Page 1118 – RTO Insider

September 18, 2018

MISO in Conservative Ops After Emergency Declaration

By Amanda Durish Cook

MISO declared a maximum generation alert at noon Monday, saying tight reserve levels amid forced outages, hotter-than-expected temperatures and higher-than-forecasted load could prompt emergency procedures.

The action followed a string of notices and alerts over the weekend. On Saturday, the RTO ordered conservative operations for its entire footprint until midnight Wednesday.

Load hit 112,907 MW at Monday’s 4 p.m. peak. Real-time LMPs ranged from $22/MWh in Minnesota to $82/MWh in Michigan.

miso outages maximum generation alert — MISO peak load and pricing on Sept. 17 | *MISO*

Last week, MISO said it had prepared for summertime conditions in September, in keeping with trends over the last three years. At the time, some stakeholders expressed doubt over the 19% probability the RTO gave itself of entering emergency procedures at least once this fall, with some saying the chance of an emergency was greater. (See MISO Sees Small Chance of Fall Emergency Procedures.)

Beginning on Saturday, MISO requested that generation and transmission owners defer or cancel all nonessential maintenance outages, asking that utilities reach out to coordinate returns to service.

In a Sept. 15 tweet, MISO said it was monitoring conditions in a hotter-than-usual MISO South, where Entergy issued public appeals to conserve energy on behalf of the RTO. Entergy said it was experiencing a “critical” shortage of electricity. MISO’s declaration of a maximum generation event requires members to make public conservation appeals and allows the RTO to make emergency power purchases to avoid load shedding.

“We appreciate our customers’ help in meeting power needs during this time by turning off all non-essential lighting, appliances and electronics as well as raising thermostats to 78 degrees. If possible, reduce use of water heaters, electric ovens, washing machines and dryers,” Entergy asked. The company eventually terminated the appeal for conservation at 6:30 p.m., hours earlier than MISO’s original prediction of 11 p.m.

19% Chance

At the Sept. 13 Market Subcommittee meeting, MISO officials said they had sufficient resources to cope with unseasonably warm conditions again this fall.

The RTO estimated a 19% chance that it would invoke emergency operating procedures to call on load-modifying resources (LMRs) this fall. Those resources are not obligated to respond when called upon after Sept. 1. MISO expects to have about 11.8 GW of available LMRs, based on availability forecasts provided by resource owners.

The RTO forecast a 110- to 120-GW peak load for September and said it prepared for loads more in line with summer conditions. The National Oceanic and Atmospheric Administration predicts above-normal fall temperatures for the MISO region.

“September generally aligns more closely with summer system conditions, at least for the last few years,” said Jeanna Furnish, MISO manager of outage coordination.

Furnish said MISO has so far this month experienced loads topping out at 114 GW, within about 1 GW of peak fall loads over the last three years.

For the last four years, MISO’s actual fall peak load has trended about 5 to 9 GW higher than load-serving entities have forecasted in 50/50 probability forecasts.

Furnish said MISO expects a 10- to 15-GW increase in planned outages from the end of September to the end of October, when load is projected to be lower. Navigating the outages will be “challenging, but manageable,” similar to the RTO’s experience in recent years.

After some stakeholders expressed confusion over the 19% statistic, MISO Executive Director of Market Development Jeff Bladen clarified that the RTO is not saying it will spend 20% of the fall in emergency operating procedures.

“There’s a 20% chance that we will go into emergency operating procedures at least once this fall,” he explained.

During the meeting, stakeholders also received an emailed capacity advisory notice for a possible shortage on Sept. 17 owing to outages and residual weather conditions from Hurricane Florence. MISO rolled out the new notification system in August for situations when its all-in capacity is forecast to be less than 5% above operating needs. (See “New Notification System,” MISO Moving to Combat Shifting Resource Availability.)

September 18, 2018

MISO Closing in on Storage Participation Plan

By Amanda Durish Cook

CARMEL, Ind. — MISO plans to hold a final Order 841 workshop on Oct. 10 to complete its collection of stakeholder opinions on its storage participation model, which will include an agreement for distribution-level storage but leave storage dispatch optimization to a later filing.

Here’s what the RTO has decided thus far.

Pro Forma for Distribution-connected Storage

MISO’s draft pro forma agreement for storage connected at the distribution level requires storage:

Be registered and modeled in MISO;
Secure agreements with distribution facilities so energy can be delivered to the MISO transmission system;
Be able to receive MISO operating instructions; and
Provide MISO with facility measurements and settlement meter data.

The agreement also specifies that MISO will make sure a storage resource owner isn’t charged twice for energy when it pays retail rates for wholesale charging. MISO said it will exclude the charging energy from wholesale rates in its settlements.

During a Sept. 13 Market Subcommittee meeting, Coalition of Midwest Power Producers CEO Mark Volpe asked if the agreement opens an avenue for distribution-connected storage assets to avoid MISO’s interconnection queue.

miso storage participation ferc order 841 — Vannoy | © *RTO Insider*

“This is not a way to circumvent the interconnection queue,” Director of Market Design Kevin Vannoy said.

“So you’re saying that distribution-level storage must go through the interconnection queue?” Volpe asked.

“I don’t have a definitive answer for that,” Vannoy responded.

Consumers Energy’s Jeff Beattie pointed out that many qualifying facilities that utilities must purchase power from under the Public Utility Regulatory Policies Act are connected at the distribution level.

Canned Corn

The Energy Storage Association’s Rao Konidena, formerly a MISO adviser, brought a can of corn with him to the MSC podium.

Storage, he said, is like a can of corn.

“We know what’s in there; we know how it’s used,” he said. MISO’s remaining piece is finalizing storage rules for an asset whose purpose is already understood. He said storage owners should be able to toggle hourly between offering energy and ancillary services and have the option to self-dispatch.

Konidena said storage asset owners must be able to enter offline mode without fear of being cited for physical withholding. “We need to have enough clarity to know that asset owners will not be penalized as they come back online,” he said.

No Optimization Yet

MISO is not ready to optimize storage resources’ energy schedules in the day-ahead or real-time markets. That means the RTO won’t pick the best and most economic hours for a battery or other storage resource to charge or discharge.

MISO said it will commit and dispatch storage respecting minimum and maximum charge limits and any self-scheduled offers. But it said its unit commitment calculations cannot be easily changed to optimize storage in charge/discharge or continuous modes across multiple periods.

Vannoy said participation must be accommodated per Order 841, but MISO should not have to change existing market services to accommodate storage. He also said FERC’s order has already suggested that storage resources will represent their energy limitations through offer prices.

“We don’t see it as a requirement of 841 that we change our optimization calculation,” Vannoy said. “We’re taking this into our research and development, and it will become more important as storage becomes more prevalent. But right now, we’re not prepared given the timeline, nor is it required in our mind.”

Storage Capacity

Meanwhile, MISO is moving forward on a multistep capacity determination process for storage resources.

The process involves a test verifying the storage facility’s capacity and its transmission deliverability. The resource must provide quarterly reports to MISO’s generating availability data system (required for storage resources 10 MW and up). The RTO will use the data to calculate an equivalent forced outage rate, installed capacity and unforced capacity for the resource.

Storage resources that are designed with limited output availability will also have to submit a day-ahead must-offer for at least four continuous hours covering the two hours before the peak, the peak hour and the hour following the peak hour. MISO forecasts its daily peak hour seven days in advance.

MISO revealed this version of the plan last month to comply with Order 841. (See MISO Fills out Storage Capacity Plan.)

“It’s not really unique to storage capacity resources,” Senior Adviser of Capacity Market Administration Rick Kim said of the proposed accreditation process during a Sept. 12 Resource Adequacy Subcommittee meeting.

But Customized Energy Solutions’ David Sapper said the storage must-offer rule for use-limited resources might be too restrictive for an RTO that is trying to place more emphasis on supply flexibility in an environment where a peak risk can occur in during several different hours, not just the summer peak hour that MISO currently plans around. (See MISO Looks to Members for Load Forecasting Ideas.)

“It ignores the operational characteristics of storage,” Sapper said.

Vannoy pointed out that the use-limited description is an optional designation, left up to the owners of storage resources. He said even use-limited storage resources are free to offer for 24 continuous hours.

MISO plans to introduce draft Tariff language for storage capacity credit at next month’s MSC, Kim said.

September 18, 2018

PJM Operating Committee Briefs: Sept. 11, 2018

VALLEY FORGE, Pa. — PJM staff last week outlined recommendations it developed to address a mysterious frequency drop on July 10. (See “Low Frequency,” PJM Operating Committee Briefs: Aug. 7, 2018.)

PJM saw its frequency drop to 59.903 Hz at 3:49 p.m. as its area control error fell 2,942 MW below its target. The RTO said the incident resulted from multiple unit trips, non-approved real-time security-constrained economic dispatch (RTSCED) cases, a drop in Eastern Interconnect frequency and poor synchronized reserve response.

Staff made recommendations for all but one of the causes. Removing ambiguity in operating procedures regarding parameter-limited schedules would address units called online that didn’t respond. Analyzing unit-tripping trends would help determine why multiple units tripped. Creating a procedure that helps dispatchers decide whether RTSCED data is valid based on system conditions would address why the RTSCED cases weren’t approved during the incident.

PJM also plans to stop approving time error corrections during emergency procedures or frequency excursions, which it said can exacerbate problems.

pjm operating committee frequency drop — Bielak | © *RTO Insider*

“It takes several hours at a lower frequency to get that time error back; there’s kind of an inherent risk whenever [you] go off 60 Hz,” PJM’s Donnie Bielak said. He added that simply scheduling time error corrections at night also isn’t a good idea because it would push units into minimum-generation operations that don’t allow them full flexibility to respond to other system changes.

Bielak said an unexplained drop in frequency across the entire Eastern Interconnection accounted for half of the problem.

“We’re certainly looking to get to the bottom of that,” he said.

Preliminary Budget

PJM’s Jim Snow presented the RTO’s preliminary project budget for 2019, which anticipates spending approximately $42 million on capital expenditures. The vast majority — approximately $39 million — will go to existing assets, including applications, systems reliability, replacements, facilities and infrastructure.

In response to a stakeholder question, Snow said about $4.4 million in projects were considered but deferred, including hardware replacements, enhancing existing monitoring tools, automating the Regional Transmission Expansion Plan and other corporate reports, implementing soak time by adding generator ramp time to day-ahead markets, and implementing a tool to register energy efficiency and non-retail behind-the-meter generation.

“This is part of a larger process,” Snow said.

At a separate presentation before the Planning Committee later in the week, Snow confirmed that the budget can be revised to address any issues that arise that require commitments from PJM.

“I would tell you if FERC issued an order, we would go back and reprioritize,” he said.

The response satisfied Greg Poulos, the executive director of the Consumer Advocates of the PJM States.

“I want to make sure there’s enough resources allocated to the Planning Committee to make sure they can get their job done,” he said.

New Reactive Transfer Interfaces

PJM’s Christina Catalano introduced two changes to reactive transfer interfaces, which the RTO uses to control voltage contingencies associated with high transfers during transmission outages.

The Central Pennsylvania interface, which includes the Lackawanna-Hopatcong, Sunbury-Juniata and Susquehanna-Wescosville 500-kV lines, was modeled to accommodate an increase in gas-fired generation in the region and planned maintenance outages on the 500-kV system. One such outage is planned for Oct. 16-20.

Catalano said staff anticipate the interface only becoming significant during the outage in case a second transmission line goes out. PJM’s Paul McGlynn said “additional contingency would go beyond any criteria we have.”

In the Western Interface, staff are adding the new Vinco substation near Conemaugh on the 500-kV line to Hunterstown. It will become effective when the Vinco substation is energized, which is expected on Oct. 16. Because of its proximity to the Conemaugh substation, staff expect minimal impact.

— Rory D. Sweeney

September 18, 2018

The Slow Death of Merchant Generation in MISO

By Mark J. Volpe

MISO recently announced that its Value Proposition provided annual quantitative benefits of $3.3 billion to its members during 2017. In the past, MISO has announced similar levels of overall monetary benefits attributable to its Value Proposition; however, over the years, based on the business decisions of numerous merchant-owned generation companies in MISO, including the non-regulated generation arm of several utilities, the overall value MISO membership provides the independent power producers is undoubtedly questionable at best.

The gradual exodus of merchant generation out of MISO began in 2009 when FirstEnergy announced it would leave MISO and consolidate all its assets from their wholly owned subsidiaries American Transmission Systems Inc. and the non-regulated generation fleet of FirstEnergy Solutions into PJM. Anthony J. Alexander, president and CEO of FirstEnergy at the time, stated, “Aligning all of our transmission assets with PJM will provide customers with the benefits of a more fully developed retail choice market and enhanced long-term planning that supports construction of new generation when and where it is needed.” Quickly following suit, Duke Energy announced in May 2010 that its Ohio and Kentucky utility subsidiaries would quit MISO and join PJM. An industry analyst observed that “Duke’s motives were clear, and the move was widely ascribed as a bid to cash in on the substantial revenues available in PJM’s capacity market, the Reliability Pricing Model (RPM), which had proven much more lucrative than MISO’s much less formal monthly voluntary capacity auction. FirstEnergy already had sought the same advantages.”

| *Coalition of Midwest Power Producers*

After the Ohio companies left MISO, in a surprising turn of events during 2012, unable to find a buyer after a long-term power purchase agreement had expired, Dominion Resources announced it would shut down their 574-MW Kewaunee nuclear reactor located in Wisconsin. What made this decision somewhat puzzling at the time was EPA’s focus on clean air regulations; however, Dominion had made the decision to forge ahead with decommissioning its environmentally friendly nuclear facility. The following year, St. Louis-based Ameren announced the sale of its entire non-regulated generation portfolio located in downstate Illinois to Dynegy (recently merged with Vistra Energy) to focus on its rate-regulated electric, natural gas and transmission operations and remove $825 million in debt from its balance sheet. Dynegy paid no cash in acquiring all of Ameren Energy Resources coal units totaling 4,119 MW — only assuming the debt.

In 2014, Tenaska Capital Management, owner of a highly efficient, natural gas-fueled combined cycle facility New Covert merchant power plant in Michigan, announced plans to directly interconnect the 1,100-MW plant with PJM in June 2016. Tenaska invested millions in the construction of a new substation, a 345-kV transmission line and significant transmission system upgrades to literally build their way out of MISO. New Covert had cleared capacity in PJM’s RPM auction in May 2013 and May 2014. Tenaska Senior Vice President Brad Heisey stated, “PJM is a good fit for merchant wholesale generators such as New Covert. It has a balanced, forward-looking capacity market that should provide certainty for covering the facility’s fixed costs.” The same year, Calpine sold their Mankato Power Plant, a 375-MW natural gas-fired, combined cycle power plant located in Minnesota, to Southern Co. subsidiary Southern Power for $395.5 million plus working capital. Calpine President and CEO Thad Hill said, “Mankato is a modern, efficient and well-performing plant under long-term contract to the local utility with an expansion in advanced development. This sale is another step in our capital allocation plan to divest plants in non-core regions when we see an attractive value opportunity.” Another major MISO merchant player, NRG Energy, recently announced its intention to sell its entire 3,555-MW South Central business to Cleco Corporate Holdings for $1 billion.

The slow death of merchant generation in MISO has been pervasive with more than 25,000 MW exiting MISO over the last decade. The strategic motivation behind several of these companies’ business decisions is very clear: monetize assets in MISO to optimize their generation portfolios for participation in the better designed eastern U.S. capacity markets. None of the companies have folded their tents and gone out of business! They can operate successfully and turn a profit in markets other than MISO. These companies decided better opportunities could be found by deploying their capital resources elsewhere. This chain of events is not a coincidence, and in our next column, we will analyze the underlying circumstances behind these business decisions forcing the independent power producers to leave MISO.

Mark J. Volpe is the President & CEO of the Coalition of Midwest Power Producers (COMPP), a newly formed non-profit trade association focused on the continued evolution of fully robust wholesale energy and capacity markets in MISO. He is the former Senior Director of Regulatory Affairs for Dynegy Inc. and continues to serve as chairman of the Independent Power Producer sector on MISO’s Advisory Committee working actively within the stakeholder process at MISO and PJM advocating on energy and capacity market design issues.

September 17, 2018

SPP Briefs: Week Ending Sept. 14, 2018

SPP stakeholders on Wednesday approved staff’s recommendation to remove American Electric Power’s 2-GW Wind Catcher Energy Connection project from the 2019 Integrated Transmission Planning’s (ITP) assessment scope.

The Markets and Operations Policy Committee approved the scope change by an 82.1% vote during a special conference call. Staff said the call was necessary to keep the ITP work on schedule to meet its planned completion in October 2019.

The change removes Wind Catcher, planned for near Tulsa, Okla., from two study futures. The MOPC had approved the scope earlier this year.

AEP canceled the $4.5 billion project in late July, one day after the Texas Public Utility Commission ruled against the proposal. (See AEP Cancels Wind Catcher Following Texas Rejection.)

Staff presented three options to the MOPC. The recommended option maintains the assessment’s timeline and makes use of the 215 resource hours staff has already put in.

Juliano Freitas, SPP’s manager of economic planning, said staff had already proceeded with the option to mitigate any schedule delays. He said the original assumptions included an expectation that Wind Catcher would be built; “thus it is appropriate to remove it and reduce the wind levels to be studied by a corresponding amount.”

The original scope included 32 GW of wind energy.

One other option was to continue the ITP without changing the model, with Wind Catcher acting as a “proxy” for other wind generation in the area.

The third option would have replaced the project with other wind sites, keeping the same 32 GW of wind.

MMU White Paper Proposes Capturing ESRs’ Opportunity Costs

The Market Monitoring Unit has published a white paper that proposes a framework for capturing the opportunity costs of electric storage resources’ (ESRs) mitigated energy offers.

The MMU produced the document to respond to FERC Order 841, which addresses electric storage participation in RTO and ISO markets.

MMU Manager Barbara Stroope said in an email to RTO Insider that ESRs are new technologies with costs that are “potentially quite different from traditional generation resources.” She said the paper provides “a solid theoretical foundation for the design efforts currently underway in SPP, and we think it can serve as the basis for a design that balances accuracy with simplicity.”

The white paper defines a mitigated energy offer as reflecting a generating resource’s short-run marginal production cost. Typically, the calculation derives from variables that include the incremental heat rate and fuel cost (where applicable), and variable operations and maintenance cost. The short-run marginal cost may also include the opportunity cost of foregone incremental generation when a resource’s ability to operate is limited.

“In the case of an [ESR], generating or charging at a given point in time may only be possible by forgoing profit opportunities later in the day or optimization period,” the MMU staff wrote, saying it’s “appropriate” to include the marginal opportunity cost in the basis for an ESR mitigated energy offer.

“The marginal opportunity cost of an ESR at any point in time is most accurately determined as the result of a dynamic optimization problem that considers the resource characteristics, state-of-charge and all future profit opportunities in the optimization period,” the MMU said.

Admitting that this approach could be “difficult or impractical” to implement in calculating a mitigated energy offer, the Monitor said a “reasonable approximation of this opportunity cost” can be determined for ESRs with relatively short charge and discharge times by “considering a simplified case to establish a lower bound of expected profits.” The lower bound would be represented by the maximum profit that would be earned if actual prices were realized as predicted.

“The approximation of marginal opportunity cost can then be determined by assessing the reduction in this expected maximum profit that may result from operating at a given point in time,” the MMU said.

July M2M Payments in MISO’s Favor

MISO reversed 11 months of market-to-market (M2M) payments to SPP, incurring $1.7 million in its favor in July. The RTO has not been on the positive side of M2M payments since July 2017.

MISO and SPP outages in North Dakota and western Minnesota contributed to heavy loading on two temporary flowgates. The two constraints were binding for a combined 91 hours, accounting for slightly more than $773,000 in payments to MISO.

Temporary flowgates were binding for 416 hours in July. Six permanent flowgates were binding for 45 hours, leading to a little more than $15,000 in M2M payments in SPP’s favor.

July’s results reduced MISO’s M2M payments to SPP to $51.9 million since the two grid operators began the process in March 2015.

— Tom Kleckner

September 17, 2018

NERC Circulating Study on ‘Accelerated’ Retirements

By Rory D. Sweeney

VALLEY FORGE, Pa. — Generation reserve margins might drop and fuel-assurance risks could increase if coal and nuclear units retire sooner than anticipated, according to the preliminary findings of a NERC study focused on PJM and ERCOT.

PJM staff confirmed at the RTO’s Planning Committee meeting on Thursday that NERC had discussed the study at its own Planning Committee meeting earlier last week. The draft report has been sent out to members of NERC’s PC for comment, with the reliability overseer planning to present the final version to its Board of Trustees at its meeting on Nov. 6-7.

NERC spokesperson Kimberly Mielcarek said the target for public release is “before the end of the year.”

She declined to provide details before the study is final but pointed to the PC agenda, which outlines the study’s history.

NERC began soliciting policy input in May 2017 from stakeholders, proposing to conduct “an assessment of the potential impacts on Bulk Power System (BPS) reliability that could be caused by accelerated retirements of traditional baseload generator resources … to understand and address reliability challenges associated with the changing resource mix.”

NERC staff analyzed aggregated supply and demand projections for the study, along with engineering studies on specific retirement scenarios. They also reviewed regional processes for managing plant deactivations.

According to the agenda’s description, the study found that “when generation retirements exceed or outpace needed replacement resources, the BPS is less capable of withstanding contingencies, unplanned facility outages and extreme conditions.”

It added that “replacing retiring coal-fired and nuclear generation with natural gas-fired generation provides essential reliability services but can result in near-term stress on the natural gas infrastructure and create challenges to fuel deliverability in extreme winter conditions and major natural gas contingencies.”

Managing those issues will require “continued adherence to rigorous resource adequacy assessment and transmission planning processes” as “large amounts of generator retirements can result in extensive network upgrade requirements” and “potentially the increased use of out-of-market solutions such as reliability-must-run (RMR) designation to address resource adequacy issues,” NERC said.

September 16, 2018

NYPSC Takes Subway into Value Stack

By Michael Kuser

ALBANY, N.Y. — The New York State Public Service Commission on Wednesday expanded the eligibility of distributed energy resources to be compensated under the state’s “value stack” tariffs, particularly standalone storage systems with 5 MW or less of capacity.

nyiso nypsc vder con ed value stack — | *NY DPS Webcast*

The commission’s Sept. 12 order (Case 15-E-0751; 15-E-0082) mentions that “energy storage systems charged by using regenerative braking technologies, such as those used by New York subway systems, be eligible for the Value for Distributed Energy Resources (VDER) tariff for any hourly injections to the grid.”

The order also authorizes interzonal crediting, allowing DERs receiving value stack compensation to apply credits to the bills of customers in the same utility territory but different NYISO load zones.

“It’s good policy to continue to expand the value stack to new types of projects and to larger sizes of existing projects,” Commissioner Gregg C. Sayre said.

Ted Kelly, assistant counsel for the Department of Public Service, testified that combined heat and power (CHP) systems would not be eligible for value stack compensation now, but that staff would analyze CHP to establish “under what conditions CHP would be eligible and that greenhouse gases would not be worse than under system power and that it does not cause local impacts in sensitive areas such as environmental justice areas.”

The PSC in February ordered the state’s utilities to open participation in their value stack programs to DER projects up to 5 MW, more than doubling the previous 2-MW limit. (See NYPSC Expands VDER Project Size to 5 MW.)

The commission’s original VDER order of March 2017 (Case 15-E-0751) directed that compensation for eligible DER transition from net energy metering (NEM) to the value stack, a methodology that bases compensation on the benefits provided by the resources.

The new order expands the eligibility for value stack crediting to any clean generation technology that qualifies as a Tier 1 resource under the Clean Energy Standard (CES). The new rules also make resources that would qualify for Tier 1 but for their start date before the Jan. 1, 2015, eligible for compensation under the value stack.

The new eligibility rules also cover tidal energy generators, biomass generators and food waste digesters that meet CES requirements.

“There is no reason to exclude any renewable DERs from value stack compensation, as the value stack represents a determination of the actual value created by those generators,” the commission said.

Commissioner Diane Burman voted against the measure.

“Some of this has direct impact on other pending proceedings, including some declaratory ruling requests,” Burman said, adding that careful analysis and wording is needed to prevent unnecessary requests for clarification of commission orders.

In a related matter on its consent agenda (Case 18-E-0130), the commission accepted the environmental review of policy options to implement New York’s Energy Storage Roadmap, supporting the state’s energy storage target of 1,500 MW by 2025.

PSC Rules on CDG Compensation

The PSC backed NRG Community Solar in its dispute with Central Hudson Gas & Electric and Orange & Rockland Utilities over compensation for NRG’s community distributed generation (CDG) projects.

The commission’s declaratory ruling (18-E-0485) said the NRG Energy subsidiary had identified a conflict between the PSC’s VDER transition order and the utilities’ Phase One NEM tariffs.

NRG said the utility tariffs would pay its projects through monetary crediting (dollar-value credits based on the $/kWh rate applicable to the project) although they were designed assuming they would receive more lucrative volumetric crediting (kilowatt-hour credits that reduce the bill based on the $/kWh rate applicable to that subscriber).

“CDG projects receiving compensation under Phase One NEM … should receive volumetric crediting, regardless of the project’s service class, meter type, or billing methodology,” the commission said. “As this declaratory ruling is explaining and clarifying the effect of prior orders, rather than establishing a new rule or modifying existing rules, it applies to all utilities with VDER tariffs.”

The ruling does not affect the compensation of CDG projects receiving value stack compensation.

“There is in fact an inconsistency between the orders and tariffs cited here,” PSC Chair John Rhodes said. “That fact is objectively true. I find this recommendation carefully and clearly addresses that inconsistency.”

Burman voted against the ruling. “What if the issue is we didn’t intend it, but that’s what happened and we didn’t do the right analysis?” she said. “If we’re saying there’s an inconsistency between the VDER order and the tariff, maybe we need to look more closely at some of the challenges that are being raised with the VDER order.”

PSC Expands Con Edison EV Smart Charging

The PSC approved Consolidated Edison’s request to expand its electric vehicle charging program, SmartCharge NY, to allow the utility to offer incentives to customers who charge medium and heavy-duty EVs during off-peak hours.

The commission’s order (Case 16-E-0060) said “it is critical to begin testing the efficacy of off-peak charging programs for the full gamut of EVs at a time when EV penetration is comparatively low.”

“This strikes me as a useful, budget-prudent and limited expansion of an existing and innovative program, tailored to some market realities,” Rhodes said.

Burman voted against the expansion, saying “this order does not clearly define or give clear guidance on the specifics of the implementation plan.” She said the commission was shirking the “hard work” of defining potential logistical issues.

The order noted that the transportation sector is the largest contributor of GHG emissions in the state, and that diesel-powered medium and heavy-duty trucks account for a disparate share of total automobile pollution.

Expanding the SmartCharge NY program should cut carbon emissions and help meet the state’s goal of reducing GHGs by 40% by 2030, the commission said.

New York’s Zero-Emissions Vehicle (ZEV) plan calls for creating statewide EV infrastructure to support 30,000 to 40,000 EV sales by the end of 2018 and 10,000 charging stations by 2021. The commission reported 26,470 EVs are now registered in New York.

On its consent agenda, the commission also approved Con Ed’s shared solar program for low-income customers, with modifications, and with a budget not to exceed $9 million (Case 16-E-0622).

September 16, 2018

Massachusetts Deploys Utility-Scale Energy Storage

By Michael Kuser

National Grid has begun operating a vanadium redox-flow battery (VRB) with its 1-MW solar PV array in Shirley, Mass., to demonstrate utility operation of storage.

The company was the prime recipient of an $875,000 Massachusetts grant awarded to an application team that also includes Vionx Energy, Worcester Polytechnic Institute and the Energy Initiatives Group. (See Massachusetts Awards $20M in Energy Storage Grants.)

Carlos Nouel, vice president of innovation and development at National Grid, told RTO Insider that “the Shirley project will serve as a test bed for integrating storage and solar through the use of flow batteries, and support the development of new frameworks for dispatching stored solar power.”

national grid energy storage vrb solar vionx energy — This table details feeder and solar site characteristics for National Grid’s site in Shirley, Massachusetts. | *National Grid*

Massachusetts lags far behind California in deploying utility-scale energy storage, but it is trying to integrate the technology into its power supply.

California utilities must procure more than 1.3 GW of energy storage by 2020. As of August, the state’s three largest investor-owned utilities are in the process of actually procuring nearly 1.5 GW, with about 332 MW currently online, according to a report last month by the California Energy Commission.

In contrast, Massachusetts last year said the state’s utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020. ISO-NE in April reported more than 500 MW of storage capacity in its interconnection queue. (See Overheard at the Energy Storage Association Annual Conference.)

Home-Grown Storage

Vionx (rhymes with “bionics”) is supplying the energy storage system for the Shirley solar project, which lies about 30 miles west of the company’s lab and headquarters in Woburn, Mass.

The company uses vanadium rather than lithium for energy storage, seeing the alternative flow battery technology as the best fit for utility-scale applications, including microgrids or industrial, behind-the-meter systems.

The use of vanadium in a flow battery was first explored in the 1930s and only made workable in Australia in the mid-1980s. Today, many companies use the technology, from giant Sumitomo to tiny CellCube, a VRB manufacturer trying to vertically integrate with its own vanadium mine in Nevada.

A VRB stores chemical energy in the form of vanadium-based electrolyte and generates electricity by inducing a reduction-oxidation (redox) reaction: that is, a transformation of matter by electron transfer across an ion exchange membrane, within a battery stack. The reaction is achieved by either applying an electrical load (discharge) or an electrical supply (charge) to the battery stack as the electrolyte is flowing or being pumped across the membrane.

“Lithium is dominating the storage market, but it is not always the best tool for the job,” said Jonathan Milley, director of business development at Vionx. “Lithium batteries are really for power applications, best-suited for short duration purposes, while vanadium flow batteries are for energy applications, and are therefore a more serious tool for keeping the lights on overnight.”

A lithium-ion battery undergoes a physiochemical change that degrades the electrodes during charging and discharging, but with a VRB, the charge differential is created by an ion exchange across a membrane, meaning the element does not wear out.

“So unlike the lithium-ion battery in your laptop, you never have to replace a Vionx battery,” Milley said. “Certain applications in the grid can cause huge challenges for a lithium-ion system. If you’re trying to drive a screw in, don’t use a hammer.” The Vionx system is also safe and cannot burn because the electrolyte is 70% water, he added.

Elemental Capacity

“The vanadium doesn’t wear out; it doesn’t degrade; it doesn’t need to be replaced or augmented,” Milley said. “The vanadium goes in the electrolyte on Day 1, and if 30 years from now you want to take the whole system apart, the vanadium is fully recoverable. It retains its commodity value [it is a key component in steel production] because it’s not consumed.”

Because the electrolyte is flowing past the electrode, a flow battery allows for the physical separation of capacity and energy, or megawatt and megawatt-hours. Vionx takes an architectural design that capitalizes on that ability and separates the two intentionally, Milley said.

“This allows for scaling at increasingly greater economies of scale; since we are adding only electrolyte to get an additional hour of run time, the cost per kilowatt-hour is much less for a 10-hour system than for a four-hour system. Also, if we have a customer who’s looking at eventually using the system to clear in the PJM capacity market or to be used as a reliability product, but in the near term needs ramping support and load reduction, then a four-hour system can be installed initially, and in the future another six hours of electrolyte can be added to achieve a 10-hour duration system,” Milley said. “Only the electrolyte is added, not any battery stacks, pumps or control components.”

Milley acknowledged that vanadium can be expensive, but he said it is still cheaper for long-duration applications than a solid-state battery that requires the purchase of more cells to expand its capability.

“In our case, you’re simply buying one component or one aspect of the system,” he said.

Team Effort

Vionx is owned by Starwood Energy Group, Vantage Point Capital and other private equity firms, and by United Technologies, whose battery stack design is under exclusive license to Vionx.

3M supplies the membranes and Jabil is the system fabricator. Glencore is currently supplying the vanadium electrolyte, by sale or lease, depending on whether the buyer wants to book it as a capital expenditure or operating expense. Siemens cooperates on a project-by-project basis.

September 16, 2018

MISO Sees Small Chance of Fall Emergency Procedures

By Amanda Durish Cook

CARMEL, Ind. — MISO has sufficient resources available to once again cope with unseasonably warm conditions this fall, although there is a small risk it may be forced to order emergency procedures.

The RTO foresees a 19% chance that it will invoke emergency operating procedures to call on load-modifying resources (LMRs) this fall, stakeholders learned at a Sept. 13 Market Subcommittee meeting. Those resources are not obligated to respond when called upon after Sept. 1. MISO expects to have about 11.8 GW of available LMRs, based on availability forecasts provided by resource owners.

MISO forecasts anywhere from a 110- to 120-GW peak load for September and said it prepared for loads more in line with summer conditions. The National Oceanic and Atmospheric Administration predicts above-normal fall temperatures for the MISO region.

miso peak load modifying resources lmr — Furnish | © *RTO Insider*

“September generally aligns more closely with summer system conditions, at least for the last few years,” said Jeanna Furnish, MISO manager of outage coordination.

Furnish said the RTO has so far this month experienced loads topping out at 114 GW, within about 1 GW of peak fall loads over the last three years.

For the last four years, MISO’s actual fall peak load has trended about 5 to 9 GW higher than load-serving entities have forecasted in 50/50 probability forecasts.

“There’s a 20% chance that we will go into emergency operating procedures at least once this fall,” he explained.

Some stakeholders wondered if MISO’s prediction was optimistic. Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out NOAA predictions of a 40 to 60% chance of a major storm forming in the Gulf of Mexico last week. During the meeting, stakeholders also received an emailed capacity advisory notice for a possible shortage on Sept. 17 owing to outages and residual weather conditions from Hurricane Florence. MISO rolled out the new notification system in August for situations when its all-in capacity is forecast to be less than 5% above operating needs. (See “New Notification System,” MISO Moving to Combat Shifting Resource Availability.)

September 16, 2018

PUCT Grants Oncor CCN for Far West Texas Project

The Public Utility Commission of Texas on Friday approved Oncor’s application for a certificate of convenience and necessity to begin work on its Far West Texas Project, a transmission upgrade to meet the Permian Basin’s oil and gas production load growth (Docket 48095).

ERCOT approved the Odessa EHV-Riverton and Bakersfield-Solstice 345-kV transmission lines in 2017. The grid operator’s Board of Directors designated the Odessa-Riverton line as critical to system reliability in February. (See “Directors Grant ‘Critical’ Status to West Texas Project,” ERCOT Board of Directors Briefs: Feb. 20, 2018.)

The project is expected to cost $336 million to $501 million, depending on the route selected. Oncor has presented a recommended route and 88 alternatives, each between 110 and 133 miles in length.

Oncor said it has already acquired between 12 and 15% of the right of way, depending on the route selected.

Garland, Cross Texas to Share 345-kV Line

ercot puct oncor far west texas project — Limestone-to-Gibbons Creek transmission line | *Cross Texas*

The PUC approved a request by Cross Texas Transmission and the city of Garland to share a 67-mile transmission line, completed as part of the Houston Import Project (Docket 48202).

Cross Texas will transfer 38 miles of the Limestone-to-Gibbons Creek 345-kV double-circuit transmission line to Garland. Cross Texas, a unit of LS Power, built the line under an agreement with Garland, which paid for a portion of the line during construction. The line was energized in April.

ERCOT had directed the entities to build the line and upgrade the Gibbons Creek substation as part of the $590 million Houston Import Project. The rest of the project comprised transmission and substation upgrades.

PUC to Intervene in FERC Dockets

The commissioners went into a closed session as soon as they convened their open meeting. Following the 39-minute executive session, Walker said the PUC would intervene in three dockets at FERC:

ER18-2358, which would place GridLiance’s Oklahoma transmission facilities and its annual revenue requirement under SPP’s Tariff.
ER18-2273, in which MISO seeks a one-year waiver of its Tariff requirement to conduct quarterly voltage and local reliability (VLR) studies. The RTO also seeks permission to designate a VLR issue in the Baton Rouge, La., area as “commercially significant,” thus allocating the costs to load-zone asset owners in the EES, CLEC, LEPA and LAGN local balancing authorities.
ER18-2363, a MISO request to revise part of its resource adequacy construct, creating external resource zones, allocating excess auction revenues to load-serving entities affected by the changes, and aligning parameters used to calculate auction inputs.

The PUC also agreed to publish questions for stakeholder comment for a rulemaking addressing battery storage and other non-traditional technologies in delivery service (Project 48023).

It also set a deadline of 8 a.m. Sept. 17 for retail electric providers (REPs) to list their offerings in both Spanish and English on the commission’s Power to Choose website, where consumers in Texas’ competitive areas can shop for electricity providers.

Chair DeAnn Walker noted 34 of the 57 REPs on the website don’t include their offerings in both languages.

“I’m not happy with that at all,” Walker said. “I’ll give them the weekend to get it done. If they don’t have it at 8 a.m. Monday, [staff] will start pulling off the ones that aren’t” bilingual.

True to her word, the PUC deactivated 221 electricity plans from 18 retail electric providers Monday morning. Some plans were quickly reactivated later in the day, when the REPs listed their offerings on both websites.

The ERCOT market has 117 REPs that offer more than 900 electricity plans.

ERCOT Files Bylaw Changes for Approval

ERCOT on Sept. 11 filed amendments to its articles of incorporation and amended and restated bylaws for the PUC’s approval. The grid operator hopes to have the changes in place for the 2019 operating year.

The ERCOT board approved the changes in August, the first to the governing documents since 2000. The amendments to the bylaws clarify the definition of affiliates and affiliate relationships.

— Tom Kleckner