Page 1171 – RTO Insider

May 22, 2018

FERC Rejects NPPD Objection to Tri-State Zonal Placement

FERC last week affirmed an administrative law judge’s 2017 decision that SPP’s proposed Tariff revisions to incorporate Tri-State Generation and Transmission Cooperative as a new transmission owner in an existing pricing zone are just and reasonable (ER16-204).

Nebraska Public Power District, the dominant TO in the affected zone, objected to SPP’s decision to incorporate certain Tri-State transmission facilities and the annual transmission revenue requirement (ATRR) into its zone.

ferc spp tariff revisions zonal placemenet — Tri-State’s service territory | *Tri-State G&T*

The commission denied NPPD’s request to reopen the record, saying it failed to demonstrate the existence of “extraordinary circumstances” and that a change in circumstances was “more than just material.”

“NPPD’s motion relies on a change in the criteria that SPP applies to determine zonal placements and additional information” regarding another potential SPP member (Western Area Power Administration-Rocky Mountain Region) joining the RTO, the commission said. “Neither of these arguments demonstrate extraordinary circumstances or changes that go to the heart of the case.”

When SPP adds a new TO to an existing zone, the TO’s ATRR and any of its load not already included in the zonal load are added to the existing zone’s totals, resulting in a new total zonal ATRR and a new total load. That leads to new service rates for all transmission customers within the zone.

NPPD argued that the proposed ATRR, including the proposed return on equity, was not just and reasonable. It said that because Tri-State’s average per-megawatt cost of serving load was higher than NPPD’s average cost of serving its existing load, adding Tri-State would shift more than half of the costs of the co-op’s transmission facilities to existing Zone 17 customers and increase the costs to serve them.

The commission accepted SPP’s Tariff revisions in December 2015, and established hearing and settlement judge procedures over whether the placement of Tri-State’s facilities and ATRR in NPPD’s zone was just and reasonable and whether Tri-State owed any refunds.

ALJ John P. Dring found SPP’s proposed Tariff revisions and their placement of Tri-State’s transmission facilities in NPPD’s zone just and reasonable. He also determined Tri-State owed no refunds in connection with its proposed zonal placement.

FERC agreed that the criteria SPP applied to determine whether Tri-State should be placed in NPPD’s zone “are appropriate for determining zonal placement” in this proceeding. It also sided with Dring that “what matters in this proceeding is whether the criteria render just and reasonable results,” agreeing that SPP’s criteria did so.

“We agree … that shifting cost responsibility for some degree of legacy costs is not per se unjust and reasonable, but there may be cases in which a cost shift would be unjust and unreasonable,” the commission wrote.

Fifteen SPP members joined NPPD in intervening in the docket, many of whom filed a Section 206 complaint in October alleging that SPP’s zonal placement is unjust and unreasonable (EL18-20). FERC rejected the complaint in March, but the TOs have filed a rehearing request. (See FERC Rejects TO Complaint on SPP Zonal Placements.)

Colorado-based Tri-State, a nonprofit cooperative that sells wholesale electricity to its member-owner distribution cooperatives and public power districts in Nebraska, New Mexico and Wyoming, joined SPP in January 2016.

Commission Denies Rehearing Requests on SPP’s ARR, TCR Rules

The commission denied Xcel Energy’s rehearing request of a 2017 order that rejected proposed revisions to SPP’s tariff regarding the eligibility of customers with network service subject to redispatch to receive certain financial transmission rights (ER17-1575).

The commission’s October 2017 order directed SPP to rewrite its rules on auction revenue rights and long-term congestion rights (LTCRs), saying the RTO’s proposed grandfathering provisions would “inappropriately extend practices that the commission finds unjust and unreasonable.” (See FERC Again Rejects SPP Rules on ARRs, LTCRs.)

FERC affirmed its decision to grandfather ARRs and LTCRs that have already been granted to network customers with service subject to redispatch. It had also said it was not reasonable to extend the grandfathering provisions through July 15, 2017, as SPP had proposed as a transition to new ARR/LTCR eligibility rules.

Xcel argued for a rehearing on behalf of its Southwestern Public Service subsidiary, alleging that FERC’s order disregarded SPS’ contractual rights, concluded that network service subject to redispatch is not similarly situated to network service not subject to redispatch and determined that the remedy did not have retroactive effect.

The commission responded that Xcel failed to show that SPP’s Tariff “provided [SPS] with a contractual right that was abrogated” in its Tariff order. FERC found it was reasonable to distinguish “between rights that customers already had been granted and rights that customers may have expected to be allocated.”

“Southwestern is not losing any rights that already have been granted and remains eligible to be allocated ARRs in the future” subject to the limitation in the Tariff order, the commission said.

FERC issued a related order that also addressed Xcel’s claims that the commission had “fundamentally mischaracterized the nature of redispatch service,” rejecting Enel Green Power North America and Southern Company Services’ rehearing request (EL16-110).

Both companies appealed October orders filed along with ER17-1575 (EL16-110 and EL17-69) that found SPP was not barred by its Tariff from allocating ARRs and LTCRs to network customers subject to redispatch for the amounts and periods subject to redispatch during the 2017-2018 annual allocation process. Enel and Southern filed on behalf of their Buffalo Dunes Wind Project and Alabama Power subsidiaries, respectively.

The commission said both parties failed to show that the Oct. 19, 2017, effective date set in EL16-110 for the Tariff revisions is not appropriate. It said the effective date preserved its ability to order refunds, if appropriate, “back to this date.”

FERC said that its decision that SPP’s Tariff revisions do not apply to the 2017-18 annual allocation process “was neither ‘internally inconsistent’ nor erroneous.” It pointed out that the annual ARR and LTCR allocations for 2017/18 were made in March and April 2017, prior to the Tariff revisions’ effective date.

OMPA Complaint Against OG&E Goes to Settlement

The commission set the Oklahoma Municipal Power Authority’s complaint against Oklahoma Gas and Electric for hearing and settlement judge procedures, with a refund effective date of Jan. 26, 2018 (EL18-58).

FERC found OMPA raised “issues of material fact that cannot be resolved based upon the record before us.” The state agency filed the complaint in January, alleging that OG&E’s ROE is unjust and unreasonable and that its formula rate needs to be revised to reflect the Tax Cuts and Jobs Act.

The commissioners said OMPA’s analysis was enough to show OG&E’s cost of equity may have declined significantly below its existing 10.6% base ROE. They also said any tax-related changes to OG&E’s formula rate should ensure that its rates properly reflect the effects of the tax legislation.

OG&E said its formula rate will automatically reflect the change in the federal corporate income tax rate, but it will not automatically address the effect of the legislation on accumulated deferred income tax balances.

— Tom Kleckner

May 22, 2018

Advocates Push PJM Board for Explanations at Annual Meeting

By Rory D. Sweeney

NATIONAL HARBOR, Md. — Consumer, small-business and environmental advocates pressed PJM’s Board of Managers on the issue of transparency at their annual meeting last week, calling on the RTO to provide more explanation of its broader plans and goals.

Advocates from several member states took turns outlining their shared perspective on what they see as the largest issues PJM is currently addressing and the obstacles the RTO faces.

PJM Annual Meeting Consumer Advocates — All but two of the 16 members of the Consumer Advocates of PJM States (CAPS) sent representatives to the PJM annual meeting last week. | © *RTO Insider*

Brian Lipman with the New Jersey Division of Rate Counsel set the tone during his discussion of PJM’s initiative to reform how energy prices are formed.

“Advocates are supportive of looking at proposals to improve the PJM market, but it needs to be done in the most efficient and effective manner,” he said. “So with energy price formation, one of our first questions is: What happened to LMP?”

He endorsed PJM’s current focus on revising how reserves and shortage pricing are calculated, but added that “it’s unclear to us” whether reviewing the LMP calculation will be a “next step.”

“We’re asking for clear communication on this front,” he said. “There’s much being juggled by all the stakeholders in PJM, and many problems on the table for consideration. … Each one impacts another, so it’s not possible for the consumer advocates or any stakeholder to merely take a look at one piece of the puzzle without thinking about how everything will fit together and what the complete picture is. … We need to know how PJM plans to fit energy price formation into its resilience initiative.”

John R. Evans, Pennsylvania’s small business advocate, said he stays involved because “many times, if you don’t have a seat at the table, you often find yourself on the menu.”

Evans is concerned about the potential for his state legislature to subsidize its nuclear fleet, as has happened in Illinois and New York and is on the brink of approval in New Jersey.

“Show us some benefit to small business classholders,” he said. “So far, we haven’t seen that.”

Erik Heinle of the D.C. Office of the People’s Counsel discussed advocates’ support for increasing PJM’s consideration of cost-containment guarantees in staff’s analysis of transmission construction bids. Stakeholders will consider several different proposals on the topic at a May 24 Markets and Reliability Committee meeting. Heinle’s office joined LS Power in developing a proposal that would require PJM to seek input from the Independent Market Monitor in comparing cost caps to cost estimates. PJM has developed two other proposals: one would limit cost-containment evaluation to construction costs while the other would give RTO staff authority to consider a wider range of factors at its discretion and require them to perform a feasibility evaluation on any cost commitments.

While Heinle advocated for his proposal, he acknowledged the “thorny issue” of having evaluation criteria developed by one stakeholder sector and called PJM’s proposals “a considerable upgrade form the status quo.”

He also addressed supplemental and end-of-life transmission projects, arguing that “the current process does not provide adequate transparency related to data and criteria thresholds each transmission owner uses to prioritize assets for replacement.”

Jackie Roberts, director of the West Virginia Consumer Advocate Division, questioned PJM’s filing in FERC’s resilience docket, saying it made her “uncomfortable” that the comments should have “demonstrated how reliable and resilient our system already is.”

“I don’t think clearing prices are any more artificially low now than they were artificially high several years ago,” she said.

The comments “befuddled” her until she realized they reminded her of how the Obama administration’s Clean Power Plan was developed, she said. It became clear, she said, that such proposals are developed by “someone who doesn’t have the authority to require a market solution.”

“PJM asking for more authority about the gas industry … I don’t understand that,” she said. “I do think there needs to be a gas industry ISO, but PJM is not the entity to do that. That needs to be a parallel, standalone effort.

“I really am not a fan of PJM saying anything that suggests to the public … that we are not resilient and that our fuel mix may not be resilient.”

PJM Response

PJM CEO Andy Ott said legislators have been asking him at what point the grid would become too dependent on one set of infrastructure.

“We have been very clear in our statements about the current situation, even with the current announced retirements, [that] we don’t have a fuel security problem and the system is fine,” he said. “However, 10 years from now, if we continue to see changes in the fuel mix, we have no criteria to look at fuel dependencies and fuel security. … It’s a legitimate question for us to analyze. If you’re insinuating that PJM’s activities here are trying to change certain resources from retirement … I think that’s a misguided suggestion.”

Ott and board members agreed on the importance of prioritizing issues based on significance but defended some of staff’s decisions to move quickly on topics that some stakeholders have questioned.

“In some cases, ‘do nothing’ might not be an option because of whatever drivers are out there,” Ott said. “Ignoring problems isn’t going to make them get any better.”

Board member Charles Robinson said PJM sometimes moves quickly specifically to be “responsive to a cost concern.”

“Sometimes we move quickly because we are concerned about cost impacts, because we feel the need to correct a perceived deficiency so that we can be responsive to a cost concern,” he said.

“The board does take both cost and benefit into consideration,” board member Susan Riley said.

IMM Support

Robinson also questioned a note from the advocates’ slides indicating their support for the Monitor.

“From my perspective, I feel as though we also care a great bit about getting an independent view, and I believe we take it into account,” he said.

Left to right: Evelyn Robinson and Charles Robinson, PJM ; Greg Poulos, Consumer Advocates of PJM States | © *RTO Insider*

“We think the level of cooperation between PJM and the Market Monitor is at an all-time high, so I’m interested in understanding if that bullet was there just to reaffirm or if there is a perceived issue,” Ott added.

Kristin Munsch of the Illinois Citizens Utility Board clarified that it was meant as support for the Monitor going into contract negotiations next year.

“We wanted to go publicly on record that this was important to us,” she said. “Don’t be surprised when you hear consumer advocates going forward reaffirming, making that point, because we understand the discussions that might be coming to the broader PJM community.”

Bill Fields from the Maryland Office of People’s Counsel said the Market Monitor provides information and analysis in stakeholder meetings that might not otherwise exist.

“We find a lot of value in the Market Monitor continuing to provide that assistance to advocates,” he said.

Roberts brought up another concern about PJM attempting to stop Monitor Joe Bowring from filing complaints at FERC.

“Along with PJM, he is the most knowledgeable person about all matters PJM, and we simply don’t understand why there is a problem with him filing complaints at FERC,” Roberts said. “We think that’s an important [thing] you have stifled.”

Environmental Concerns

The Sierra Club’s Mark Kresowik voiced concerns about what he suggested is a common assumption: that environmentalists seek high energy prices in order to drive efficiency.

“The answer is actually ‘no’ because, in addition to clean electricity being the single most important way that we’re doing to reduce carbon pollution from the economy and ultimately combat climate disruption, clean electricity also has to power the rest of the economy … in order to achieve the levels of carbon pollution reductions that we need,” he said. “In order for clean electricity to play that role, it has to outcompete gas and oil in those sectors, which means it needs to be affordable for all.

“We are increasingly concerned that many of the decisions that are made by PJM, that are in the process of being recommended by PJM, threaten to raise costs, particularly for states and consumers that are actively choosing and preferring clean energy, often without a clear reliability benefit.”

pjm pjm annual meeting consumer advocates — Mike Jacobs, Union of Concerned Scientists | © *RTO Insider*

He also expressed interest in a comment made by Robinson that the board requests cost analysis on major decisions sent to FERC, noting that no such analysis was included in PJM’s recent filing to revise its capacity construct. (See PJM Capacity Proposals Widely Panned.)

“That’s a major concern for us,” he said, “and we’re seeing similar things going forward.”

Mike Jacobs with the Union of Concerned Scientists said the current capacity construct excludes some resources on the grid and he urged PJM to consider allowing resources more flexibility to make capacity offers into annual, summer or winter auctions.

“Optimization is something this organization knows how to do … instead of being stuck with old models and old resources,” he said.

May 22, 2018

Resilience Leads Discussion at PJM Annual Meeting

By Rory D. Sweeney

NATIONAL HARBOR, Md. — Attendees who didn’t pick up on the theme of PJM’s annual meeting last week weren’t listening. “Resilience” was uttered so many times during the General Session that speakers were sheepishly joking about using the word before launching into their own comments.

What did the audience learn from all of it? That it’s complicated. That it requires coordination across multiple organizational levels, and that there’s no template. It’s also likely very expensive — although so are the consequences of disasters when necessary provisions aren’t in place.

Rob Glenn, director of private sector integration for the Federal Emergency Management Agency, urged stakeholders to develop “a culture of preparedness” and run response exercises routinely. Because emergency responders aren’t always paid professionals, he said, coordination needs to occur all the way to the community level and begin well before an event occurs.

Pat Hoffman, the Department of Energy’s principal deputy assistant secretary for the Office of Electricity Delivery and Energy Reliability, warned of cyberattacks on the industry within the next year from Russian hackers.

“Cybersecurity is one of the most important issues facing this industry today,” she said. “We have a huge bullseye on our back. … At this stage of the game, it’s not if but when, so how do we make sure we can continue to operate after an attack?”

The industry is focusing on improvements in sensing technology to support outage recovery, asset management and machine learning, she said. She said one of the industry’s main strengths is being able to articulate how much damage it has sustained from an event, how secure its network remains, what work needs to be accomplished and the steps necessary to move forward.

Resilience Panel

The meeting included a panel discussion on lessons learned about resilience from recent events. Several of the panelists recounted their experiences helping to rebuild Puerto Rico’s electricity grid following Hurricane Maria last year.

resilience pjm annual meeting — Rojas | © *RTO Insider*

Saul Rojas, a vice president of technical compliance for the New York Power Authority, said one of the main takeaways was how tired people were. He said he “never felt so powerless as a manager” when his agency’s satellite phones failed, preventing him from communicating instructions to his crews. NYPA is following up with its vendors to figure out the cause of the problem.

Rojas said NYPA had to think “outside the playbook” in mobilizing to an island with unexpectedly rugged terrain. “When I went to Puerto Rico, I was expecting flat lands and beaches,” he said.

Because of the mountainous terrain and lack of vegetation management in rural areas, the general rule was it took 30 linemen two weeks to restore power to less than 10 customers, he said. “Does it really make sense for them to be connected to the grid? Perhaps … reimagining the grid” with distributed energy resources makes more sense, he said.

Michael Hyland, American Public Power Association’s senior vice president of engineering services, who coordinated with Rojas throughout his time in Puerto Rico, said mobilization was much different than on the U.S. mainland. In contrast with APPA’s mobilization of 60,000 workers in response to Hurricane Irma in Florida, he said, “I can’t just tell them to start driving down I-95.”

He said many utilities don’t recognize the value of mutual aid agreements until they’ve been hit, but that the work in Puerto Rico has been effective. Utilities in Trinidad and Tobago have now joined APPA, he said.

APPA is also developing a variety of drills to simulate potential regional events, such as earthquakes, hurricanes and mudslides. Game theory is also being incorporated to require dynamic responses. “Think [the video game] ‘Oregon Trail,’” he said. “You may die.”

Don Daigler, Southern California Edison’s director of business resilience, recapped his company’s response to last year’s wildfires, noting that at one point there were five fires within its territory for three weeks. He said much of the state was a “powder keg” because of fuel from unusual amounts of undergrowth combined with the “unprecedented” continuation of the hot, dry, fast Santa Anna winds into December.

The company found issues with incident command, executive engagement, real-time investor relations to mitigate stock-price fluctuations, and ground-level strategies to ensure notification. The company embedded workers with fire and lineman experience to provide useful information to responders.

Caitlin Durkovich, a director at Toffler Associates, the strategic consulting and advisory firm founded by “Future Shock” author Alvin Toffler, said the idea is to think about “critical dependencies” between infrastructure systems, such as electricity and water, and realize there are “no bright lines or boundaries” but rather “concentric circles that move outward.” Organizations must be ready to make major changes, said Durkovich, former assistant secretary of infrastructure protection for the U.S. Department of Homeland Security.

Scott Aaronson, Edison Electric Institute’s vice president for security and preparedness, told attendees to focus on unity of effort, message and investment to develop preparedness for a spectrum of possible events.

Ott Defends Fuel Security Initiative

PJM CEO Andy Ott wrapped up the discussion by defending the fuel security initiative announced last month and imploring stakeholders, “I need your help” to improve resilience. (See PJM Seeks to Have Market Value Fuel Security.)

“I do believe that fuel security is resilience,” he said, responding to criticism that the initiative is an effort to funnel money to ailing coal and nuclear plants. “Sometimes folks have been critical of our policies. Sometimes, it’s like democracy: It’s not perfect, but it’s the best game in town.”

Schneider Retires

The meeting culminated in an emotional sendoff for Board of Managers Chairman Howard Schneider, who was forced by term limits to retire from the board. He was the last of the original board members from its inception in 1997 and was its first and only nonexecutive chairman, assuming the position when it was developed in 2007. (See related story, Retiring PJM Chair Schneider Reflects on 21 Years at the Helm.)

Several members of PJM leadership reflected on Schneider’s term, including Ott, who said Schneider taught him how to run the RTO “the right way, to run it with inclusiveness, to run it with integrity.”

Gabel Associates’ Mike Borgatti, chair of the Members Committee, noted that Schneider’s “fingerprints are all over PJM.”

Ake Almgren, who was later elected to succeed Schneider as chair, praised Schneider for how he “always made the extra effort to engage all board members … making the aggregate board stronger than its individual members.” (See PJM Board Elects New Chair, Welcomes New Member.)

In his farewell remarks, Schneider praised his fellow board members.

“I can truly say to you that you have a strong board with a hardworking and knowledgeable person in every slot,” he said.

He also extended a final peace offering to the Independent Market Monitor, with which he had clashed in the past, calling it “not technically a part of PJM, yet an integral part of PJM.”

“The [Market Monitor] is a good check and balance and has important ideas to convey,” he said.

He requested that PJM and its stakeholders protect its markets, keep grid reliability as a priority and value input from the board.

“It usually provides sage advice,” he said.

Finally, he said, PJM “has prospered over these 21 years and my wish is may it continue to do so.”

Stakeholder Process Reforms

Borgatti teased the launch in June or July of an effort to consider potential changes to the stakeholder process and urged members to become involved in the discussion.

“I think it’s incredibly important that we lean in on this one,” he said. “Anyone who wants to participate needs to be given an opportunity to weigh in.”

May 20, 2018

FERC Affirms Rulings in Entergy Bandwidth Dispute

By Amanda Durish Cook

The longstanding disagreement over how Entergy once equalized production costs among its operating companies was at the center of two FERC decisions last week, with the commission upholding opinions from two administrative law judges pertaining to a seven-month period of bandwidth calculations from 2005.

The allocation of production costs from 2005 to 2015 among Entergy’s half-dozen operating companies under its multistate system agreement has been a source of disagreement for a decade. Before 2015, the companies functioned as one system, although each had different operating costs. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average.

Regulators in each state where Entergy operates have regularly challenged the annual bandwidth filings, with the Louisiana Public Service Commission long contending that the company’s bandwidth payment calculation was plagued by inconsistencies. (See FERC Affirms Ruling Favoring Entergy Bandwidth Calculation.)

In the first order issued Thursday, FERC affirmed a presiding ALJ’s 2016 finding that interest on the 2005 bandwidth period should begin to accrue starting on June 1, 2006, instead of on June 1, 2005, the first day of a test period, as the Louisiana Public Service Commission had argued (EL01-88-015).

The commission also sided with the judge that Entergy Louisiana should exclude most of its net operating loss accumulated deferred income tax (ADIT) from the bandwidth calculation because it stems from a $1.8 billion tax deduction associated with above-market value energy purchases from a long-term contract with the Vidalia hydroelectric power station ending in 2031. The Vidalia tax deduction was properly excluded from the bandwidth formula to “avoid shifting tax burdens and benefits” to other Entergy operating companies, FERC said. The Louisiana PSC had argued that Entergy Louisiana’s net operating loss ADIT is not a tax savings and should be included in the bandwidth formula.

ferc entergy bandwidth calculations — Hydroelectric station in Vidalia | *Brookfield Renewable Power*

FERC also agreed that Entergy did not properly account for three regulatory asset deferrals in the 2005 bandwidth calculation and ordered the company to make corrections by switching the deferrals to bandwidth-eligible accounts. The commission confirmed that Entergy should calculate the impact of those accounting changes and make a new compliance filing within 60 days.

In the second order Thursday, FERC affirmed another ALJ’s ruling that Entergy had already addressed the question of how 2005 bandwidth calculations should be handled. The commission said Entergy can use its 2006 compliance filing on bandwidth calculations, which FERC accepted in 2007 (EL01-88-017).

Entergy had questioned whether it could apply its 2006 filing for the bandwidth formula calculation to the seven-month period of bandwidth calculations in 2005 after the Louisiana PSC argued that the 2006 filing was not the properly filed rate for 2005 and could not accommodate a seven-month remedy, as it was designed for an annual calculation. FERC said the Louisiana PSC’s argument amounted to a “collateral attack” on its prior rulings in the Entergy bandwidth calculations.

However, FERC disagreed with the judge that the bandwidth formula used for 2005 must “contain all amendments that have been made to the formula in subsequent years.”

May 20, 2018

Michigan Farm Granted Partial Waiver of QF Filing Requirements

By Amanda Durish Cook

FERC ruled last week that a Michigan soybean farm operating two small biomass plants is not excused from a requirement to file as a qualifying facility under the Public Utility Regulatory Policies Act, but it reduced the consequences of the farm’s yearslong failure to do so.

The commission on Thursday said Zeeland Farm Services had a responsibility to file for QF status, even though the company claimed it was unaware of its filing obligation for 10 years. The order partially waived the filing requirement so the two facilities could be largely treated as QFs for the time they operated out-of-compliance (EL17-70, et al.).

The farm owns two 1.6-MW landfill gas-fueled facilities located at its soybean processing facility in Zeeland, Mich. Under a FERC rule enacted in 2006, generating facilities larger than 1 MW must file for QF status.

Zeeland Farm QF Filing FERC PURPA — Zeeland Farm Services | *Google Maps*

One of Zeeland Farm’s biomass facilities began operating in late 2005, with the other following in 2008. The farm had sold the output to Consumers Energy under two, seven-year power purchase agreements.

FERC did not shield Zeeland from Sections 205 and 206 of the Federal Power Act, leaving the farm facing refunds for “the time value of the revenues collected … for the entire period that the rate was collected without commission authorization.” The farm has already filed a report approved by FERC earlier this month establishing that over the course of the PPAs, it lost money on fuel expenses and operations and maintenance costs, which totaled about $7.9 million (QF17-935). Zeeland collected a total $7.6 million for energy and capacity sold to Consumers, and the commission agreed a refund report should not be required because the farm was unable to recover some variable costs.

FERC also said Zeeland will not have to refund the difference between a market-based rate and a cost-justified rate, as the FPA prescribes, because rates were negotiated with Consumers.

Zeeland said it only became aware of the filing requirement in late 2016, and it filed notices of self-certification last May after informing Consumers of the mistake and conducting a review to make sure the biomass plants still fit the QF definition. Zeeland said its failure to timely submit notices of self-certification was the result of a “good-faith, inadvertent error by individuals and companies otherwise not engaged in the power business.”

But the commission didn’t express sympathy for the oversight. “Zeeland Farm has not justified its failure to comply with a filing requirement that has been present in the commission’s regulations since 2006,” FERC said. “In similar situations, the commission has not been persuaded by claims that the facility met all other requirements for QF status because that argument improperly minimizes the importance of the filing requirement.”

May 20, 2018

FERC Clarifies CEII Rules, Denies Rehearing

By Rich Heidorn Jr.

FERC on Thursday rejected the Edison Electric Institute’s request for rehearing of its 2016 order on handling of Critical Energy Infrastructure Information but offered clarification on several points.

EEI challenged several aspects of Order 833, which implemented the CEII provisions attached to the 2015 Fixing America’s Surface Transportation (FAST) Act. (See FERC OKs Information Security, FOIA Rules.) It said the commission failed to adequately specify the criteria it uses to determine whether a member of the public is eligible to obtain CEII.

The commission responded that it has obtained “vast experience” since instituting the CEII process in 2003, noting it “routinely processes CEII requests from, among others, consultants, academics, landowners and public interest groups.”

Critical Energy Infrastructure Information EEI FERC — | © *RTO Insider*

However, it clarified that “public safety benefits” are one criterion that it should consider in balancing “the requester’s need for the information against the sensitivity of the information.”

EEI also said the commission should revise its CEII nondisclosure agreement “to mitigate against the risk of a CEII recipient involuntarily sharing CEII with a hostile actor.”

FERC declined to change the minimum requirements for the NDA but said the commission’s CEII coordinator “may consider adding additional provisions to the NDA on a case-by-case basis.”

The commission also rejected EEI’s contention that it erred in not providing a way for entities to comment on the sharing of commission-generated CEII.

“The FAST Act does not require, and EEI identifies no provision in the FAST Act requiring, the commission to provide notice and opportunity for public comment about the prospective release or sharing of commission-generated CEII. Furthermore, the commission is not persuaded that we should establish a requirement for stakeholder input when the commission combines information not filed as CEII with other information and potentially creates CEII,” FERC said.

“We, however, clarify that nothing in the FAST Act or the commission’s CEII regulations prevents the CEII coordinator from exercising discretion in an individual situation to solicit comments from a submitter of CEII or other information when evaluating whether to release a commission-generated CEII document.”

May 20, 2018

PJM Markets and Reliability Committee Preview: May 24, 2018

Below is a summary of the issues scheduled to be brought to a vote at Thursday’s PJM Markets and Reliability Committee meeting, which will be held at the PJM Conference and Training Center and not its normal location at the Chase Center in Wilmington, Del. 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 in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:45)

Members will be asked to endorse the following proposed manual changes:

A. Manual 36: System Restoration. Revisions developed as part of the manual’s annual review; includes clarifications regarding synchro-check relays, blocking governors and black start generators.

B. Manual 3: Transmission Operations. Biannual review to update operating procedures. Revisions update remedial action schemes, sectionalizing schemes and definitions for the Cleveland and Eastern interfaces; designates voltage limits for Ohio Valley Electric Corp.’s impending integration; adds language regarding reactive reserve check submittals and clarifies notes on load shed activity.

C. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to ensure consistency between the manual and Operating Agreement regarding price-based offers of more than $1,000/MWh. The change was necessitated by FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. (See “Offer Cap Resolution,” PJM Market Implementation Committee Briefs: May 2, 2018.) Also includes conforming changes regarding bidding locations for virtual transactions.

D. Manual 14A: New Services Request Process. Annual review. Revisions developed to introduce the Queue Point software for submitting data for feasibility and system impact studies.

E. Manual 7: Protection Standards. Revisions developed by the Relay Subcommittee to add clarity, update terms and add reliability requirements.

F. Manual 14D: Generator Operational Requirements. Revisions developed to define procedures and notification deadlines for transferring ownership of generation resources. (See “Gens Get Commercial Realities into Gen Transfer Processes,” PJM Operating Committee Briefs: May 1, 2018.)

3. Cost Containment (9:45-10:25)

Members will be asked to vote on proposals to include consideration of cost-containment commitments in PJM’s analysis of transmission construction bids. This is the continuation of a discussion that was tabled for four months as stakeholders attempted to find consensus. PJM has two proposals it plans to offer, but LS Power’s proposal will be considered first since a vote on it was deferred at the January MRC. (See Cost Containment Proposal Survives; Headed to MRC.)

4. Variable Operations & Maintenance Packages (10:25-10:45)

Members will be asked to vote on proposals to change rules on submitting variable operations and maintenance (VOM) costs for recovery. Two proposals were endorsed at April’s Market Implementation Committee meeting:

The PJM package, which was supported by a 75% vote, would allow only actual maintenance costs directly tied to electric production can be included in a unit’s incremental energy offer.
The default VOM package, which won an 81% endorsement, would allow resources to choose between filing actual costs under the PJM package or a default value no greater than the new build data published by the U.S. Energy Information Administration.

A third package developed by the Independent Market Monitor may also be considered. (See “VOM Proposal,” PJM Market Implementation Committee Briefs: April 4, 2018.)

5. Operating Agreement Confidentiality Provision (10:45-10:55)

Members will be asked to endorse OA revisions allowing PJM to share member confidential information with the Eastern Interconnect Data Sharing Network (EIDSN) in addition to NERC and other reliability entities. EIDSN was created in 2014 to develop industry tools that NERC has decided it no longer wants to create and maintain.

— Rory D. Sweeney

May 20, 2018

Emerging Tech Taking Center Stage at MISO Market Symposium

MISO last week announced that it will hold its second Market Symposium in downtown Indianapolis on Aug. 15-16.

This year’s theme is “Markets in 3D: Preparing for Digitalization, De-marginalization and Decentralization,” and the two-day event includes industry experts discussing how wholesale market design and technology may change with increasing use of connected devices, distributed energy resources and renewable generation with near-zero marginal costs.

MISO CEO John Bear at the 2016 MISO Market Symposium | © *RTO Insider*

“The MISO team is working to create a forum for industry leaders at the forefront of future market design to explore longer-term challenges and opportunities,” MISO CEO John Bear said in a statement. “The symposium will provide a venue to interact with thought-leaders, explore emerging technologies and build relations with decision-makers and innovators who are at the helm of a changing industry.”

The symposium will feature FERC Commissioner Richard Glick as special guest speaker, and MISO has again partnered with the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) to host the event.

MISO’s first symposium was held in 2016, and the sold-out event focused on future low-carbon energy trends. (See Panelists Envision Low-Carbon Future at MISO Symposium.)

This year’s symposium also includes an emerging technology and market solution showcase. MISO is currently accepting applications for booth exhibits and five-minute presentations on industry innovations on the main stage.

“We know our industry is transforming,” said MISO Research and Development Director Jessica Harrison. “We want to foster thought-provoking discussions so that the industry can meet future challenges with innovative solutions that ultimately improve service and value for consumers.”

— Amanda Durish Cook

May 20, 2018

CAISO Board Approves Forecast Error Measures

By Jason Fordney

CAISO’s Board of Governors on Wednesday approved new provisions to account for errors in load forecasts by allowing grid operators to manually update the forecasts to deal with changing conditions on the grid.

CAISO imbalance conformance rules board — Berberich | © *RTO Insider*

At its May 16 meeting in Folsom, Calif., the board also heard from CEO Steve Berberich about the tight supply conditions the ISO foresees this summer, as well as what he called “a very serious issue” regarding inverters that caused an 860-MW loss of solar resources on April 20.

The board approved the new “imbalance conformance” rules that allow the ISO to account for errors in renewable energy forecasts or instances when generators deviate from their dispatch orders. The Energy Imbalance Market Governing Body approved the rules last month. (See EIM Body Approves Imbalance Conformance Rules.)

The board also approved alterations to the Imbalance Conformance Limiter, an ISO software tool designed to prevent price spikes caused by imbalance conformance adjustments. The limiter keeps the market from trying to dispatch more supply than is available in a particular dispatch interval to account for imprecision in the adjustments.

CAISO Department of Market Monitoring Director Eric Hildebrandt told the board that while the department supports the changes, the magnitude of load adjustments has increased dramatically, doubling between 2016 and 2017. The adjustments should be more random in nature and not used as systematically as they have been, he said.

In his presentation, Hildebrandt said “the ISO appears to use load conformance as means to procure additional imports in the hour-ahead process to ensure more ramping capacity is available in the 15-minute and five-minute markets.”

The Monitor recommends the ISO focus on how it can reduce the need for operators to make manual adjustments in real time.

Southern California Edison opposed the changes, saying that the new limiter enhancements should be implemented in addition to the old limiter logic in order to maintain price stability. Powerex also opposed the measures, saying they might suppress scarcity pricing in some situations, according to a presentation from CAISO Vice President of Market Infrastructure Keith Casey. FERC must approve the changes before they take effect.

Warnings of Tight Supply, Inverter Issues

Berberich explained to the board that on April 20, the Mira-Loma-Vincent 500-kV line in the SCE service territory relayed, causing 860 MW of solar to trip off because of voltage fluctuations.

CAISO Board of Governors left to right: Richard Maullin, Angelina Galiteva, Dave Olsen, Mark Ferron, Ashutosh Bhagwat | © *RTO Insider*

“It’s a really exciting event down in the control room when we lose 860 MW,” Berberich said during his CEO report.

CAISO has been trying to reprogram inverter settings so they can ride through the relays and is working with NERC to create an appropriate industry-wide standard to address the problem. While the ISO has been able to reprogram some inverters, others cannot be reprogrammed, leading it to rely other resources at certain times.

“We are going to keep a close eye on this issue,” Berberich said, adding that the ISO views the new NERC standard as an important goal. He said public calls for demand reductions will be key in managing grid conditions this summer.

“We expect to have very tight conditions this summer,” Berberich said, adding that the gas system is operating at a “bare minimum.”

An ISO presentation showed that after modeling 2,000 scenarios, it was found there is a 50% probability of a Stage 2 emergency for at least one hour this summer. CAISO declares a Stage 2 emergency when it becomes clear that operating reserves will be less than 5% after dispatching all resources, including demand response. The ISO did not include in its modeling the gas supply limitations from restricted use of Aliso Canyon, which it said could represent further reliability risk. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)

FERC said last week it will closely monitor grid conditions in Southern California this summer as the region faces the likelihood of above-normal temperatures. (See FERC Keeps an Eye on ERCOT, CAISO as Hot Summer Approaches.)

May 20, 2018

NYPSC Reviews Storm Recovery, Summer Grid Prep

ALBANY, N.Y. — About 194,000 customers in New York were without electric power in the state after a series of thunderstorms hit on May 15, the Public Service Commission heard Thursday.

NYPSC outages thunderstorms — Worden | © *RTO Insider*

The outages were mostly in the Lower Hudson Valley, the same area that suffered severe outages in March, said Michael Worden, director of the commission’s Office of Electric, Gas and Water.

“We have about 5,550 [full-time equivalents] of line, tree and service crews there providing support to the area,” Worden said. “That includes on the order of 1,250 out-of-state, out-of-region crews, and also includes a large contingent of New York crews that have been redeployed from, for example, Western New York. So there’s a significant recovery effort going on.”

By Saturday, most customers had had their power restored, with only about 13,600 still out, according to PowerOutage.us, which aggregates utility-reported outage data.

The commission is continuing to investigate the various utilities’ March outages and storm response efforts, Worden said.

Grid Ready for Summer

New York’s bulk electric system is prepared to reliably meet this summer’s load forecast, according to the Department of Public Service.

Department staff based its assessment on a review of utility data and meetings with individual utilities and NYISO, Vijay Puran, DPS senior engineer for electric transmission planning, told the commission.

“Utilities will complete all planned major reinforcements, inspections and repairs prior to the start of the summer season, and they have adequate spare equipment on hand to meet unforeseen circumstances,” Puran said during a presentation.

The ISO predicts demand will peak at 32,904 MW this summer. With a total resource capability of 42,169 MW on hand, the grid’s margin of safety comfortably exceeds the 18.2% required installed reserve margin, Puran said.

Peak demand forecasts have dropped by more than 3,000 MW since 2015, which the ISO “attributes to the positive effects of the state’s energy programs and to underlying forecast econometric growth rates,” he said.

Puran said hundreds of megawatts of load reduction are available to Consolidated Edison through its demand response programs, and other utilities have similar load-relief measures they can turn to if needed.

DPS staff expect the cost for electricity this summer to be higher than last year but 9 to 12% below the five-year average.

“I hear this as an outlook that is good news for New Yorkers, giving us comfort that we can confidently expect adequate supply and reasonable costs,” PSC Chair John B. Rhodes said.

National Grid Utilities Audit

In its consent agenda, the commission ordered a management and operations audit of three National Grid USA subsidiaries: Niagara Mohawk Power, Brooklyn Union Gas and KeySpan Gas East (18-M-0195). The effort will focus on construction program planning and operational efficiency.

“The audit will include an assessment of the utilities’ readiness to respond to the Reforming the Energy Vision initiative and closely examines how the utilities plan for and manage information systems projects,” Rhodes said in a statement. “The audit will also address issues from previous management audits that require follow-up review, such as organizational structure, project estimating processes and work management processes.”

Gov. Andrew Cuomo in 2013 highlighted the importance of management and operations audits of the state’s utilities, and introduced — and subsequently signed — legislation that required utilities to file plans for implementing audit recommendations.

This is the fourth comprehensive audit since 2013, and three additional audits are underway, the commission said.

“To date, these audits have recommended numerous productivity enhancements, better risk mitigation strategies, and improved planning processes, as well as other operational improvements at New York’s utilities,” the commission said. “These process improvements result in savings for customers over time, and those savings are captured in rate cases.”

— Michael Kuser