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December 25, 2024

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MISO Foresees Manageable 2018/19 Winter

By Amanda Durish Cook

CARMEL, Ind. — While MISO expects to have ample resources on hand to manage what should be a warmer-than-normal winter, it is still preparing for the possibility of entering emergency procedures.

The RTO is forecasting a 103-GW peak this winter, 6 GW short of the all-time winter record of 109 GW, set Jan. 6, 2014, during the polar vortex. With 140 GW in total available capacity to meet demand, the RTO foresees having a 36% systemwide reserve margin this winter, more than double the current annual level.

Rob Benbow | RTO Insider

But Executive Director of Energy Rob Benbow told an Oct. 29 winter readiness workshop that MISO is preparing for the possibility of extreme winter conditions and estimates a 40% probability of having to call on load-modifying resources (LMRs) at least one time during the season.

“While we project ample resources under normal operating conditions, MISO is also prepared to proactively manage potential challenges created by periods of extreme weather, generation and transmission outages and other developments,” Benbow said.

MISO’s most probable operating scenario shows about 25.1 GW of outages with 18.8 GW in reserves. But in a high load and extreme outage scenario, outages could reach 38.6 GW, resulting in an almost 2-GW shortfall in reserves.

Resource Adequacy Coordination Engineer Eric Rodriguez said it’s “critical” that LMR owners update their wintertime availability in MISO’s nonpublic communication system to ensure readiness in the face of above-normal load or outages.

Eric Rodriguez | RTO Insider

“We’re showing a challenging winter if a high-load, high-outage scenario is realized,” Rodriguez said.

MISO’s biannual coordinated seasonal assessment, which simulates stressors on the transmission system, showed no unanticipated thermal, voltage or phase angle issues this winter.

“Our transmission system also looks like it’s in good shape for this winter,” Benbow said.

However, MISO said it could experience delayed injections in the natural gas pipeline system and the region is experiencing the lowest gas storage levels in a decade due to a long cold snap in spring and high summertime demand.

But the RTO also predicts current high gas production will offset the low storage levels this winter, likely keeping prices flat. It also noted two new large pipelines from the Marcellus and Utica basins were placed into service last month and are increasing takeaway capacity.

“We have two new pipelines to offset the storage and we’re looking pretty good heading into winter,” said Trevor Hines, MISO operations communications lead.

More Precautions

This marks the first winter MISO will use its new capacity advisory notification, an intermediary step before declaring a maximum generation alert and used only when all-in capacity is forecast to be less than 5% above operating needs. (See MISO: Sept. Emergency Response Improved by Jan. Event.)

Benbow said MISO has been working through drills and training on emergency purchases with suppliers outside the footprint. MISO has also clarified its emergency operating procedures to ensure public appeals for energy conservation occur before MISO makes emergency energy purchases from external suppliers, a revision some members had advocated.

In response to the Jan. 17 MISO South emergency, MISO and SPP have been collaborating on both emergency protocols and the use of SPP’s contract path linking MISO’s Midwest and South regions, “making sure we understand when they’re having challenging times … and also making sure they understand our [emergency] process,” Benbow said.

“Ever since we’ve got out of the Jan. 17 event, we’ve met with the joint parties and our neighboring reliability coordinators to the South … to work on the management of the regional dispatch transfer,” he said.

5th Waiver

For the fifth straight winter, MISO is seeking a Tariff waiver to allow resources to recover energy costs in excess of the current $1,000/MWh offer cap.

In early October, FERC granted MISO an October 2020 deadline to implement a new $2,000/MWh hard cap for verified cost-based incremental energy offers. MISO said it needed the extra time to work the new offer caps into its fast-start pricing and extended locational marginal price. (See MISO Granted Longer Deadline for Offer Caps.)

MISO market adviser Chuck Hansen said if FERC approves the waiver, generator offers greater than $1,000/MWh will again be subject to the RTO’s verification process.

“They won’t be able to directly submit those offers, but they will be able to recover those costs after the fact through uplift costs,” Hansen said.

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Returning Chair Pledges to Protect FERC’s Independence

By Michael Brooks

WASHINGTON — It was little more than a year ago that FERC Chairman Neil Chatterjee gathered reporters at commission headquarters to assuage worries that Energy Secretary Rick Perry’s recent proposal to compensate coal and nuclear plants would destroy the markets. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)

Much has happened since: Kevin McIntyre took over as chair; the commission unanimously rejected Perry’s proposal; and, last week, McIntyre relinquished the chair back to Chatterjee while staying on as a commissioner.

On Wednesday, Chatterjee once again met with reporters at FERC headquarters, where he struck a more muted, sober tone in explaining the commission’s work under his leadership while McIntyre struggles with what he called a “serious setback” in his battle with a brain tumor. (See McIntyre Steps Down; Chatterjee Named FERC Chair.)

FERC Chairman Neil Chatterjee addresses reporters at commission headquarters in D.C. | © RTO Insider

“Kevin McIntyre is not just my colleague; he is my friend,” Chatterjee said. “I think it is important that he is focusing his energies on his health and his family. This situation is certainly not something I sought, and I most definitely do not relish it. But we have important work to do, and Kevin wants me to be a strong leader for him and for the agency that he cares so deeply about. And I am committed to working with my colleagues to live up to that expectation.”

Chatterjee said he would not discuss McIntyre’s health, saying he wanted to give him and his family privacy. But he spoke extensively about McIntyre’s leadership at the commission, and the influence McIntyre has had on him.

“I thought Chairman McIntyre was exemplary in his leadership,” he said. “I had time to meet with stakeholders, with staff in the building, with my colleagues and folks around the country to learn the importance of the commission’s processes, and culture, and mores, and traditions. And I think the individual who is … most responsible for my growth in this position is Kevin McIntyre. …

“He so emphasized the importance of the rule of the law … of adhering to [the record]; he could not be more strenuous in saying that politics could not be allowed to interfere with the work of the commission. And that has really helped me grow in my role as I made the transition from formerly partisan legislative aide to independent regulator. … I hope to lead in the same way. But I have big, big shoes to fill.”

Resilience and Avoiding Politicization

Chatterjee joined the commission as chair in August 2017, holding it until McIntyre joined later in December.

“The circumstances in which I stepped into the chairman role last time were not ideal,” he said Wednesday. But “quite frankly, they were a dream compared to this circumstance.”

Before being replaced by McIntyre, Chatterjee appeared supportive of Perry’s Notice of Proposed Rulemaking for FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel. The commission unanimously rejected the NOPR in January, opening its own docket to explore grid resilience (AD18-7). (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)

On Wednesday, Chatterjee was asked whether he felt FERC was doing enough on the resilience issue. A former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) and Kentucky native, he again brought up his partisan background.

“Again, this is where my growing into this role has been significant. I first came to the commission last fall, coming from a partisan legislative role in which I worked on behalf of my boss to fight against the retirement of coal-fired generation. Initially I was sympathetic to Secretary Perry’s proposal because of my concern for these rural communities, because of my concern about what the retirement of nuclear units might mean for mitigating carbon emissions.

“But as I evolved into the role, I realized that that is not part of our record. That doesn’t factor into the statutes that govern us. And I had to make a decision on the DOE NOPR based on the record that was before us. I have been thus far satisfied with the record that is being formed since we opened that new docket in January. And I’m going to review that docket and see what could the facts bear out. …

“So, it’s premature for me to say we’re doing enough or we’re not doing enough until I’ve really had the opportunity to work with my colleagues and analyze that record. … This will not be a politically influenced decision.”

Chief of Staff

Chatterjee said he had not given any thought to personnel changes. “In light of the difficult circumstances in which this transition is occurring, I think it is important for all stakeholders of the commission, as well as us inside the commission, that we have some continuity moving forward.”

Chatterjee praised Chief of Staff Anthony Pugliese. “There [are] tremendous administrative responsibilities in the chairman’s office, and as someone who has been a commissioner for the past year, from what I’ve seen, Anthony has managed the administrative capabilities of the agency very well.”

Speaking at the Energy Bar Association’s Mid-Year Energy Forum on Tuesday, however, Commissioner Richard Glick said Pugliese’s appearance in July on the conservative “Breitbart Radio Show” was “ill-advised.” (See Democrats Call Out ‘Partisan’ Remarks by FERC Chief.)

“To go on various radio shows and make attacks against the governor of New York and then to … take certain positions that were more in line with … the administration than the commissioners I think is not a wise strategy,” Glick said. “I’ve had this conversation with the chief of staff; I’m sure others have as well. And I’m hoping that we won’t see that anymore. I thinks it’s very important that we demonstrate that we truly are independent and that we’re acting on what we think is in the best interest [of the public and] … make sure that we’re not either doing the [bidding] of the Trump administration, or … [House Minority] Leader [Nancy] Pelosi [D-Calif].”

“I agree completely with Commissioner Glick that we should be separate and apart from any political influence on either side,” Chatterjee said Wednesday. “No one was more committed to ensuring the depoliticization of the agency and not allowing political interference than Kevin McIntyre. And I think that if you look at the record under Chairman McIntyre’s leadership, there’s no evidence that there’s been political influence or interference at the agency. … And I’ve made very clear to all of the staff at the agency, including the chief of staff, that the agency’s independence from political influence will continue.”

The chair downplayed recent 3-2 rulings by the commission on natural gas pipeline certificates, in which Glick and Commissioner Cheryl LaFleur have insisted the commission’s analyses include consideration of downstream greenhouse gas emissions.

“While much has been made of the fact that we’ve been having 3-2 votes and it appears to be political, I think there’s some genuine disagreements on policy, but my colleagues have been narrow and discreet in their dissents. And I view that as an opportunity to build consensus.”

He said he wasn’t concerned about 2-2 ties since the departure of Commissioner Robert Powelson in August. He also noted that in his resignation letter to President Trump, McIntyre said he felt he could fulfill his duties as commissioner. “I expect he will do that,” Chatterjee said. “In terms of votes that he will cast, that is entirely his determination and decision. … I am not empowered to deny him his vote.”

Going Forward

Chatterjee said his priorities as chairman will be the same as they were when he was a commissioner. He listed the reliability and resilience of the grid, processing LNG facility applications, breaking down barriers to entry for new technology, and cybersecurity, the last of which “continues to be foremost on my mind.”

He declined to give a timeline on the commission’s resilience proceeding, nor on its work on updating its policy statement on pipeline certificates.

Asked what he thought could accomplish before the end of the year, he half-jokingly said, “I think my first and most significant priority that I know I have the support of my colleagues on — but I’m not sure whether I’ll be able to achieve it — is to fix eLibrary.”

Earlier this month, Trump nominated Bernard McNamee, DOE executive director of the Office of Policy, to the commission. Chatterjee said the commission’s work would proceed without regard for McNamee’s confirmation process. That includes a disregard for the date of McNamee’s hearing before the Senate Energy and Natural Resources Committee: He seemed unaware that it had been scheduled for Nov. 15, the same as the commission’s next open meeting.

“There’s so much on the commission’s plate right now that we need to take action on.”

Based on his career as McConnell’s aide and his own nomination, he said he knew that the road to confirmation “is an unpredictable one.”

Rich Heidorn Jr. contributed to this report.

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NY Task Force Talks LBMPc, Residuals, Hedge Effects

By Michael Kuser

RENSSELAER, N.Y. — NYISO on Monday floated a plan to calculate the carbon pricing impact on locational-based marginal prices (LBMPc) using the social cost of carbon (SCC) as determined by the New York Public Service Commission, while also altering its recommendation for allocating carbon charge residuals.

Both proposals came up as part of New York’s ongoing effort to explore how to incorporate carbon pricing into the state’s wholesale electricity market through the multi-agency Integrating Public Policy Task Force (IPPTF).

A post-carbon pricing project with a hedge must pay the LBMP with carbon despite the carbon having been removed. | Calpine

Ethan D. Avallone, ISO senior market design specialist, told the IPPTF that the market would generally use the net SCC to determine the carbon reference level for a CO2-emitting generator that functions as the marginal resource.

While the grid operator needs to calculate the LBMPc in order to allocate carbon credits to load-serving entities, most internal generators would not be charged the LBMPc, instead being charged for their actual emissions.

The NYISO straw proposal envisions including carbon pricing in the market using the existing offer structure, Avallone said. During intervals when there are too few marginal resources to calculate LBMPc, the ISO proposes “to persist” the last carbon impact to the LBMP from the prior interval.

IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said, “In practice, we back into the marginal units by looking at whether resources have their offer equal to the LBMP at their location. Given that, when the demand curves are active, we can’t use that method to back into what resources are marginal.”

Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said that while that approach seems most convenient, it “would have pretty significant implications and you would get very different results from what was presented in the consumer impact studies on this.”

One reason is that hydro units are on the margin nearly 50% of the time in New York, which eventually reflects an energy storage problem, LeeVanSchaick said. “If you back down hydro in one hour, you’re going to get more hydro in another hour, which is likely to reduce output from a carbon-emitting generator.”

“The idea generally is that if you do have to use the next unit on the margin, that’s a change,” Avallone said. “So we’ll take that back and think about it.”

“I’m glad you’re taking it back,” said Warren Myers, director of market and regulatory economics for the state’s Department of Public Service. “This has always been a really big issue conceptually for us — what you do about the storage hydro that’s limited over the course of a year. We know that in a given hour it does not have zero carbon consequences. If it ramps up or down, it affects the carbon in other hours.

“It’s not a trivial implementation, in-the-weeds issue. It’s a big deal.

“With respect to the harmonizing with state policy,” Myers continued, “whenever DPS has tried to figure out what the [carbon] content on the margin is, we do not treat these hours as if they’re zero carbon. We try to somehow, heuristically or however … treat these resources as if they’re combined cycle gas units.”

LeeVanSchaick said the MMU takes a similar view of the opportunity costs for hydro units. He recommended the ISO “consider alternatives to just using the real-time market software’s flags” to determine which fuel is on the margin. He also recommended the ISO address what principles and objectives it seeks to achieve with the method to help evaluate its success in doing so.

Allocating Residuals

As part of the state’s evolving plan to price greenhouse gas emissions, a carbon charge would also be applied to most wholesale market suppliers holding renewable energy credit contracts with the New York State Energy Research and Development Authority. (See NY Carbon Task Force Looks at REC, EAS Impacts.)

For the carbon charge residual that results from charging suppliers for their carbon emissions, NYISO now recommends a proportional allocation approach, saying it would provide an equitable impact to consumers consistent with the current REC contract cost allocation to load, Avallone said.

NYISO originally proposed a levelizing approach but revised its recommendation based on recent analysis, Avallone said. It considered that there was a higher percentage impact to upstate load relative to downstate load under levelizing methodology compared with the proportional percentage allocation.

At the Sept. 24 IPPTF meeting, the Brattle Group provided a comparison of the carbon residual allocation options as part of the carbon pricing consumer impact analysis. That analysis showed that the proportional allocation methodology minimizes cost shifts among consumers, Avallone said. Allocation would not affect revenues to generators, who would receive the LBMP, inclusive of the carbon impact.

Considering dynamic effects, the proportional allocation methodology provides the most levelized allocation of carbon residuals. | NYISO

Hedge Effects

Brett Kruse, Calpine’s vice president for governmental and regulatory affairs, told the task force how NYISO’s proposed “clawback” of the carbon price from the LBMP provided to resources with REC contracts might affect lender-required financial hedges required for renewable generation financing.

“As proposed by NYISO, removing carbon prices from LBMP of some contracted generation is very disadvantageous to those of us with hedges in place,” Kruse said.

Under NYISO’s current proposal, the power produced by a unit with REC contracts would be settled at the LBMP net of the carbon charge (that is, after the clawback), but energy hedges would be settled at the actual LBMP, reducing the unit’s revenues.

Calpine proposes applying a discount that modifies the carbon price to account for the estimated carbon emission savings from existing RECs. The company argued that a discount to the SCC that decreases as REC contracts roll off could integrate the beneficial impacts of RECs and carbon pricing without disrupting commercial hedging practices needed by most renewable energy projects.

“The way these hedges work, and this is quite typical even if you’re not talking wind generation, is they sell at the hub,” Kruse said. “Because of the liquidity value at the hub, they don’t settle at the individual generator node. The banks … don’t want to write a hedge that settles at your node.”

The most popular type of hedge is a fixed-for-floating price swap, where a project company receives a pre-agreed fixed dollar-per-megawatt-hour price from a bank, and the project pays the bank the underlying LBMP, which ensures a certain amount of energy revenue for the project, he said.

While the New York Power Authority buys both RECs and power, NYSERDA just purchases the RECs, “so in today’s world, it’s not the late 90s where you had a lot of financing. … The markets started to unbundle … and the banks are very skittish about who they give their money to,” Kruse said.

There are only one or two companies with a large regulated business at their core who do renewables on the side that have big enough balance sheets to finance their own projects. “The rest of us cannot, so we have to get financing for the whole thing, and as a result, the financing requires us to get the hedge on the power side,” Kruse said.

Daymark Analysis Update

Marc Montalvo of Daymark Energy Advisors said his “massive slide deck” of an analysis on the carbon pricing scheme, updated from last month, has as its major theme “humility in the face of complexity.”

“This proposal adds more than a small wrinkle to the marketplace,” Montalvo said. “How we get it implemented matters an awful lot.”

Brattle took a no-arbitrage model with fairly low friction and fairly low transaction costs and estimated net benefits to consumers, he said.

“What I wanted to understand is what happens if you perturb those things?” Montalvo said. “What happens if there is friction, what happens if there are actually higher transaction costs? What happens if the implementation and the consequent behaviors that underlie the no-arbitrage premise don’t hold up?”

Daymark’s perturbed model, particularly regarding border charges, increases market volatility, with asymmetric results, “which means things tend to be worse, not better,” Montalvo said. Similarly, charges on internal resources “and the way the carbon charges are estimated and calculated really does matter.”

The analysis also found that the carbon charges proposed are not sufficient to motivate the volume of buildout being sought under the state’s Clean Energy Standard without further public policy action.

“You don’t get 15,000 MW of renewables over the 12-year study period with the carbon charge by itself … [and] a lot of the non-market barriers are not addressed at all by a carbon charge,” Montalvo said.

The task force next meets via teleconference on Nov. 9 to talk about three recent analyses and updates by Brattle, Daymark and Resources for the Future (RFF), and how they interrelate.

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Entergy Share Price Jumps with Solid Quarter

By Tom Kleckner

Entergy reported third-quarter earnings of $536 million ($2.92/share), as compared to $398 million ($2.21/share) a year ago. The New Orleans-based company’s results exceeded analysts’ expectations by 33.2%, with adjusted earnings of $3.77/share, a 94-cent overperformance.

Investors rewarded Entergy by boosting its share price more than $2 following the company’s earnings announcement Wednesday. The company’s stock opened at $82.11, peaked at $84.84 during the day and closed at $83.95.

Entergy’s New Orleans headquarters | Wikimedia Commons

Company executives updated its year-end consolidated operational earnings guidance, from $6.25 to 6.85/share to $6.75 to 7.25/share.

Entergy warned that costs related to the sale or closure of its merchant nuclear plants could cut into as-reported EPS by $2.95/share this year.

CEO Leo Denault told financial analysts during a conference call that the company continues to move away from nuclear power by devoting a “large portion” of its capital expenditures to building large- to medium-sized combined cycle gas turbines. Entergy in August announced a $314 million purchase of GenOn Energy’s Choctaw Generating Station in Mississippi, an 810-MW gas-fired unit.

Denault said he is “hopeful” Vermont Yankee’s sale to NorthStar Decommissioning Holdings will be approved by Vermont regulators by year-end. The Nuclear Regulatory Commission has approved the transfer of the nuclear plant’s license to NorthStar.

Choctaw Generating Station | Entergy

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SPP Regional State Committee Briefs: Oct. 29, 2018

By Tom Kleckner

Changing of the RSC’s Guard

LITTLE ROCK, Ark. — SPP’s Regional State Committee on Monday elected a 2019 slate of officers that includes Arkansas Public Service Commissioner Kim O’Guinn as its president.

Scott Rupp (Missouri) and incoming RSC President Kim O’Guinn (Arkansas) listen to the discussion. | © RTO Insider

The committee also said goodbye to New Mexico Public Regulation Commissioner Pat Lyons, who has served on the committee since his election to the PRC in 2010.

Lyons is term limited; however, he is running to regain his old job as New Mexico’s Commissioner of Public Lands, which he also held for eight years. A Republican and a 10-year state senator, he is in a tight race with Democrat Stephanie Garcia Richard.

New Mexico Commissioner Pat Lyons enjoys his last RSC meeting | © RTO Insider

“It’s been a pleasure,” said Lyons, the RSC’s longest tenured member. “I know everyone in this room cares for the affordability and reliability of electric services, and that’s what we’re about. Thank you for helping the consumer.”

Dana Murphy, chair of the Oklahoma Corporation Commission, paid tribute to Lyons and SPP Directors Jim Eckelberger and Harry Skilton, who are also stepping down from their positions. Fighting back her emotions, Murphy noted SPP staff members “no longer with us” and RSC members campaigning to retain their positions.

Murphy lost a runoff in August for the Republican nomination for Oklahoma’s lieutenant governor. After taking 45.8% of the vote in the GOP primary, she lost the runoff by more than 16 points. (See Okla. Commissioner Murphy Loses Runoff for Lt. Governor.)

“Some of you are wondering if it hurts to lose. It does,” said Murphy, who was credited with running a positive campaign. “I would rather lose with honor, than win without.”

Also elected as RSC officers were Nebraska Power Review Board Member Dennis Grennan as vice president and South Dakota Public Utilities Commissioner Kristie Fiegen as secretary. Their terms, and O’Guinn’s, begin Jan. 1.

SPP, MISO Regulators to Meet Nov. 11 at NARUC

The RSC issued its approval of goals and guiding principles brought forward by state regulators hoping to improve market coordination and seams issues between SPP and MISO.

A liaison committee comprising regulators from both the RSC and MISO’s Organization of MISO States will hold a public meeting Nov. 11 in Orlando, Fla., coinciding with the National Association of Regulatory Utility Commissioners’ annual meeting.

The committee has asked SPP and MISO to present white papers “identifying barriers to more efficient seams operations and transmission planning” and offer solutions. Those papers will be discussed Nov. 11.

The group’s goals are to:

  • Increase benefits to ratepayers in both markets by improving market-based transactions and operations across the seam;
  • Ensure equal consideration of beneficial regional and interregional projects in transmission planning, including evaluation of projects identified in the coordinated system plans;
  • Support the timely interconnection of new resources that includes consideration of the dynamics of both RTOs’ interconnection queues; and
  • Improve inter-RTO relations through state-led cooperation.

The OMS approved the goals and principles during its Oct. 25 annual meeting.

Dennis Grennan (Nebraska) and RSC President Shari Feist Albrecht (Kansas) share a laugh. | © RTO Insider

The two committees agreed this summer to work together in the hopes of helping resolve issues SPP and MISO haven’t. The task force is seen as increasing benefits to ratepayers in both markets and ensuring equal consideration of beneficial interregional projects. (See “RSC, OMS to Take Crack at Interregional Issues,” SPP Regional State Committee Briefs: July 30, 2018.)

The liaison committee includes Louisiana’s Lambert Boissiere, North Dakota’s Julie Fedorchak, Missouri’s Daniel Hall and Minnesota’s Matt Schuerger from OMS; and Kansas’ Shari Feist Albrecht, South Dakota’s Fiegen, Arkansas’ O’Guinn and Texas’ DeAnn Walker from the RSC. Iowa’s Nick Wagner, NARUC’s president-elect, serves as an ex officio member.

CAWG Addressing Cost Allocation in Wind-rich Areas

The Cost Allocation Working Group told the committee that work continues on a white paper reviewing cost allocation in wind-rich areas and determining whether changes are necessary, an issue raised by Sunflower Electric Power earlier this year. (See “Committee Takes on Cost Allocation Issues,” Mountain West, Cost Allocation Top SPP RSC Concerns.)

John Krajewski, who represents the Nebraska PRB, said the group developing the paper is analyzing rate design options that will meet FERC’s definition of “just and reasonable” rates, but that also reflect cost-causation principles.

“We want something that’s easy to explain to stakeholders and FERC, and something that is easy to administer,” Krajewski said. ”We don’t want six different vendors and five years of back billing.”

The paper is due by the RSC’s April 2019 meeting.

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Texas PUC Briefs: Week of Oct. 27, 2018

By Tom Kleckner

ERCOT Re-evaluating Costly CenterPoint 345-kV Project

AUSTIN, Texas — ERCOT told the Texas Public Utility Commission last week that it will produce “higher quality estimates” for a major transmission project that raised the commissioners’ eyebrows with its escalating costs.

The Texas PUC’s Oct. 25 open meeting | © RTO Insider

Warren Lasher, the grid operator’s senior director of system planning, said during the PUC’s Oct. 25 open meeting that staff are refining its previous studies and analyzing alternatives to CenterPoint Energy’s proposed 345-kV line project in the industrial Freeport area south of Houston.

CenterPoint’s application for a certificate of convenience and necessity included 30 alternative routes, ranging from 53 to 84 miles in length and $481.7 million to $695.2 million in costs (Project No. 48629). ERCOT’s initial study indicated a project cost of $246.7 million, leading the commission in September to direct the grid operator to take a second look at its analysis. (See PUCT Urges 2nd Look at Freeport Project Costs.)

“We’re going to have to spend some quality time thinking through our confidence … in the cost estimates we have for the alternatives that are different from the ones we presented,” Lasher told the commissioners. “We’ll do our best to provide as good an information set as we can back to the commission.”

Commissioner Arthur D’Andrea questions ERCOT’s Warren Lasher (2nd from right). | © RTO Insider

Lasher said ERCOT is considering upgrading existing infrastructure as one alternative, which was rejected in the first study because it would create congestion “and the cost associated with congestion,” he said.

The commissioners agreed to wait on the analysis before issuing a preliminary order. Lasher said staff would need no more than three months to complete its work.

Hearing Set for Golden Spread Tx Cost of Service Case

The commission consented to a procedural schedule that sets a hearing for Golden Spread Electric Cooperative’s petition to reduce its transmission cost of service (TCOS) and wholesale transmission service rate (Docket 48500).

The PUC set a Dec. 21 discovery deadline, with a hearing scheduled Jan. 29-30 at the State Office of Administrative Hearings.

Golden Spread in June requested an annual TCOS of $2.42 million and an annual wholesale transmission rate of 3.6043 cents/kW-year to reflect the recent acquisition of transmission assets from Taylor Electric Cooperative.

Golden Spread’s last TCOS case, in 2011, resulted in an ERCOT transmission rate base of $2.54 million and a TCOS revenue requirement of $853,063.

PUC Passes Measure Modifying Energy Efficiency Savings

The PUC approved new “deemed savings” estimates for several utilities’ energy efficiency measures, which it said will “encourage additional energy efficiency projects” in the commercial and residential sectors and reduce the offerings’ expenses (Docket 48265).

The proposed calculations will serve as guidelines for estimating savings associated with the installation of program energy efficiency measures. The savings will be used to determine the incentive payments made to energy efficiency service providers.

The order applies to nonresidential door air infiltration and door gaskets for walk-in coolers and freezers, and for residential Energy Star-connected thermostats.

AEP Texas, CenterPoint Energy Houston Electric, El Paso Electric, Entergy Texas, Oncor, Southwestern Electric Power Co., Southwestern Public Service and Texas-New Mexico Power filed the request together.

MidAmerican Wind Increases Holdings to 2.7 GW

MidAmerican Wind has gained equity shares in a pair of wind farms, Blue Cloud Wind Energy’s facility near the Texas Panhandle (Docket 48386) and the Tahoka Wind Project near Lubbock (Docket 48429).

The PUC approved the transfer of undisclosed equity interests from the wind farms’ holding companies to MidAmerican Wind Tax Equity Holdings. MidAmerican owns 2.7 GW of installed generation capacity in ERCOT either directly or indirectly through affiliates or subsidiaries.

Blue Cloud will maintain a managing interest in its 148.35-MW project, which will interconnect with SPP through SPS’ transmission facilities. The 300-MW Tahoka project will connect with ERCOT through Sharyland Utilities.

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PJM Regulation Rule Endorsed Despite Criticism

By Rory D. Sweeney

WILMINGTON, Del. — PJM stakeholders last week endorsed a new rule that is likely to fuel consternation among owners of energy storage participating in the RTO’s regulation market. (See “Regulation,” PJM Operating Committee Briefs: Oct. 9, 2018.)

The rule approved by the Markets and Reliability and Members committees would effectively lower the amount of storage that can clear in the market’s hourly auctions. PJM proposed the change along with a problem statement and issue charge focused on the issue.

PJM’s performance-based regulation market, which went into effect in October 2012, splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units like batteries that operate for shorter periods. It also developed a “benefits factor” to compare the value of the two types of resources through a ratio.

In December 2015, the benefits factor was floored at 1, meaning that a megawatt of RegD would never be valued less than a megawatt of RegA. Staff then modified the regulation signal in January 2017 and removed the benefits factor floor entirely in August 2018 “based on operational analysis.” A proposal developed by PJM and its Independent Market Monitor that was endorsed by stakeholders in June 2017 would have implemented use of a “marginal rate of technical substitution” instead of the benefits factor, but FERC rejected the filing as unreasonably discriminatory against storage resources. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)

PJM’s Lisa Morelli | © RTO Insider

With the benefits factor allowed to fall to zero, more megawatts of RegD would need to be substituted for each megawatt of RegA, but the resulting values create unintended price spikes. Staff explained that where the benefits factor fits into the pricing formulas, a situation can develop where “minimally effective resources” clear the hour-ahead auction with a $0/MWh offer price. When they operate, however, their adjusted lost opportunity cost (LOC), which is based on the current LMP when accounts are settled every five minutes, can “drastically increase” the clearing price, PJM’s Lisa Morelli said. Staff have seen the math result in clearing prices as high as $10,000/MWh, and there were 80 five-minute intervals between May and August when the clearing price rose above $500, she said.

PJM’s solution would reinstate a benefits factor floor of 0.1 so that the ratio would be limited to 10 MW of RegD to provide 1 MW of RegA and prevent extreme LOC escalations. Staff said the 0.1 floor would have impacted 264 hours, 2.58% of the total hours, between August 2017 and September 2018.

Gabel Associates’ Travis Stewart criticized the proposal for limiting the ability for storage resources to participate in the market by putting a floor on the replacement ratio. He said his storage-owning clients are willing to discuss ways to correct the issue that don’t limit the resources’ market access.

“This solution, I don’t really know that it gets us where PJM really wants to go,” he said.

“That revenue is a very important for some resources,” Dayton Power and Light’s John Horstmann said. “They’re kind of on the edge because of other changes PJM has made” in the market.

Gabel Associates’ Travis Stewart | © RTO Insider

Susan Bruce, who represents the PJM Industrial Customer Coalition, strongly supported the measure to address unintended “aberrant and costly results.”

Both arguments seemed to resonate with Direct Energy’s Marji Philips.

“I’m not trying to drive to price outcome here; I’m trying to drive to what is best for the market,” she said, noting there is an ongoing effort in PJM’s Energy Price Formation Senior Task Force to support inflexible units and that batteries provide a “counter” to that. “I’m trying to vote the right way here, which is sort of balancing letting the right technology in versus getting the markets right.”

“It looks to me like we’re fixing the low-hanging fruit of a much larger problem,” Calpine’s David “Scarp” Scarpignato observed.

“I would agree with you,” Morelli said. “We recognize that there are some flaws in the regulation market design.”

“The underlying issues are the same that we have been discussing for over a year, so they’ve been known for a while. The effects on market prices became more common after the issues were first discussed in the stakeholder process. Changes in offer behavior can increase the frequency of inefficient high prices,” the Monitor’s Catherine Tyler said.

Morelli said fixing the problem “in a holistic manner” would require reopening the Regulation Market Issues Senior Task Force, which “given that process took well over a year, I don’t expect that that will come to a speedy conclusion.”

Instead, PJM hopes to implement the “narrowly targeted” proposal to “address this very narrow piece of the puzzle as a stop-gap measure” and then return to the issue “early next year” to resolve the issues in a way that addresses FERC’s reasons for rejecting the first attempt, she said. The change wouldn’t be implemented until FERC approves it and the ongoing settlement that resulted from the rejection is completed.

Some stakeholders questioned whether the proposal encroached on issues being addressed in the settlement proceedings, but PJM’s Stu Bresler didn’t see a “direct conflict in any way shape or form” between the two.

Horstmann suggested deferring the vote until the Dec. 6 MRC meeting to allow PJM time to quantify the market revenue impact of the proposed change and to allow more storage resources to participate in the discussion, which Philips seconded. However, PJM staff and Dominion Energy’s Jim Davis objected to a delay.

“We would like to see a vote today on the issue,” he said.

The deferral motion failed with 1.87 in support in a sector-weighted vote that had a 3.34 threshold for adoption.

An acclamation vote approved the problem statement and issue charge with one opposed and one abstention. Endorsement of the stop-gap proposal passed with 4.09 in favor in a sector-weighted vote that also had a 3.34 approval threshold. The proposal was also subsequently approved in the MC by acclamation with four opposed and two abstentions.

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MISO Members Uneasy over Board Nomination

By Amanda Durish Cook

MISO members uneasy about the nomination of Minnesota Public Utilities Commission Chair Nancy Lange to the RTO’s Board of Directors raised concerns last week about a sitting commissioner being appointed to the oversight body.

MISO
Minnesota PUC Chair Nancy Lange was nominated to the MISO Board of Directors | RTO Insider

MISO’s Principles of Corporate Governance require new directors to observe a one-year moratorium between their involvement with member companies and their election to the post. The bylaws state that a “director shall not be, and shall not have been at any time within one year prior to their election to the board either a director, officer or employee of a member, user or an affiliate of a member or user.”

While stakeholders say that Lange’s appointment would not explicitly violate the RTO’s bylaws, they pointed out during an Oct. 24 Advisory Committee conference call that Lange would have made decisions about the grid on behalf of Minnesota customers and utilities up until her election.

While a sitting commissioner is not considered either a member or a user, some sector representatives contend that Lange’s role as a regulator in a state within the MISO footprint warrants further discussion.

Lange’s term on the Minnesota PUC expires Jan. 7. MISO Senior Vice President of Compliance Services Stephen Kozey said that upon her election to the the RTO’s board, Lange would immediately resign her PUC position to avoid overlap between positions.

‘A Flare’

Members have been quick to point out that nominating a sitting member of a MISO state regulatory commission does not explicitly violate the RTO’s independence guidelines. Several also stress they are not concerned about Lange in particular.

But they do say that the situation falls into a gray area and that MISO should consider subjecting regulators to the same downtime requirement as industry officials. Multiple sector representatives, including the Independent Power Producers, Transmission-Dependent Utilities, Transmission Owners, Power Marketers and the non-voting Environmental sector voiced apprehension during the call.

Independent Power Producers sector representative Mark Volpe told RTO Insider that Lange has been “influencing and voting and making decisions” on behalf of MISO members and users in her state. He said although the nomination doesn’t breach the RTO’s bylaws, it “sends up a flare” about “the spirit of the rules and what it means to be independent.” He said the concern was “flagged by a number of IPP sector companies.”

Voting on Lange’s appointment is already underway, with polls open until Nov. 2. Incumbent board members Phyllis Currie and Mark Johnson are also on the ballot. MISO’s Nominating Committee last month decided the slate of candidates. (See MISO Board of Directors Briefs: Sept. 20, 2018.)

MISO rules require board candidates to capture a simple majority of a quorum of voting members, which currently stands at 35.

Board candidates are rarely rejected, the last instance being in the early 2000s when two incumbents were voted out. Although MISO has had former state commissioners on its board (Judy Walsh of Texas and the late Paul Hanaway of Rhode Island), the RTO has never appointed either a sitting commissioner or one from a MISO state.

MISO’s rotating Nominating Committee this year consists of board members Thomas Rainwater, Baljit Dail and Barbara Krumsiek, and RTO member representatives Megan Wisersky of Madison Gas and Electric and Commissioner Daniel Hall of the Missouri Public Service Commission.

Wisersky acknowledged the concerns in a statement to RTO Insider.

“Although the Nominating Committee followed the process correctly, many members of the Advisory Committee expressed concerns with the board nominating process itself,” she said. “They have specific concerns with the lack of a ‘cooling-off period’ for commissioners from states in the MISO footprint. Other potential board candidates, if they work for an organization that is a MISO member, do business with an organization that is a MISO member, or do business with MISO itself, must have a one-year separation from those businesses before they are eligible to run for a seat on the MISO board. State commissioners have no such requirement. These MISO stakeholders think this is inappropriate and would like to explore potential changes to the nominating rules.”

By the Book

MISO says the nomination process for the current election followed all current governance procedures.

“MISO leadership and its Board of Directors have received feedback from members that they were surprised to see a currently sitting commissioner within the MISO footprint nominated for a seat on the board. There is a waiting period of one year for potential candidates from within the industry, but that time restriction does not apply to members of state regulatory bodies,” MISO Senior Director of Stakeholder Affairs and Communications Shawna Lake said in an email. “Several parties have asked that the Corporate Governance & Strategic Planning Committee review and discuss candidate eligibility requirements.

“The questions and concerns to date have been about candidate eligibility generally, not about Commissioner Lange or her qualifications as a potential director,” Lake added.

Lange’s appointment to the board would fill a seat reserved for members with corporate leadership experience. MISO requires that six directors have corporate leadership experience in either board governance, finance, accounting, engineering or utility laws and regulation; another should have transmission system operation experience; another, transmission planning experience; and the final, experience in commercial markets and trading.

The Advisory Committee will take up the issue during its Dec. 6 meeting scheduled as part of MISO Board Week. Some stakeholders are asking that the item be discussed in the committee’s morning session, when the full board is present, as opposed to the afternoon session, when board members usually adjourn to other meetings. Committee leaders said the rotating team of members that determine agendas will decide on the timing of the discussion. In any case, the discussion will come weeks after the Nov. 15 publication of election results at MISO’s Informational Forum. Lake said Kozey will be on hand at the forum to answer clarifying questions about the election process.

Because the Advisory Committee functions strictly in an advisory role to MISO leadership, stakeholders cannot halt or alter the voting process. Multiple stakeholders declined to venture a guess as to the election outcome.

Lake said MISO has in the past adopted multiple Advisory Committee board process recommendations, including expanding the number of board member seats, adopting term limits for directors and adding stakeholder seats on the Nominating Committee.

“The AC has always been a key voice in governance processes. It has been highly effective in the past to offer stakeholder views and advice to the board via the Advisory Committee, transmission owners and Organization of MISO States chairs’ reports to the full board,” Lake said.

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PJM MRC/MC Briefs: Oct. 25, 2018

By Rory D. Sweeney

Summer-only Demand Response

WILMINGTON, Del. — Stakeholders at last week’s PJM Markets & Reliability and Members committees meeting agreed to fast-track a proposal on demand response so it can potentially become effective in time for the deadlines related to the Base Residual Auction for the 2022/23 delivery year, which will be held next August.

The proposal, developed through the Summer-Only Demand Response Senior Task Force, is intended to “better value” summer-only DR by allowing the resources’ value to impact the load forecast as an alternative to participating as a supply-side resource in capacity auctions. To avoid double counting, resources that take the peak-shaving alternative wouldn’t be eligible to participate as either a DR resource or price-responsive demand (PRD) in the same year. (See Plan Would Reduce PJM Capacity Curve Through Peak Shaving.)

PJM’s Markets & Reliability and Members Committees met on Oct. 25, 2018. | © RTO Insider

The proposal received 3.48 in favor in a sector-weighted vote that had a 3.34 endorsement threshold in the MRC. PJM sought and was granted permission to seek approval at the MC on the same day, a request that is usually discouraged. The proposal received 3.69 in favor in another sector-weighted vote with the same threshold. A competing proposal developed by EnerNOC that had also been scheduled for MRC consideration was retracted prior to the meeting.

Carroll | © RTO Insider

PJM’s Rebecca Carroll said the same-day request was made because the necessary changes to the Reliability Assurance Agreement require approval by the Board of Managers, whose next meeting occurs before the next MC. Additional delay would mean the revisions wouldn’t get approved until the board’s February meeting.

The endorsed proposal was developed in conjunction with proposed revisions for measuring PRD, but PJM decided to delay seeking an endorsement on the PRD changes pending the outcome of the vote on the peak-shaving proposal.

Scarpignato | © RTO Insider

Calpine’s David “Scarp” Scarpignato questioned that approach, saying he would have preferred to see them “voted together, if possible,” though he did not motion to defer the peaking-shaving vote.

“My comments are more to the stakeholders to make sure everyone understood that these proposals are meant to be tied together,” he said.

The PRD proposals received a first-read at the MRC and will be considered for endorsement at its Dec. 6 meeting. They address whether PRD should be required to reduce load in the winter like other Capacity Performance resources.

Proxy Fight

Members and staff engaged in a debate within a debate during a vote on revisions to the regulation market when a stakeholder requested time to set up voting as a proxy for another member not in attendance.

Panda Power Funds’ Bob O’Connell challenged the move, saying PJM’s policies require making that announcement by noon the day before the meeting. PJM’s Dave Anders said that requirement was simply meant to give the RTO enough time to make the necessary changes and that it’s traditionally been allowed if possible.

Direct Energy’s Marji Philips challenged that, saying she has experienced situations where she’d been told the proxy can’t be set up in time.

“You need to stop telling people that if that’s not true,” she said. “We [either] have a process or we don’t going forward.”

PJM CFO Suzanne Daugherty, who chairs the MRC, acknowledged the need for predictability.

“We do want to always give consistent feedback on the procedures,” she said.

Anders announced the issue was resolved when the market participant joined the meeting to vote without the proxy.

Day-ahead Market Timeline

Stakeholders also supported fast-tracking a proposal that would allow more time each morning to submit day-ahead bids and offers. Thanks to improved computing power, staff are able to push back the submission deadline from 10:30 a.m. to 11 a.m., PJM’s Tim Horger said.

While the proposal was only scheduled for a first read, Old Dominion Electric Cooperative’s Adrien Ford motioned for a vote on it, prompting Philips to voice concern that rules were once again being subverted. Ford acknowledged the point, saying she wouldn’t have made the proposal other than for the benefit of timing. It was also approved in the MC as part of its consent agenda.

Staff also agreed to seek expedited approval from FERC.

“PJM has heard loud and clear that the membership would like to have this implemented as soon as possible,” PJM’s Stu Bresler said.

Opportunity Cost Calculator Vote Deferred

A faceoff between PJM and its Independent Market Monitor about whose opportunity cost calculator reigns supreme might be ending amicably and without FERC involvement.

The situation escalated in August after stakeholders threatened to push through Operating Agreement changes if PJM held on to a recently enacted policy of not accepting the Monitor’s calculator in determining generators’ cost-based energy offers. The threat incentivized PJM and the Monitor to work toward a deal (See “PJM, Monitor Come to Agreement on Opportunity Cost Calculator,” PJM MRC/MC Briefs: Sept. 27, 2018.)

pjm price formation
Tyler | © RTO Insider

Prior to the MC vote on the OA changes, Bresler thanked the Monitor’s staff for providing “an extensive review” of how its calculator works and explained that the cooperation has allowed PJM to find a way to work within its existing policies to approve using the Monitor’s calculator.

“We are in a good place now as to how the two calculators can coexist,” he said.

The announcement satisfied O’Connell, who initiated the stakeholder threat, and he motioned to postpone the scheduled vote on the OA changes until the Jan. 24 MC meeting. The motion was approved.

“It’s my preference that we don’t amend the OA unless we absolutely have to,” he said.

The Monitor’s Catherine Tyler cautioned that the idea shouldn’t be taken off the table completely. The IMM has proposed alternative revisions to address the issue, as has PJM.

Market Seller Offer Cap Balancing Ratio

By the slimmest of margins, the MC declined endorsement of proposed Tariff revisions that would change how PJM estimates the expected future balancing ratio used in the default market seller offer cap.

The proposed method would take the average balancing ratios during the three delivery years that immediately precede the BRA using actual balancing ratios calculated during RTO performance assessment intervals (PAIs) of the delivery years, along with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI for any preceding delivery year with less than 360 intervals (30 hours) of RTO PAIs. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: July 11, 2018.)

“We’re in a spot where we’re not comfortable supporting this proposal,” said Susan Bruce, who represents the PJM Industrial Customer Coalition. Greg Poulos, executive director of the Consumer Advocates of the PJM States, said many of his members also can’t support it.

grid resilience andy ott pjm fuel diversity
Ott | © RTO Insider

The measure received 3.3 in favor in a sector-weighted vote, short of the necessary 3.34. Bresler said the existing process can be used because there are PAIs from this year, which range between 80 and 90%.

“We have reviewed this with legal and the Tariff does not say anything about the scope or the region over which [the PAI] occurred,” he said. The two PAI incidents earlier this year were very localized. (See 2nd Load Shed of PJM’s CP Era Follows Closely on 1st.)

While the proposal would have been a better approach, staff believe they fulfilled the required investigation of the issue, Bresler said.

“We think we’re good,” PJM CEO Andy Ott said.

The Monitor, however, might not be as satisfied.

“We may circle back. We have concerns about using those [PAIs],” Tyler said.

Super Forum

Members endorsed a proposed problem statement and issue charge related to potential enhancements to the stakeholder process developed in response to feedback gathered in the Stakeholder Process Super Forum held on July 25, 2018. (See Poll: PJM Stakeholder Process Imperfect, Necessary.)

The approval included a friendly amendment to the problem statement suggested by Duquesne Light’s Tonja Wicks that an additional pathway “or pathways” need to be developed for vetting issues that are contentious or must be decided quickly. Action on the plan is set to start on Jan. 1.

Nominating Committee Recommendations

Members approved nominees for the 2018/19 class of the Nominating Committee. They include: Pat McCullar of the Delaware Municipal Electric Corp. for the Electric Distributor sector; Kristin Munsch of the Illinois Citizen Utility Board for the End Use Customer sector; Scarp for the Generation Owner sector; DC Energy’s Bruce Bleiweis for the Other Supplier sector; and John Horstmann of Dayton Power & Light for the Transmission Owner sector.

Stakeholders Approve Variety of Actions

Stakeholders endorsed by acclamation several manual revisions and other operational changes:

  • Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). Revisions developed to clarify the process for considering external bulk electric system facilities for modeling.
  • Manual 13: Emergency Operations. Revisions developed as part of PJM’s comprehensive security-threat review.
  • Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product designed to address overlapping congestion for units pseudo-tied out of PJM.
  • Manual 28: Operating Agreement Accounting. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product for units that are pseudo-tied out of PJM.
  • RPM Credit Requirement Reduction Clarifications: Tariff language to remove an apparent overlapping credit reduction provision for qualified transmission upgrades, to clarify milestone documentation requirements for internally financed projects and to clarify that capacity market sellers should submit requests for reductions..
  • Transmission Constraint Penalty Factors: Joint PJM-Monitor package developed at the special Market Implementation Committee sessions related to transmission constraint penalty factors and draft Manual 11 and Manual 33 revisions, as well as OA and Tariff language. It was also approved in the MC as part of the consent agenda. (See “Transmission Constraint Relaxation Removed,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)
  • FERC Order 831 – Offer Caps: Manual 11 language that describes the long-term automated process for price-based offers greater than $1,000/MWh. There were seven objections from consumer advocates. (See “Automating Offer Confirmation,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)
  • 2018 Reserve Requirements Study Results: The results recommended a 15.7% installed reserve margin and a 1.0887 forced pool requirement, both of which are decreases from last year’s recommendations. It was also approved in the MC as part of the consent agenda. (See “IRM Study,” PJM PC/TEAC Briefs: Oct. 11, 2018.)
  • Cost Development Manual Biannual Review: Members will be asked to endorse draft revisions to Manual 15 developed through the required biannual review, which include addressing terminology inconsistencies and updating the Handy-Whitman Escalation Index.
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Overheard at OMS 2018 Annual Meeting

By Amanda Durish Cook

AUSTIN, Texas — The Organization of MISO States last week reflected on its 15 years of existence and looked ahead to how its member states can best accommodate an evolving grid.

Organization of MISO States
OMS Annual Meeting | © RTO Insider

During the organization’s Annual Meeting on Oct. 26, Executive Director Tanya Paslawski pointed out the group was established in 2003 at the time of the Eastern blackouts. “I think it’s entirely appropriate that OMS take credit that the lights have not gone out since for 50 million people,” she said to laughter.

OMS President Ted Thomas, chair of the Arkansas Public Service Commission, joked the group managed to land the meeting in “the largest city in America with a boil-water advisory,” referring to the flooding in Austin that rendered water non-potable for the week.

“That’s a mathematical improbability,” he quipped.

‘Decentralized AND Integrated’

Talk quickly shifted from past and present to the future of the bulk power system, the rise of distributed energy resources and cloudy jurisdictional issues.

Independent consultant Lorenzo Kristov, formerly principal of market and infrastructure policy at CAISO, said that while the bulk system isn’t likely to disappear anytime soon, grid defection is a possibility. But he said the grid can coexist with distributed resources, calling up a quote he attributed to author J.M. Greer: “The best way to get nothing done is to convince people they’re on one side or the other of a duality.”

“Decentralization can’t occur without the bulk power system,” Wisconsin Public Service Commissioner Mike Huebsch said.

Electrification will take place locally, at the “grid’s edge,” Kristov predicted, with urban planning and community-level programs. “Certainly, you can say that the bulk electric system isn’t where all the action is now,” he said.

Even in that environment, Kristov said it’s possible for the grid to become both “decentralized and integrated,” where the system operates in differently controlled layers. He said distribution utilities should consider becoming distribution system operators (DSOs), where the utility manages local electricity generation and use on the distribution network. Distribution owners could test the waters by rolling out the process on just one substation. In that framework, microgrids could assist a DSO with load management, Kristov said.

DERs

The discussion fit a pattern of recent OMS panels by veering to DERs and how states can best manage them.

Thomas wove together three rapid-fire analogies on how states must approach DERs, working in Southern euphemisms, hippies and holiday dinners.

He said the pace of solar adoption is increasing in his state. “In the South we say ‘fixin’ to happen. It’s not ‘fixin’ to happen. It’s happening. And if it’s happening in Arkansas, it’s happening in other places.”

Thomas contended that it’s time for state regulatory agencies to reach out to utilities to hammer out policies on the most pressing DER issues: “In the protest era of ‘make love, not war,’ we need to decide what policy we’re going to make love on and what we’re going to make war on,” he said.

He rounded out the quick speech by talking turkey: “It’s Thanksgiving. We’re trying to deal with a whole menu of policy items, and some things are hot, some things are served cold, [and] there are [dishes] ready at different times,” he said, urging states to first work on policies related to DER trends that are occurring today.

‘The Bus’

Sally Talberg | © RTO Insider

Michigan Public Service Commission Chair Sally Talberg reflected on a recent trip to observe Mexico City’s grid management, which she said was straightforward. There is one system operator and no state jurisdictions to worry about in the Mexican capital.

“Not that I’m suggesting that’s a great model, but it is simpler,” she quickly added.

Talberg quoted an unnamed PSC staffer that often says Michigan can respond to grid transformation by either “driving the bus, riding the bus or getting run over by the bus.”

“We try to ride the bus in Michigan,” Talberg said, meaning the state seeks to move on a mixture of developing some DER policies, making sure rate design is reasonable and working on how distribution systems that contain generation should be controlled.

We try to “get out of the bus to make sure the road is clear for the bus,” Huebsch said, explaining that his state aims for rules that allow DERs to crop up “organically” from customers and utilities.

In response to audience questions about when FERC will issue an order on DER aggregation — an issue left untouched by the commission’s Order 841 — Jette Gebhart, deputy director of FERC’s Office of Energy Market Regulation, said commission staff were paying a great deal of attention to the matter, though she wouldn’t comment on a possible date of an order.

Richard Doying | © RTO Insider

MISO Executive Vice President of Markets Richard Doying predicted the RTO will significantly redesign its markets to accommodate the switch from a one-way power system to a cloud-based system. But he also said there’s increasingly scarce time to complete a redesign.

“When we think about how much time MISO has to prepare for that, it’s virtually none,” he said.

Doying said MISO already at times experiences zero-dollar energy pricing from its wind power contingent — not a sustainable situation for coal and other thermal units.

ERCOT Senior Director of Market Design and Operations Joel Mickey said the grid operator has so far successfully supervised its high influx of wind, with penetration spiking to 50% at one point in early 2017.

Joel Mickey | © RTO Insider

“If you’d asked me 10 years ago … ‘Can you handle 50% wind?’ I’d have said, ‘Hell no.’ Luckily, we’ve gotten used to it, and we’ve proven you can integrate intermittent renewables. It’s a lot of work, and we’ve gotten into the business of forecasting,” Mickey said.

Doying said MISO is researching to find the inflection point when reliability might be threatened because the RTO can no longer accurately forecast load because of nonvisible DERs. He said MISO today has 5,000 MW of distributed megawatts offered into the market, much of it not visible to the RTO.

“I don’t know where that point is, but it’s something that we are actively studying,” Doying said.

Blurred Lines

Advanced Energy Economy’s Jeff Dennis said DERs exist in a jurisdictional gray area, governed by sporadic and “nuanced” FERC precedent and the 1935 Federal Power Act, which was drafted when there was sharp distinction between transmission and distribution.

“The reality is between 1935 and today, the system has become much more interconnected,” Dennis said.

Ari Peskoe | © RTO Insider

Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, made a case against direct FERC regulation of DER sales, saying states should oversee transactions to utilities and aggregators. He said sales by a DER to a local buyer, not an RTO, should be categorized as “other sales” and not wholesale sales “in interstate commerce,” as currently prescribed by the FPA.

“The current jurisdiction is a bit of a mess,” Peskoe said, contending that DERs should be categorized as “intrastate wholesale sales” so states can assume full jurisdiction.

“We know there is such thing as intrastate wholesale sales. Look at ERCOT,” he argued. “DERs are very much a local product. … I’d like to give states the flexibility to decide.”

But, he said, FERC relinquishing power over DERs is unlikely unless the commission is pressed on the issue by states and utilities.

That scenario set panelists into thinking about a complex set of hypothetical situations. Talberg said possible state jurisdiction over DERs could become muddled again when aggregators join RTOs as market participants, thus reintroducing FERC jurisdiction in the mix.

Kristov added that industry experts rarely raise the question of how DERs will be able to afford to participate in the wholesale markets, as upgrades on the distribution system are likely needed before the resources are equipped for RTO market participation. He hopes FERC contemplates the burden of those local costs if the commission allows DERs into wholesale markets.

Panelists also said they didn’t know what DER interconnection agreements to wholesale markets will look like. Some even ventured that states might be able to prohibit individual DER wholesale market participation if those DERs agree to enter a statewide aggregation program.