Page 1384 – RTO Insider

April 29, 2018

Stakeholders Oppose PJM PFR Mandate for Existing Units

By Rory D. Sweeney

VALLEY FORGE, Pa. — Although FERC has required almost all new generating units to provide primary frequency response, PJM stakeholders are strongly opposing any move by the RTO to require existing units to follow suit.

That disapproval became clear last week at a meeting of the Primary Frequency Response Senior Task Force (PFRSTF), during which staff reviewed the resu l ts of a nonbinding poll that revealed stakeholder support for the only PFR proposal that does not impose a mandate on units that don’t increase their output.

PJM FERC primary frequency response PFR — Stakeholders at PJM’s Primary Frequency Response Senior Task Force meeting listen to a presentation from PJM staff on why PFR is necessary during system restoration. | © *RTO Insider*

The proposal from American Electric Power (AEP) would apply PFR capability requirements on new units and existing units that modify their interconnection agreement to increase their output. Units that already provide PFR would be “encouraged to continue to do so” and can seek compensation at FERC. Units would annually confirm whether they will continue to provide the service, and PJM and transmission owners would revise system restoration plans accordingly.

A 10% dip in the system-wide aggregate PFR would trigger reconvening the task force “to analyze and suggest, if necessary, possible solutions.”

Stakeholders strongly opposed all three other proposals, two of which came from PJM and the third from the Independent Market Monitor. They all applied PFR capability on existing units but differed on minimum size or use thresholds and cost-recovery mechanisms.

“Part of the hang up we have with PJM’s initial proposal is the universal requirement for all. Where we get concerned is … if there’s compensation involved, we’ve got to foot the bill here,” explained Dave Mabry, who represents the PJM Industrial Customer Coalition (ICC). “I think the AEP proposal gets us a little bit closer to looking at: Does it make sense for a unit to have it?”

The PJM ICC believes existing units already have an avenue to be compensated for PFR costs through the capacity market, Mabry said, and would support provisions that develop a cost-benefit analysis for whether units should make those investments.

Carl Johnson, who represents the PJM Public Power Coalition, said he was “a little confused” by the lack of support for PJM’s “option B” proposal, which would require PFR only for units involved in system restoration plans and would offer them a one-time capital recovery method.

“On behalf of my members who both represent load but also self-serve load and have a lot of generation … we have concerns about anything that’s going to add costs for a service that we think maybe you should be providing anyway, but at the same time we have concerns about being audited and reported for failure to provide it, [including] the possibilities of selective enforcement. So, we’re of two minds on this,” he said. “I think we still need to work out a lot of issues with regard to what a broad requirement for PFR would be.”

GT Power Group’s David Pratzon and Tom Hyzinski voiced concerns about “retroactive ratemaking” and unfair demands on generators.

“If you take a look at those existing resources, a lot of them are resources that are financially challenged in the market right now. So, on one hand, to say they’re absolutely critical to the integrity of the system but then to turn a blind eye to the fact that they’re challenged in the market and to not make any attempt to compensate the vast majority of them for this critical value that they bring to the table” is unfair, Hyzinski said.

Package Criticism

PJM’s Glen Boyle said staff heard feedback that the proposals weren’t aligned with FERC Order 842, which some stakeholders believe specifically exempts existing resources from PFR requirements — the opposite of PJM’s interpretation. Stakeholders also said that exempting nuclear units — in harmony with the exemption of any new nuclear units in FERC’s order — was discriminatory.

The requirement would be an “unfunded mandate” and wouldn’t support capital cost recovery, stakeholders said. Calpine’s David “Scarp” Scarpignato agreed.

“If you have to go through a complex, very expensive, tedious process in order to get paid back for something, and there’s no kind of internal rate of return, I think some people might view those as unfunded,” he said.

Finally, RTO staff heard they did not satisfactorily make the case for the requirement, a criticism they attempted to address with presentations on a recent repo r t from the Lawrence Berkeley National Laboratory and the i m portance of PFR in system restoration. PJM’s presentation detailed the many uses of PFR during such events, while the laboratory study emphasized the importance of having as many generators as possible provide the service.

Pratzon noted the possibility that some units may find it’s not worth the investment to provide PFR if they’re required to do so, weighed against a related concern that, without such a mandate, those who continue to provide PFR will be unfairly overcompensating for those who don’t.

“There are problems going down either direction,” he said.

Next Steps

Johnson noted that FERC is awaiting a report from NERC in July on the availability of existing facilities to provide PFR and suggested that discussions should continue but hinge on the report’s publication.

Scarp said he plans to offer an alternative package based on the feedback from the meeting.

PJM staff decided against moving for a binding vote until the group comes to a consensus or FERC responds to a request for rehearing of Order 842. The task force’s next meeting is May 23.

April 29, 2018

MISO Storage Group Begins Order 845 Consideration

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Energy Storage Task Force will now add to its to-do list storage-related aspects of FERC’s recent rulemaking on generator interconnection procedures (Order 845).

The group said it will begin examining how MISO might need to alter provisions for energy storage interconnection to comply with the April 19 order, which prescribes more transparency and timeliness for RTOs’ large interconnection agreements.

MISO Energy Storage — AES battery storage | *AES*

The order is expected to remove even more barriers to storage interconnection, according to MISO stakeholders. It explicitly revises the definition of a generating facility to include storage, permits interconnection customers to apply for interconnection service lower than the capacity of their generating facility and requires transmission providers to provide interim interconnection agreements for limited operation of a generating facility prior to completion of the full interconnection process, among other rules. (See FERC Order Seeks to Reduce Time, Uncertainty o n Interconnections.)

“There are plenty of decisions in that order that are going to be impactful to storage,” Energy Storage Task Force Chair John Fernandes said during an April 26 meeting.

Currently, there’s just under 500 MW of energy storage in various stages of MISO’s interconnection queue.

The task force began discussing the order after an April 25 conference call in which MISO’s Steering Committee agreed to allow the group to explicitly consider both Order 841 and Order 845 when identifying discussion topics to recommend to other stakeholder groups. (See Committee Ponders Expanded Role for MISO Storage Group.)

MISO executives at the meeting said they are still reviewing Order 845 to identify how the RTO will be required to alter the interconnection process.

Executive Director of Resource Planning Patrick Brown said FERC’s final order did not prescribe how to best model electric storage for the interconnection process, instead leaving storage modeling to be worked out between transmission providers and stakeholders.

Brown also noted the final order denied a request that energy storage be modeled as transmission assets in the interconnection process but said MISO is still determining whether the denial precludes storage from being treated as transmission.

“We’re going to have to talk with our legal team about this,” Brown said.

However, American Transmission Co.’s Bob McKee said he found nothing in the order preventing storage from being modeled as transmission.

“FERC is certainly still open to storage as a transmission asset,” McKee said.

“Storage as transmission, that’s kind of the next big thing in our industry to get FERC to make some rules around,” Fernandes said. “I still think FERC is giving the green light to go ahead and do this; they’re just not providing explicit rules yet.”

Brown also said MISO may have to make a few tweaks to allow for interconnection service with surplus capacity, although the RTO’s process for net-zero interconnection service requests could probably cover most of the directive.

“We believe that revisions to our net-zero provisions take care of that,” Brown said, while conceding that some of MISO’s net-zero rules may be too restrictive to meet FERC’s compliance.

However, Wind on the Wires’ Rhonda Peters said it’s too “cumbersome” for projects to line up for net-zero interconnection service because of the requirement that customers must already be in the queue and provide milestone payments before they’re able to respond to a request for proposal for net-zero service.

But Fernandes cautioned that while the Energy Storage Task Force could debate the interconnection queue as far as storage eligibility, queue improvements are the domain of MISO’s Interconnection Process Task Force (IPTF).

“This task force is not assigned queue reform,” Fernandes said.

Brown agreed a majority of work on Order 845 will be done at the IPTF. Fernandes said he would try to plan a joint conference call of the IPTF and the Energy Storage Task Force prior to mid-May to discuss how FERC’s order might make MISO’s queue process more storage-friendly.

Brown said some work to comply with Order 845 will come down to finding language already included in MISO’s business practice manuals and copying that language into the Tariff.

Some stakeholders asked if MISO would consider requesting an extension with FERC on the July compliance filing deadline for Order 845. Brown said MISO is judicious when requesting extensions, making sure it requests them only when necessary.

“It’s a fairly short lead time,” Brown conceded.

Process Holdup?

Stakeholders in attendance worried the July deadline would not provide enough time for the task force to identify Order 841/845 storage issues, then turn them over to the Steering Committee, which must then assign discussion to other stakeholder groups.

Customized Energy Solutions’ Ginger Hodge said she was becoming “increasingly concerned” that the formal process of identifying issues and sending them to the Steering Committee was creating a roadblock to getting proposals written and vetted in other stakeholder groups.

Hodge said she didn’t want the Steering Committee to become a place where “good ideas are quietly strangled.”

April 29, 2018

Dominion: ‘No Flexibility’ on SCANA Bid

By Rory D. Sweeney

South Carolina legislators continue to maneuver as if there is some room to negotiate the terms of a deal to sell SCANA to Dominion, but Dominion CEO Thomas Farrell emphatically rejected that presumption on a Friday conference call to discuss the company’s first-quarter earnings.

“No flexibility,” Farrell said. “We’ve made our offer, and it’s going through the political process now.”

The state legislature must approve the nearly $8 billion takeover bid, which includes controversial provisions for customers to continue paying on a failed nuclear plant in the state. He noted that the legislature’s session ends on May 11.

Dominion reported first-quarter operating earnings of $741 million ($1.14/share), which beat analysts’ estimates by $0.08/share and improved on earnings of $611 million ($0.97/share), for the same period in 2017. Revenue of $3.47 billion improved 2.7% from the same period last year but missed expectations by $50 million.

Dominion Energy SCANA big earnings Q1 2018 — Dominion announced its first-quarter earnings on Friday. | *Dominion*

The company’s unadjusted earnings were $503 million ($0.77/share), compared with $632 million ($1.01/share), for the same period in 2017.

Paul Koonce, Dominion’s executive vice president and CEO of the Power Generation unit, was also upbeat about the prospects for its Millstone nuclear plant to receive subsidies through a Connecticut procurement process previously reserved for renewables. State officials will be issuing requests for proposals for renewable generation in May, he said. Bids will be open through September and approved by year end. The company plans to pursue an “at-risk” designation for the plant that will allow it to include non-price factors in its offer, including zero carbon emissions, fuel diversity and grid reliability, he said.

“They have a report … that showed what it would cost consumers if Millstone were to retire, so I think there is some recognition of the value of Millstone, so really [all those developments are] supposed to play out between now and September with bids being approved by year end,” he said.

April 29, 2018

PJM Stakeholders Clash Over “Heart” of Containment Provisions

By Rory D. Sweeney

Stakeholders last week plowed through several hours of material at a special PJM Planning Committee session on whether the RTO should include cost containment provisions in its analysis of competitive bids for new transmission, but they ended up tabling what has become the most important issue.

The wide-ranging discussion covered the results of a stakeholder p o ll and related comm e nts, PJM’s proposal temp l ates, proposed contract languag e regarding revenue requirement provisions and proposed chan g es for evaluating Order 1000 projects. However, stakeholders were unable to reach consensus on whether PJM’s criteria for selecting projects should weigh a developer’s commitment to a cap on the return on equity (ROE) it will seek during its ratemaking process at FERC. The issue received a significant amount of contentious discussion, including a consumer advocate pres e ntation on the importance of such caps, but no decision was reached.

PJM Planning Committee Cost Containment Provisions — PJM is considering a realignment of how it considers competitive transmission proposals to include cost-containment provisions. | *PJM*

Alex Stern with Public Service Electric and Gas (PSEG) said he didn’t think the idea is consistent with applicable law and called it “a complete end-around” of Section 205 of the Federal Power Act.

“I am very concerned about enforceability,” he said.

Erik Heinle of Office of the People’s Counsel for the District of Columbia, who presented on the value of ROE caps, disagreed that the voluntary proposals ran afoul of FERC’s authority.

“We are very clear that FERC is the rate-maker. They should be the rate-maker,” he said. “I don’t think this makes it some sort of coercive issue where everybody has to do it.”

LS Power attorney Mike Engleman of Washington, D.C., firm Engleman Fallon also took issue with objections to the provisions.

“We completely disagree that this is outside what PJM can look at or do. PJM isn’t setting the rates. PJM is accepting a voluntary commitment of what the developer will do in filing at FERC,” he said. “The entire purpose of Order 1000 is to get the benefits of these types of proposals to ratepayers. … Nobody’s forcing PPL or PSEG or anybody else to make a proposal they don’t want to make.”

Representatives from fellow transmission owners PPL and Duquesne Light Co. backed Stern’s position, noting legal precedents for why the provisions wouldn’t stand. However, Ruth Ann Price, who represents the Delaware Division of the Public Advocate, challenged them to provide their cases.

“At the right time, they’ll be provided,” Stern responded. “That’s what we do when we go to FERC. This is not a legal proceeding.”

“What right time? Now is the right time. We’re discussing it,” Price said.

PJM staff attempted to reach agreement that everyone favored additional transparency and move on from the topic, but LS Power’s Sharon Segner insisted that it continue to be addressed.

“The ROE discussion is at the heart of what this discussion is supposed to be about,” she said. “It is not a discussion solely about transparency.”

The issue will be addressed again at the next special session on the issue on May 11.

Segner acknowledged some very “positive developments” in the proposal templates PJM presented, particularly on aspects regarding clear disclosures of cost commitments. PJM’s templates would create clear, uniform and organized proposal submissions that would make project comparison easier. Segner, with strong support from several consumer advocates, has largely led the push for cost-containment considerations and templates, having proposed her own set in recent meetings. (See PJM Stakeholders Explore Cost Containment C o mplexities.)

Segner also noted that LS has backed away from proposing any caps on operations and maintenance costs and won’t include them in its proposal to the Markets and Reliability Committee on May 24.

“We weren’t able to find any evidence that the market was responding robustly to [operations and maintenance] caps” in other RTO/ISO competitive windows, she said. “These other issues are bigger-ticket items to the ratepayers, so why not focus discussions there?”

April 29, 2018

SPP Regional State Committee Briefs: April 23, 2018

KANSAS CITY, Mo. — SPP’s Regional State Committee (RSC) last week approved the scope for a study of cost allocation in wind-rich areas, a problem that grows along with the RTO’s wind generation.

The study will work with SPP staff to review correlations between generation and load flows on systems below 300 kV and identify potential rate approaches, selecting up to three for further review. Final recommendations are due back to the RSC in April 2019.

RSC SPP cost allocation Wind generation — Regional State Committee gathers for its April meeting. | © *RTO Insider*

“We’re not throwing the highway/byway out,” said Cost Allocation Working Group (CAWG) Chair John Krajewski, who represents the Nebraska Power Review Board, during the RSC’s Apr. 23 meeting, referring to the methodology by which SPP allocates transmission costs according to project size.

Under highway/byway, facilities of 300 kV or more are considered highway facilities and their costs allocated on a regionwide, postage stamp basis; facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide. Projects under 100 kV are allocated entirely to the host zone.

The RSC in January directed the CAWG to study the issue, following a presentation by Sunflower Electric Power on cost allocation issues in wind-rich areas. (See “Committee Takes on Cost Allocation Issues” in Mountain West, Cost Allocation Top SPP RSC Concerns.)

Sunflower’s Al Tamimi told the RSC in January transmission projects used to be based on changes in load or in designated resources in the same geographical area where the facilities are built. Today’s renewable generation is built at great distances from load centers, with many wind projects in small load zones exported elsewhere, he said.

While the local zones don’t necessarily benefit from the reduced energy costs from the additional wind, they are saddled with the byway costs in the highway/byway methodology, Tamimi said.

CAWG to Get Liaison with HITT

The RSC determined the CAWG should have a liaison on the Holistic Integrated Tariff Team (HITT), given that the group’s work overlaps with the HITT’s proposed scope. “HITT’s work touches on everything the RSC does,” said Oklahoma Corporation Commissioner Dana Murphy.

RSC SPP cost allocation — Missouri’s Scott Rupp (l-r), South Dakota’s Kristie Fiegen, Kansas’ Shari Feist Albrecht share a laugh. | © *RTO Insider*

The committee left the recommendation on a CAWG liaison to HITT Chair Tom Kent.

The RSC also voted unanimously to suspend “until further notice” the CAWG’s work on the new member cost allocation review process.

The committee had asked the group in January to draft a report on the effect of new members on existing cost allocations, a reaction to the Mountain West Transmission Group’s pending integration into SPP. Xcel Energy’s sudden departure from the group has temporarily rendered the report moot.

Committee Approves Triggers to Baseline Cost Escalation

The committee approved a Tariff change that memorializes as a business practice the current practice of using triggers to stop the annual escalation of transmission projects’ undefined baseline costs.

The Markets and Operations Policy Committee approved the Project Cost Work Group’s (PCWG) revision request on Apr. 10. PCWG-RR255 adds triggers when a designated transmission owner provides 1) SPP a letter of commercial operation; 2) notification that an upgrade is in-service; and 3) notification that an upgrade is complete.

— Tom Kleckner

April 27, 2018

EIM Body Approves Imbalance Conformance Rules

By Jason Fordney

Western Energy Imbalance Market (EIM) leaders on Tuesday approved rule changes that would allow EIM balancing areas to manually adjust load forecasts during market operations to ensure the grid can support system conditions.

The five-member EIM Governing Body at a meeting in Vancouver, Canada, approved the ISO’s proposed “Imbalance Conformance” rule changes, which allow operators to manually update the load forecast to account for changing grid conditions. Conformance is used to account for errors in the load forecast, CAISO Market Design Manager Brad Cooper told the body.

“A lot of times it is [used] because of supply deviations, whether it is generators deviating from their dispatch or renewable energy forecast error,” Cooper said during a pres e ntation. The body’s decision conforms with CAISO’s final proposal issued in mid-March, which clarifies that ISO and EIM balancing area operators can make imbalance adjustments, a clarification CAISO said it was making in the interest of transparency.

The proposal also includes alterations to the “Imbalance Conformance Limiter,” an ISO software tool designed to prevent price spikes caused by imbalance conformance adjustments. The adjustments can be imprecise, CAISO said, and the limiter keeps the market from trying to dispatch more supply than is available in a particular dispatch interval.

The Governing Body unanimously approved the tariff clarifications under its primary authority, while the Imbalance Conformance Limiter changes fall under the body’s advisory role. CAISO plans to seek approval from its Board of Governors on May 16 and then submit them to FERC.

Imbalance Conformance EIM Governing Body Western RTO — Average ISO conformance data from third quarter 2016 & 2017 | *CAISO*

The ISO said the changes were approved by all stakeholders, including Arizona Public Service, the Department of Market Monitoring, Pacific Gas and Electric, Public Generating Pool, Powerex, Southern California Edison and the Six Cities group of Southern California utilities.

CAISO initially announced the rule changes last November. Also called “load bias,” the practice has drawn comment from some market participants that note CAISO is increasingly relying on it, particularly in early morning and evening hours when solar generation comes online and offline. (See ‘Load Bias,’ Prices Rise in C A ISO Q3.)

In its proposal, the ISO noted that imbalance conformance is imprecise because it uses an aggregated value since manually updating all the supply deviations every five minutes with 100% accuracy is not possible. Using the load forecast allows the conformance adjustments to be spread evenly across the system.

Two Spots to Open

EIM Governing Body Chairman Doug Howe is due to step down from the panel at the end of June, when his first term ends. (See ‘Hesitancy’ Around Western RTO, E IM Chair Says.) Body member Carl Linvill’s term also ends on June 30, and it is not known whether he will seek re-nomination. Other members include Vice Chairs Valarie Fong and John Prescott, whose terms end in 2019, as well as Kristine Schmidt, whose term runs out in 2020. All five are original members of the panel overseeing the regional market, which is expected to incorporate CAISO’s day-ahead market functions, a major change. (See CAISO S a ys Changes Will Better Match Forecasting, Demand.)

CAISO Regional Affairs Manager Peter Colussy told the board that an eight-member nominating committee and a third-party executive search firm are looking nationwide to fill two positions on the board. In-person interviews for new EIM Governing Body candidates are set for May 10-11 in Phoenix, Ariz. Relevant expertise is needed, as well as a familiarity with the Western Interconnection, and candidates must be independent of participants in the ISO and EIM markets or those who advocate for certain positions in the ISO stakeholder process, Colussy said in a presen t ation.

The approved slate of candidates is due for approval by the Governing Body on June 20. Terms are three years, beginning July 1 of each year and ending on June 30.

In January, the EIM Governing Body rejected a proposal that would have changed how the board nominates members. (See EI M Body Tables Nominating Process Changes.) The rejected proposal would have eliminated the EIM Nominating Committee’s obligation to use an executive search firm to help fill Governing Body vacancies, instead encouraging committee members to rely more on their own contacts.

April 26, 2018

PSEG to Pay $39.4M to Settle FERC Investigation

By Rich Heidorn Jr.

Public Service Enterprise Group’s energy trading arm has agreed to pay $39.4 million to settle an investigation into violations of PJM’s energy market bidding rules over 9 years (IN18-4).

The commission’s April 25 order approving a consent agreement with PSEG Energy Resources & Trade, which markets the output of PSEG Power’s generation fleet, both praised and criticized the company’s actions in the matter.

The non-public investigation was disclosed earlier this month, when FERC’s Office of Enforcement issued a Notice of Alleged Violations charging PSEG with violating PJM’s Tariff and FERC regulations by submitting incorrect cost-based bids into PJM’s daily energy market between 2005 and 2014, when the company self-reported the violations to the commission. (See FERC Investigation Shows PSEG Violated PJM Bidding Rules.)

PSEG agreed to a civil penalty of $8 million and to pay PJM disgorgement of $26.9 million and $4.5 million interest. It also will submit annual reports to ensure future compliance. The company did not admit any wrongdoing.

In April 2014, PSEG told FERC of inaccuracies in the cost-based offers for some of its fossil units due to the inclusion of incorrect environmental adders for the prior two years. The company later provided the commission self-reports that identified incorrect cost-based offers dating to 2005.

public service enterprise group ferc pjm energy trading — Map showing location of PSEG’s fossil fuel generators | *PSEG*

Among PSEG’s “errors,” as FERC described them in its order approving the consent agreement, were: including CO₂ adders in its cost-based offers after New Jersey withdrew from the Regional Greenhouse Gas Initiative; including seasonal NOx adders in offers outside the NOx compliance season; incorrectly stating the amounts of fuel required for minimum operations at Unit 2 of its 1229-MW natural gas and kerosene Bergen Generating Station; and providing inaccurate heat rate data for some units.

The commission said it decided on the $8 million penalty considering “that PSEG self-reported the violations, cooperated fully and comprehensively throughout the investigation and has no prior history of violations. The remedy also reflects that although PSEG had a compliance program in place, it was not sufficiently robust to detect or prevent the violations.”

“In addition to responding to Enforcement’s data requests, PSEG provided extensive data, conducted extensive data analyses regarding the cost-based offers and demonstrated exemplary cooperation during the investigation,” the commission added.

But the order also noted, “PSEG’s compliance program and existing compliance procedures did not detect the errors in the cost-based components of the offers, in some cases, for multiple years.”

After the self-report, FERC said PSEG adopted new procedures requiring that daily offers be double-checked for accuracy and revised its fuel policy “to more clearly articulate the calculation of cost-based offers in accordance with PJM’s rules.”

The company also added staff to its internal audit department and hired an independent audit company to help develop additional compliance procedures.

It also made unspecified personnel changes in the trading and asset optimization groups “to impose additional accountability and focus attention on compliance issues,” FERC said.

FERC directed PJM to disburse the disgorgement and interest pro rata to affected market participants.

April 26, 2018

Eckelberger, Skilton Step Down from SPP Board

By Tom Kleckner

KANSAS CITY, Mo. — For 18 years, Jim Eckelberger and Harry Skilton have been a steady presence on SPP’s Board of Directors, providing strategic direction and financial guidance.

The men joined the board in 2000 as two of its first seven independent members, helping to oversee SPP’s classification as an RTO in 2004. Until Tuesday, they were the only two original directors still active on the board.

SPP Board — CEO Nick Brown (left) and SPP members listen to Jim Eckelberger’s final comments as board chair.| © *RTO Insider*

No more. SPP CEO Nick Brown began the board’s April 24 meeting by telling the Members Committee that Eckelberger and Skilton would be moving to emeritus status, although they will continue to remain under contract with the board.

“They will continue to bring the tremendous amount of experience and institutional knowledge they’ve gained over 18 years of service to this organization,” Brown said.

Vice Chair Larry Altenbaumer replaces Eckelberger as chair, while Graham Edwards takes over as vice chair. The moves became effective following the board meeting’s conclusion.

Eckelberger, who was first elected board chair in 2004, took his final moments in the role to reflect on his time with SPP and to thank everyone around him. He said he was only following the Jesuit philosophy of serving others.

“Instead of being in a leadership role, I will be in a resource role. I love that,” Eckelberger told the board and members. “I think that’s a wonderful opportunity for me to be a benefit to others. Thank you for allowing me to go beyond age 80 into this resource position.

“Bottom line, if you look at the last few months, October onward, the [prices] in our footprint have been phenomenal, lower than they’ve ever been,” he said. Referring to his audience, Eckelberger said, “We’ve done a wonderful job for the organization’s members and the consumers in the footprint. It’s been a win-win situation all around.”

Eckelberger heaped praise on staff, his fellow board members, and the Regional State Committee and Markets and Operations Policy Committee. “The success is all about you,” he said.

“I’ve watched over the years as people with very disparate ideas have found a way, without going to Washington, to make progress we can all agree to. Everyone has to represent their organization, but it’s been a phenomenal ability of everyone to bring about evolutionary change and a relationship-driven and member-driven organization. I appreciate the Members Committee for finding a way to do that.

“To SPP, you said you’ve wanted an independent board. I can say I’ve pissed off every member of the staff in one way or another,” Eckelberger said, drawing a laugh.

“Then I look at the board and the Members Committee. I’m surrounded by peers for whom I have great respect,” he said, as his eyes filled with tears. “I want to say to you, the members who have made all this possible … Thank you, thank you, thank you.”

SPP’s directors, members and staff rewarded Eckelberger with a standing ovation.

Now composed, he turned to Altenbaumer, shook his hand and said, “And to my successor, whom I have great respect for … Good luck!”

With that, Eckelberger’s tenure as board chair was over.

Brown said Eckelberger and Skilton will be honored with “much more fanfare” during SPP’s Annual Meeting of Members in October.

A 30-year veteran of the U.S. Navy, Eckelberger rose to the rank of rear admiral before entering the corporate world and joining SPP. He served in the first Gulf War during his last year of active duty.

Skilton spent 25 years in senior executive and general management positions, including CEO of American Meter Company and treasurer for Celanese Corporation.

Altenbaumer was elected to the SPP board in 2005 and recently succeeded Skilton as chair of the Finance Committee. He served as president of Illinois Power, a regulated electric and natural gas delivery company, and was executive vice president of regulated energy delivery for Dynegy.

SPP hopes to select replacements for Eckelberger and Skilton before the annual members meeting in October.

April 26, 2018

MISO Ops Easily Handle Quiet March

By Amanda Durish Cook

CARMEL, Ind. — MISO easily managed what turned out to be a “near-normal” March, the RTO said Tuesday.

The RTO’s load averaged 71.1 GW for the month, in line with the 70.8 GW average a year earlier. But the 85.3 GW monthly peak set on March 14 came up 2.5 GW short of last March’s peak.

During an April 24 Informational Forum, MISO reported relatively mild weather in most of the footprint during March, although cold conditions persisted in parts of MISO Midwest.

MISO Queue Cycles — Benbow | © *RTO Insider*

“I would say winter just won’t go away this year,” observed MISO Senior Director of Systemwide Operations Rob Benbow, who added that lower temperatures kept demand relatively low during the month.

“We did see a lot of diversity in our weather footprint,” Benbow said, noting that one day in March saw snowstorms up north while parts of MISO South were under tornado warnings.

“When you span that far across the United States, you expect that,” he added.

Real-time prices in March were about 14% lower than they were last year, averaging $25.40/MWh, while day-ahead averaged $25.55/MWh.

Benbow said the price drop was due to lower congestion and natural gas prices compared with last year. Gas prices in March averaged $2.48/MMBtu at Chicago Citygate and $2.66/MMBtu at Henry Hub, down from $2.84/MMBtu and $2.83/MMBtu, respectively.

Benbow said the month brought the usual onset of generation maintenance outages, with planned outages doubling to about 25 GW as February transitioned into March.

MISO also set a new, 15.6-GW record peak for wind generation on March 31, toppling its previous 15-GW wind record set in January.

Queue Progress

MISO also provided an update on its interconnection queue, with Benbow saying completion of affected systems studies continue to slow queue progress, a topic debated in early April at a FERC technical conference. (See Rene w able Gens Face Off with RTOs at Seams Tech Conference.)

MISO Queue Cycles Natural Gas — MISO Informational Forum on April 24 | © *RTO Insider*

MISO’s generator interconnection queue currently includes 561 projects, totaling 93.1 GW, and the April 2018 definitive planning phase queue cycle added 244 projects, representing 41.2 GW.

MISO said it is managing 14 ongoing queue cycles with five more queue cycles set to begin in the coming months. The lion’s share of the queue is renewable generation, with 42.7 GW of wind, 37.4 GW of solar and 12.3 GW of natural gas generation.

April 26, 2018

Avangrid Posts Steady Q1 Income, Highlights Renewables

By Michael Kuser

Avangrid on Monday said its first quarter earnings rose slightly on new rate plans and increasing output from its wind fleet, and the company highlighted its growing opportunities in renewable energy — particularly offshore wind.

The company posted net income of $244 million for the quarter ($0.79/share), up 2% from the same period a year ago.

CEO James P. Torgerson said in an analyst ca l l that “earnings improved primarily due to the implementation of our multiyear rate plans [and] increased wind production, mainly from the 534 MW of capacity that came on line in 2017.”

offshore wind avangrid earnings q1 2018 — | *Vinyard Wind*

Torgerson noted Avangrid subsidiary Central Maine Power (CMP) is set to sign a contract with Massachusetts by the end of this month for the state’s 9.45-TWh clean energy solicitation, which was awarded to CMP’s New England Clean Energy Connect (NECEC) transmission project after the original winner was rejected by siting officials in New Hampshire. (See Mass. P i cks Avangrid Project as Northern Pass Backup.)

CMP partnered on the project with Hydro-Québec, which will deliver up to 1,200 MW of Canadian hydropower to the New England grid via a 145-mile transmission line. The partners estimate the project will cost $950 million and will soon file with the Massachusetts Department of Public Utilities, said Torgerson.

Avangrid also completed the sale of its gas trading business last quarter and expects to sell off its gas storage business in May.

The company said it has 497 MW of onshore wind and solar under construction, to be operational by the end of 2019. Avangrid’s Vineyard Wind partnership with Copenhagen Infrastructure Partners bid 400-MW and 800-MW projects into Massachusetts’ offshore wind solicitation, the winners of which will be announced in May. (See Mass. Receive s Three OSW Proposals, Including Storage, Tx.)

Vineyard Wind in the first quarter also submitted a bid for 190 MW of offshore wind in Connecticut, with selection scheduled for June.

Regulatory Update

Torgerson expressed muted optimism about a FER C administrative law judge’s March ruling that municipal utilities and commission staff failed to prove the New England Transmission Owners’ base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable, rebuffing requests to reduce it. (See ALJ Rules New England Tx Owner s ’ ROEs not Unjust.)

“We feel that’s positive, but the commission will still ultimately need to decide, and there’s really no time frame at this point to make that decision,” said Torgerson.

The corporate tax cuts passed by the Trump administration in December created benefits for the company, and Avangrid is working with state regulators in New York and New England to offset major storm recovery and advanced metering infrastructure (AMI) costs through the windfall before passing benefits to customers.

The AMI discussions are ongoing in New York and the company anticipates approval later in 2018. “The earnings adjustment mechanism discussions have been impacted by the ongoing storm activity and the AMI discussions and other things, so that’s been delayed somewhat,” said Torgerson.

Offshore Potential

After establishing its offshore wind business last year, Avangrid quickly won a Bureau of Ocean Energy Management (BOEM) lease auction off Kitty Hawk, N.C., an area that could produce up to 2.5 GW of energy. The company also last year acquired its 50% partnership in Vineyard Wind.

Torgerson also highlighted upcoming opportunities in offshore wind.

“In New York, they are looking for 800 MW in the fall and 2,400 MW by 2030,” he said. “Rhode Island is evaluating or looking to evaluate the implications from the Massachusetts RFP and want information on that, how it could impact Rhode Island. So, there is an expectation that Rhode Island may be looking for some offshore wind as well.”

Offshore wind got a boost on two fronts earlier this month when U.S. Interior Secretary Ryan Zinke announced two new proposed offshore wind leases for Massachusetts, while the Interior Department’s BOEM issued a call for commercial interest in four wind energy areas in the New York Bight. (See Interior Plans Would Boost Mass., N Y Offshore Wind.)

“We will be looking at those very closely,” said Torgerson. “And Governor Phil Murphy in New Jersey is said to be looking for about 3,500 MW offshore of New Jersey.”

Quotes courtesy of Seeking A lpha