Page 1126 – RTO Insider

July 24, 2018October 31, 2023

Massachusetts Seeks Input on Energy Plans

By Michael Kuser

WESTFIELD, Mass. — Massachusetts officials last week held three hearings across the state to get public input ahead of a September release of the statutorily mandated Comprehensive Energy Plan (CEP).

The state’s Department of Energy Resources is preparing the plan to project the state’s 2030 energy demands for electricity, transportation and thermal conditioning and help it meet its greenhouse gas emissions targets. The state’s Global Warming Solutions Act (GWSA) requires a 25% reduction in emissions by 2020 from the 1990 baseline and an 80% reduction by 2050.

The state accounts for 45% of electricity demand in New England.

Morin | © RTO Insider

“This report is really looking at supply and demand of energy going forward,” DOER Deputy Commissioner Joanne Morin said on July 19. “The CEP is going to demonstrate the modeling, the impact and required balance in pursuing these goals simultaneously, and looking at different pathways that we could take with our energy future.”

State lawmakers are now considering legislation to increase the state’s renewable energy and reduce high-cost peak demand. Earlier this year, two senators touted a goal to achieve 100% renewable electricity by 2035 and to make the heating and transportation sectors 100% powered by renewables by 2050.

Hopkins | © RTO Insider

Asa Hopkins of Synapse Energy Economics, the DOER’s consultant on the energy plan, sought feedback on its assumptions and analysis of 2030 scenarios.

“Have we got it right or have we got it wrong? Should we be designing these policy features in some different way?” Hopkins asked.

The public has until July 31 to submit comments at the CEP website.

“That’s not much time for public comment,” said Rosemary Wessel, director of “No Fracked Gas in Mass,” a program of the Berkshire Environmental Action Team.

Wessel also complained about what she called a lack of transparency in clean energy data, saying the DOER shows state emissions data only up to 2014. She also said the DOER website “has become much harder to use.”

Several audience members murmured their agreement to the website assessment, and Morin said, “I’ll have to follow up on that.”

Soft or Hard Push?

Hopkins’ study included a status quo scenario and also analyzed the impact of adjusting “key levers,” including efficiency, renewables and electrification via electric vehicles and heat pumps.

Under the status quo or “sustained policies” scenario, renewables would supply 45.5 TWh in 2030, or about 35% of electricity in the region, with Massachusetts hitting its 25% renewable portfolio standard target. Under a “high renewables” scenario, the amount increases to 38% (49 TWh), with all of the increment serving Massachusetts, which would get about half its electricity from Class I renewables in 2030, Hopkins said.

Massachusetts CEP Comprehensive Energy Plan Electrification

2030 electric consumption is projected at 11% above 2018 under aggressive policies leading to high electrification in New England. | Synapse

“We’re looking at electrification, which in the case of electric vehicles, is associated with a substantial increase in efficiency, as it is with heat pumps, so there’s a common thread there,” Hopkins said. “There are distinctly more heat pumps in Massachusetts than there are EVs, but more people consciously see EVs than see heat pumps.”

Because they’re moving heat rather than generating it, heat pumps have efficiencies well over 100%.

“A typical seasonal average in Massachusetts would probably be well over 200%, and for a heat pump water heater it will go up well over 300%,” Hopkins said. A 300% efficient heat pump produces three units of heat for every unit of energy, Hopkins explained.

The “high electrification and high renewables” scenario includes a “clean peak” idea to incentivize generation or energy dispatch to be available to meet winter and summer peaks without emissions.

The scenario for increased efficiency, electrification and renewables would reduce the average commercial building’s heat energy by 25% or more with the state getting 50% of its electricity from renewables, Hopkins said.

Enhancing both electrification and renewables would push wind and solar growth to 33.7 TWh in 2030, while natural gas use would be 29% lower than today.

System demand graph shows results under aggressive policies leading to high electrification in New England. Regional demand increases 13% by 2030 but most of the increase is powered by renewables (+165%). Gas generation drops (-25%). | Synapse

“Once those clean peak resources are there, it’s not like they’re only there on the peak day; they also run all the rest of the time around the year and are impacting what’s going on with dispatch of different resources,” Hopkins said.

Massachusetts has a goal of 300,000 EVs on the road by 2025 and 1.7 million in 2030. Hopkins said the state can probably only reach 160,000 EVs by 2025 under current policies but could exceed its EV goals by enhancing all policy levers.

Several people asked about energy storage and whether EVs can act as batteries for the grid.

“The place where storage makes a difference is on an hourly basis,” Hopkins said. “One learning from this is that what you assume about the load shape of when all those 1.2 million or 1.7 million EVs are charging, it really matters a lot. And what you assume then about when those batteries will charge and discharge really matters a lot.”

If peaks are in the afternoon and you have everyone charge their cars overnight, “you create a giant super-peak at 3 in the morning,” Hopkins said. “That’s probably not the actual path forward, but things we learn there can flow into policy development.”

Solar Woes

Robert Camus, a Granby selectman and member of the town’s energy committee, said that if the state wants to increase solar energy by 50% by 2030, it should change policies to promote local ownership of solar farms.

“The SMART [Solar Massachusetts Renewable Target] program awards Eversource [Energy] and National Grid so much each year, but there’s no differentiating between a private landowner and a municipality,” Camus said. “If the municipality was to have the solar field, versus a private landowner, you’d have a lot more advantages.”

Attendees of one of three public hearings last week on Massachusett’s Comprehensive Energy Plan. | © RTO Insider

If a private landowner makes a deal with a solar developer, the money goes to one individual, he said.

“If you go to the municipality, every taxpayer in that town gets a share of the money, which would decrease the demand of the municipalities on the administration every year for money for schools, infrastructure and everything else,” Camus said. “If the money goes to the taxpayer[s] of Massachusetts rather than to out-of-state developers, we can more enhance our own economic growth, because the money stays.”

He suggested that the SMART program devote 75% of its money to municipalities, leaving 25% for individual landowners.

Morin directed Camus to contact Michael Judge, director of DOER’s renewable energy division. The CEP is intended to complement another effort, the Clean Energy and Climate Plan (CECP), which talks about emissions targets and how the state is going to meet them, Morin said.

July 24, 2018November 13, 2023

SPP Markets and Operations Policy Committee: July 17-18, 2018

OMAHA, Neb. — Given a proverbial second bite of the apple, SPP stakeholders easily approved a revision request that requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.

The Markets and Operations Policy Committee rejected the measure (RR272) during its April meeting. The Board of Directors/Members Committee tabled the request but asked for a review of RR272’s economic impact and that the Market Working Group build greater consensus among the membership. (See “Board Forced to Table NDVER Conversion Change,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

MWG Chair Richard Ross, of American Electric Power, began discussion of the change by noting he was one of the few people in the meeting room wearing a tie.

“I’m not trying to make anyone nervous,” he quipped. “But if you get unruly, I’ll take the tie off.”

There was no need. The measure passed with more than 81% approval, almost 20 points better than it fared in April. It was opposed by only two transmission owners (Empire District Electric and Omaha Public Power District) and eight transmission customers with various ties to renewable energy. Seven transmission customers abstained.

“We wanted to see this happen, sooner than now,” said Southwestern Public Service’s Bill Grant. “This is a compromise we can live with. It took a lot of work to get to this point, but we’ve moved to a point where most people are happy.”

Staff shared its analysis of RR272’s economic effects, which compared the conversion of NDVERs to DVERs against a base case using real-time security-constrained economic dispatch data. They found the conversion resulted in improved congestion management and, with it, better convergence of real-time and day-ahead prices. That resulted in about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.

The data also indicated a significant reduction in the number of operating hours with negative pricing.

The MWG revised the proposal to exempt run-of-river hydro not capable of following dispatch instructions and to provide additional time for certain NDVERS to convert. They now face a deadline of either Jan. 1, 2021, or the 10-year anniversary of a resource’s original commercial operation date.

Market Monitoring Unit Executive Director Keith Collins said he supports the proposal, saying the benefits come from “an increase in prices at locations that are primarily non-dispatchable.”

“We’re investing upgrades for controls we don’t own, which increases the [power purchase agreements] for our customers. That’s not something we’re keen on,” said Empire’s Aaron Doll. “Our specific limitation is contractual language that limits curtailments to a certain amount in a 24-hour period. The dispatch signal puts us in bad spot pretty quickly. Anything short of providing an exemption for entities with contract language that precludes curtailment is not something we can support.”

The MOPC also approved RR266, which would model a joint-owned unit (JOU) as a single resource in market-clearing decisions, while performing an after-the-fact allocation of revenues based on ownership shares. Other JOU shares would be used for settlement purposes, and each share would exist only in the context of settlements where final clearing results are split based on the submitted ownership share percentages.

The change is contingent upon final approval by the Regional Tariff and Operating Reliably working groups. Nebraska Public Power District and Oklahoma Gas & Electric’s Transmission and Electric Services divisions opposed the measure, citing problems with the language.

“We have a couple of JOU situations we manage fine ourselves,” said OG&E-Transmission’s Greg McAuley. “We’ll continue to pound the table as it relates to some of these administrative costs.”

Stakeholders approved against minimal opposition three other revision requests brought forward by the MWG:

- RR306, which would minimize potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
- RR304, which streamlines the process by which frequently constrained areas are re-evaluated, in order to make adjustments in a timely manner.
- RR312, which would calculate the FERC Schedule 12 rate based on current data. The change aligns the collections of revenue against the customers’ megawatt-hours being assessed.

SPP Prepared for January’s ‘Big Chill’

Staff’s update on what they call “The Big Chill,” the abnormally frigid temperatures Jan. 17-18 that led to heavy north-south transfers of MISO flow across SPP’s system and a maximum generation alert in MISO South, caused one member to recall his scouting days.

“I wouldn’t call this an emergency event,” said MOPC Chair Paul Malone, of NPPD. “It was pretty well known we would have severe weather over a wide area. That begs for proper planning. As the Boy Scout motto says, ‘Be prepared!’”

“Let’s just say, some people are surprised every day by what happens,” said SPP COO Carl Monroe, “and some people were surprised that day.”

MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP system during the event and was forced to make emergency purchases from Southern Co.

SPP Vice President of Operations Bruce Rew said the RTO never had to issue an emergency alert, as it was never short of generation. “It was uncomfortable for us,” he said. “We have to make sure it doesn’t happen again.”

David Kelley, SPP’s director of seams and market design, credited SPP’s and MISO’s neighboring reliability coordinators with helping to prevent load shed and keeping the lights on during the event. He said recent discussions among the Regional Transfers Operating Committee (RTOC), a six-person group comprising two representatives each from SPP, MISO and joint parties to a 2016 settlement agreement, centered on better understanding the non-firm, available nature of MISO’s north-south flows and their effects on neighboring entities. (See SPP, MISO Reach Deal to End Transmission Dispute.)

“Anything over 1,000 GW is on a non-firm, as-available basis. To us, that means SPP’s service should not be in jeopardy of load shed,” Kelley said. “When this event happens again, and will happen again, we’ll be prepared.”

Kelley said staff has also met with FERC staff to “ensure FERC had a clear understanding of what happened that day,” given “very inaccurate statements that found their way into the media.” (See SPP Seeks FERC Meet in MISO Tx Dispute.)

Kelley also briefed the MOPC on a proposed interregional project with Missouri-based Associated Electric Cooperative Inc., a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.

The project’s regional cost allocation was rejected by FERC last year. (SPP would be responsible for 89% of the $13.75 million in engineering and construction costs). SPP staff have since developed data that indicate the project would yield the region $17 million in load ratio share benefits by eliminating the need for upgrades at City Utilities of Springfield’s John Twitty Energy Center and also reduce day-ahead market uplift costs.

“We feel like we’re in much better shape,” said Kelley, who met with FERC staff on July 12. “They look forward to seeing our next filing.”

Kelley said that filing should be made in late July or early August.

Stakeholders Endorse $47.4 Million in Near-term Tx Work

The MOPC endorsed the Transmission Working Group’s recommendation to approve the Integrated Transmission Planning process’s 2018 near-term assessment portfolio, a package of 13 transmission projects with an estimated cost of $47.4 million

However, when taking into account four withdrawn projects from previous assessments that cost a total of $53 million, the portfolio has a net cost of -$5.6 million.

Several of the Kansas and Missouri projects are being driven by the retirement of about 1.9 GW of 50- to 60-year-old generation later this year and in early 2019.

The projects will solve 101 reliability needs. They include a new 345-kV, 50-MVAR reactor at City Utilities’ Brookline substation, a project originally identified as an interregional project with AECI.

OG&E’s Travis Hyde, who chairs the TWG, noted SPP approved nearly $8 billion in construction between 2006 and 2014. With the strategic shift to maintaining “an economical, optimized transmission system,” he said, the RTO has since approved just more than $1 billion in base plan funded investment.

Staff developed a summary presentation of the assessment using a story map tool.

Stakeholders also endorsed NorthWestern Energy’s sponsored upgrade of less than 4 miles of new 115-kV line in Aberdeen, S.D., and a working group recommendation to approve the 2019 ITP’s needs sensitivity scope addressing study results affected by Lubbock Power & Light’s potential exit from the system.

RC Efforts in West Absorb MWTG Integration

Monroe told members that the integration of the Mountain West Transmission Group has been “subsumed” in the debate out West over who will provide reliability coordinator (RC) services — a debate that involves SPP.

The RTO said in June that it plans to offer RC services in the Western Interconnection, matching an earlier announcement by CAISO. Not coincidentally, Peak Reliability said last week it will wind down its RC role by the end of 2019. (See related story, Peak Reliability to Wind Down Operations.)

SPP’s Carl Monroe (c), NPPD’s Paul Malone, NE Texas Electric Co-op’s Jason Atwood, GDS Associates’ Jack Madden anchor the MOPC’s head table. | © RTO Insider

“There’s still interest in [joining SPP],” Monroe said. “The importance of making sure RC is provided, and in an efficient and reliable way, has subsumed their work right now.”

SPP’s efforts to integrate Mountain West were dealt a blow in April when Xcel Energy announced it was withdrawing from the Rocky Mountains group and its efforts to join the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Monroe said there have been no changes to the Mountain West’s initial proposal to join SPP, adding he hopes to be able to provide “what kind of a footprint we would have with RC services” by Sept 1.

“As we work through the process, our intent is to meet the goals of what we normally do through contract service, which is providing benefits back to the members themselves,” he said.

MRO’s Patrick Welcomes New Entities

Midwest Reliability Organization CEO Sara Patrick introduced herself to SPP members, many of whom were among the 100 registered entities that joined the organization after the SPP Regional Entity’s recent dissolution. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)

Patrick said all compliance monitoring and enforcement program (CMEP) data was successfully transferred from the SPP RE to MRO on July 3, and that all entities in its expanded footprint are now using MRO’s webCDMS portal.

Patrick gave credit to the SPP RE’s staff in a “well-coordinated” transition and data transfer. The $1.5 million in transition costs will be recovered by transferring assessments from the SPP RE to MRO, she said.

The MRO’s board of directors last month approved a $4.3 million increase, reflecting the expanded footprint. Patrick said the budget will result in $4.8 million in savings, when compared to the combined MRO and SPP RE budgets.

The board also agreed to add four new directors next year, including two regional directors from the SPP RE’s footprint.

MOPC Sends Two Initiatives Back

The MOPC declined to take action on a pair of work efforts, asking that both be returned to the stakeholder process for further clarification.

Following an update on SPP’s prioritization process for revision requests and project proposals, stakeholders debated potential improvements to the process before the committee’s leadership said it would return to the next meeting in October with ideas on how to proceed.

Stakeholders complained about a lack of transparency, the amount of information they had to deal with and not knowing where decision-making authority lies. Staff said it stopped the quarterly meetings because of a lack of feedback.

Several members familiar with ERCOT’s stakeholder process suggested the Texas grid operator’s Protocol Revisions Subcommittee (PRS) as a good model to follow. Tenaska’s John Varnell, who once chaired the PRS, said if members listened in on the group’s meetings, “You will see how we can do better at this process.”

“That’s one thing that ERCOT does quite well,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on ERCOT’s MOPC equivalent, the Technical Advisory Committee.

“[The PRS] does a really good job of ensuring financial stability or accountability. [Members] debate [revision requests] quite substantially before they ever enter in the queue for approval at the TAC. Many of us want this to be like what we have at ERCOT. It puts more decision-making in the hands of the stakeholders, rather than SPP.”

Grant, who headed the task force that developed the prioritization process, called for more stakeholder involvement in the process. He reminded the committee that the task force hasn’t been disbanded.

“If we’re going to spend the time and effort to improve the process, we need better participation and more dedication to the issue,” he said. “It doesn’t matter what we set up if the stakeholders aren’t going to participate in the process.”

The MOPC also sent back a Credit Practices Working Group (CPWG) revision request, saying it needed more information and noting the Finance Committee had tabled the request. The CPWG reports to the committee.

The CPWG’s RR311 would change the way reference prices are used to estimate the settlement exposure of transmission congestion rights (TCRs). The group’s analysis of a two-year period indicated its proposed methodology would have reduced collateralization in the TCR market by $124 million to $327 million, and more than doubled under-collateralization from $17 million to $39 million.

Staff recommended tabling the change, saying it needed more analysis in light of a market participant’s recent default in PJM’s financial transmission rights market. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)

“It sounds like the hesitancy to move forward is lack of understanding of what’s happening in the PJM situation,” said Kansas City Power & Light’s Denise Buffington.

Given that the CPWG has yet to gain approval from the Finance Committee and the Regional Tariff Working Group, stakeholders agreed to send CPWG RR311 back to the working group so that it can be properly shepherded through the stakeholder process.

Members Endorse RRs, Process Language Change

Members endorsed language changes to improve efficiency of the revision request process by reducing the time it takes to gain approval for a change and removing duplicate references that cause unnecessary changes.

The proposal (RR291) would allow a revision with approved “normal status” to progress through the stakeholder process while its primary working group waits on the impact analysis. It would also revise language to reference the applicable documents as SPP revision request documents and remove their multiple references.

The MOPC’s consent agenda, which passed unanimously, included nine revision requests and a new baseline cost estimate for SPS’ 115-kV loop rebuild in West Texas. The project’s original cost of $28.4 million was reduced almost 23% to $21.9 million.

- BPWG RR307: Clarifies that partial service may be offered to short-term transmission service requests when the full amount requested cannot be granted.
- CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
- MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governance, to eliminate confusion over whether entities are performing obligations for market or NERC standard reasons. Also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
- MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
- MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; circumstances if violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
- ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
- RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
- RTWG RR315: Removes references to the SPP RE in the governing documents.
- RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.

— Tom Kleckner

July 24, 2018

Little Work Needed to Comply with Order 845, MISO Says

By Amanda Durish Cook

CARMEL, Ind. — MISO staff say the RTO is mostly up to speed with a recent FERC order aimed at increasing the transparency of the generator interconnection processes — but they continue to tackle issues related an overbooked queue.

Compliance with Order 845 largely involves inserting FERC-directed language and existing Business Practices Manual text into the Tariff, MISO said last week.

MISO FERC Order 835 interconnection — Supino | © *RTO Insider*

“Most of the compliance directives we already comply with in some shape or form,” counsel Chris Supino told stakeholders at a July 17 Interconnection Process Task Force meeting. He said MISO is “early” in its compliance plan and plans to share draft Tariff language in September.

“Most of these are fairly administrative; some we’ll have some more discussion around,” Supino said.

FERC issued the order in April, setting out 10 new rules intended to increase the transparency and timeliness of RTO generator interconnection processes. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.) MISO in mid-May joined an ISO/RTO Council request to extend the original Aug. 7 filing deadline, which FERC pushed out to Nov. 5.

Supino said most of MISO’s remaining work will focus on a new requirement to post quarterly summary statistics on its queue, including the number of withdrawn projects, completed projects and delayed projects; the proportion of studies completed by Tariff deadlines; and average study completion time.

MISO is now also obligated to file informational reports for four consecutive quarters if it misses deadlines on 25% or more queue studies during two consecutive quarters. The reports must explain reasons for the delays, steps taken to minimize them and the total number of employee and consultant hours spent on studies during the quarter.

Supino told stakeholders:

MISO generally complies with a directive to list specific study processes and assumptions because it already posts study models for review on its nonpublic Open Access Same-Time Information System. It will examine how the directive interacts with its existing nondisclosure agreements and whether it should issue more NDAs in order to share the models with a broader group.
The RTO will revise its generator interconnection agreement to give customers the option to build interconnection facilities and standalone network upgrades regardless of whether a transmission owner can meet a customer’s proposed in-service dates. It will also likely leverage its existing alternative dispute resolution language used for settlements to apply to members’ queue disputes.
MISO’s net zero interconnection option should cover a directive to allow customers to utilize or transfer surplus interconnection service at existing generating facilities. Net zero permits customers to transfer existing interconnection rights to a new generator at the existing point of interconnection, provided the total interconnection does not exceed the original service limit granted in the interconnection queue.
MISO will revise procedures to allow interconnection customers to request service lower than their generating facility capacity.
The Tariff will be updated to include a definition of permissible technological advancements to generators that it can accommodate without a change being considered a material change, something FERC has left up to the RTOs. Instead of listing every permutation of acceptable changes, MISO will instead develop a standard to study changes.

Further GIP Alterations

Meanwhile, MISO is once again tinkering with its proposal to make generation owners more accountable for site control earlier in the interconnection queue.

MISO is now proposing to require that interconnection customers have 90% site control at the time of application based on a per acre format, with 50 acres/MW for wind generation, 5 acres/MW for solar, 1 acre/MW for battery storage and a flat 50 acres for conventional generation. All generation types must provide a detailed site map showing turbine layout. All generators would be required to demonstrate 100% site control by the second decision point of the queue.

Apex Clean Energy’s Swaraj Jammalamadaka asked whether it is fair to require generation developers to hold that amount of land especially if MISO’s queue studies become delayed.

“It’s not a bad thing to have site control, but is this reasonable?” he asked.

WEC Energy Group’s Chris Plante also questioned whether the flat 50-acre requirement for conventional units was a reasonable standard. Neil Shah, MISO manager of resource interconnection, said the requirement was based on SPP standards, but staff are open to stakeholder suggestions.

MISO last month softened its original stance that developers should provide evidence of 100% site control before their projects can enter the queue and unveiled a plan to increase the deposit due upon entry from the current $100,000 to anywhere between $500,000 and $2 million in cash, depending on project size. (See “MISO Softens Site Control Requirements in Queue Streamline,” MISO Planning Advisory Committee Briefs: June 13, 2018.) Now, the cash deposit option will only apply to projects that demonstrate regulatory restrictions to procuring site control.

MISO also still plans to remove its dynamic stability, short-circuit and affected-system analyses from the first phase of the definitive planning phase. Staff said the revisions are needed because the overbooked queue currently contains almost 93 GW of prospective generation.

“It’s in a glut, or it’s clogged, and everyone, MISO included, needs to do something,” Shah said.

Revised Milestones

MISO also plans to revise the queue’s existing milestone payment and refund structure to include a percentage of upgrades identified in affected-system studies and introduce more monetary risk for customers who keep unprepared projects in the queue.

The RTO plans to keep its current format of a $4,000/MW initial payment upon entering the DPP with two subsequent milestone payments based on a percentage of upgrade costs. However, MISO now proposes to introduce upgrade costs found in affected-system studies that occur during the phase two system impact study. The third milestone payment will now consist of 10% of necessary network upgrades and another 10% of costs associated with needed upgrades uncovered in the affected-system study. The two combined percentages are a departure from MISO’s existing third milestone payment of a flat 20% of network upgrades.

Multiple stakeholders said MISO’s proposal will make milestone payments more burdensome and riskier to stakeholders by adding the affected studies element.

Jammalamadaka pointed out that MISO cannot control the outcome of affected system studies, which to date have shown inconsistent findings.

“That more money should be a percentage of something that’s predictable,” Jammalamadaka said.

Milestone refunds will also be slightly altered under the plan. MISO will offer to refund 50% (instead of the current 100% ) of the second and third milestone payments if a project opts to withdraw at the corresponding decision points. Projects that do not elect to withdraw at a decision point risk losing their entire milestone payment even if they fail to complete a GIA.

Shah said none of the refund changes will affect the penalty-free withdrawal options that MISO built into its queue overhaul last year. Penalty-free withdrawals are allowed in MISO if network upgrade costs increase too dramatically from one phase to another in the DPP.

“We want to make sure the new rules accomplish the goal of moving projects and incentivize the not-ready projects to get out as early as possible and potentially not even enter the queue,” Shah said. “We want ready projects to progress through the process. We want non-ready projects to drop out as soon as possible. This is our intent with this proposal, and we want to process the queue as quickly as possible.”

“We’re not changing too many things here,” said MISO Resource Utilization Director Vikram Godbole. “If you’re not willing to put money up for your project, maybe you don’t belong in the [definitive planning phase], I’m sorry to say. We’re designing a process for real and ready projects.” Godbole added it would be impossible to eradicate all speculative projects from the queue.

Shah said MISO hopes to file the new queue milestone details by the latter half of September.

Some stakeholders indicated that they might contest the filing with FERC.

MISO’s Patrick Brown reminded stakeholders that the RTO will collect two more rounds of feedback on the proposal, including a discussion before the Planning Advisory Committee.

“This is not set in stone. This is wet cement here. I think it’s a little premature to talk about contesting the filing,” he said.

Brown pointed out that MISO estimates it currently has a 20% completion rate of prospective projects that enter the queue. He said MISO is trying to “thin the herd to the most viable projects” and said he hopes the RTO can achieve a 50% completion rate of queue entrants in the future.

July 24, 2018

FERC Grants KCP&L Greater Missouri’s Dividends Petition

By Tom Kleckner

FERC last week found that KCP&L Greater Missouri Operations’ proposed payment of dividends complies with the Federal Power Act (EL18-146).

The commission found that Greater Missouri had clearly identified the source of its proposed dividends and that “nothing in the record indicates that the dividends will be excessive.” FERC found that the dividends would be “generally consistent with the amount and timing of the dividends” the utility has traditionally paid to its parent Great Plains Energy.

ferc kcpl federal power act — KCP&L’s Slate Creek Wind Project | *KCP&L*

The commission said that, “consistent with prior precedent,” the issuance of dividends would not harm GPE. It conditioned its approval on the utility’s compliance with its capitalization and credit rating commitments.

Greater Missouri filed the petition in May, saying it had deferred income tax assets and liabilities related to its regulated operations and significant deferred income tax assets for net operating losses (NOLs) generated prior to it’s acquisition by GPE in 2008. The utility said last year’s Tax Cuts and Jobs Act required it to revalue all of its deferred tax assets and liabilities in December based on the lower 21% corporate tax rate, and to revise its assumptions regarding the use of certain tax credits and NOLs.

The utility recognized a $111.6 million one-time, non-cash charge to income tax expense, approximately 1.6 times its average net income from 2014 through 2016 ($71.4 million). The charge caused Greater Missouri to have an accumulated deficit in its retained earnings account, which, according to FPA Section 305a, restricted the utility’s ability to pay dividends to GPE.

Section 305a forbids any public utility’s officer or director to receive “for his own benefit” any security issued or to share in any of the proceeds from any funds properly included in the capital account. The commission said a key concern was “corporate officials raiding corporate coffers for their personal financial benefit.”

FERC used a three-factor analysis to determine whether the proposed dividends payment violated the FPA. The commission considered whether: (1) the utility clearly identified the dividends’ sources; (2) the dividends would be excessive; and (3) the proposed dividends would have an adverse effect on the value of shareholders’ interests.

GPE recently acquired Kansas-based Westar Energy. (See Westar-Great Plains Merger Wins Final Approval.)

July 24, 2018

MISO Files Revised Upgrade Funding Provisions

By Amanda Durish Cook

CARMEL, Ind. — MISO has submitted a pre-emptive Section 205 filing to retain the option to allow new generators to self-fund interconnection transmission upgrades after the D.C. Circuit Court of Appeals vacated related FERC orders from 2015, stakeholders learned last week.

MISO facility construction transmission upgrades — Blackwell | © *RTO Insider*

“We asked for the commission to issue an order within the requisite 60 days,” MISO counsel Mike Blackwell said during a July 17 Interconnection Process Task Force meeting.

MISO policy previously allowed incoming generators to self-fund new construction regardless of whether transmission owners wanted to fund the construction themselves. FERC in 2015 directed the RTO to remove the option for a TO to elect to fund the interconnection upgrades.

The D.C. Circuit in January vacated FERC’s decisions on the self-funding option, saying the commission didn’t consider complaints from Ameren and five other TOs who claimed the policy forced them to accept “risk-bearing additions to their network with zero return” and essentially act as “nonprofit managers” of network “appendages.” The TOs had argued the Federal Power Act and Constitution prohibits FERC from forcing them to construct and operate generator-funded network upgrades. The case was remanded back to FERC. (See MISO Awaits FERC Following Remand on Tx Upgrade Funding.)

MISO made two separate filings July 5: one to reflect the vacatur (ER18-1964), and the other to propose a revised option that removes the requirement that an interconnection customer must consent before a TO can fund an interconnection upgrade (ER18-1965), a move intended to preserve the option for generators to self-fund upgrades. If FERC agrees, the change would apply to MISO’s generator interconnection agreement, Facility Construction Agreement and Multi Party Facility Construction Agreement.

Fallout Undetermined

Blackwell said a FERC decision on MISO’s filing could affect GIAs dating back to 2015. In both early July filings, the RTO committed to working “with parties to GIAs executed since June 24, 2015,” over the next three months to “establish a process for reviewing and revising those agreements to reflect the legal consequences.”

Wind on the Wires’ Rhonda Peters asked if the impacts of the decision could render some past GIAs uneconomic.

“MISO’s intent is merely to bring its Tariffs up to a state that’s as current as possible. We haven’t analyzed the financial impacts for specific interconnection projects,” Blackwell said of the proposed revision.

Peters also asked what would happen if the terms of an upgrade change after it is already funded. Blackwell said he would consult MISO staff on the consequences of such a scenario before attempting to answer the question.

In its filing, MISO warned FERC that not accepting its agreement amendments in a timely manner could have dire consequences: “MISO estimates that agreements already in process contain millions of dollars of affected systems upgrades. … These agreements (and the parties to them) would be subject to significant confusion and uncertainty if the commission does not act promptly to accept this filing, and delays associated with such confusion and renegotiations of agreements of this magnitude could implicate the timely construction of these upgrades.”

July 22, 2018

ERCOT Shatters Demand Records as Texas Bakes

By Tom Kleckner

Hell may be hotter, but it has nothing on Texas these days.

A high-pressure system that has swamped much of the state with triple-digit temperatures has triggered numerous heat advisories and led to all-time systemwide peak records in ERCOT.

ercot demand records — Sunday’s forecasted highs | *National Oceanic and Atmospheric Administration*

The grid operator broke its previous high for system demand on Thursday, when load topped out at 73.3 GW between 4 and 5 p.m. That was more than 2 GW over the previous record of 71.1 GW, set in August 2016.

All told, demand surpassed the old record nine times last week as temperatures reached 110 degrees Fahrenheit and heat indexes were as high as 115. On Sunday, ERCOT set a new weekend demand record of 71.4 GW between 5 and 6 p.m., breaking the old mark set last July by almost 3 GW after surpassing it three times on Saturday.

The ISO came up short of another record Monday, but cracked 73 GW for the second and third times during the intervals ending at 4 and 5 p.m. System load also exceeded the 2016 record during the intervals ending at 3 and 6 p.m.

Demand has exceeded 70 GW every day since July 16. The grid operator in spring projected a peak demand of 72.97 GW in August, assuming normal weather conditions.

Through it all, ERCOT has met demand without issuing conservation appeals. Staff in spring said it would have as much as 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

“Everyone in the ERCOT market — from our operators to generators to transmission providers to retailers — is doing what they can to keep the power on for consumers,” said ERCOT spokesperson Theresa Gage.

Dallas/Fort Worth International Airport set a daily record for the third day in a row Saturday at 109, while Waco has broken its daily record five consecutive days, topping out at 109. Lubbock in West Texas saw a daily low of 81 on Thursday, the first daily low in the 80s in more than 100 years of record-keeping, according to The Weather Channel.

Houston and Dallas both opened cooling centers over the weekend for residents without access to air conditioning.

A jet stream is expected to shift the high-pressure dome to the West this week, cooling Texas temperatures down into the 90s.

“We fully expect to keep hitting new demand records as summer 2018 continues,” ERCOT said in a written statement.

Real-time hub average prices peaked at $1,922.20/MWh on Thursday in the 15-minute interval ending at 4 p.m. Wednesday’s high price of $2,281.95/MWh in the West zone was the highest seen since August 2015, when they hit $2,233/MWh, according to Bloomberg data.

Several retail providers have asked their customers to reduce their usage between 2 and 6 p.m. Cirro Energy, Reliant Energy and Xcel Energy have all offered conservations tips to their customers.

July 22, 2018

PJM MRC/MC Preview: July 26, 2018

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members Committees on 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 in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

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

Members will be asked to endorse the following manual changes:

A. Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). Revisions developed to include or update technical specifications and procedures.

B. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address inconsistencies between PJM’s governing documents regarding price-based offers above $1,000. The RTO hopes to introduce additional system controls to improve validation of price-based offers by November. (See “Energy Market Caps,” PJM Market Implementation Committee Briefs: July 11, 2018.)

C. Manual 14A: New Services Requests Study Process and Manual 14G: Generation Interconnection Requests. PJM is seeking to split out part of Manual 14A into a new Manual 14G to better organize interconnection information. (See “Interconnection Procedure Split,” PJM PC/TEAC Briefs: June 7, 2018.)

3. Governing Document Revisions for Seasonal Demand Response Registration (9:30-9:45)

Members will be asked to endorse revisions to Manual 18: PJM Capacity Market, the Tariff and the Reliability Assurance Agreement associated with the registration process for aggregated seasonal demand response resources. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: July 11, 2018.)

4. Revisions to RAA and Manual 18: PJM Capacity Market (9:45-10:00)

Members will be asked to endorse revisions to the RAA and Manual 18 associated with changes developed by the Demand Response Subcommittee to address issues identified with atypically low customer load during winter peak load calculation period. The Market Implementation Committee endorsed the changes in June.

5. Fuel Requirements for Black Start Resources Problem Statement & Issue Charge (10:00-10:20)

Members will be asked to approve a proposed problem statement and issue charge on fuel requirements for black start resources. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: July 10, 2018.)

6. FTR Credit Proposal (10:20-10:50)

Members will be asked to endorse proposed Tariff revisions to implement a 10-cent/MWh minimum monthly credit requirement for financial transmission rights bids submitted in auctions and cleared positions held in FTR portfolios. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)

7. Variable Operations & Maintenance Packages (10:50-11:30)

Members will be asked to endorse one of four proposals on what maintenance cost components should be included in generators’ cost-based offers. A proposal sponsored by American Electric Power will be considered first, followed by proposals from PJM, the Independent Market Monitor and Rockland Electric. (See “VOM Update,” PJM Market Implementation Committee Briefs: July 11, 2018.)

Members Committee

1. FTR Credit Proposal (1:10-1:25)

Members will be asked to endorse proposed Tariff revisions to implement a minimum per-megawatt-hour FTR credit requirement. (See MRC item 6 above.)

2. Variable Operations & Maintenance Packages (1:25-1:40)

Members will be asked to endorse the proposal on where and how to include VOM costs in generators’ offers that is endorsed in the MRC meeting. (See MRC item 7 above).

— Rory D. Sweeney

July 22, 2018

Midcontinent Must Play Catch-up on EVs, Group Says

By Amanda Durish Cook

Middle America is falling behind other U.S. regions in the adoption of electric vehicles, but utilities could play a key role in turning that around, according to a group of industry leaders, government officials and automakers.

“We clearly are not anywhere near California in terms of adoption to date,” Great Plains Institute Vice President Brendan Jordan said of the MISO footprint during an interview with RTO Insider.

Jordan said the midcontinent region — the Midwestern states and those directly south of them — lacks state-by-state policies like a zero-emissions mandate on car sales or incentives that automakers refer to as “cash on the hood” that can reduce the cost of a new EV.

miso great plains institute electric vehicles evs — Tesla charging station in a supermarket parking lot in Carmel, Ind. | © *RTO Insider*

He pointed out that — for a time — Georgia had one of the highest rates of EV sales in the country because of a state policy that offered a $5,000 tax credit. Sales in the state dropped sharply when Georgia ended the program in 2015.

Jordan’s views are backed by findings in an April white paper from the Midcontinent Transportation Electrification Collaborative (M-TEC), a joint effort of GPI and ChargeUp Midwest. The group comprises more than two dozen state government representatives; electric utilities and cooperatives; charging companies; environmental organizations; and automakers General Motors and Nissan.

The group’s aim: to increase EV use and infrastructure and decarbonize the transportation sector. It says that with some grid transformation, meeting EV demand could concurrently benefit utility customers, the economy and the environment.

But the MISO footprint — along with Ohio — currently has inadequate charging infrastructure to support widespread EV adoption, the white paper contends.

“The midcontinent region is falling behind other regions and falling behind what analysis indicates is needed in preparing for increased EV adoption. … Adequate public charging is a prerequisite for increased EV adoption as cited by numerous studies that establish a connection between EV adoption and adequate charging infrastructure,” M-TEC said.

Utilities Need to Lead

ExxonMobil estimates about 100 million EVs will be in use worldwide by 2040; Bloomberg puts that figure at 530 million. The National Renewable Energy Laboratory recently predicted that about 600,000 charging plugs will be needed to support about 15 million EVs in the U.S., with 400 DC fast-charge stations needed along interstates for long-distance travel.

Jordan said utilities should take the lead in encouraging adoption when states elect not to create incentives.

“Some investment from utilities might help adoption,” he said.

Utilities can provide education and outreach, monetary assistance for charging and reduced rates for charging times, Jordan said.

And he thinks that while states’ roles in stimulating EV purchases should not be ignored, utilities are positioned to act today, a sentiment echoed in the white paper.

“We’re not saying that states won’t or shouldn’t take action. Obviously, states should take action. We wanted to separate out that role that utilities can play independent of state policy,” Jordan said. “I think the point is the utilities don’t need to wait around for states to take action. There are moves they can make that are good for the environment and good for their customers. They shouldn’t wait around for states to take the lead.”

That’s not to say midcontinent utilities are completely inactive on the EV front. Earlier this month, DTE Energy filed a $328 million rate request with the Michigan Public Service Commission that includes a $13 million pilot program for EV charging stations, while Consumers Energy also recently proposed a $7.5 million EV pilot program.

AEP Ohio’s $10 million EV pilot program won approval from the Public Utilities Commission of Ohio in April, and Xcel Energy that month also rolled out a revised charge-at-home pilot program for 100 customers after gaining approval from the Minnesota Public Utilities Commission. Madison Gas and Electric also maintains charge-at-home pilot program where customers can have a car charger installed for a $20 monthly fee.

While private charging companies and automakers’ public stations should exist, Jordan said the reality is most EV charging will be done at the residential level.

“Charging on a public station at a fast-charge station while on a road trip isn’t a big part of use, but it will be critical,” Jordan said. “The fact is that 90 or 95% of charging is going to take place at home.

“I don’t think anyone is saying that utilities should make all those investments, but the fact is that there’s a gap there,” he said. Jordan pointed out that up to 15% of each state’s settlement from the Volkswagen emissions scandal can be spent on light-duty EV infrastructure, and Minnesota has already issued a request for proposals for DC fast-charging stations using its Volkswagen settlement funds.

Taming Load

Electric demand from EV charging could boost sluggish load growth, M-TEC says. “Transportation electrification is a huge part of that,” Jordan added.

Jordan thinks EVs can absorb MISO’s abundant nighttime wind generation. The M-TEC white paper argues EV adoption would only minimally increase the daily system peak, and that the controllable nature of EVs can over time can flatten the load curve and increase overall system efficiency.

“I think, generally speaking, there needs to be programs in place to control when charging takes place,” Jordan said. “At high levels of EV adoption, you can make a real observable difference in the load curve.”

The white paper points out that multiple studies from consulting firm M.J. Bradley project that additional utility revenues from EV charging will likely exceed the cost to supply the demand, putting downward pressure on utility rates.

Jordan also says interested consumers don’t have to wait until the later 2020s to purchase EVs, when costs are expected to fall into parity with traditional vehicles.

“I would argue that regular folks can afford some form of EV today,” he said, adding that used EVs are becoming more available as leases are turned in. Operations and maintenance are much cheaper over the life of the car despite a high upfront cost, he added.

Jordan also said EV fuel costs tend to be spent locally because they draw from a local electric source. “You can power a car on electricity a lot cheaper than you can power it on fuel or diesel,” he added.

Decarbonized Everything

With the white paper published, the group will now focus on modeling a completely decarbonized transportation system in the midcontinent to show it is economically feasible. Jordan said the modeling will be completed this fall.

Meanwhile, the group will hold a one-day conference July 24 to reveal a plan to completely decarbonize the electric sector by 2050.

“Step 1 is electric sector decarbonization and step 2 is transportation decarbonization,” Jordan explained.

He also said GPI and Midcontinent Power Sector Collaborative are in the process of raising money to model decarbonized buildings, industry and agriculture.

“We plan to model the entire [decarbonized] economy eventually,” Jordan said.

July 22, 2018

State Regulators Hear Challenges, Promise of Electrification

By Rich Heidorn Jr.

SCOTTSDALE, Ariz. — The Electric Power Research Institute says electrification of transportation and buildings could boost U.S. electric load growth by as much as 52% by 2050. That’s 1.2% per year.

“Compared to 2005 to 2015, that’s a lot. … Compared to the 1990s, that’s not much,” said Tom Wilson, EPRI’s principal technical executive, who briefed state regulators on the organization’s April 2018 National Electrification Assessment at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week.

The promise of electrification, and the challenges to achieving it, were recurrent themes at the NARUC conference, which attracted more than 800 regulators, utility officials and others.

Charging Infrastructure

Speakers said reducing electric vehicles’ costs and increasing charging infrastructure are among the biggest obstacles to reaching the top end of EPRI’s forecast (its “Transformation” scenario, which assumes a $50/ton CO₂ price in 2020).

“We have to get cost out of the vehicle without sacrificing durability, reliability,” Britta Gross, General Motors’ director of advanced vehicle commercialization policy, said during a dinner panel sponsored by the Brattle Group on the sidelines of the conference. “The next four or five years will be crucial.”

Former NARUC President Phil Jones, now executive director of the Alliance for Transportation Electrification, decried the “woefully inadequate” vehicle charging infrastructure during the Brattle panel and an earlier NARUC session on the effects of electrification.

Jones said developing DC fast-charging infrastructure will be challenging for regulators because the system is likely to see low utilization rates initially. That will call for creative rate structures, said Jones, who served 12 years on the Washington Utilities and Transportation Commission.

“The problem is demand charges kind of kill the business case for that. So, for utilities to put that into a proposal, you all are going to have to grapple with that,” he told the regulators. “Do you spread those costs out over two years, five years, 10 years?”

Gross said the U.S. has only 1,300 DC fast chargers, which can deliver 50 kW and provide a 90-mile charge in 30 minutes. “We need 10 times as much DC fast charging and 20 times as much Level 2 charging,” a 240-V AC outlet that can charge in 5.5 hours.

“Benefits accrue at scale,” she said. “How do we get there?”

Utilities’ Role

The Brattle panel focused on whether utilities should help build some of the infrastructure.

High level overview of modeling results | *National Electrification Assessment, EPRI*

“Absolutely they should [be involved] … because there are market failures and gaps today,” Jones said. “The infrastructure we have through the non-utility competitive model today is totally insufficient in each of the states that you live in. Do the utilities need to do everything? No, but the utilities in our view … have a very important role in catalyzing the market.”

Attorney Paul Afonso, a board member of Braemar Energy Ventures, disagreed with Jones’ declaration that the market has failed. Braemar has invested $141 million in ChargePoint, which builds EV charging infrastructure.

“We can’t condemn [the market] to failure before we get it to start,” he said. “The utility has a relationship … with their customers that’s unique. … There need not be, nor should there be, disintermediation between that. So [ChargePoint is] working with pilots in Columbus with [American Electric Power]. That [charging] station [is branded] AEP. And it’s our network that runs the network software.”

Brattle principal Jurgen Weiss said European regulators have generally opposed utility ownership of charging infrastructure. “There are lots of potential players out there. It’s entirely understandable how it could be a competitive service — in the long run. But we’re not in the long run; we’re hardly in the short run. … We’re trying to get something to scale.”

Weiss insisted the need for capital is so large there will be room for investments both by utilities and private capital.

“It’s worth considering utilities being part of this game for the next ‘X’ years, and then … we can collectively reconsider whether this is not a flourishing competitive market,” he said.

To overcome range anxiety, drivers need to know charging stations are available “even if they will never use” them, Weiss continued. “We will probably need to build more than we need.”

Indeed, according to Gross, 95% of vehicle charging currently occurs at home or work. How the charging network is marketed may be more important than its size, she said.

“If you could just find a way to tell a story better with 20 stations around your state, it’s a lot better than wasting your money on 200 stations. … In Michigan, if every DC fast-charge station was near a lighthouse in Michigan you’d [say], ‘Oh, I know what that means,’” she said. “Storytelling can go a long way to raising the perception of the availability of infrastructure without having to make it ubiquitous.”

Jones said the development of charging infrastructure has been hurt by proprietary charging systems that “can’t talk to each other.”

Jones (left) and McGill | © *RTO Insider*

“It reminds me of the telecom days 10 to 15 years ago. So, we have Tesla with a proprietary system. We have many … vendors building out proprietary systems, both on the network management side — the back end — and even on the front end, we have plug issues.”

Jones said regulators should insist on open standards as a condition for ratepayer-funded investments by utilities.

Utilities also will have a role in planning systems, Jones said. “We have the West Coast electric highway. This was politically driven by the governors and state [transportation departments]. They decided [to use] DC [fast charging]. … Has that been incorporated into the utility [integrated resource plans] in Oregon, Washington and California? No. … We have the Electrify America Network that’s building out a charging infrastructure on its own. Is that coordinated with the [state] commissions? … No. … From a planning standpoint it’s kind of a mess, so I would just posit that the utilities have a big role to play.”

Jones said several states are leading the transition to EVs, naming Michigan, Maryland, Ohio, Washington, California and Oregon.

Role for Oil Companies?

From the Brattle audience, Betty Ann Kane, chair of the D.C. Public Service Commission, asked why service stations haven’t jumped at the chance to install charging stations.

Gross said oil companies have shown little interest “in what feels like a logical answer.”

Jones said his organization has talked with the American Petroleum Institute and National Association of Convenience Stores.

“They are studying the opportunity … but they aren’t coming around to the realization that this is a real opportunity. And in fact, in many states in the Midwest, they are opposing us. … And others in the industry are kind of aligning with the oil and gas interests to oppose utility investments in this infrastructure.”

Weiss was blunt. Oil companies “want to slow this [transition away from gasoline-powered cars] down as long as they can,” he said. “The oil companies are going to come around. The question is how quickly.”

New Value Proposition

Weiss said EV proponents need to change the way regulators look at benefits and costs, noting that electricity purchases represent only 1.6% of disposable income. “There’s just not a lot of money in there compared to the [fuel cost] savings [of] changing from internal combustion engine car to driving an EV. … You probably don’t even have to look at greenhouse gases” as a benefit.

Emily Levin of the Vermont Energy Investment Corp. raised a similar concern in a second NARUC session on energy efficiency’s role in electrification.

“The boundaries we’ve drawn in a lot of cases around energy efficiency programs are too narrow, in having goals around kilowatt-hour savings,” she said. For example, EE programs on heat pumps “often don’t count the fuel savings, the gas or the oil savings. … They only count the increment of savings from an efficient heat pump over a baseline heat pump. … They’re leaving a lot of savings on the table.”

She called for “next generation” goals that consider carbon emissions or focus on peak demand reductions rather than baseload cuts.

In the same session, Jim Lazar, senior adviser for the Regulatory Assistance Project, recalled his work on projects 30 years ago that concluded that natural gas space and water heat were superior to electric space and water heat for new construction. “But then heat pumps weren’t very efficient. Heat pump water heaters weren’t available. Wind and solar were not real grid resources,” he said. “Every assumption we made in those papers is now obsolete.”

Now, he said, the most efficient new homes use too little energy to justify both natural gas and electric service connections.

Sheryl Carter, director of the Natural Resources Defense Council power sector, briefed regulators on the findings of the organization’s 2017 study outlining a strategy for reducing greenhouse gas emissions by 80% by 2050 from 1990 levels through increased efficiency, electrification and renewable generation. It envisions electricity supplying 45% of all energy needs, up from the current 20%.

NRDC says its strategy would increase U.S. energy costs by only 1%, an annual cost of $22 billion that it says would produce more than $154 billion a year in health and environmental benefits.

In an earlier NARUC session, Chris McGill, vice president of energy analysis and standards for the American Gas Association, criticized those who want to quickly eliminate fossil fuels.

“What problem are you trying to solve?” he asked. “Is natural gas no longer a good consumer value? Do we no longer have an enormous resource base? Do we no longer have a huge legacy infrastructure? … Natural gas use in the household here in the U.S. accounts for 4% of greenhouse gas emissions … a pretty small target.”

McGill cited an AGA-funded study that found a “policy-driven” electrification of the residential sector would cost $590 billion to $1.2 trillion by 2035, the equivalent of $572 to $806/ton of CO₂.

“When I hear discussions around electrification — that it’s going to happen very quickly … and it’s not going to cost anybody anything, I believe that is preposterous.”

July 22, 2018

NARUC Talks Innovation at the ‘Water-Energy Nexus’

By Rich Heidorn Jr.

SCOTTSDALE, Ariz. — It used to take SUEZ in North America four years to apprentice an operator at its Boise, Idaho, water utility, with its 90 “pressure planes” (service territories), 80 tanks and 60-plus source wells.

But after developing an algorithm based on 10 years of supervisory control and data acquisition throughout its network, SUEZ created a system that sets the optimal setting for every pump and integrates data from its power utility to determine the best time to run them.

The result: a 10% reduction in the water company’s energy demand and a $350,000 rebate from the power company.

But that wasn’t the biggest achievement, David Stanton, SUEZ’s president of utility operations and federal services, told the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week. Stanton was invited to speak at Monday’s general session by NARUC President Jack Betkoski, who has made the “water-energy nexus” the centerpiece of his year as head of the state regulators.

“Because we’re capturing knowledge in the system, we now can train operators within six months,” Stanton said. “So we’re actually solving what I think is a much more systemic big problem” — an aging workforce.

Stanton said the new system illustrates his company’s need to “reinvent” its information technology. “Traditionally we talk about technology in the context of physical assets. But more and more I’m thinking that the data … that’s coming is going to change the physical technology asset that we want to deploy dramatically. So we really have to solve for data innovation first.”

That means not using enterprise resource planning (ERP) systems like SAP and Oracle for managing big data. “You need ERPs for financials and maybe billing, but you want an innovative environment … that is safe and secure and isolated from your ERP. The future of IT has much more to do with the sources of data and operations than it does big back-office ERPs.”

‘Benchmark Like Crazy’

Four years into what Stanton called the company’s “smart utility” program, he shared his lessons learned.

“We benchmark like crazy. Everything we do that we like, we go find somebody that’s already done it and does it really well. And we go worldwide with the benchmarking.”

Left to right: Arvizu, Stanton and Distal | © *RTO Insider*

SUEZ implemented innovations “at scale” but at one regional utility at a time, Stanton said. “And then once it worked, we hopscotched that out to other regions.

“We never went out and did everything at once, and as a result, we were running 12 or 14 projects around our utility footprint nationwide. … We never bet the ranch on one idea. If something didn’t work, we could throw it out.”

But getting other regions to buy in was a problem, Stanton said. “A lot of utilities run their regions with a strong president or general manager for each region. Getting them to work together … is like a ‘Game of Thrones’ type of activity.

“Once we had enough of these project implementations working, I made 50% of the bonus of each leader dependent on their ability to get what they implemented adopted by the other utilities. So half their bonus all the sudden was based on, ‘If I do it your way for your project, you have to do it my way for my project. We’ve got to work this out.’

“In two weeks, we had everything worked out. We had heard for years that New York couldn’t do it like New Jersey. … So that solved the cultural problem almost overnight.”

‘First Customer’ Syndrome

Also appearing on the panel was Oded Distel, founder and director of Israel NewTech, a program in the country’s Ministry of Industry, Trade and Labor that supports research in the water and renewable energy sectors. Distel described how Israel overcame the reluctance of utilities to become the “first customer” for new technologies.

“We encourage utilities … and tech companies to come together. They form a joint project for the first implementation of a new technology and then the government supports those projects. The money is not huge but … the guy who has to make the decision — the head of the utility, the chief engineer — feels that he’s not alone. He’s part of a national effort. … If something fails, he’s not left there alone to pay the price,” Distel said. “The influence over the utilities was amazing. All of the sudden, they opened up, and they started thinking and having discussions in a totally different manner.”

Dan Arvizu, recently appointed chancellor of New Mexico State University, told regulators about his experience as director of the National Renewable Energy Laboratory between 2005 and 2015.

“Even though our public policy at the federal level — and many times at the state level — aspired to do certain things, the technology was typically ahead of the policy, and the finance was way behind,” he said.

He offered his own advice for innovating: “You need to think big, you need to try small, you need to fail fast and then regroup and then try and scale again.”

And he had a warning for utilities about the new customer choices that will become available from the falling prices of renewables and energy storage. “If utilities are not on the forefront [of the transformation], they could become obsolete,” he said.