Page 1405 – RTO Insider

March 13, 2018

MISO RASC Zeroes in on Priorities

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Resource Adequacy Subcommittee will devote time this year to several projects focused on improving the RTO’s resource adequacy construct, stakeholders learned last week.

Key among the efforts: a continuing discussion on how to deal with the shifting availability of resources.

MISO RASC resource adequacy Dominion Resources Inc. — Harmon | © *RTO Insider*

Speaking at a March 7 RASC meeting, Manager of Resource Adequacy John Harmon said the seven projects are the result of a draft work plan MISO began in January. They were prioritized based on previous commitments to stakeholders in 2017, the urgency of each project, and the staff and capital spending available to devote to each project. (See MISO Seeks To-Do List for Resource Adequacy Panel.)

Harmon noted that the RASC will naturally dedicate time to discussing the nearly completed proposal to create external resource zones for the RTO’s Planning Resource Auctions. (See related story, MISO Closing in on External Capacity Zones.)

Resource Availability and Need

The RASC’s 2018 priorities will also include a larger discussion on resource availability and need, a topic evolving from MISO’s former proposal to create seasonal capacity procurement requirements, a generally unpopular move among stakeholders.

MISO will now consult with stakeholders to determine whether it should revise current resource availability requirements and price signals in the face of shifting availability, itself a product of tightening supply, increased renewables, more frequent extreme weather events and an aging baseload fleet more susceptible to outages. RTO officials say the proposal is no longer as simple as applying separate clearing requirements to two-season and four-season capacity auctions.

The effort will also explore the possibility of MISO factoring the effect of outages during peak load into its loss-of-load expectation study in time for the 2019/20 planning year, which could boost the planning reserve margin requirement. MISO is planning to inform its modeling with an average of outages on peak during the last five planning years, translating to an average 729 MW in outages and a 0.6% increase in the reserve margin, Resource Adequacy Coordinator Ryan Westphal said. MISO’s current modeling assumes generation owners do not schedule any planned outages during the peak. (See MISO to Fold Outage Forecasting into Larger Resource Effort.)

“Zero seems we’re not modeling the reality — the risk — correctly,” said MISO Director of Resource Adequacy Coordination Laura Rauch.

“Current modeling practice could be relying on resources that might not be available. … These ought to be captured,” Westphal added.

Speaking on behalf of the Coalition of Midwest Transmission Customers, attorney Jim Dauphinais warned against “socializing the cost of planned outages” with an increased planning reserve margin if only a few units are the culprits of planning outages on peak.

“I disagree; we’re a risk-sharing insurance pool,” responded Consumers Energy’s Jeff Beattie, adding that generation operators agreed in MISO’s Tariff that even companies covering reliability with several smaller units would share risk with companies relying on a single large unit that carries more outage risk.

Westphal asked stakeholders to provide more feedback by March 21, noting that MISO would need to complete a proposal by June to allow it to model planned outages on peak in the 2019/20 planning year.

Other RASC priorities this year will include:

Improving alignment between MISO’s loss-of-load expectation study and its annual resource adequacy survey with the Organization of MISO States;
Discussing how energy storage resources could earn capacity accreditation;
Discussing how behind-the-meter generation can fit into MISO’s resource adequacy construct;
Deciding whether MISO should bar units on extended outages from offering into the capacity auction;
Determining the best approach to potentially importing capacity from Ontario’s Independent Electricity System Operator into MISO.

Harmon said MISO plans to postpone until next year a project that would alleviate partial unit clearing, which occurs when the RTO’s algorithm clears a marginal offer on a pro rata basis, resulting in revenue shortfalls for resources that clear a fraction of their unforced capacity values.

The RASC will not focus on two other previous suggestions: developing forward capacity price indices and raising the PRA price cap above MISO’s approximate $250/MW-day cost of new entry (CONE). Harmon said MISO “has no role in bilateral markets” and “should not be involved in facilitating pricing information outside its markets.” He also said there’s no indication at this time that MISO’s cost of new entry needs to be raised because auction clearing prices are far from closing in on the CONE.

March 13, 2018

Basin Electric Freed of PURPA Purchases Over 20 MW

By Robert Mullin

FERC on Monday approved Basin Electric Power Cooperative’s requests to eliminate its obligation to purchase power and capacity from generating facilities over 20 MW under the Public Utility Regulatory Policies Act.

The consumer-owned co-op, which provides supplemental wholesale power to 141 rural electric member systems in MISO and SPP, last year assumed the mandatory obligations of its members to purchase output from PURPA qualifying facilities — QFs of 150 kW or more in the case of SPP.

FERC PURPA basin electric power cooperative — Crow Lake facility | *Basin Electric Power Cooperative*

In its rulings — one for QFs in MISO (QM18 –7) and one for SPP (QM18 –6) — the commission agreed to terminate Basin’s mandatory purchase obligation under FERC regulations, which stipulate that QFs in excess of 20 MW of net capacity in the two RTOs have nondiscriminatory access to a market, satisfying PURPA’s requirements.

The commission dismissed the combined protests of two wind farm developers, Thomas Mattson and David VanderLeest, who argued that Basin was attempting to “rewrite” and “violate” PURPA and other laws intended to protect small generators.

Mattson and VanderLeest contend e d that larger developers have received “substantially” better power purchase agreement terms from Basin than smaller developers, causing the complainants to lose out on a number of proposed projects because of expiring option agreements.

“Basin destroys their competition, keeping all small cooperatives under their rule,” their protest said. “QF wind farms would provide less costly power than Basin, reducing customer rates while providing economic stability for the small cooperative.”

The developers asked FERC to take six actions, including an order to reduce interconnection costs.

The commission said the issues raised in the protest went beyond the scope of the proceedings. “Mattson and VanderLeest allege, among other things, delays in providing developers with accurate long-term avoided costs rates and failures in the overall implementation and enforcement of PURPA at the federal and state levels,” the commission said. The Basin proceedings were limited to whether QFs in MISO and SPP have nondiscriminatory access to a market that satisfies PURPA’s requirements, it said.

FERC cited Order 688, in which it “explained that there can be factors unique to individual QFs, including operational characteristics and transmission limitations, that prevent such QFs from having nondiscriminatory access to the markets described in Section 210(m)(1) of PURPA.

“However, Mattson and VanderLeest’s protest does not discuss those factors or otherwise attempt to rebut the arguments in the [Basin] application,” FERC said.

Basin’s territory includes portions of Colorado, Iowa, Minnesota, Montana, Nebraska, New Mexico, North Dakota, South Dakota and Wyoming.

March 13, 2018

AMP Seeks More PJM Scrutiny of TO Projects

By Rich Heidorn Jr.

American Municipal Power contended Thursday that PJM’s limited review of transmission owner projects is not rigorous enough to ensure the RTO is avoiding unnecessary costs or that TOs’ evaluation of other stakeholders’ proposed solutions are accurate and unbiased.

AMP’s Ryan Dolan noted that Manual 14B prohibits PJM from evaluating supplemental projects as part of the Regional Transmission Expansion Plan, meaning the plan can’t capture whether a supplemental project creates or alleviates economic issues. “We can’t assure an optimized build-out of the system,” said Dolan, who presented a list of proposed rule changes at Thursday’s Planning Committee meeting.

Dolan said PJM’s limited review was not a problem in the past but that the RTO should provide more scrutiny now, because supplemental and other TO projects represented 88% of RTEP spending last year.

“There’s information that PJM has that the TOs don’t have, that we [stakeholders] don’t have,” said Dolan, who said the RTO should tap all available expertise in its analyses.

‘Do No Harm’ Reviews

Dolan spoke after Aaron Berner, PJM manager of transmission planning, explained the RTO’s “do no harm” reviews of baseline upgrades, supplemental upgrades and new service requests. The review is intended to identify any reliability issues caused by new upgrades, determine if the upgrades should be more or less “robust” and assess the cost efficiency of packages of upgrades needed to correct reliability violations.

The testing required depends on the scope of the upgrade, not the type of upgrade, Berner said. No analysis is required for direct in-kind replacements, while minor changes to impedances or ratings undergo “minimal analysis.” Significant changes to impedances, ratings or new topology may require “significant” review — load-flow, short-circuit and stability analyses.

AMP wants PJM to vet supplemental projects to identify interdependencies with baseline projects and quantify the impacts of TO proposals on previously approved economic projects or whether they eliminate previously approved reliability projects or change cost allocations.

Dolan said many TOs create their own base cases with generation dispatch and load profiles that differ from PJM’s practice, but the RTO’s analysis is only applied on its own models. “There are no checks and balances to ensure that the [TO’s] process is being followed and that [that] process is consistent,” he said.

Dolan also expressed concern about the large number of TO projects submitted at the end of the RTEP cycle, saying PJM should establish start and stop dates for TOs to submit needs and proposed solutions, aligned with competitive windows.

He also called for standardizing the data reporting requirements for all project submissions and requiring reporting of all scenarios, models, standards and documentation used to justify and size project facilities; and a process that allows for formal submission and PJM review of alternative proposals.

Supplemental Projects AMP PJM — Stern | © *RTO Insider*

Alex Stern, manager of transmission strategy and policy at Public Service Electric and Gas, said AMP’s proposals were “misplaced.”

“My initial reaction is the PJM stakeholder process might be the wrong forum” for AMP’s proposal, said Stern, noting FERC’s Feb. 15 ruling, which he said accepted PJM’s current role and declined to mandate it do more (EL16-71, ER17-179). (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)

“FERC just advised that it doesn’t believe there is any modification needed to PJM’s analysis. It confirmed the acceptability and appropriateness of PJM’s role with respect to planning for supplemental projects and specifically declined to require greater PJM involvement in planning for and selecting supplemental projects.

“The stakeholder process probably shouldn’t be discounting FERC on this,” Stern added.

“They weren’t saying [PJM] couldn’t do more,” Dolan responded. “They were just saying, ‘It’s OK.’”

Internal Discussions on Sharing More Info on Tx Projects

Earlier in the meeting, Berner described the RTO’s internal discussions about how it can respond to requests for more information on proposed transmission projects.

Berner said PJM is developing a tracking mechanism for identifying information shared without disclosing critical electric infrastructure information. The RTO is considering making more information available through the Planning Community portal launched in September.

The RTO expects to share its proposals within “a couple months,” Berner said. Some information requests to the RTO indicate it should offer additional education on its study process, he added.

TOs Answer Questions at TEAC

At the Transmission Expansion Advisory Committee meeting later Thursday, officials of Baltimore Gas and Electric and Commonwealth Edison answered questions Dolan had posted on supplemental projects brought up for a second read. BGE, for example, said that circuit breakers slated for replacement at its Jericho and Howard substations are 47 and 27 years old, respectively, and have been the subject of expensive repairs.

Dolan appeared pleased to be receiving responses, smiling in the room when the BGE representative spoke up on the phone. He had posed the questions to Berner, who said PJM was still in collecting the necessary information and determining how to respond, but BGE then volunteered the responses. When Dolan later brought up his questions about replacing a transformer and installing two breakers at ComEd’s Wayne substation, Berner deferred to a ComEd representative on the phone, who provided responses.

Earlier in the TEAC, stakeholders received first-read presentations on eight supplemental projects: six by American Electric Power totaling $163.4 million and two by Dominion, totaling $860,000. (See table.) When discussing an AEP project to replace two breakers at its Jefferson station, Berner told Dolan he didn’t have answers to questions AMP had submitted and wasn’t planning to bring the project back to a subsequent meeting to review the responses “unless something changes.” Dolan argued that AMP had submitted questions within the timeline laid out in the TOs’ recently proposed Tariff Attachment M-3, which they developed to codify the “additional detail and transparency regarding the process for planning supplemental projects” they’ve agreed to. It is currently circulating for review and comments.

In a discussion on a $53 million project to replace aging transformers at AEP’s Wyoming substation, Dolan asked whether stakeholders would be permitted to review maintenance records on the transformers. “There’s a discussion about whether maintenance records need to be made available,” said Berner.

Vice President of Planning Steve Herling said PJM’s reading of FERC’s February order is that stakeholders should be able to replicate the TO’s planning studies, “not replicate asset conditions.”

“As we’ve been discussing, we’re trying to change the progress of the supplemental upgrades as they come to PJM,” Berner said at one point. “It’s going to take us a little bit of time to get those specifications of the required upgrades to a point where we can present them all in a fashion that would allow identification of the issues earlier in the process, but there are a number of issues out there right now that need to be addressed. We can’t delay that.”

March 12, 2018

McIntyre Discloses Brain Tumor Surgery

FERC Chairman Kevin McIntyre disclosed Sunday that he underwent successful surgery for a brain tumor that was discovered last summer.

The disclosure, made in a statement posted on FERC’s website, appears to explain the dramatic difference in McIntyre’s appearance between his Senate confirmation hearing in September and his swearing in in December, after his hair — apparently having been partly shaved — was beginning to grow back.

FERC CAISO Kevin McIntyre Kevin and Rich Gates — FERC Chairman Kevin McIntyre at his Senate confirmation hearing in September 2017 (right) and his testimony before the Senate in January (left), after his hair — apparently having been partly shaved — was beginning to grow back.| © *RTO Insider*

The health issues also may have played a part in McIntyre’s delayed arrival at FERC. He took office on Dec. 7, more than a week after Commissioner Richard Glick; both were confirmed by the Senate on Nov. 2.

McIntyre said he issued the statement because of inquiries about his health. He said the tumor was discovered unexpectedly last summer. “Through an incidental finding, i.e., a medical issue discovered by accident, I was diagnosed with a brain tumor. I was very fortunate that the tumor was relatively small, that I had no symptoms and that I was otherwise in excellent health.

“Thereafter, I underwent successful surgery, followed by the post-operative treatment that is the standard of care for my situation. I was advised at the time that, with the surgery and subsequent treatment behind me, I should expect to be able to maintain my usual active lifestyle, including working full time, and that expectation has proven to be accurate.”

The chairman expressed gratitude for the support he received from those who had been aware of his situation “especially those in the White House, Congress and the FERC.”

He said he did not intend to provide further details or updates “for reasons of personal and family privacy.”

“I am grateful that my health is now stable and that I am able to devote my full energy to serving the American public every day as chairman of the FERC and continuing to work to earn the trust that has been placed in me,” he said.
McIntyre joined FERC after two decades at Jones Day, where he represented energy clients in administrative and appellate litigation, compliance and enforcement matters, and corporate transactions.

— Rich Heidorn Jr.

March 12, 2018

Competition Gives Everyone Better, Cheaper Energy Choices

By Anne Hoskins and Dan Dolan

Open markets drive competition. Competition drives innovation and affordability. Case in point: Today, more and more consumers are utilizing innovative battery solutions — with many powered by rooftop solar — to provide clean energy to homes and businesses. In the coming weeks, regulators will consider proposals by utilities in Massachusetts and New Hampshire that seek to fully control customer-owned batteries, or seek to reach into peoples’ homes and actually own batteries. There is no reason for regulators to allow utility control or ownership of generation and storage resources that can be supplied competitively. With no natural monopoly to regulate or market failure to fix, enabling utility ownership and control will serve only to stifle innovation and impede competitive solutions. We urge regulators to consider a better future.

NEPGA Sunrun competitive markets batteries — Sunrun’s Brightbox home battery service | *Sunrun*

The way Americans make and use electricity is in the midst of a remarkable evolution. For more than a century, we were unable to store electricity at our homes or businesses the way we store gasoline or recharge devices like our cell phones. Energy needed to be generated and consumed simultaneously. As a result of steep cost reductions in technology and competitive innovation, we are entering an exciting new era of empowerment. Consumers and businesses across the country are pairing batteries with rooftop solar. Large power plants are also now pairing with batteries to smooth spikes in demand. These new resources can enter markets, lowering costs for all consumers.

Twenty years ago, many states unleashed innovation by restructuring and creating competitive markets, no longer allowing monopoly utilities to own generation. That policy choice helped pave the way for consumers to benefit from electricity supply options and unleashed fierce competition in how electricity is produced. The result? More efficiency. Thanks to increased competition in the marketplace, today it takes three plants to generate the same amount of electricity as it used to take four to generate. This in turn helped lower the price to produce power dramatically, though consumers’ bills are still increasing, as utilities continue distribution and transmission spending and charge us more to transmit power. These efficiency gains and competitive investments have also helped power plants in New England drive down carbon dioxide emissions by more than 40% since 1990, now representing only half of the emissions of the transportation sector. The framework of a competitive and dynamic marketplace set the stage for more competitive storage options.

But the glide path for consumers and competitive markets is riddled with bumps along the way. Some utilities are seeking to own batteries in peoples’ homes and businesses. Others are requesting the right to the energy in a consumer’s battery, at the very least. Their goal? To receive returns for their investors by controlling storage that was funded by consumer and business investments. In other words, utilities want to take control of a family’s home battery, which was charged by the family’s home solar system, and bid that electricity into the competitive wholesale markets themselves. That is anticompetitive and counter to public policy goals that encourage investments in a cleaner and more resilient electricity grid.

The New England Power Generators Association and residential solar and storage companies agree that utilities should not impede consumer energy and storage investments when there are competitive options available. Such utility ownership or control is a dramatic step away from open energy markets. Rate-based utility ownership of batteries stifles competition — both at the rooftop and large generator scale — and threatens to raise rates for everyone.

Let’s get this right. Dozens of innovative companies are already stepping up to replace portions of our aging energy infrastructure with innovative storage solutions — competitively and with increased flexibility for consumers and generators. At the same time, however, utilities are spending tens of billions of dollars annually on building poles and wires. Some of these investments are necessary to replace power lines and substations at the end of their useful life, but some can be avoided with distributed energy solutions and large-scale storage. Consumers will foot the bill for utility infrastructure now and for decades into the future — if we don’t allow competitive solutions to emerge. With the right policies in place, investments in competitive electricity supply and storage can improve resilience and affordability. By providing clear price signals, utilities or system operators can incentivize private storage assets, at all scales, to meet system demands. There is no need for utilities to own or control the assets.

As the National Energy Marketers Association, which represents global suppliers and major consumers of natural gas and electricity, wrote, “After nearly two decades of experience with competitive retail markets, it is abundantly clear that the anticompetitive impacts of monopoly utility participation in competitive energy markets … is poor public policy, is not in the public interest and deters and discourages the private capital investment and technology innovation.”^[1]

Dan Dolan, President, New England Power Generators Association. NEPGA’s mission is to support competitive wholesale electricity markets in New England. We believe that open markets guided by stable public policies are the best means to provide reliable and competitively-priced electricity for consumers.

Anne Hoskins, Chief Policy Officer at Sunrun. Sunrun is the nation’s largest dedicated residential solar, storage and energy services company with a mission to create a planet run by the sun.

“Comments of the National Energy Marketers Association.” State of New York Public Service Commission. Case 14-M-0101. Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision. 9/22/14. http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={929C1EFF-B6C6- 4779-934A-23EDD5DA11D2. ↑

March 11, 2018

Outages Small Risk for MISO Spring Operations

By Amanda Durish Cook

CARMEL, Ind. — In what marked a first for the grid operator, MISO last week detailed its spring readiness and said there’s a small possibility of emergency conditions.

While the RTO expects to have adequate resources on hand to meet sometimes volatile demand, it might also have to rely on emergency operating procedures during what was once considered a calm shoulder period, stakeholders learned during a March 8 Market Subcommittee meeting.

MISO outages planning reserve margins — Furnish | © *RTO Insider*

“Projected spring transmission and generation outages show challenging but manageable outages, similar to recent years,” said Jeanna Furnish, MISO manager of resource planning and transmission studies.

MISO’s analysis shows a 25% probability it will need to invoke systemwide emergency operating procedures during the spring, but only if either loads or forced outages are higher than normal, Furnish said.

“My presence here isn’t to cause any alarm but to talk about … the realities of challenges that may exist on the system,” Furnish said.

Based on forecasts from the National Oceanic and Atmospheric Administration, the RTO is expecting a warmer-than-usual spring for MISO South and normal to above-normal precipitation in most of its footprint.

MISO said volatile spring loads that deviate from forecasts will require careful coordination of outages.

Furnish pointed out that MISO maintains a nonpublic member webpage called “Maintenance Margin” that keeps a monthly forward account of how many megawatts can be taken out of service without affecting reliability. The RTO uses the data to inform generators when it predicts outages will have an impact on reliability and will recommend alternative outage schedules.

Last year, high generation and transmission outages paired with unseasonably elevated loads in MISO South produced an early April maximum generation event, unusual for a shoulder season, prompting the RTO to call on load-modifying resources for the first time in a decade. The event prompted the Independent Market Monitor to call for MISO to have increased authority over approving maintenance outages. (See 4 LMRs Face Penalties after MISO Max Gen Emergency.)

Customized Energy Solutions’ Ted Kuhn asked if Maintenance Margin provided any indication that emergency conditions were imminent last spring.

“Was the Maintenance Margin showing a deficit, or did we just fall into a black hole?” Kuhn asked.

Furnish didn’t know but said MISO continues to work with stakeholders to enhance outage coordination, including developing reserves that can be available within 30 minutes and improving congestion management with PJM at the seams by swapping control of flowgates.

MISO did not venture a guess about the projected spring peak. The RTO is planning for a 126-GW summer peak load, which it predicts will require a 17.1% planning reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)

March 11, 2018February 13, 2025

Visibility Key as EVs Seek Growth Beyond Early Adopters

By Rich Heidorn Jr.

WASHINGTON — Growing the electric vehicle market beyond early adopters will require creative regulations, an expanded charging network and a vastly improved customer experience, speakers told the Institute for Electric Innovation’s (IEI) spring 2018 forum Wednesday.

Fisher | © RTO Insider

“The early adopters were able to deal with some of the challenges of interacting with five different charging networks and the fact that sometimes stations didn’t work; maybe they’re in the back of a parking lot that wasn’t well lit and it was kind of dangerous,” said Scott Fisher, vice president of market development for Greenlots, which sells EV charging software and services.

Fisher said he senses increased momentum for EVs, with moves in Europe to ban diesel vehicles and Volvo announcing all its models will be electric-powered by 2019.

“There seems to be a commitment among large credible companies to create this positive customer experience. So, it’s not going to cater to the 1% anymore. … To get to that 5% or 10% — that next stage of early adopters — thinking about the customer experience that’s needed” is crucial, he said. “Some of it’s in place, but making it more consistent is a really important objective.”

Oshima | © RTO Insider

Alan M. Oshima, CEO of Hawaiian Electric and the owner of a plug-in Ford Fusion, agreed. “The [conflicting] charging protocols we have right now is even worse than Betamax vs. VHS,” said Oshima, who moderated the panel discussion.

“It can’t be depending on niches. It can’t just work in California or Massachusetts or New York,” said Mark S. Lantrip, CEO of Southern Company Services. “Somehow we’ve got to think about how we bring everyone along. Until that, it’s going to be a series of fits and starts.”

Exhibit A is Georgia, which — thanks to a $5,000 state tax credit — was the fastest-growing EV market in the U.S. between 2010 and 2014, according to the Edison Electric Institute, which funds the Edison Foundation and IEI. When the tax credit expired, EV sales in the state plummeted. (The federal government continues to offer a $7,500 tax credit.) Still, with 25,500 EVs as of 2016, the state ranked second to California in EV sales between 2011 and 2016.

Wooing Newcomers

Although U.S. EV sales increased by 26% last year to almost 200,000, they still represented only 1% of new vehicle sales. Globally, EV sales jumped by more than 60% last year, with China responsible for more than half the sales in the third quarter.

Fisher said the best marketing EVs could get is more charging stations. “Whenever I talk to my liberal friends in Princeton, N.J., where I live, [they say] ‘Oh, that’s a great car, but where would I charge it?’ If I have to explain to them, I’ve already kind of lost them.”

Wood | © RTO Insider

Lisa Wood, IEI’s executive director, said EVs also will benefit from the increasing visibility of electric fleets such as city buses, United Parcel Service delivery vans and school buses that can provide energy storage in summer. Electric companies have increased their EV fleets by more than 40% since 2015, according to EEI, with more than 70 companies investing more than $120 million last year alone.

Lantrip | © RTO Insider

Lantrip said proponents are discouraging potential adoptees from making the switch with talk of EVs’ potential as distributed energy storage.

“We’re trying to get people to just even entertain the idea of buying [an electric] car, and what I see in so many presentations on electric vehicles is they immediately go to vehicle-to-grid, vehicle-to-home, and that freaks out the average new potential buyer … because they just don’t get it or want it. It’s like, ‘You’re going to drain my battery?’ We have to separate those two conversations.”

Lantrip predicts EV penetration will not surge until there is price parity between EVs and conventional vehicles and charging times are reduced to five minutes. “We have to manage our expectations,” he said, warning that current investments in the technology and charging infrastructure should be limited to “no regrets” steps while the market remains small and different technologies are competing for dominance.

About 80% of EV charging is done at home, where residents can use either a Level 1 charger (a standard AC outlet providing up to 1.5 kW of electricity that takes 30 hours to fully charge a 115-mile battery) or a Level 2 (a 240-V AC outlet delivering up to 9 kW, which can charge in 5.5 hours). Commercial charging locations with DC-powered fast chargers deliver 50 kW and reduce a 90-mile charge to 30 minutes. In Europe, a new generation of chargers is being installed offering 350 kW, which would complete a charge in 10 to 15 minutes, but no vehicles currently offered can use them.

Policy Questions for Regulators

Norm Saari, a member of the Michigan Public Service Commission, shared Lantrip’s concern about investing in technology that could be rendered obsolete.

Saari said policymakers could be hesitant to act because of uncertainty over what is the “proven, right technology.”

“[Do] you want to have a Level 1 or Level 2 or DC fast charging? Or do you want inductive charging on the road? Or let’s forget about that. Let’s go to hydrogen fuel cells instead. There’s a lot of issues that still have to be resolved,” Saari said.

The Michigan commission held its second technical conference on EVs in February. Saari said he and his colleagues are concentrating on four primary areas: customer education, rate design, the impact of EVs on the grid and charging infrastructure — “who is going to build what, where and how is it going to be priced out?”

Under the “make ready” model, the utility supplies the service connection and supply infrastructure, with the customer supplying the charging equipment. Another model would have the utilities assume full ownership of the charging equipment — the opposite of the business-as-usual model in which the customer is responsible for all equipment.

Speakers left to right: Oshima, Adler, Fisher, Lantrip and Saari | © RTO Insider

Saari said he expects both DTE Energy and Consumers Energy to request money for EVs in rate cases the companies will file later this year.

Lantrip said Southern Co.’s Georgia Power will propose several pilot projects to regulators later this year on getting EVs to low-income customers. “It could run the gamut from something like Zipcars or it could be electrified Ubers targeted in certain areas or something in between that,” he said.

Lantrip called on utilities and regulators to be “creative in developing new rate designs.”

Fisher said that although higher EV penetration will mean more electric demand, the grid investments required to expand the market are “going to turn out to be a wise ratepayer investment.”

Adler | © RTO Insider

In California, which has more than 277,000 EVs — about half of the nation’s total — a joint study by the state’s three investor-owned utilities reported the costs of distribution upgrades to serve EVs have been “immaterial.” But Southern California Edison has said 25% of its network must be upgraded to support new chargers.

Dan Adler, vice president of policy for the Energy Foundation, which promotes energy efficient buildings and appliances, said the industry needs “durable” coalitions to ensure regulatory policy does not become an obstacle to growth. “You get better policy outcomes … if the coalition is formed ahead of time,” he said.

Role for Gas Stations

From the audience, D.C. Public Service Commission Chair Betty Ann Kane asked whether the industry was working with gas stations that might otherwise become “stranded investments” in an electrified transportation system.

“If you get the charging times down, there’s an opportunity to work with that community,” Adler said. Because gas stations make most of their profits from snack and beverage sales and not fuel, Adler said, station owners may welcome a new way to generate foot traffic.

Lantrip said new gas stations are increasingly being designed to be fit with electric charging. He said they may be the best locations for charging in urban areas where few residents own garages. Last October, Royal Dutch Shell announced it was buying one of Europe’s largest EV charging providers; it is also beginning to add EV chargers at its stations in the U.K. and the Netherlands.

March 11, 2018

Marquez to Depart Texas PUC

AUSTIN, Texas — Texas Public Utility Commissioner Brandy Marty Marquez quietly resigned Thursday, saying she will pursue life in the private sector after two decades of public service.

Her resignation is effective April 2.

The announcement came several hours after the PUC’s open meeting. There was little hint of what was to come during the meeting, other than when Chairman DeAnn Walker, a close friend of Marquez, choked up in announcing the commission was going into a closed session to “deliberate personnel matters.” Walker avoided looking at Marquez as she gathered her composure.

“Is that it? Can we go?” Marquez said, smiling broadly. She had already met separately with Walker and fellow Commissioner Arthur D’Andrea before the open session to tell them of her decision.

Marquez’s resignation will mean the three-person PUC has completely turned over since last May, when longtime Chair Donna Nelson left. Her departure was followed by that of Ken Anderson, who resigned after his term expired in August. They were the two longest serving commissioners in PUC history, each having served eight years or more.

Marquez was appointed to the commission in August 2013 by then-Gov. Rick Perry and reappointed by Gov. Greg Abbott in 2015. Her term was to expire in September 2019.

She said in a statement she leaves the commission knowing it will continue to serve Texas “with fairness under the principled leadership” of Walker and D’Andrea.

“Supported by the best staff of any Texas agency, the PUC will continue working tirelessly on behalf of stakeholders and consumers,” Marquez said. “I am honored to have served my fellow Texans. I leave with a happy heart.”

Despite speculation that she would return to the political arena, Marquez said she plans to enter the private sector. She served as Perry’s policy director during his successful 2010 gubernatorial campaign and was his chief of staff during Texas’ 83rd legislative session. The Legislature next meets in January 2019.

Brandy Marquez ERCOT PUCT ORDC — PUC of Texas Commissioners left to right: Brandy Marty Marquez, DeAnn Walker, Arthur D’Andrea | © *RTO Insider*

“The state of Texas has benefited greatly from the more than 17 years of dedicated service from Brandy Marquez,” Abbott said. “Her commitment and passion for public service have been on full display throughout her impressive career. I commend Brandy for her extraordinary accomplishments during her tenure as commissioner.”

While at the commission, Marquez also served on the Texas Reliability Entity, which serves as the PUC’s reliability monitor for the ERCOT region and enforces NERC standards.

Commission Directs ERCOT to Revise ORDC

The PUC directed ERCOT to begin the process of removing reliability unit commitment (RUC) capacity from the ISO’s operating reserve demand curve (ORDC), which creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves (Project No. 47199).

Marquez said her preference was to wait until after the summer, when operating reserves are expected to be tight, but she joined with Walker and D’Andrea in the decision.

“I think taking out the RUC is the right thing to do,” Walker said. “I don’t think it’s going to make a significant difference for the summer, but it sends the signal we’re fully supportive of the energy-only market, and we will stand behind it.

“I want to be clear that this decision is based on what I believe is the correct decision, and not because anyone has made me believe this,” she continued. “I’ve been there a long time, and I didn’t need help getting there.”

“I can’t envision anybody … who believes in this market that wouldn’t support this change,” Marquez said. “We’ve never gone into a summer like this. It will be an incredible learning opportunity for our market. Anything we’re preparing for now will potentially look very different after August.”

PUC staff have also recommended removing the RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics. Some market participants have pushed back, sharing Marquez’s view that it would be best to wait until after the summer to make the change. (See “Participants Caution Against Market Changes Before Summer,” Overheard at the Infocast ERCOT Market Summit.)

ERCOT staff filed a report with the PUC on March 2 that indicates removing RUC capacity from the ORDC would have provided generators an additional $6.6 million and $18.6 million in revenue in 2016 and 2017, respectively. Given that total generator revenues in ERCOT were about $8.4 billion in 2016 and $9.5 billion in 2017, the adders respectively represented about 0.07% and 0.2% of total revenue, staff said.

The ISO study estimated it would cost $15,000 to $25,000 to modify ERCOT’s systems to remove online RUC and RMR resources from the ORDC capacity value, and could be done internally within 60 days.

ERCOT will include the revised protocol language for its April 10 Board of Directors meeting.

PUC to Intervene at FERC in MISO’s Docket

Following the PUC’s executive session, Walker announced the commission would be intervening in MISO’s application before FERC to create targeted market efficiency projects, a new category of small interregional transmission projects (ER18-867).

Walker also said Thomas Gleeson, the commission’s director of finance and administration, will serve as its interim executive director until a full-time replacement can be found. Brian Lloyd resigned from the position March 1, after seven years. (See Texas PUC Executive Director to Resign.)

— Tom Kleckner

March 11, 2018

‘Hesitancy’ Around Western RTO, EIM Chair Says

By Jason Fordney

LOS ANGELES — Despite recent developments favoring more organized energy markets, Westerners still hold some “anxiety” and “hesitancy” about a new RTO in the region, says Doug Howe, chairman of the Western Energy Imbalance Market’s (EIM) Governing Body.

EIM PJM Western RTO Doug Howe — Howe | © *RTO Insider*

Howe, a doctor of mathematics, independent consultant, former utility executive and former New Mexico regulator, joined the body when it was established in 2016.

At an EIM meeting in Los Angeles last week, RTO Insider asked Howe how he sees the Western landscape taking shape, and what his concerns are about a possible new Western RTO.

“My sense is still that there is a lot of hesitancy towards a full RTO,” Howe said. “The idea of transmission allocation and a uniform transmission price across a region as big as the Western Interconnection gets a lot of people a little nervous, because we have widely varying transmission costs in the West.”

Several possible changes are stirring the West, including a joint proposal by Peak Reliability and PJM to create a new market and CAISO’s plan to extend its day-ahead market across the EIM. (See Calif. Lawmakers Relaunch CAISO Regionalization.)

CAISO and EIM Governing Body Personnel left to right: Keith Casey (CAISO) Carl Linvill, Valerie Fong, Howe, John Prescott, Kristine Schmidt, Roger Collanton (CAISO) | © *RTO Insider*

While the Peak/PJM market proposal only sets out to establish an energy market, and not a full RTO, Peak executives have described it as a “pathway” to an RTO.

“All of these initiatives are in some sense a pathway to an RTO,” Howe said. The question is how to deliver the benefits of an RTO, such as day-ahead, real-time and ancillary services markets, “without triggering all this anxiety,” he said.

The best approach, according to Howe?

“Let’s get the energy markets established first and then we will see where stakeholders are comfortable going.”

Howe said industry participants have several choices to examine now and will be analyzing the costs and benefits of each one, “and whether it has sufficient bells and whistles — is it the right market to be in?”

One concern is “the absence of a real exit strategy” if a market participant joins an RTO, he said.

“If you find it’s not working out for you, getting out is extraordinarily expensive,” Howe said. While CAISO is seeking to extend the day-ahead market across the EIM, an RTO “is not what we are proposing at this point.” The trade-off is that participants don’t get the full benefits of an RTO either, he said.

When asked about whether there is unease about a balkanized and noncontiguous market taking shape, Howe said, “I don’t think there is a lot of concern about that.” The Eastern U.S. is balkanized to some degree and “it’s a spider web of transmission,” he said. In the West, transmission lines run north and south and east and west from the coast inland.

“They have worked that out in the East, but there is some concern that the West is not the same as the East, and that is going to be part of the working-out process,” Howe said. “There might be a little more concern about the reliability coordinator becoming balkanized, because they are the ones that have a high-level view of the entire grid.”

March 11, 2018

EIM Governing Body Approves CAISO Bidding Flexibility

By Jason Fordney

LOS ANGELES — Western Energy Imbalance Market (EIM) leaders last week endorsed CAISO’s controversial proposal to give generators more bidding flexibility, but not without giving ground to the plan’s skeptics.

The EIM’s Governing Body on Thursday approved the ISO’s Commitment Costs and Default Energy Bid Enhancements (CCDEBE), designed to give generators more latitude in how they reflect their commitment — or start-up and minimum load — costs and overhaul the way the ISO calculates the default energy bid, which replaces bids of units found to have market power.

The EIM Governing Body met last week in Los Angeles, California | © *RTO Insider*

The current method can artificially limit a generator’s commitment cost and limits what the generator can bid in, the ISO has said.

But to the end, market participants and the ISO’s Department of Market Monitoring raised questions after a lengthy stakeholder process to develop the rules. (See CAISO Developing New Bidding Rules.)

The rule changes still require approval by the CAISO Board of Governors, which will consider the proposal at its March 21-22 meeting.

‘A Good Place’

CAISO’s proposal replaces a static commitment cost bid cap with a local market power mitigation test, which identifies whether a resource needs to be committed to relieve a transmission overload or other constraints, the same way energy bids are handled. The ISO will only mitigate bids when a generator fails the test.

Under the current rules, the ISO calculates reference levels for each gas-fired generator based on published natural gas price indices. The commitment cost reference level is determined by multiplying costs by 125% and bids are capped at the generator’s reference level.

CAISO plans to phase in commitment cost bidding flexibility, first raising the commitment cost multiplier to 150% for the first 18 months after implementation, and then increasing it to 300% if no issues arise.

During the rulemaking process and at Thursday’s meeting, there was heavy debate over CAISO’s plan to automatically increase the reference levels after 18 months. Some commenters, such as Governing Body member Kristine Schmidt, suggested that a new stakeholder process might be needed at the 18-month point.

caiso eim commitment cost — Casey | © *RTO Insider*

But CAISO Vice President of Market and Infrastructure Development Keith Casey resisted the idea, saying “it sends a message to the market that we are not serious about this.”

Body members compromised by adding a provision to the decision that the ISO provide a status report to the EIM and CAISO board at the 18-month point.

“This was tough one, but I think we ended up in a good place on this,” Governing Body Chairman Douglas Howe said.

The ISO recently lowered the proposed multiplier for the first 18 months to 150% from 200%, in an “abundance of caution,” Market Design Manager Brad Cooper said, calling the bid cap a “circuit breaker.” The proposal also allows suppliers to seek adjustments to their reference levels based on changes in documented costs.

“We believe that we have a robust design, but we agree we need to proceed cautiously with changes,” Cooper said during a presentation to the Governing Body.

Respectful Disagreement

DMM Director Eric Hildebrandt supported the proposal, saying “the basic framework is there.” But he recommended a few changes, saying there are some gaps, a potential for economic withholding and for a “kind of gaming.” (See Monitor Critical of CAISO Commitment Cost Mitigation Plan.)

“We have looked at it, and we respectfully disagree,” Casey responded, adding that some power suppliers are “sort of biting their tongue” on the arrangement for the first 18 months. An automatic change at the 18-month point provides certainty that the ISO is committed to moving to the higher cap, he said, adding that CAISO can always file with FERC to keep the level at 150% if it discovers issues.

Howe said the EIM’s decision “is trying to carve a middle road,” but he didn’t think CAISO should “back into” a second stakeholder process that would “allow everybody to have a second bite” at things they didn’t like.

Body member John Prescott said, “I support this, and I would advise the Board of Governors to support this as well.” He said he expects the DMM to make sure issues don’t materialize.

Representing the Western Power Trading Forum, Carrie Bentley of Resoro Consulting told RTO Insider that the parties most affected by the change will be EIM entities or others who have experienced challenges with CAISO calculating their proxy costs, and generators and scheduling coordinators impacted by high gas prices.

She said that while WPTF supports the proposal, she called CAISO’s changing the reference level late in the proceeding “an unfortunate circumstance of panic policymaking in response to a few influential stakeholders. The CAISO had an excellent proposal, and it would have been better if they just remained confident in it.”