Page 1097 – RTO Insider

November 19, 2018

MISO to File Queue Changes Before Year-end

By Amanda Durish Cook

MISO will soon file a proposal with FERC to relieve its overfilled generation queue by implementing more stringent site control requirements and increasing the milestone payments imposed on project owners.

The proposal is down to a final review from the Planning Advisory Committee, stakeholders learned during the committee’s Nov. 14 meeting. MISO Resource Interconnection Planning Manager Neil Shah said the RTO will file the queue changes before the end of the year.

“Why is MISO revising its queue again when it just did a queue redesign two, three years ago? And the answer is, yes, the queue reform implemented in 2017 is working, but there are areas that we need to tweak because MISO’s queue is getting clogged with numerous projects,” Shah said.

Staff say the changes will encourage stalled projects to withdraw from the queue earlier in the process. (See “MISO to File Queue Changes,” MISO Queues up Interconnection Options.)

Shah said MISO currently conducts unnecessary definitive planning phase (DPP) studies because unready projects enter the first phase of the queue without first securing a location and are nevertheless studied. He said such projects often withdraw too late in the DPP process, affecting other projects and complicating their subsequent studies. The RTO wants to make the queue easier for projects that have site control, are viable “and have done their homework.”

MISO will now define site control as 50 acres/MW for wind generation, 5 acres/MW for solar generation, 0.1 acre/MW for battery storage and 10 acres for other resource types. An interconnection customer that wants to secure less land than required will now have to hire consultants to prove their project does not require the full amount of space.

Documentation of exclusive site control will now be due 90 days before MISO begins queue studies. The RTO will also no longer accept a $100,000 cash fee in lieu of site control. Shah said 75% of the projects entering in the April 2018 cycle and 62% of the projects entering in the August 2017 cycle elected to pay the $100,000 fee instead of demonstrating site control.

However, MISO will still allow interconnection customers experiencing regulatory holdups to submit a refundable, $10,000/MW fee along with detailed documentation and affidavits demonstrating the restrictions. It will also change the first milestone payment from a $4,000/MW fee to 10% of the average network upgrade cost from the RTO’s last three DPP cycles. The second and third milestone fees will remain unchanged at 10% and 20% of network upgrades costs found in system impact studies, respectively.

MISO will now withdraw a project before the queue’s second decision point if the customer fails to demonstrate exclusive site control.

The proposal also alters MISO’s current practice of refunding 100% of the first and second milestone payments at the two decision point “off ramps” embedded in the queue, where projects can drop off without risking the most recent fees. The RTO will now only refund 50% of the first milestone payment at the first decision point and 75% of the second milestone payment if a project withdraws at the second decision point.

Shah said MISO is expecting another heavy round of queue entrants in the first quarter of 2019 and that the changes will help in the long term to limit the number of projects that enter and trigger multiple studies. The queue currently contains nearly 80 GW worth of generator projects.

Multiple stakeholders thanked MISO for researching and proposing the queue changes.

“I really appreciate MISO making these changes to progress the queue and not allowing it to reach a stalemate. I really hope this will make things better so we can do our job at the state level,” Minnesota Public Utilities Commission staff member Hwikwon Ham said.

Additional work on the queue will continue in 2019. The Interconnection Process Task Force (IPTF) will work early next year to propose rules that allow hybrid generation interconnections and two generators to share one point of interconnection.

The IPTF may also begin work on several stakeholder suggestions currently on hold. They include:

Reducing phase one of the DPP by 30 days;
Cutting down the generation interconnection agreement timeline from 150 to 90 days;
Putting a megawatt limit on the total number of projects that can enter a queue cycle; and
Reviewing how many projects submit cash versus a letter of credit for milestone fees, possibly opening the credit practice to changes.

Freshly Minted Interconnection Working Group

MISO will also be providing the IPTF with a facelift after agreeing to convert the task force into a more permanent working group.

The IPTF was set to sunset in January. In MISO’s stakeholder structure, working groups are more permanent than task forces, which have an expected sunset date.

The Steering Committee approved the move by general consent on Nov. 15, adopting the October consensus from the PAC. MISO’s eight voting stakeholder sectors voted 5.33 in favor, with 0.67 opposed and two abstentions, to convert the task force into a working group. (See MISO Stakeholders Rally to Save Interconnection Group.) MISO sectors are allowed to split their votes based on differing organization and company opinions within a sector.

Seeing the “overwhelming” vote in favor of the move, MISO Director of Planning Jeff Webb said the RTO will now support the move, despite initially opposing the change. MISO had initially recommended the IPTF merge into the Planning Subcommittee, because both deal with technical issues of modeling and study processes used in its annual Transmission Expansion Plan.

Webb said the RTO believed that a group merger was “pretty consistent with … MISO’s stakeholder redesign,” which discourages duplicate discussions across stakeholder groups. However, he said MISO will be able to continue to provide staff, liaisons and meeting space for an Interconnection Process Working Group.

PAC Chair Cynthia Crane said it was important for MISO to recognize the strong stakeholder consensus to preserve a working group.

Additionally, the Steering Committee adopted additions to the Stakeholder Governance Guide that clarify rules around sunset dates for MISO groups. The committee added language that parent committees and the Steering Committee “should be diligent in the review and manage of entity sunset dates” of task teams and task forces. The language also specifies that motions for retirement should originate in the groups in question, with the Steering Committee “charged to review and manage sunset dates if applicable.”

Parent entities will be responsible for bringing retirement recommendations before the Steering Committee. The revisions also specify that the Advisory Committee can vote to “uphold or modify” Steering Committee retirement recommendations, particularly if the Steering Committee, the group in question or the parent entity disagree on whether to retire the group.

November 18, 2018

ISO-NE Planning Advisory Committee Briefs: Nov. 15, 2018

By Michael Kuser

FCA 14 Capacity Zone Development Preview

MARLBOROUGH, Mass. — ISO-NE last week kicked off its formal annual review of the transmission system to delineate zones for Forward Capacity Auction 14, which will be held in February 2020 to cover the 2023/24 capacity commitment period.

Al McBride, the RTO’s director of transmission strategy and services, told the Planning Advisory Committee that “we’re coming out of a significant backlog of interconnection requests in Maine.” He noted that FERC’s approval last year of clustering has enabled the queue to move forward. (See FERC Approves ISO-NE Queue Clustering.)

New England ISO — Potential capacity zone construct for FCA 14. | *ISO-NE*

The first cluster of more than 600 MW is proceeding through the system impact study process, as is an external elective transmission upgrade of 1,200 MW, which are collectively driving the creation of a Maine capacity zone, he said. The RTO is not proposing a Northern Maine capacity zone because the deliverability standard requires new resources in the state to be deliverable throughout the Maine load zone.

“That’s a significant number of new resource additions,” McBride said. “Maine used to be export-constrained, particularly from north to south, but after the Maine Power Reliability Program upgrades, there has been headroom. This headroom would more than be used up by the projects moving forward in the system impact study process.”

The trigger to model an export-constrained zone is based on the quantity of existing and proposed new resources compared with the maximum capacity capability in the zone.

Zone formation is a two-step process: First, identify the potential zonal boundaries and associated transfer limits to be tested for modeling in the Forward Capacity Market; then use objective criteria to determine whether or not the zone meets the trigger to be modeled for the capacity commitment period.

To form capacity zone boundaries, the RTO considers significant changes over the past year, including new transmission upgrades, resource retirements and new capacity resources.

Boundary Specifics

ISO-NE does not expect transmission upgrades in the Southeastern Massachusetts and Rhode Island (SEMA/RI) area to change the boundaries of that area or the Southeast New England zones, McBride said.

Most of the SEMA/RI Reliability Project upgrades have not yet been certified for use in the FCM, and certifications for FCA 14 will be known in January 2019. However, if the SEMA/RI Reliability Project upgrades are certified, planners will assume they will be in place for the 2023/24 period.

Mystic 7 will be retiring with the start of the 2022/23 period. The RTO has previously analyzed different potential future retirement scenarios, including the loss of Mystic 7 and other units, and did not expect such retirements to drive a change in capacity zone boundaries.

Capacity interconnection requests as of Nov. 1 are more than 700 MW from West/Central Massachusetts, with the rest, all nameplate, being more than 4,100 MW from New Hampshire/Vermont; more than 6,200 MW from Maine; more than 7,700 MW from SEMA/RI; and more than 2,700 MW from Connecticut.

SEMA/RI 2028 Needs Assessment

ISO-NE’s SEMA/RI 2028 Needs Assessment Scope of Work study assumes the complete retirement of the 2,274-MW Mystic plant and includes analysis assuming that Vineyard Wind and the New England Clean Energy Connect (NECEC) projects will be in service, according to Kannan Sreenivasachar, ISO-NE’s transmission planning technical manager.

Sreenivasachar told the PAC on Thursday that the study for the 10-year horizon will be using data from the 2018 Capacity, Energy, Loads and Transmission (CELT) report to determine the forecasts for the peak load levels evaluated.

All transmission and generation facilities operating as of June 1, 2018, are included in the base cases, and the 34,092-MW 90/10 summer peak load includes 5.5% transmission and distribution losses.

The study evaluates reliability performance and identifies reliability-based needs in the SEMA/RI study area for the year 2028 while considering future load distribution, resource changes based on FCA 12 results, and the 2018 solar and energy efficiency forecasts, Sreenivasachar said.

The study assumes that resources without an obligation (typically through the FCM) cannot be relied upon to resolve a reliability need and are therefore not considered in the steady state analysis. However, they do contribute to the available short-circuit current, as they may be in service as part of the energy dispatch of the system, he said.

The study bases its short-circuit base case on the expected topology in the 2023 compliance steady state base case. No significant project is expected in the 2023-2028 time frame, and hence the 2023 case was considered acceptable, Sreenivasachar said.

Asked about future generation selected in state solicitations, Director of Transmission Planning Brent Oberlin said there were two options.

He said if the RTO finishes the study ahead of final approval of those projects, the identified needs will be based on conditions without the generation in place. Upon approval of the generation, the needs will be changed to those associated with the scenarios that included the generation. If the generation is approved prior to the completion of the study, the needs associated with scenarios that do not model the generation can be ignored.

Stakeholders should submit comments on the study to pacmatters@iso-ne.com by Dec. 2. The RTO plans to post the draft study and intermediate study files in the first quarter of next year before completing the study area 2028 Needs Assessment and presenting it to the PAC by Q2 2019.

The RTO’s next steps will be to review transmission certifications for FCA 14 with the Reliability Committee in January, and to further discuss the potential capacity zone boundary construct at the PAC in the first quarter of 2019.

Moody’s Sees Region in Good Economic Shape, for Now

Moody’s Analytics Director Ed Friedman told the PAC that New England is leading the Northeast in economic development, particularly job growth, which is not typically the case, as that occurs more frequently earlier in an economic expansion or business cycle.

“That’s been a good development over the past year, but probably not sustainable over the long term,” Friedman said.

Massachusetts and New Hampshire have led the region in new hiring since last October, both outpacing the national average, with Rhode Island very close to the U.S. figure of about 1.7% in employment growth.

“The drivers are the booming tech sector in Boston … and in and around the Seaport district,” he said.

New England is unfortunately hampered by a generally weak and aging demographic outside places like Massachusetts, which holds back labor force growth, he said. “Very good job growth just cannot go on forever” without a growing population to feed the labor force.

The better than 3% wage gains posted in most of the region’s six states over the past year — only Connecticut and Rhode Island fell below that level — will likely continue over the coming year, but consumer confidence in New England is lower than in any other part of the U.S., Friedman said.

November 18, 2018

Montana Wind Farm Exempted from Frequency Response Rule

By Amanda Durish Cook

FERC ruled last week that an existing Montana wind farm awaiting a new interconnection is exempt from a recent commission order requiring all new generators to be capable of providing primary frequency response.

The commission’s Nov. 15 ruling said Order 842 does not apply to NaturEner’s Glacier Wind Farm II, which has been in the queue for Enbridge’s Montana-Alberta Tie-Line (MATL) since 2013 and currently the only resource to request to join the 214-mile, 230-kV AC line extending from Lethbridge, Alberta, to Great Falls, Mont. (ER18-1788). The wind farm began operating in SPP in 2009.

Order 842 requires all new generators to be capable of providing primary frequency response as a condition of interconnection. The rule has been in effect since May.

Enbridge’s U.S. operating subsidiary for the line, MATL LLP, asked the commission to clarify that Order 842 does not apply to the pending interconnection request, saying the wind farm applied for interconnection and was studied before the rule was issued. The company said requiring frequency response service would “cause significant equipment installations and system restudies that would cause unduly burdensome delays and expenditures.” MATL estimated that restudies would cost anywhere from $15,000 to $20,000 and take three to six months.

FERC assured the company that the rule does not apply to the existing generator. The commission pointed out that MATL’s pending request involves a generator that has already been in operation under another interconnection agreement for about nine years and has been lined up for interconnection for five years, well before the issuance of the final rule. FERC also said the wind farm has not taken “any action that requires the submission of a new interconnection request.”

MATL noted that its has nearly completed the associated interconnection studies with NaturEner and expects to proceed with the negotiation of an interconnection agreement in the near future.

November 18, 2018

MISO Gets 5th Winter Waiver of Offer Cap

By Amanda Durish Cook

MISO now has a fifth wintertime waiver of its $1,000/MWh offer cap in hand after FERC approved the RTO’s request on Nov. 16 (ER19-27).

The commission allowed a waiver with conditions identical to the last four. (See FERC Grants MISO 4th Winter Offer Cap Waiver.) The waiver is effective from Dec. 1 through April 30, 2019.

“MISO’s experiences during the 2014 polar vortex, as well as the cold weather events of January 2018, demonstrate that fuel costs can increase to a level such that the current $1,000/MWh offer cap prevents resources from submitting incremental energy offers that reflect their marginal production costs. If similar weather and natural gas supply conditions materialize in the 2018/2019 winter, some resources could face the untenable position of being forced to offer electricity at levels below their actual cost,” FERC said.

Last winter, MISO experienced extreme cold in its North subregion starting Dec. 27, with frigid temperatures hitting the entire footprint Jan. 1 to 6. In all, MISO said the cold snap lasted longer than the 2014 polar vortex. Less than two weeks later, MISO South faced another cold snap. The event is the subject of a joint FERC/NERC investigation, which was announced in early fall. (See FERC, NERC to Probe January Outages in MISO South.)

While MISO said published gas index prices did not hit the $67/MMBtu experienced during the polar vortex, “there were a few resources during late December 2017 that offered within a dollar of the $1,000/MWh energy offer price cap due to high intraday prices for procuring non-firm gas.” The RTO said its ongoing coordination work with neighboring balancing authorities and a lower outage rate kept prices below 2014 levels.

However, MISO said its fourth waiver was helpful in that it granted generator operators peace of mind that they could have recovered costs that inched above $1,000/MWh.

MISO has until Oct. 1, 2020, to implement a $2,000/MWh hard cap for verified cost-based incremental energy offers. (See MISO Granted Longer Deadline for Offer Caps.) The RTO is all but certain to request another offer cap waiver for the 2019/20 winter.

“After implementing the reforms required by Order No. 831, MISO will no longer require temporary waivers because these reforms are intended to provide for a long-term solution to the issues associated with MISO’s offer cap,” the commission said.

In its request for this year’s waiver, MISO said it couldn’t yet tell whether 2014-style price spikes could occur during the 2018/19 winter months.

This year, MISO is using forecasts of a warmer-than-normal winter in much of its footprint, though the RTO says it’s prepping for a 40% possibility of entering emergency procedures at least once during the season. (See MISO Foresees Manageable 2018/19 Winter.)

November 18, 2018

PJM Reiterates Support for Embattled Transource Project

By Rory D. Sweeney

PJM’s highly anticipated re-evaluation of its largest-ever congestion-reducing transmission project reiterated staff’s analysis that the project’s economic benefits to the region exceed its costs.

The $366.17 million project proposed by Transource Energy — the Independence Energy Connection — would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border. One line would run between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; the other would run between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.

Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | *PJM*

The RTO published its findings in a white paper released Thursday that showed a final benefit-cost ratio of 1.4, down slightly from the 1.42 staff reported at the September meeting of the Transmission Expansion Advisory Committee.

The slight decrease is attributable to a roughly $8 million increase in the project’s 15-year annual revenue requirement to $505.85 million. The benefit — measured in decreased load costs — held steady at $707.29 million. The actual estimated project costs increased from $366.17 million at the TEAC meeting to $372.2 million in the white paper.

The 1.4 ratio is still higher than the previous 1.32 evaluation from February and well above the RTO’s 1.25 threshold to consider projects. The current analysis shows that without the project, reliability violations will materialize as early as 2023 on three 115-kV lines in Adams County, Pa., the 500-kV Peach Bottom-Conastone line and the 500/230-kV transformer at Three Mile Island.

The project will also increase the ability to import power into the Baltimore Gas and Electric locational deliverability area.

Opposition

Residents of the region where the lines are planned attended the September TEAC meeting to register their objections, but staff pointed them toward the ongoing project proceedings being held in both states. (See PJM Redirects Residents’ Protests of Tx Project to States.)

The inclusion of newly identified reliability benefits has done little to sway the residents’ opposition, who believe it’s a ploy to avert the project’s potential failure at the state level.

“Faced with near certain failure, PJM is trying to reposition the IEC as a reliability project,” Pennsylvania resident Barron Shaw wrote in a recent blog post. “This is a desperate assertion made by an organization that has no credibility remaining. … Why would anyone believe PJM’s assertion that this project was suddenly all about reliability? The load forecast for the target market is flat, and every year the forecast is decreased. New high-voltage lines in York and Harford County have been constructed and are operating at less than 50% capacity. Recent and pending upgrades to move power across the grid in Maryland have drastically cut electrical congestion. The project is simply not needed.”

Shaw also accused PJM of fixing the ratio analysis and decried the millions of dollars taxpayers and ratepayers are already on the hook for, whether the project ever gets built or not.

“PJM allowed Transource to announce their new cost estimates one month after PJM announced their recalculated benefits for the project, in effect giving Transource the ability to provide the ‘right’ answer and save the project from cancellation,” he said. “This project is dead, and it is time that PJM admits it and moves on … before people begin to question why PJM is needed at all.”

November 18, 2018

ERCOT Sets Wind, Monthly Demand Records

By Tom Kleckner

Papalote Creek Wind Farm in South Texas | © *RTO Insider*

HOUSTON — ERCOT set a pair of demand records last week, establishing new marks for wind energy generation and November monthly demand as temperatures dipped below freezing in much of the state.

The grid operator recorded 17.9 GW of wind generation on Nov. 12, accounting for more than 40% of the generation in its footprint. That broke the old record 17.5 GW set on Feb 19.

ERCOT, which manages the grid for about 90% of Texas, has more than 21 GW of installed wind generation. It has another 40 GW of wind energy in its interconnection queue.

It twice set monthly demand records for November, reaching 55.3 GW the evening of Nov. 13 and 56.3 GW the next morning. That broke the old 2014 mark by more than 5.4 GW.

“We’re busting through these records,” ERCOT CEO Bill Magness said during a Gulf Coast Power Association luncheon. “We continue to see load growth in Texas.”

ERCOT’s last capacity, demand and reserves (CDR) report indicated its load will grow from 71.7 GW in 2019 to almost 78 GW in 2023. The grid operator will release an updated CDR in December, but Magness said he expects the load projections to grow again.

Load projections in West Texas | *ERCOT*

Magness shared with his audience a slide of Culberson County in West Texas, where oil and gas exploration has driven demand through the roof. Eight studies have been conducted in the area since 2014, with a load increase each time.

Petrochemical plant lights up the night sky over Corpus Christi Bay. | © *RTO Insider*

“If you’re a planner, this will make your stomach hurt,” Magness said. “Every time we’ve done a forecast, it’s gone up dramatically.”

The demand record for November was the 10th the grid operator has set since January 2016. Only February and March have demand records that date back to 2015 or earlier.

November 18, 2018

MTEP 18 Advancing with 2 Contentious Projects

By Amanda Durish Cook

MISO staff are seeking to advance the RTO’s full 2018 Transmission Expansion Plan despite stakeholder objections to two projects, board members heard last week.

Staff recommend moving ahead with all 442 projects currently spelled out in the $3.3 billion plan, but the Planning Advisory Committee endorsed only 439 of the proposals, Executive Director of System Planning Aubrey Johnson said during a Nov. 13 conference call of the Board of Directors’ System Planning Committee.

The MISO System Planning Committee of the Board of Directors in September | © *RTO Insider*

The two projects sparking concern at the PAC include the rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota and American Transmission Co.’s Straits of Mackinac project to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas. Stakeholders have complained the costs for the Wabaco-Rochester project will shift from generator interconnection customers to local load customers and have said that an alternate solution would better suit the Mackinaw area.

The third proposal not receiving endorsement has stirred less controversy: ITC Midwest’s capacitor bank project at the Walters 161/69-kV substation in southern Minnesota, which was only held from endorsement to allow MISO to update the project’s details. (See MISO PAC Puts MTEP 18 to Vote, Removes 3 Projects.)

The 10 voting sectors of MISO’s Advisory Committee eventually voted 5.25 in favor of the nearly complete MTEP 18, with 2.75 opposed and two abstentions. MISO’s sectors can divide their single vote based on differing opinions between organizations and companies within the same sector.

MISO is openly defying the strong objections of at least some stakeholders by recommending that the Wabaco-Rochester line and Straits of Mackinac circuit rebuild move ahead as planned.

Johnson said MISO staff are recommending the $11 million Wabaco-Rochester project despite stakeholder concerns over cost allocation and Xcel Energy’s request to defer the project in favor of a larger solution later. The RTO said the project improves market efficiency and has benefits “well in excess of costs” at 6.8:1. Johnson said staff have studied alternatives to the project, including proposals submitted by Xcel.

“The area is experiencing congestion currently, and there are no generator interconnection customers identified as responsible for upgrading this circuit,” MISO said.

MISO also continues to recommend ATC’s $105 million plan to replace its underwater circuit linking Michigan’s Upper and Lower peninsulas, which was damaged last year when the cables were struck by a passing vessel.

While stakeholders agree that ATC’s damaged cables should be replaced, some are divided on whether the cables should be installed on the bottom of the lake or in an underwater tunnel. Stakeholders have raised the possibility of an interim solution if the more complex tunnel option is needed. Some have also proposed alternative or joint ownership of the replaced cables.

Johnson said MISO believes the best course of action is ATC “expeditiously” replacing the cables, which solves the immediate planning issue. He also pointed out that ATC has the right to replace its own equipment under the terms of MISO’s Transmission Owner Agreement.

Johnson added that MISO “does not address regulatory requirements governing the manner of placement of the cables within the straits, as that is a state siting issue.” The siting on the Mackinac project has not been finalized with the Michigan Public Service Commission.

The uncontroversial $11 million Walters substation project was originally proposed as a line and transformer project but has evolved into a capacitor bank installment to improve voltages in the area. The PAC withheld approval so the alternate project could be updated into the MTEP 18 list. MISO said it has since updated the project details and isn’t aware of any outstanding stakeholder issues with the project. Johnson said the issue was resolved prior to the close of the PAC meeting in October.

Stakeholder Pushback

During the call, Director Phyllis Currie asked for stakeholder reaction to MISO’s decision to move ahead with the Wabaco-Rochester project, but none offered opinions during the open comment period. It was later discovered that technical difficulties prevented stakeholders from getting a line opened on the operator-assisted call. MISO held a special comment period by phone on Nov. 15, and CEO John Bear that same day apologized to stakeholders for the mishap during an Informational Forum.

During the make-up call, stakeholders repeated criticisms of the two proposed projects.

Representatives of Wolverine Power Supply Cooperative said the company submitted an alternative proposal to the Mackinac project and said MISO staff may have been too quick to dismiss it.

But ATC’s Brian Drumm said MISO evaluated the project and alternatives properly. He also pointed to ATC’s contractual right to perform upgrades on its own equipment.

Dairyland Power Cooperative’s Terry Torgerson said MISO’s estimated savings on the Wabaco-Rochester line are overstated.

Xcel Energy’s Carolyn Wetterlin said Xcel and MISO also “ended on a disagreement” this year concerning the Rochester-Wabaco line. She said the proposed line only shifts congestion into another area. Wetterlin asked that MISO delay the solution until MTEP 19.

The board will vote on whether to approve MTEP 18 in its entirety at its meeting on Dec. 6.

November 18, 2018

FERC Waives VLR Tariff Requirement in MISO South

By Amanda Durish Cook

FERC last week granted MISO a one-time Tariff waiver allowing the RTO to designate certain Louisiana resources as commercially significant to voltage and local reliability (VLR) without first collecting and studying a year of data to back up the determination (ER18-2273).

MISO plans to allocate the majority of VLR commitment costs incurred in the Fancy Point load area on the Mississippi River to Entergy, which has the largest amount of load and stands to benefit most. Entergy said it did not oppose the waiver, which is effective for one year beginning Aug. 22, 2018.

The RTO’s Tariff requires it to conduct quarterly VLR issue studies using data from the previous 12 months before it can label VLR commitments “commercially significant.”

FERC said the waiver is “narrowly tailored” to allow MISO to make the designation while accumulating the 12 months of data necessary to conduct a study pursuant to its Tariff. It added that the move is “consistent with the principle of cost causation in that it is designed to allocate revenue sufficiency guarantee make-whole payments for VLR commitments to the load in the local balancing areas that benefit from the VLR commitments.”

MISO said that absent a waiver, it would be required to allocate VLR commitment costs to the local balancing area where the VLR-committed resource is located, instead of allocating costs on a load-share basis to the entities that benefit from commitments.

FERC found that MISO acted in good faith on the designation by working with affected parties to create an operating guide and convening a special meeting to discuss VLR issues.

November 18, 2018

NYPSC OKs CCA, Rejects Residential EV Charging Tariffs

By Michael Kuser

The New York Public Service Commission on Thursday unanimously approved renewing Westchester County’s community choice aggregation (CCA) program, which since 2016 has pooled municipalities to purchase electricity and natural gas in bulk.

The New York PSC held its regular monthly session in Albany on Nov. 15, 2018.

The county’s Sustainable Westchester is the only active CCA in the state so far (Case 14-M-0564), though the PSC has approved three others. CCAs also provide consumers increased access to distributed energy resources and efficiency programs and products.

Commissioner Diane Burman supported the order but asked Department of Public Service staff about low-income provisions in the programs.

Ted Kelly, DPS assistant counsel, said, “As with the other CCA programs, Sustainable Westchester can only serve low-income customers with the start of the new, renewed program if they offer and provide those customers with a guaranteed savings product, and they did discuss that in their master implementation plan and acknowledge that they were aware of and would comply with that requirement.”

Commissioner Gregg Sayre said that CCAs are consistent with “increased customer choice and a market-based encouragement of new options for clean energy and distributed energy resources.”

Home EV Charging Tariff Nixed; Revisions Ordered

The PSC rejected tariff filings for residential electric vehicle charging from all the major investor-owned utilities in the state (Case No. 18-E-0206) and ordered them to file revisions that implement time-of-use (TOU) rates equal to the traditional residential customer charge.

“The incremental customer charge associated with TOU rates can deter EV customers from adopting the TOU tariff and can impact a customer’s decision as to whether to purchase an EV,” the commission said. “Minimizing such costs will lower barriers for customers to adopt TOU rates.”

“We know electric vehicles are coming, and we know that it’s up to us to make sure that this coming call on the electric system is managed well,” PSC Chair John Rhodes said. “That in turn calls for good engineering, but also for good economics and, specifically, good rates.”

Mary Ann Sorrentino, acting DPS chief of electric rates and tariffs, testified that the relevant statute (PBS Section 66-o) was intended to provide incentives to buy EVs and encourage the adoption of grid-responsible charging times.

New York law requires utilities to file residential EV charging tariffs and to report periodically, but the commission’s Nov. 15 order defines the reporting as annual and directs Central Hudson Gas & Electric, New York State Electric & Gas, Rochester Gas and Electric, Consolidated Edison and Niagara Mohawk Power to file their annual report every Jan. 30, starting in 2019.

“The tariffs addressing 66-o are essentially similar in that each of the electric utilities proposed a one-year price guarantee for residential customers with qualifying EVs that go on the residential time-of-use rate for their entire load,” Sorrentino said.

Under TOU rates, charges are lower during off-peak hours. The commission has already approved price guarantees for EV owners in Con Ed and Orange and Rockland Utilities service territories to reduce customers’ fear of trying a new rate, she said.

“The PSC has a broader proceeding underway to develop its approach to EVs comprehensively [Case 18-E-0138], but in the meantime, this is a smart, pragmatic adaptation of existing approaches that fits with our principles and makes sense,” Rhodes said.

The commission’s order on residential charging rates “complements the broader proceeding” on EV infrastructure and also the proceeding on the value of distributed energy resources (Case 15-E-0751), Sorrentino said.

Thursday’s order also addresses utilities with residential TOU rates that contain incremental meter charges as opposed to increased customer charges, such as National Grid and RG&E, directing that “residential customers with qualifying registered EVs that take service under residential TOU rates shall not be subject to the incremental charge.”

The commission in September approved Con Ed expanding its EV charging program, SmartCharge NY, 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.”

New York’s zero-emissions vehicle 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 in September reported 26,470 EVs registered in New York.

November 16, 2018

FERC Proposes $10M Threshold on Merger Reviews

By Rich Heidorn Jr.

FERC would no longer review mergers valued at less than $10 million under a Notice of Proposed Rulemaking (NOPR) approved Thursday (RM19-4). The NOPR would implement congressional direction under an amendment to Section 203 of the Federal Power Act.

“The commission interprets the amendment … as establishing a $10 million threshold, but not removing the commission’s jurisdiction to review transactions with a higher value that involve a public utility’s acquisition of facilities from non-public utilities if those facilities will be subject to the commission’s jurisdiction after the transaction is consummated,” FERC said.

The NOPR also would require mergers or consolidations by public utilities valued above $1 million to notify the commission of the transactions.

“Although the [smaller] transactions … are unlikely to present concerns under the commission’s public interest analysis and public utilities entering into these transactions are not required to secure an order of the commission … the information the commission proposes to require in the notification filing will allow the commission to collect information about the transaction should a question arise related to the underlying facilities and the commission’s oversight under the Federal Power Act,” FERC said.

“This may seem like just a simple legislative change, but its impact in relieving administrative burdens on regulated entities is significant,” said Chairman Neil Chatterjee.

Comments on the NOPR will be due 30 days after its publication in the Federal Register.