Page 1190 – RTO Insider

April 9, 2018

FERC Approves Change to Eliminate Gaming in SPP Markets

FERC last week overruled a stakeholder’s objections in approving SPP’s proposed Tariff revisions to eliminate a gaming opportunity related to regulation deployment adjustments (ER18-757).

The commission found that SPP’s modifications to the regulation deployment adjustment charge and payment calculations to be just and reasonable, accepting them to become effective May 1.

FERC said that by allowing the use of mitigated energy offer curves or as-dispatched energy offer curves in regulation deployment adjustment calculations, the Tariff revisions “help ensure that the regulation deployment adjustment amount will compensate resources for their output associated with regulation deployment.”

The RTO’s Market Monitoring Unit had pushed for the change (MWG-RR243), saying manipulation of regulation-down offers has cost the SPP market more than $1 million in recent years.

FERC disagreed with Westar Energy’s argument that the revisions represent a “fundamental change” in the incentives for market participants’ selection between the energy or regulation markets. It also disagreed with Westar’s complaint that incorporating resources’ mitigated energy offer curves as a component of the regulation deployment adjustment’s calculation is unjust and unreasonable — noting that market participants perceiving any inequity between the markets can modify their regulation offers accordingly.

SPP FERC Regulation Deployment Adjustment — Westar Energy’s headquarters | *Seeking Alpha*

The commission said it agreed with the MMU that closing the gaming opportunity outweighed concerns that the Tariff revisions would extend the use of the mitigated energy offer curve beyond local market power mitigation.

“We find that using the mitigated energy offer curve when calculating the regulation deployment adjustment amount should limit gaming opportunities and also helps ensure that the resources deployed to supply regulation recover their costs,” FERC said.

Westar contended that the proposed revisions would automatically cause all regulation deployment adjustment payments to be based on the type of offer (mitigated or market-based) that causes credits to be minimized. It said SPP was proposing a solution that “inappropriately and unreasonably affects all resources, when SPP should instead narrowly address the few bad actors believed to be economically withholding.”

The utility proposed that SPP be required to apply some type of economic withholding evaluation instead. SPP responded that Westar had confused gaming with economic withholding, and said that its market-clearing engine co-optimizes energy demand and regulation requirements with energy and regulation offers while ensuring resources are agnostic relative to selection for energy or regulation.

Commission Denies Golden Spread’s Rehearing Request

The commission denied Golden Spread Electric Cooperative’s rehearing request for its 2017 approval of SPP’s Order 825 compliance filing (ER17-772).

FERC’s September order accepted Tariff changes made to comply with Order 825, which requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. (See FERC Approves SPP Shortage Pricing Changes.)

Golden Spread argued that SPP’s filing did not comply with Order 825 because it did not address the RTO’s practice of committing additional capacity through the reliability unit commitment (RUC) process or through manual operations that can prevent scarcity pricing events. The commission said the protests were outside the proceeding’s scope and encouraged the cooperative to address its concerns through SPP’s stakeholder process.

In its appeal, the cooperative argued that FERC’s dismissal of its concerns as beyond the scope “effectively overlooks the fact that SPP’s current, unchanged practices purposefully and fundamentally mask the presence of market scarcity and subvert the primary goals of Order No. 825.”

The commission noted that its September ruling found that Order 825 did not require Golden Spread’s suggested modifications to SPP’s RUC or manual commitment processes. “The absence of such requirements places these SPP practices beyond the scope of a compliance filing,” FERC said.

The commission has “stated on numerous occasions” that the sole relevant issue in reviewing compliance filings is whether they comply with the directions in the order requiring them, it said. It also pointed out that it will not consider arguments raised in a compliance proceeding “that are not responsive to the narrow issue of the filing utility’s compliance.”

FERC Accepts ITC Midwest’s Interconnection Agreement

FERC accepted ITC Midwest’s third restated interconnection agreement with Corn Belt Power Cooperative and Interstate Power and Light (IPL), effective April 7 (ER18-801).

The agreement adds a substation as an additional point of interconnection between IPL and Corn Belt. The interconnection was expected to be in service in the first quarter of 2018.

Corn Belt and IPL are parties to other dockets (consolidated under ER15-2028) before the commission involving Corn Belt’s entry into SPP as a transmission owner and the resulting implications for existing agreements between the utilities.

The original agreement with ITC dates to 1956 but was designated as a grandfathered agreement (GFA) under MISO’s Tariff. ITC said that because of its possible GFA status under SPP’s and MISO’s Tariffs, Corn Belt and IPL had declined to execute the agreement.

The commission dismissed concerns by Missouri River Energy Services (MRES) that the proceeding’s outcome could affect cost allocations in its transmission zone, finding the proceeding “not to be relevant” to ITC’s proposed addition of the substation.

“We therefore are not persuaded to consolidate this proceeding with [ER15-2028] or otherwise hold it in abeyance,” FERC said. It said its acceptance of the agreement does not affect the ongoing proceeding in that docket.

East River Co-op Granted Waiver to Revise Tx Rates

The commission granted East River Electric Power Cooperative’s request for a one-time waiver to revise its 2018 update and associated informational filing for its formula rate template and protocols under SPP’s Tariff (ER18-860).

The waiver allows East River to reclassify the Groton-Ordway 115-kV transmission project, which it said it had initially understood should be classified as a base plan upgrade eligible for recovery through zonal and regionwide charges. The project will now be included in the cooperative’s annual transmission revenue requirement as part of its zonal charges.

East River is a wholesale electric power supply cooperative serving 24 rural electric cooperatives and one municipally owned electric system in eastern South Dakota and western Minnesota. It became a TO member of SPP in 2015 as part of the Integrated System.

— Tom Kleckner

April 9, 2018

Experts Predict EV Adoption, Charge Management in Illinois

By Amanda Durish Cook

Electric vehicle experts last week descended on the Illinois Commerce Commission to discuss the eventual adoption of EVs in the state and the need to manage customers’ charging patterns to avoid stressing the grid.

The ICC held the policy session in Chicago to learn more about the relationship between EVs and the grid. Panelists agreed that widespread EV adoption is years away and said state policymakers will eventually devise ways to stagger charging.

Illinois now has 15,000 EVs, with 100,000 projected to be on the road in the coming years, said Katie Bell, Tesla’s energy policy and business development manager. A recent study by the Illinois PIRG Education Fund and Frontier Group predicted Chicago will have 81,000 EVs by 2030. The ICC predicts that widespread EV adoption could bring Illinois up to $43 billion in benefits by 2050, “stemming from reduced utility bills, carbon pollution and fuel and vehicle expenses.”

EV Electric Vehicle Charging Stations Illinois — Tesla Supercharger station | *Tesla*

Bell said Tesla is working to make its cars more affordable and examining how to site new charging stations, as well as ways to encourage owners to charge during off-peak hours.

“We’re trying to give customers a better option than what’s available today,” Bell said.

EVs are expected to drive 54% of new car sales by 2040, according Bloomberg. The ICC says that Illinois currently ranks sixth in the nation in terms of numbers of plug-in EVs.

“Currently, Illinois’ framework is light in that it doesn’t heavily regulate electric vehicles,” said energy attorney Elizabeth McErlean of law firm McGuireWoods.

McErlean said the question still remains whether EV charging station owners should be regulated as public utilities, though the Illinois General Assembly in 2012 exempted station owners from the definition of utilities. With Illinois keeping regulations light to encourage the development of private EV charging stations, McErlean said charging providers can grow unfettered and experiment to find best practices.

“Fossil fuels have enormous impact on our climate and health,” said Christie Hicks, manager of clean energy implementation for the Environmental Defense Fund. “Electric vehicles offer the greatest emissions reduction in the transportation sector. … It’s not a matter of when electric vehicles are coming, but how. … The future is electric.”

But Hicks acknowledged that fears of low travel range, scarce inventory and high upfront costs remain a barrier to widespread adoption.

Citizens Utility Board Executive Director Dave Kolata said there’s “a lot of momentum for transportation electrification.” He noted that charging patterns must be optimized, and that if all EV owners charge at night when wind generation creates negative electricity prices, it will eventually create a new peak. Kolata said he supported using time-of-use rates for charging and predicted that EVs will ultimately be automated to respond to price signals while charging.

When Illinois Senior Assistant Attorney General Susan Satter asked the room who owned an EV, she was greeted by a show of four or five hands.

“I have an EV,” Satter said. “Eighty percent of charging is done at home, in the garage. When we talk about charging stations, we’re talking about filling in for the times when we’re not at home.”

Satter said consumers have a lot of options for the fill-in charges: employers, city-owned free or low-cost charging stations, and stations placed at shopping centers to attract customers. Satter said states must be careful of developing policies that only consider utilities’ charging projects.

“We’re at the beginning of the EV revolution,” she said.

Satter said the growing number of EV owners will increasingly need to understand energy pricing and peak demand in order to select the lowest-price charging times. Panelists generally agreed EV owners will eventually need to be pushed to charge at off-peak times to avoid stressing the grid.

Satter pointed out that EV owners are still early adopters that earn well above the national median income and cautioned utilities about providing these owners incentives when they’re already high earners.

“What is an incentive? It’s giving people more money,” Satter said. “When we get past the early adopters and into the mass market, it’s going to be cheaper.”

Other panelists urged policymakers to be cognizant that EV owners today tend to be wealthier and less in need of subsidies.

“Many of the communities that stand to benefit the most from electric vehicles don’t have access to them,” Hicks said. She urged policymakers to subsidize charging stations and develop more local pilot programs.

Kolata agreed that incentives for EV adopters should not come at the cost of other economic classes of customers.

But Ryan Schonhoff, Ameren supervisor of rates, said lack of a “holistic charging system” is hindering growth of EVs.

Chicago Transit Authority analyst Kate Tomford said a solar and storage combination could work well in the city’s bus garages. She said that while the city owns two electric buses now, it plans to have a fleet of 20 in the “near future.”

Commonwealth Edison Vice President of Regulatory Policy and Strategy Jane Park said EVs in the U.S. are set to reach cost parity with internal combustion engine vehicles in seven years and credited growing popularity with “a confluence of technology advancements and national and internationally policy.” States with the highest EV adoption offer a “portfolio” of purchase incentives, dynamic pricing programs, infrastructure plans and a plan for access for low-income communities, she said.

Park said it’s not quite the time to place strict regulations on EV ownership because policymakers don’t yet understand how to strike the best balance of regulations.

April 9, 2018

California Utilities Propose New CCA Rules

By Jason Fordney

California’s three large investor-owned utilities asked state officials last week to change the rules to protect bundled customers from being saddled with expensive long-term renewable contracts as others defect for increasingly popular community choice aggregators (CCAs).

Much has changed in the state since CCAs were created in the wake of the California energy crisis of the early 2000s, the utilities argued. The CCAs didn’t start operating until 2010 but have pulled 40% of Northern California’s bundled load from Pacific Gas and Electric, and 35% of Southern California Edison’s retail load is in the process of CCA formation. The two utilities, along with San Diego Gas & Electric, filed a 363-page proposal with the California Public Utilities Commission. They noted that 85% of their load could move away by the mid-2020s.

“The combination of these two developments leaves high-cost, long-term renewable contracts in the IOUs’ bundled service customer portfolios that are far in excess of their need,” the utilities said. The situation has also brought the utilities’ procurement of large-scale renewable projects to a halt.

The cost of renewable power has decreased significantly since the legacy contracts were signed, which the IOUs say “transformed the renewables market consistent with state policy and commission direction.”

The more than 200 legacy contracts representing hundreds of millions in costs were the topic of a hearing at the Senate Energy Committee last summer, at which Chairman Ben Hueso expressed concern about creating an ungovernable system. (See California CCAs Spur Worry of Regulatory Crisis.)

CCA Long-Term Renewable Contracts — California’s utilities proposed a new regulatory regime for CCAs to the CPUC | © *RTO Insider*

The PUC got some pushback from CCAs in February when it fast-tracked new regulations for new and expanding CCAs over resource adequacy concerns. (See CCAs Oppose CPUC Decision, Process.)

The April 2 IOU proposal would restructure the power charge indifference adjustment (PCIA), which is meant to ensure that bundled customers are not affected financially by other customers deciding to join CCAs.

The IOUs had previously proposed that the benefits and costs of previous IOU procurement be allocated to customers for whom those assets had been procured or constructed, a process called the portfolio allocation methodology (PAM).

Despite their new proposal, the utilities “still support their original PAM proposal as being a viable and relatively straightforward methodology to implement to ensure an equitable and efficient allocation of benefits and costs among all customers should the commission wish to consider it,” they said.

The new proposal uses two allocation mechanisms: the “green allocation mechanism” (GAM) for renewable portfolio standard-eligible resources and large hydro, and a “portfolio monetization mechanism” (PMM) including gas, nuclear, non-pumped hydro and energy storage.

“The joint utilities’ proposal of combining the allocation of [renewable energy credits] and [resource adequacy] from RPS and large hydro-electric resources (GAM) with a cost-based allocation approach for other resources (PMM) balances the resource technology concerns of a number of CCA parties while ensuring compliance with state law and continued support of state policy objectives,” they said.

The IOUs proposed that all contracted and utility-owned resources subject to the current methodology be considered eligible for GAM or PMM.

April 9, 2018

MISO Looks to Address Changing Resource Availability

By Amanda Durish Cook

CARMEL, Ind. — MISO is kicking off an effort to examine its changing resource availability in the face of increasing generation retirements, poor outage coordination, growing volumes of emergency-only capacity and rising use of intermittent resources.

“In the past, a [maximum generation event] occurred every year or two when MISO needed access to emergency-only resources. Now, there have been 12 since the start of the 2016/17 planning year, and they have occurred in all four seasons,” the RTO wrote in a white paper laying out the issue.

To remedy the situation, MISO is broadly proposing to increase transparency of resource availability times and energy requirements, revamp availability requirements, and improve price signals to attract generator response.

But it needs stakeholder feedback to develop the specific rules and market improvements needed to meet those goals, RTO staff said at an April 5 Reliability Subcommittee meeting.

‘Degrading Ability’

MISO resource availability — Bladen | © *RTO Insider*

Executive Director of Market Design Jeff Bladen said MISO is experiencing a “degrading ability to convert committed capacity” in a reliable fashion because of “more volatile supply and demand conditions,” forcing it to increasingly rely on resources not scheduled in the day-ahead market.

“There is less operational energy available through dispatch than the year before,” Bladen said. “Each succeeding year we’ve had fewer megawatts offered.”

MISO had 126 GW in average energy must-offers in the 2014/15 planning year, with about 17 GW of outages. In the 2015/16 and 2016/17 planning years, offers declined to 125 GW and 117 GW, respectively, while outages rose to 18 GW and roughly 23 GW.

Bladen said peaks are becoming less predictable and occur even in shoulder seasons: “It’s becoming apparent that this is a challenge we will face year-round, and not just in the summertime.” He said outages have played a role in most of MISO’s maximum generation events since late 2016, with the majority occurring during off-peak months.

The RTO could once confidently group outages in the spring and fall because it had a greater margin of error.

“That seems to be a fleeting confidence. We have to plan for more volatile loads,” Bladen said.

MISO’s “resource availability and need” topic evolved from a 2015 proposal to create seasonal capacity procurement requirements, a generally unpopular move among stakeholders. RTO officials now say the proposal is no longer as simple as applying separate clearing requirements in a two- or four-season capacity auction.

“In some cases, we may have jumped to conclusions on some of these challenges — opportunities, but challenges nevertheless. This topic is an evolving one,” Bladen said.

Staff have said solutions could include a capacity procurement requirement and an examination of whether current requirements and price signals must be revised in light of shifting availability, a product of tightening supply, more renewable energy participation, increasing instances of extreme weather events and an aging baseload fleet more susceptible to outages.

MISO is already considering whether to factor the effects of planned and maintenance outages on peak in its loss of load expectation study by the 2019/20 planning year, which could boost the RTO’s planning reserve margin requirement. (See MISO RASC Zeroes in on Priorities.)

resource availability miso — Peak loads shown in red versus supply over 2016 and 2017 | *MISO*

Customized Energy Solutions’ Ted Kuhn asked why MISO is regarding retirements as out of the ordinary given that they’ve always existed.

“The fleet in general is getting older in aggregate,” said Bladen, stressing that MISO’s current retirement rate is amplified when compared to the historical rate.

He said MISO’s expected renewable expansion combined with its aging baseload generation will only exacerbate reliance on emergency-only resources.

“The queue today gives us every indication that more intermittent resources are on the way,” he said.

Bladen added that individual load-modifying resources often don’t perform to the levels accredited to them in the annual capacity auction and can have long start-up times, up to 12 hours.

Madison Gas and Electric’s Megan Wisersky criticized some aspects of MISO’s longstanding rules for load-modifying resources. She noted the RTO has always required load-modifying resources to be available for both capacity and transmission emergencies and restricted them to being price takers in the market.

“It’s almost like this trend is self-fulfilling,” Wisersky said.

Bladen said MISO would be looking for stakeholder input on any changes to the treatment of load-modifying resources.

“The idea is that we give tools to our resources so they have the ability to cure,” he said. MISO’s load-modifying resources currently do not have a must-offer obligation for any time periods outside summer, and they can only be called on five times each summer during emergency declarations.

We Energies Tony Jankowski asked why MISO was hinting at the need for such drastic measures and cautioned against overbuilding the system. Other stakeholders in attendance also worried aloud that the RTO would use the white paper as justification for big changes.

Bladen said MISO’s 25% expectation that it will initiate emergency operating procedures sometime this spring belies the fact the RTO likely faces a nearly 100% chance of entering an emergency during the season.

“We’ve been in a max gen event 12 out of the last 11 quarters. We’re not saying the sky is falling, but we’re saying it’s cloudy, and we’re concerned,” Bladen said.

“Despite the odd way of saying it, our goal is to be adequate,” he added, smiling.

Last month, Reliability Subcommittee Chair Bill SeDoris said he expected the discussion on the topic to extend into 2020.

April 9, 2018

SPP Seams Steering Committee Briefs: April 4, 2018

SPP and Associated Electric Cooperative Inc. stakeholders last week approved a scope for a joint study to determine the existence of any mutually beneficial transmission projects, enabling them to continue with their agreement to conduct a biennial study.

The SPP-AECI Interregional Planning Stakeholder Advisory Committee meeting was held April 4 during the Seams Steering Committee meeting in Dallas.

A joint planning committee will determine the cost allocation of any potential projects on a case-by-case basis, with costs assigned equitably based on the constraint being resolved.

Should any projects be identified, SPP will solicit detailed proposals, similar to those used for its Order 1000 competitive projects.

The groups’ 2016 joint study identified a pair of projects that is still awaiting final regulatory approval.

TSR Proposal

The seams committee also discussed a draft business practice for unreserved use of the transmission system. The draft envisions three days for entities to submit transmission service requests (TSRs) for unreserved use, allowing them to avoid usage charges. After three days of unreserved use, a TSR would be required.

February M2M Results in $3.97M Charge to MISO

SPP and MISO’s market-to-market (M2M) process resulted in a nearly $4 million payment to SPP for February, the seventh straight month, and the 15th of a total of 17 M2M months, that MISO has paid its seams partner.

SPP has now received almost $48 million in M2M payments since the two RTOs began the process in March 2015, staff told the SSC.

SPP’s Nashua-Hawthorn and Riverton-Neosho-Blackberry flowgates accounted for most of the charges, binding for a combined 430 hours in January because of high winds and outages. That resulted in $3.4 million of the MISO payments to SPP.

— Tom Kleckner

April 9, 2018

UPDATE: Vistra-Dynegy Merger Closes After FERC Nod

By Rich Heidorn Jr.

Vistra Energy said Monday it closed its acquisition of Dynegy following a FERC order concluding the $1.7 billion deal raised no competitive concerns (EC18-23).

The all-stock deal will create a power generation and retail giant owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE. FERC’s April 4 approval was the last regulatory step required to complete the deal, which had already been cleared by regulators in New York and Texas.

Vistra-Dynegy Merger FERC — | *Vistra Energy*

Dynegy’s combined cycle gas turbine fleet and geographically diverse portfolio were a big attraction for Vistra, which owns 18,000 MW of generation capacity in ERCOT. Dynegy’s 27,000 MW will give it the following market shares in these organized markets:

CAISO: 2.96% (2.16% after accounting for capacity under long-term contracts).
ISO-NE: 12.1% (Rest of Pool zone); 11% (Northern New England zone).
MISO: 0.3%.
NYISO: 4.6%.
PJM: 6.9% (RTO-wide); 3% (MAAC locational deliverability area); 7% (PPL LDA).

FERC has no jurisdiction over the combined company’s generation in ERCOT. The Public Utility Commission of Texas declined a staff recommendation that it require Luminant, Vistra’s generation arm, to divest itself of at least 1,281 MW of capacity to keep the post-merger Vistra below the statutory cap of 20% of ERCOT installed capacity. (See Texas PUC Conditionally Approves Vistra-Dynegy Merger.)

FERC rejected a protest by Public Citizen, which argued that the applicants’ horizontal competitive analysis should have included generation owned by Dynegy’s major shareholder, Energy Capital Partners. Public Citizen noted that ECP is seeking to acquire Calpine.

But the commission ruled ECP’s generation did not have to be included in the analysis after its action in January to reduce its stake in Dynegy from 14.88% to 9.9%, below the 10% threshold that imputes control. ECP’s post-transaction ownership of the combined Vistra entity will be 1.7%, FERC said. “As such, under the commission’s regulations, Dynegy will not be affiliated with ECP, nor under its control,” FERC said.

The commission also said the Dynegy acquisition would not have an impact on vertical competition, saying the only transmission facilities controlled by the applicants in commission-jurisdictional markets aside from generator interconnections are Smoky Mountain Transmission — 86 miles of transmission connected to the Duke Energy Carolinas and Tennessee Valley Authority systems — and Electric Energy, six 8-mile-long parallel generation tie lines. Both provide service under commission-approved open access tariffs.

In related orders Thursday, FERC also set hearing and settlement procedures to review the reasonableness of the reactive service rates for Dynegy’s Illinois Power (ER16-233-001, EL18-133) and 15 other subsidiaries (ER15-1641, et al.).

Vistra CEO Curt Morgan’s executive team, including Chief Operating Officer Jim Burke and Chief Financial Officer Bill Holden, will lead the combined company, based at Vistra’s headquarters in Irving, Texas. The new board is expected to have 11 directors: the current eight members of the Vistra board and three members from Dynegy’s board.

April 6, 2018January 3, 2024

Wisconsin Transmission Picks up Slack After Upper Peninsula Outage

By Amanda Durish Cook

MISO on Tuesday began using Wisconsin transmission to deliver electricity to Michigan’s Upper Peninsula after the failure of two of American Transmission Co.’s submarine cables in the Straits of Mackinaw.

The situation is not disrupting the RTO’s grid reliability, and there is adequate Wisconsin transmission capacity to offset the outage, according to MISO spokesperson Mark Adrian Brown.

“MISO continues to work closely with ATC to maintain electric reliability in the Upper Peninsula. Power to serve the Upper Peninsula of Michigan continues to be routed through Wisconsin, as is the normal flow of power into the Upper Peninsula, and there is ample transmission via the alternative route,” Brown told RTO Insider in an email.

ATC has said it does not know how long the outage will last. MISO may seek to reschedule future planned outages to ensure continued reliability depending on the duration, Brown said.

The company on Tuesday said it took the “unprecedented step” of shutting down two damaged underwater transmission lines that connect lower Michigan with the Upper Peninsula. The pair of 4-mile circuits were leaking a toxic, petroleum-based fluid used for insulation into the lake, and that “extreme weather conditions, including icing in the channel and on shore” prevented an investigation of the damage, according to the company.

ATC said the cables initially tripped offline about 30 seconds apart on April 1, although aerial patrols showed no visible damage to the overhead parts of the system. One of the cables was constructed in 1975, the other in 1990. According to the U.S. Coast Guard, about 600 gallons of hazardous petrochemical fluid leaked into the water.

The company has not established the cause of the damage and said the lines “cannot be repaired and have been rendered permanently inoperable.” The company said it will be checking on the condition of the other four cables it operates in the straits once weather permits. Upper Michigan this week experienced heavy snow and gusty winds.

ATC spokesperson Jackie Olson on Thursday said the company is testing the remaining cables to determine if they can be reconfigured to restore one of the circuits to operability.

“Our investigation as to the cause is ongoing; however, the weather conditions are such that we cannot get a remote submarine vehicle in to do an inspection any time soon,” Olson said.

“It was an extraordinary set of circumstances, but ultimately, the decision to shut down the cables had to be made,” said ATC Chief Operating Officer Mark Davis. “We will continue to investigate the cause of the incident, determine any necessary remediation efforts and continue communicating with the appropriate regulatory agencies.”

ATC said it is coordinating with MISO and Midwest Reliability Organization “to determine short-term and long-term solutions.” The company said it has notified multiple agencies of its decision to shut down the electrical cables, including EPA, the National Oceanic and Atmospheric Administration, the Coast Guard, U.S. Fish and Wildlife Service, Michigan Department of Environmental Quality, Michigan Department of Natural Resources and the Michigan Public Service Commission.

The Coast Guard on Wednesday said it established a unified command comprised of MDEQ members, county emergency managers, local native tribes, NOAA, FWS, EPA and ATC “to oversee the pollution response and mitigate any risks to the environment.” The Coast Guard said the maximum potential for the spill is more than 4,000 gallons, though ATC took pressure off the lines and fluid was not leaking as of April 4. The toxic risk to wildlife and drinking water is low, the Coast Guard said.

April 6, 2018

Another Wind Penetration Record for SPP

By Tom Kleckner

Having cracked wind penetration levels of 50% and 60%, SPP has now set its sights on the once unimaginable 70% barrier.

The RTO’s latest record came early on March 31, when wind energy accounted for almost 14.5 GW, or 62.13%, of its 23.3-GW total load at 1:54 a.m. SPP said it also set a new renewable penetration record of about 64.7% at the same time.

Spokesman Derek Wingfield told RTO Insider it’s difficult to predict how high SPP’s wind penetration levels can go, but staff have studied the effects of 70% levels. He said the RTO had forecast 70% penetration in late 2017, but transmission outages wound up limiting wind energy that day.

“It could be a possibility again this spring as load reaches minimum levels,” Wingfield said.

SPP broke the 60% barrier on March 16, when wind energy met 60.56% of the system load. (See SPP Hits 60% Penetration Level, as Promised.)

It was one of five wind penetration records set during the month, and the sixth of the year.

In February 2017, SPP became the first North American RTO to exceed wind penetration levels of greater than 50%. Its all-time high for wind generation came in December, when the system generated almost 15.7 GW of power from wind farms.

“The records are an indicator of the evolution of our system, and wind continues to be added to it,” Wingfield said. “Reliability and economics drive our market, and we’re proud that we’re able to reliably manage so much wind and provide some of the least-cost electricity in the country, based on the resources available to us.”

SPP CAISO Wind Power ZECs — | *Oklahoma Municipal Power Authority*

The RTO has 17.75 GW of installed wind, much of it in Kansas, Nebraska, Oklahoma and West Texas. Another 5.3 GW of wind capacity has interconnection agreements but is not yet in service, and 35 GW of wind capacity is under various stages of review in the generator interconnection queue.

SPP’s Wind Penetration Records

March 31, 2018: 62.13%
March 16, 2018: 60.56%
March 11, 2018: 58.49%
March 5, 2018: 58.07%
March 3, 2018: 57.87%
Feb. 19, 2018: 56.88%
Dec. 4, 2017: 56.25%
April 24, 2017: 54.47%
March 19, 2017: 54.45%
March 6, 2017: 52.65%
March 5, 2017: 52.11%
Feb. 12, 2017: 52.08%

April 6, 2018

MISO Storage Ambitions Look Beyond Order 841

CARMEL, Ind. — MISO says it will likely go above and beyond complying with FERC Order 841, as it expands its market rules for storage after its initial filing with the commission later this year.

MISO FERC energy storage FERC Order 841 — Vannoy | © *RTO Insider*

MISO Market Design Manager Kevin Vannoy said the RTO will soon begin presenting stakeholders with straw proposals for Order 841 compliance, but it intends to keep going after submitting a final proposal. MISO will continue to study the operational characteristics of energy storage to make a more comprehensive, but still unidentified, set of market rules in 2019 and 2020.

“We’re not going to just stop at Order 841 compliance,” Vannoy promised stakeholders during an April 4 Energy Storage Task Force meeting.

FERC last month granted MISO permission to create a Stored Energy Resource Type II to facilitate market participation, although it said the new definition needs more work that can be deferred into the RTO’s Order 841 compliance filing due in early December. (See FERC OKs MISO Plan to Expand Storage.) Vannoy said revising the resource type definition will get MISO “part way, but not all the way there” to compliance.

He added that MISO’s list of improvement projects, the Market Roadmap, includes a more comprehensive storage participation plan, although it didn’t place in the top eight priorities this year despite stakeholders giving it top ranking. (See 8 Projects Set for 2018 MISO Market Roadmap.)

MISO Director of Policy Studies J.T. Smith reported the RTO is meanwhile beginning to study how storage resources could be considered for economic transmission projects.

“There are still a lot of questions out there but not a lot of firm answers,” Smith said.

— Amanda Durish Cook

April 6, 2018

Connecticut Kicks off Grid Modernization Effort

By Michael Kuser

NEW BRITAIN, Conn. — Utility representatives and other stakeholders shared their views on evolving cost drivers, changing customer demand and new technologies at the Connecticut Public Utilities Regulatory Authority’s first-ever technical conference on grid modernization on Tuesday (17-12-03).

“We need to have technologies in place that understand how the system is operating in real time, with power coming from any direction on the system,” said Chuck Eves, director of engineering and strategic planning at Avangrid subsidiary United Illuminating (UIL).

Eversource Energy filed comments ahead of the conference calling for “foundational investments in sensing and monitoring communications, analytics, automation and control solutions.”

Jennifer Schilling, Eversource’s director of grid modernization, said her company breaks down its investments “into peak load, new customer growth, reliability and ageing infrastructure, and basic business, which includes capital repairs.”

The new opportunities arising from the growth in distributed energy resources are “adding a new dimension in our planning process,” which is why the company supported the timing of the technical conference, Schilling said.

“The nature of the changes in demand and the forecasting will be important in terms of thinking about what do we need to do differently to be able to say, ‘OK, if I have these categories of investment, how are they likely to change in the future?’” Schilling said.

Using Data

Connecticut Green Bank Associate Director Anthony Clark said his organization’s current investments are following and helping to boost customer demand, “but they are not following grid demand much at all. We just don’t have that insight.”

PURA NARUC grid modernization National Grid — The Connecticut Public Utilities Regulatory Authority (PURA) held their first-ever technical conference on grid modernization on April 3. | © *RTO Insider*

Clark thanked PURA, the state’s Department of Energy and Environmental Protection and UIL for helping the Green Bank start “really digging into this process on the grid side” through clean energy pilot programs.

“In much of the discussion here we’ve talked about the challenge of having solar PV or other resources where there isn’t sufficient data or resolution into the resource or ability to control it,” Clark said. “The technologies themselves are becoming smarter, so we’re looking at deploying smart inverters that will actually sense grid conditions and respond to them.”

Christian Bilcheck, vice president for smart grids innovation at ‎Avangrid, said it’s important to think of DER in the aggregate, not as individual elements.

The utility is not necessarily going to have the answers to a lot of questions in the early days, he said.

“I can picture a data request coming in and it will look like we’re not sharing information, but we don’t have DER adoption modeling forecasts for circuits and substations right now,” Bilcheck said.

“It gets complicated, but I think if we keep approaching it from a practical perspective, we’ll get there,” he said. “Not just the data needs, but I think the goal of the data is to help inform the types of investments that we should be looking forward to, how DERs can play a role in that frame and even help shape policy.”

Lauren Savidge, DEEP director of energy supply, said the agency is learning from what other states are doing with DER, citing a recent Michigan Public Service Commission solar program report “that was pretty thorough on compensation for solar, how different customers in their territory use solar.”

Cost and Sustainability

PURA Chair Katie Dykes said, “The cost-effectiveness testing will help us learn a lot about — particularly from the utilities’ perspective — what the grid currently can do and where the limitations are.”

Eves said it’s important to consider the long-term sustainability of solutions “as we evaluate the lifecycle costs of the choices we make, to sustain those into the future, five, 10, 20, 40 years down the road.”

In its comments, the Acadia Center said that any calculation of cost-effectiveness should be aligned with the state’s consumer, energy and environmental goals.

“Cost-benefit frameworks should be designed or expanded to fully reflect priorities such as reducing energy bills and reducing consumers’ energy burden, addressing climate change, enhancing consumer control and choice, and systemwide efficiency,” Acadia said.

PURA Commissioner Michael Caron returned the conversation to what Connecticut can learn from other jurisdictions.

“In California and Hawaii, they are blazing the trail ahead of us from the perspective of penetration and how they’re dealing with those issues, so there’s a lot to learn from what’s occurred in those states … learning from their mistakes as well as from their successes,” Eves said.

PURA is seeking written follow-up comments on the technical conference by April 10 and will later this month issue a final notice of scope of procedure for its exploration into the issues of grid modernization. The agency plans to begin discovery in the coming months and form working groups by this summer before soliciting reports from them in the fall.