeholders to help determine the group’s key priorities before the December call. The group expects to also submit an issue prioritization to the Steering Committee, which assigns specific issues to other committees.

Task force members said the group could track storage issues in MISO committees to ensure they are being addressed in order of priority. Some stakeholders cautioned the group that it shouldn’t tread on the Steering Committee’s assignment authority.

Fernandes said the task force will next month take up general education on energy storage issues, identifying what MISO market rules already accommodate storage and reviewing FERC’s Notice of Proposed Rulemaking on storage participation in wholesale markets.

Some stakeholders asked the task force to be mindful of the need to act quickly on storage issues.

“MISO has already indicated that it’s going to model storage in transmission planning. At what point in the calendar is MISO going to start modeling these things?” asked Customized Energy Solutions’ David Sapper. “It seems like the sooner the better.”

In written comments to MISO, DTE Energy asked the task force to make storage modeling in MISO planning its top priority.

The Energy Storage Association asked the task force to avoid “unnecessary administrative burden” and assign issues as quickly as possible, suggesting that the most urgent issue is the development of resource adequacy rules and capacity accreditation for storage resources.

Indianapolis Power and Light suggested that stakeholders this month already begin focusing the discussion on storage participation in the interconnection process and energy and ancillary services markets, and send any readied issues to the Steering Committee. Entergy, however, asked for the first storage issue referrals by the end of the first quarter of 2018.

IPL also asked that MISO create a Gantt chart — a bar chart that illustrates project tasks and their start and end dates — to track storage discussions in the RTO’s different stakeholder committees.

State of MISO Storage

MISO currently has one 1-MW battery that offers regulating reserves under a Stored Energy Resource designation, a market definition for short-term storage that was developed in 2008. However, an additional 50 MW of storage went through the interconnection queue in recent years, 20 MW of which is already in service, while the remaining 30 MW is expected to go live by the end of 2019, according to MISO spokesperson Mark Adrian Brown. The U.S. Department of Energy estimates that even more “distribution-connected energy storage is active or under construction in the MISO footprint,” he said.

The RTO currently has 150 MW of storage in its interconnection queue.

MISO said that while its current rules do not expressly limit storage participation in regulating service, they do not “explicitly define a storage resource or product or fully clarify rules for how storage would integrate under other resource types.” The RTO envisions creating a second type of Stored Energy Resource designation that would allow storage to be eligible to offer energy, capacity, up and down ramping, spinning reserve, supplemental reserve or regulating reserve “to the extent a particular storage resource is technically capable of providing any or all of these products.”

December 5, 2017

PJM Demands Agreement on Tx Replacement Definitions

By Rory D. Sweeney

VALLEY FORGE, Pa. — After years of intractability, can PJM’s Transmission Replacement Process Senior Task Force play nice? The RTO is hoping it can be forced to.

PJM’s Fran Barrett, who administers the task force, told stakeholders at last week’s meeting that transmission owners and customers must agree on a common definition of “end-of-life facilities” to move forward. He said that at its next meeting on Feb. 1, stakeholders will vote to approve a working definition that would apply only to discussions within the task force.

“We’re going to put an end to the end-of-life discussion at the next meeting,” he said.

The directive came after transmission owners declined to endorse a definition developed by Mark Ringhausen of Old Dominion Electric Cooperative. Stakeholders had debated the meaning of the term at previous meetings, and Ringhausen offered to develop a proposed definition.

pjm — Tatum (left) and Ringhausen | © *RTO Insider*

The task force has made little progress since it was chartered in May 2016 to “develop alternatives for providing more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan.” FERC issued a show cause order in August 2016 questioning whether PJM TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). That precipitated a 10-month hiatus of the task force, which ended in July. (See Softer Rhetoric as PJM Members Seek Replacement Rules Accord.)

Supplemental projects are proposed by TOs to meet local needs, but they are not required by PJM’s reliability, economic efficiency or operational performance criteria. Their costs are paid by the TO zone and are not regionally allocated, unlike baseline upgrades resulting from the RTEP.

The commission’s show cause order directed the TOs to file rule revisions, or counter with evidence that they were already in compliance with Order 890, within 60 days. The TOs responded Oct. 25, contending that the PJM Operating Agreement already complies with the order, but also proposed a Tariff amendment, Attachment M-3, that they said would improve transparency. Attachment M-3 would add more specificity to annual stakeholder reviews of TOs’ assumptions and methodology, along with TO presentations of their views on local transmission needs and proposed solutions.

FERC, which was without a quorum between February and August, has not ruled on the filing despite promising it would act within about three months of the TOs’ response.

Endorse or Propose

pjm end-of-life facilities replacement — Richardson | © *RTO Insider*

At last week’s meeting, TOs were divided on Ringhausen’s proposal. PPL’s Frank “Chip” Richardson said it “helps define it for me as to what are we really talking about in this task force,” but others hesitated to support it. Tonja Wicks of Duquesne Light said she had not received approval to endorse a definition and asked that the vote be deferred until her company could review it.

“This is a recommendation by one stakeholder of a definition, not the task force definition,” she said.

“And what I’m asking the task force participants: Can you march under this flag for purposes of this discussion to say this is the end-of-life definition?” Barrett said.

“Duquesne is okay with this definition being an ODEC-represented definition,” Wicks said. “We haven’t agreed on any of terms in the definition.”

“That doesn’t help us very much,” PJM’s Steve Herling responded. “We’re trying to have a set of boundaries for the conversation this group needs to have.”

“We can use those words any way you define them, as long as we’re not committing that we agree with those definitions,” Exelon’s Gary Guy said.

Barrett agreed to the deferral requested by Wicks but told stakeholders to come prepared to endorse the definition or propose an alternative.

“One thing that I do not want to get involved in is … trying to parse every component [at a transmission facility] to justify whether it falls within this definition,” Herling warned. “If it has to be replaced, it has to be replaced.”

Analysis Details

Earlier in the meeting, Ed Tatum of American Municipal Power asked PJM to detail its procedures for analyzing projects proposed by TOs.

“With regards to the baseline projects, the narrative is very clear as to what PJM is going to be looking at and thinking about,” Tatum said. “With regard to projects that are not in [FERC] Form 715 and/or are not part of PJM’s baseline — in other words end-of-life and/or supplemental projects — we do not have a narrative evaluation or assessment about how these things work.”

“That actually seems like a fairly trivial thing to fix because the level of analysis that we do is the same, so we can memorialize that somewhere,” Herling said, adding that the analysis is consistent with other studies PJM performs to determine whether retiring a facility will cause a reliability violation. “That’s based on all the tests we do in the RTEP. … I don’t see [that] there’s a documentation issue, but we can make it more clear if people are concerned.”

Tatum continued, asking how certain Form 715 filing requirements are met for supplemental projects, which are submitted by TOs and aren’t necessarily individually vetted by PJM.

“I don’t think that the filing requirements are specific to each facility on the grid individually,” Herling responded. “We don’t try to demonstrate that every facility individually satisfies some criteria. We show the system is reliable and that we have done the appropriate analysis.”

PJM agreed to review its documentation to address both of Tatum’s concerns.

Design Component Changes

AMP also reviewed additional proposed revisions to the task force’s design components. AMP’s Lisa McAlister said the group felt it had “moved” substantially to include TO feedback.

Herling questioned some of the details AMP proposed.

“Some of that level of specificity, we’re going to have to figure out does that actually make sense in the direction that we’re trying to take the [Transmission Expansion Advisory Committee], which is to more dynamic communication, not focused on monthly meetings. Once we see what the proposals are and how they fit together, then we’ve got to figure out is that undoing some of what we’re trying to accomplish with the TEAC.”

Barrett asked that stakeholders begin reviewing the proposed language and formulate positions on what to include in a final supportable package.

December 5, 2017

No Solution for PJM Incremental Auctions

By Rory D. Sweeney

VALLEY FORGE, Pa. — It turns out overtime won’t resolve this jump ball.

PJM Incremental Auction climate change — Chmielewski | © *RTO Insider*

During a September meeting of PJM’s Markets and Reliability Committee meeting, the RTO’s Brian Chmielewski announced that, while no proposal from the Incremental Auction Senior Task Force (IASTF) received the more than 50% approval needed to be moved for endorsement to the MRC, poll results showing that a majority of stakeholders wanted a change indicated a “jump ball” — and that compromise might be possible.

The task force is considering structural changes to the Incremental Auction process to eliminate significant clearing price differences between a delivery year’s capacity auction and its three subsequent IAs.

But at the IASTF’s meeting last week, Chmielewski revealed similar results from a vote taken in November, despite two additional months of meetings and negotiation. PJM’s proposal, known as Proposal A”, was seven votes short of receiving the support needed to move on to the MRC.

The result wasn’t altogether unexpected, as Chmielewski’s early hope for compromise quickly faded at subsequent meetings. (See PJM Members Still Split on Incremental Auctions.)

“I think we’ve kind of come full circle,” he said.

He later confirmed that Proposal A” would nonetheless be presented for a first read at the MRC meeting on Thursday.

While the overall results were similar, Chmielewski noted that there were less total votes the second time around. Exelon’s Sharon Midgley wondered if holding the vote shortly before the Thanksgiving holiday accounted for the voter apathy.

“As a whole, the group has done a lot of compromising,” she said.

The IASTF was also tasked with investigating concerns about market distortion stemming from market participants using replacement capacity to take advantage of the clearing price differences, but stakeholders decided to hold off on that issue until the MRC has decided on the Proposal A” structural changes.

“I would certainly support putting the replacement discussion in abeyance until we see the outcome,” said Carl Johnson, who represents the PJM Public Power Coalition.

“I’m happy to revisit that conversation once that path is clear,” agreed NRG Energy’s Neal Fitch.

Fitch also asked when stakeholders could expect the Independent Market Monitor’s promised update of its report on replacement capacity. An IMM staff member said it would be published shortly.

With those concerns in mind, stakeholders agreed to cancel the task force’s Dec. 18 meeting and instead reconvene at the next meeting scheduled for Jan. 19.

December 5, 2017

NYISO Reports Adequate Capacity for Winter

New York’s electric system has the capacity to meet demand for electricity during extreme cold weather conditions through the 2017-2018 winter season, according to NYISO.

The ISO forecasts peak demand this winter of 24,365 MW, slightly higher than the 24,164-MW peak of last winter, when weather was milder than the 10-year and 20-year averages, Vice President of Operations Wes Yeomans said in a review of the ISO’s 2017-2018 winter outlook Thursday.

New York set its record winter peak in 2014, during polar vortex conditions that pushed demand to 25,738 MW. If extreme weather produces colder conditions, with composite statewide temperatures in the 5 to 6 F range, peak demand across the state could increase to approximately 25,989 MW.

Total capacity resources, which include generation, imports and demand response, are expected to total 44,557 MW this winter, including 41,454 MW of generation, 2,311 MW in net external capacity purchases and 792 MW of DR. The ISO maintains 2,620 MW of operating reserves — generation resources above the amount needed to meet projected demand for electricity on any given day.

— Michael Kuser

December 5, 2017

Xcel Can Recover Costs if Minn. 345-kV Project is Canceled

By Amanda Durish Cook

Xcel Energy can recover its investment in a recently approved 345-kV line project in southern Minnesota if the project is abandoned for reasons beyond the company’s control.

“We agree that the project faces certain regulatory, environmental and siting risks that are beyond the control of management and which could lead to abandonment of the project,” FERC said in a ruling Friday (ER18-12).

FERC Xcel Energy MTEP — Huntley Wilmarth preliminary route options in pink |

Xcel put the incentive request to FERC on behalf of subsidiary Northern States Power, which will design and construct the $108 million Huntley-Wilmarth 345-kV line. The company will be able to recover all “prudently incurred costs” associated with its investment in the line. The abandoned plant incentive was effected Dec. 1.

Northern States Power is investing $54 million with project partner ITC Midwest contributing the other half. Earlier Xcel estimates pegged project cost around $81 million. (See MISO Board Approves MTEP 16’s $2.7B in Tx Projects.)

The line will connect Xcel’s Wilmarth Substation and ITC Midwest’s Huntley Substation in south central Minnesota near the Iowa border. The project, which is expected to be in service by the end of 2021, needs permitting approval from the Minnesota Public Utilities Commission.

FERC can consider the abandoned plant incentive if the transmission project “results from a fair and open regional planning process” or if a project “has received construction approval from an appropriate state commission or state siting authority.”

The Huntley-Wilmarth project was part of the 2016 MISO Transmission Expansion Plan, though some stakeholders objected to the RTO’s decision not to open the project up to competitive bidding. MTEP 16’s only market efficiency project, it would have been put to a competitive process save for Minnesota’s right of first refusal law. FERC cited the planning studies from MISO’s annual MTEP process as grounds for approval.

“In this case, the MTEP transmission planning process, through which the project was approved, evaluated whether identified transmission projects will enhance reliability and/or reduce congestion,” FERC said.

December 5, 2017

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be at the Cira Centre in Philadelphia covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Price Formation Problem Statement and Issue Charge

In addition to the voting items listed below, PJM will present a problem statement and issue charge on revising its price formation procedures. The initiative, which would seek ways to allow inflexible units to set LMPs, will be brought to a vote at the next MRC meeting, scheduled for Dec. 21. The RTO has scheduled four education sessions on the topic, which began on Dec. 4 with an explanation of the price formation status quo. The remaining sessions are scheduled for Dec. 11 and morning and afternoon sessions on Jan. 17. (See PJM: Energy Price Formation Addresses DOE NOPR.)

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse changes to Manual 11: Energy & Ancillary Services; Manual 18: PJM Capacity Market; Manual 27: Open Access Transmission Tariff Accounting; Manual 28: Operating Agreement Accounting; and Manual 29: Billing. The revisions implement PJM’s transition to five-minute settlements under FERC Order 825.

3. Distributed Energy Resources Update (9:30-9:45)

Members will be asked to endorse a proposed charter to convert stakeholders’ work on distributed energy resources into a subcommittee reporting to the MRC. It includes a revision FirstEnergy offered on respecting relevant regulatory authorities. (See “Big Support for Jurisdiction Mention in DERS Charter,” PJM Market Implementation Committee Briefs: Nov. 8, 2017.) The subcommittee was created because of concerns that previous DER discussions — which had been conducted in special sessions of the Market Implementation Committee — were hampered by an overly narrow problem statement and issue charge.

4. 2018 Day Ahead Scheduling Reserve (DASR) Requirement (9:45-9:55)

Members will be asked to endorse proposed revisions to the 2018 day-ahead scheduling reserve requirement. (See “DASR Requirement Drops Again,” PJM Operating Committee Briefs: Oct. 10, 2017.)

5. Credit Requirements for Regulation (9:55-10:05)

Members will be asked to endorse Tariff revisions to address a billing mismatch affecting credit requirements for regulation-only resources.

Regulation credits are accrued daily and billed monthly, while energy charges are accrued daily and billed weekly. Although the regulation-only resources’ credits are much greater than the charges, the weekly bills for charges create a credit requirement, even though the much larger credit is due to the provider at the end of the month. The proposal would include daily regulation credits in weekly instead of monthly activity for calculating credit requirements. The change will apply to all resources, not just regulation-only resources.

6. FTR Credit Requirements for Transmission Upgrades (10:05-10:15)

Members will be asked to endorse proposed revisions allowing PJM to use modeling to improve its financial transmission rights credit requirements. FTR credit requirements for prevailing paths currently are based on weighted historical congestion on those paths, but transmission system upgrades can reduce congestion, decreasing the value of prevailing-flow FTRs.

The proposal would incorporate the PROMOD simulation results into the FTR credit calculator prior to the FTR bid window to incorporate consideration of major upgrades and reduce default exposure to PJM’s members. (See “Give Them Some Credit,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

7. Price-Responsive Demand (10:15-10:30)

Members will be asked to endorse one of three proposals developed at the Demand Response Subcommittee to adapt price-responsive demand (PRD) to Capacity Performance rules.

PRD, which lets customers reduce their loads in response to energy prices in exchange for reduced capacity requirements, was developed before CP rules changed the requirements for demand response.

PJM says PRD bids should be available year-round, the same as generation resources under CP. But state regulators argue they should be allowed the option to make only seasonal contributions because PJM’s summer peak loads exceed winter peaks by more than 20,000 MW.

The RTO’s proposal and a similar one from Calpine would require PRD to reduce load in the winter like other CP resources. The status quo would relieve PRD resources from having to reduce winter loads. (See PJM Grilled on Price-Responsive Demand Rule Changes.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse Operating Agreement revisions associated with PJM sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)

1. Elections (1:25-1:35)

Members will be asked to elect members of the Finance Committee, sector whips and the Members Committee vice chair for 2018.

2. Credit Requirements for Regulation (1:35-1:45)

Members will be asked to endorse Tariff revisions related to a proposed change in credit requirements for regulation resources. (See MRC Item 5 above.)

3. FTR Credit Requirements for Transmission Upgrades (1:45-1:55)

Members will be asked to endorse Tariff revisions to FTR credit requirements to reduce exposure posed by congestion changes resulting from major transmission upgrades. (See MRC Item 6 above.)

4. Price-Responsive Demand (1:55-2:15)

Members will be asked to endorse proposed Reliability Assurance Agreement revisions to address PRD. (See MRC Item 7 above.)

— Rory D. Sweeney