Page 1112 – RTO Insider

October 14, 2018

NYISO Business Issues Committee Briefs: Oct. 10, 2018

NYISO and PJM last month jointly filed a request with FERC for a waiver of their joint operating agreement (ER18-2442), Rana Mukerji, ISO senior vice president for market structures, told the Business Issues Committee on Wednesday while presenting the monthly Broader Regional Markets report.

The waiver would permit the two grid operators to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. If granted, it will enable PJM to conduct redispatch operations to control flows to the more restrictive rating on the New York side of the line without violating the PJM Tariff for a limited time while the RTO and NYISO work to develop a permanent solution.

NYISO and PJM have jointly filed a request with FERC to waive a portion of their JOA to allow the East Towanda-Hillside tie line to be added as a market flowgate. | *NYISO*

Mukerji also highlighted efforts to clarify the minimum deliverability requirements for external capacity from PJM into NYISO’s Installed Capacity (ICAP) market. The ISO will continue discussions of this topic with stakeholders at the Installed Capacity/Market Issues Working Group meeting this month, he said.

In August, the ISO briefed the BIC on proposed market design changes to improve the supplemental resource evaluation process for external capacity resources.

Improving Public Policy Tx Planning

The BIC approved revisions to improve the efficiency of the Comprehensive System Planning Process in the short term, including eliminating the requirement that the New York Public Service Commission issue an order before NYISO begins evaluating transmission solutions. Under the proposal, the PSC retains the ability to cancel or modify identified public policy transmission needs (PPTNs) prior to the ISO’s selection of the more efficient or cost-effective solution, which would halt the evaluation or result in an out-of-cycle process to address the modified need.

In one case, NYISO had to wait about five months before evaluating and selecting Western New York PPTNs, according to a report by Yachi Lin, senior transmission planning manager. Under the new process, the ISO would begin the process following completion of a viability and sufficiency assessment and if developers meet the necessary requirements to proceed.

NYISO has proposed related Tariff amendments and will seek approval from the Operating and Management committees this month before seeking board approval in November.

In addition, the ISO will clarify in the Tariff that the project description in the transmission interconnection application or interconnection request must match the description in the PPTN proposal or face rejection.

Technical Details

Within 60 days after a formal solicitation from NYISO, interested developers must submit both redacted and unredacted versions of their complete project proposal to satisfy the PPTN, submit identical proposals in the interconnection process and provide a nonrefundable $10,000 deposit and a $100,000 study deposit for each project.

NYISO will then post a brief description of the project proposals within five business days after the solicitation window closes.

The ISO will file the final viability and sufficiency report at the PSC, and within 15 days of the filing, each developer must confirm that it intends to proceed and agree to a system impact study.

Long Term

NYISO will present a long-term process design concept to stakeholders by the end of 2018 to improve its Local Transmission Owner Planning Process (LTPP); Reliability Planning Process (RPP); Congestion Assessment and Resource Integration Studies (CARIS); and Public Policy Transmission Planning Process (PPTPP).

Under the proposal, prior to issuing a formal solicitation, the ISO will hold a technical conference to get input from developers and interested parties on the application of selection metrics to the PPTN.

LBMPs Up 31% Year-on-Year

NYISO locational-based marginal prices averaged $38.70/MWh in September, down from $42.56/MWh in August but up 31% from the same month a year ago, driven by four days in early September in which the peak load topped 28 GW compared with no such days in September 2017, Mukerji said in his monthly operations report.

Year-to-date monthly energy prices averaged $45.75/MWh in September, a 29% increase from a year ago. September’s average sendout was 458 GWh/day, lower than 537 GWh/day in August and 437 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.75/MMBtu, down about 8.3% from August and up 21.5% from a year earlier. Distillate prices climbed slightly compared to the previous month but were up 23.3% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $16.21/MMBtu and $16.08/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour came in lower than August, with the ISO’s 37-cent/MWh local reliability share in September down from 59 cents the previous month, while the statewide share climbed from -61 cents/MWh to -48 cents. Uplift, excluding the ISO’s cost of operations, was -11 cents/MWh, lower than -2 cents in August.

The Thunderstorm Alert (TSA) cost in New York City was 33 cents/MWh, more than double the 14 cents in August.

— Michael Kuser

October 14, 2018

MISO Market Subcommittee Briefs: Oct. 11, 2018

CARMEL, Ind. — MISO’s Independent Market Monitor last week pointed to other RTOs to illustrate the ineffectiveness of the coordinated transaction scheduling (CTS) between MISO and PJM.

Market Monitor David Patton at MISO Board Week in September | © *RTO Insider*

Monitor David Patton told the Market Subcommittee on Thursday that the CTS between ISO-NE and NYISO includes an explicit waiver of uplift and transmission charges between them. As a result, the process last year yielded bids and offers of 700 MW in one direction and 400 MW in the other.

Patton has recommended that MISO remove transmission charges from CTS with PJM. MISO currently applies transmission charges to these transactions when they are offered, not just when they are scheduled, which the Monitor said discourage CTS offers and subsequent savings. (See 7 New Recommendations from MISO IMM.)

Patton admitted that the New England numbers weren’t as high as he’d like, but that it’s important that the coordination is used.

“CTS has basically completely failed between PJM and MISO. Quantities have fallen to essentially zero,” Patton said.

MISO and PJM launched CTS a year ago to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because of the double transmission charges.

MISO will respond to the recommendation later this month, when it releases its formal response to the Monitor’s State of the Market Report.

Dynamic Line Ratings

The Monitor is also renewing calls for MISO to adopt dynamic line ratings that are adjusted based on weather conditions, opening up transmission lines for more capacity when temperatures are cooler.

“The hotter the temperature, the less electricity you want through the conductor,” Patton said. “Transmission owners have long recognized that there are benefits to different ratings. … Every additional megawatt you can flow over the line can help you ramp down a higher-cost generator and ramp up a lower-cost generator.”

Transmission lines are rated based on seasonal ambient temperature and wind speeds. Patton said that of MISO’s TOs, “almost none” submit upratings beyond seasonal limits.

Customized Energy Solutions’ Ginger Hodge asked the Monitor how MISO might incentivize TOs to offer dynamic ratings. “I think there are few that offer dynamic ratings because they introduce risk to their system,” she said.

Patton said TOs themselves can benefit from higher ratings. “This capability is valuable, and they should see an economic value from providing it,” he said.

— Amanda Durish Cook

October 14, 2018

NY Carbon Task Force Looks at REC, EAS Impacts

By Michael Kuser

NYISO on Thursday recommended steps to prevent certain wholesale market suppliers, designated as carbon-free in the New York Clean Energy Standard (CES), from collecting double payments for carbon-emission reductions that have already been captured by renewable energy credit contracts.

“The idea is to prevent these resources from benefiting from a change in [locational-based marginal prices] resulting from a carbon price,” said Michael DeSocio, the ISO’s senior manager for market design. DeSocio presented a report on the treatment of REC contracts to the state’s Integrating Public Policy Task Force (IPPTF), which met by teleconference.

NYISO proposes applying a carbon charge to wholesale market suppliers with active, fixed-price REC contracts with the New York State Energy Research and Development Authority that are based on a REC solicitation that began or was completed prior to the carbon pricing rules taking effect.

At the July 16 IPPTF meeting, the ISO said it was considering options to reduce or eliminate the potential for such double payments. (See NY Sets Carbon Pricing Timeline, Reviews Progress.)

NYSERDA Only

“I want to remind everybody that NYISO is not a party to any of these agreements, and we’re aware of resources only because NYSERDA has made us aware of them,” DeSocio said.

The proposal is limited to NYSERDA contracts because the ISO believes it has no authority to put conditions on out-of-state REC contracts, DeSocio said.

Wholesale market suppliers with such NYSERDA REC contracts are initially settled at the LBMP, including the carbon component. NYISO will then deduct the carbon charge from the supplier’s settlement based on the social cost of carbon and the real-time marginal emission rate for the supplier’s zone.

Marginal emissions rate by month for Load Zones F, G, J and K. | *NYISO*

“This carbon charge will be applied to the actual output of the resource based on the proportion of the REC contract to the nameplate capacity,” DeSocio said.

Generators designated as carbon-free under the CES, and whose NYSERDA REC contract has expired, will settle at the LBMP including the carbon component — and not be subject to a carbon charge. Zero-emission credits and offshore wind RECs are not included, as they have an option to adjust to changes in market conditions, he said.

‘Hard Squeeze’

Seth Kaplan of EDP Renewables said, “NYSERDA has entered into REC contracts for virtually all of the output of the facilities they contract with — that’s just what they do.” He suggested that NYISO check with NYSERDA about how much of the output it buys from projects.

Kaplan said the ISO “is assuming that RECs are carbon payments and that therefore there is a problem to be solved.” He referred to an updated Brattle Group analysis showing a minimal effect of carbon pricing on pre-2020 RECs, with actual customer costs of 4 cents/MWh in 2020 and 2 cents/MWh in both 2025 and 2030.

“It raises a very serious question of whether the hard squeeze that you’re putting on companies that have taken risk and moved forward under REC contracts is worth the juice that comes out of the bottom of the orange, [and] of whether this is an enormous effort that would produce, as I believe [Brattle’s Sam] Newell said, nearly invisible impact, and whether this is really worth the trouble,” Kaplan said.

Kathy Slusher, director of energy procurement and utility regulatory affairs for the State University of New York, said the university system has a campus that will put a bid request out for 150,000 RECs, representing 150,000 MWh of energy in a “ready commodity market.”

“However this is going in NYISO would interrupt that market and would really throw everything for renewables in New York up in the air because none of us could sign a [power purchase agreement] because we don’t know if we’re going to get RECs, what value they would have, or if they’d be able to be sold,” Slusher said. “Sorry … but I think NYSERDA punted this over to [NYISO] and it doesn’t belong in your court.”

To the extent that there’s a secondary market for RECS, the ISO doesn’t know about it or seek to administer some clawback, DeSocio said.

Weird Dynamic

Anne Reynolds, executive director of the Alliance for Clean Energy New York, said that not considering REC sales elsewhere “does raise a weird dynamic.”

“If you’re saying the generators can’t sell their RECs to NYSERDA and still realize the carbon charge revenue increment, but they can sell them to someone else … there’s no logical reason for that, and it illustrates again that a REC payment and a social cost of carbon are not the same thing,” she said.

Reynolds also spoke of the perception among some industry participants that the Public Service Commission addressed the grid operator’s responsibility regarding RECs in a state proceeding, “but the fact is that petition [Case No. 15-E-0302] has never been answered by the commission; it’s an open petition. In the offshore wind order [Case No. 18-E-0071], there was discussion of the issue, and one sentence that said, ‘it might be more appropriate for the ISO to take on this issue’ or something like that, but there was no ordering clause from the commission telling the ISO to solve this problem.”

She also said the utilities are acquiring RECs through value of distributed energy resources (VDER) payments and that VDER projects are getting LBMPs that include the carbon charge increment. She noted that some VDERs qualify as Tier I renewables (for example, a community solar project getting the value stack and exporting to the grid) and utilities can use those RECs to meet their Tier I obligations.

Warren Myers, Department of Public Service director of market and regulatory economics, said the utilities can use such RECs for compliance: “They’re not tradeable RECs, but they can use them to satisfy their Tier I REC requirements.”

ICAP Demand Curve and Net EAS Revenues

Ryan Patterson, NYISO associate for capacity market design, presented a report recommending that any carbon charge in the wholesale market should be rolled into net energy and ancillary services (EAS) revenue estimates through the existing annual update process.

Carbon pricing impacts the capacity market through the ICAP demand curves. | *NYISO*

The ISO analyzed the impacts of carbon pricing on the installed capacity (ICAP) demand curves to illustrate how the annual update process could affect future capacity market clearing prices, finding that net EAS revenue will be impacted by a carbon charge.

Increasing carbon prices and LBMPs will likely impact both cost and revenue, Patterson said. The net EAS revenue offset values and the reference point have an inverse relationship: as net EAS revenue increases, the reference point decreases, and vice versa.

In the last ICAP demand curve reset process, the ISO moved to a historic model that averages projected net EAS revenue over a three-year period preceding the new ICAP demand curves taking effect. The study period ran from Sept. 1 of Year 1 through Aug. 31 of Year 3, using actual historic data such as LBMPs and fuel and emission costs.

The 2017/18 ICAP demand curves used net EAS revenue offset values measured from Sept. 1, 2013, to Aug. 31, 2016, and the ISO implemented an annual update process that allows for specific variables used in calculating the reference point to be recalculated each year between the quadrennial resets.

Changes to the reset process implemented in 2016 were intended to allow for the ICAP demand curves to capture changes in market conditions over time, including the impacts of changes to market rules. Adjustments to the net EAS model to allow for incorporation of a carbon charge will be evaluated as part of the upcoming reset process, Patterson said.

Two datasets were used to run several scenarios, Patterson continued. The first was 2015 and 2016 marginal emissions rates (MER) prepared by Brattle, under which the LBMP was increased by $50/MWh and, to account for the carbon price change, the Regional Greenhouse Gas Initiative price was increased by $50 for hours that LBMPs were adjusted for carbon pricing.

The second dataset was derived from modeling and pricing software (MAPS) runs for 2020, 2025 and 2030, in which LBMPs were output for carbon and no carbon base cases, and then fed into the net EAS model along with projected fuel costs used in each respective MAPS run. As with the previous dataset, the RGGI price was increased by $50 for the carbon cases.

No stakeholder asked questions about the net EAS revenue impact analysis, but Brett Kruse of Calpine said he would like to make a presentation to the IPPTF on Oct. 22 on the issue of how a carbon charge might affect hedges on transmission congestion contracts.

IPPTF Chair Nicole Bouchez, the ISO’s principal economist, shared a revised schedule that foresees the task force meeting on the remaining Mondays this month, collecting stakeholder feedback in November and presenting a formal proposal on carbon pricing Dec. 17.

RTO Insider will have coverage later this week of the task force’s Monday meeting at NYISO headquarters.

October 14, 2018

SPP Briefs: Week of Oct. 8, 2018

FERC last week approved SPP’s first seams project with a neighboring utility when it accepted Tariff revisions incorporating a cost-sharing and usage agreement with Associated Electric Cooperative Inc. (AECI).

The Oct. 10 letter order allows SPP and AECI, a Missouri-based collection of six generation and transmission cooperatives, to proceed with the Morgan transformer project. It was the entities’ second attempt to gain FERC approval (ER18-2243, ER18-2245).

SPP says the project is the most efficient, cost-effective solution to economic and reliability issues identified in two separate studies. It also said the project will reduce day-ahead market uplift costs and avoid the cost of a more expensive regional solution, resulting in a regionwide load-ratio-share benefit of more than $17 million.

The RTO included both arguments in its revised filing, after its first attempt failed in 2017. (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)

SPP has proposed to regionally fund the project, as it will solve congestion issues on its side of the seam. The RTO will cover 82.91% of the $13.75 million engineering and construction cost, while AECI will cover the remainder and is responsible for the project’s construction, operations and maintenance.

SPP FERC m2m settlements aeci — David Kelley | © *RTO Insider*

David Kelley, the RTO’s director of seams and market design, told RTO Insider that FERC’s approval “is evidence it’s possible to share both costs and benefits of new transmission projects across regions.”

“We continue to work with all of our seams partners to enhance our processes to identify and approve mutually beneficial transmission projects,” Kelley said.

The Morgan project comprises a new 345/161-kV transformer at AECI’s Morgan substation and an uprated 161-kV line, both near Springfield, Mo. It was identified during an SPP-AECI 2016 study as outlined by the entities’ joint operating agreement and by the RTO’s 2017 10-year assessment.

“It’s important to SPP and our industry to continue to provide affordable and reliable electricity to our customers, and our success in doing so will depend more and more on our ability to work across regional boundaries to create win-win scenarios,” Kelley said.

SPP said stakeholders, its Board of Directors and state regulators have consistently recommended regionwide cost allocation for the Morgan project.

FERC last year rejected SPP’s first attempt to allocate the project’s costs, ruling it had not shown that the proposed allocation on a regionwide, load-ratio-share basis was “roughly commensurate” with the project’s benefits.

The commission in 2015 also rejected SPP efforts to create a new class of seams transmission projects, saying its plan to identify projects outside the Order 1000 interregional planning process was “too broadly drawn” (ER15-2705). FERC did allow SPP to make filings on a project-by-project basis for non-Order 1000 facilities. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)

FERC does not comment beyond an order’s language. A spokesperson would not confirm whether this was the first interregional project the commission has approved on a case-by-case basis.

August M2M Payments Again in MISO’s Favor

Replicating an outcome last seen two years ago, the market-to-market (M2M) process between SPP and MISO resulted in the latter receiving more than $531,000 in payments for August.

MISO last received back-to-back payments in July and August 2016, the beginning of the only three straight months the RTO has seen M2M payments in its favor. SPP has been on the right side of the ledger 19 of the 21 ensuing months.

Temporary flowgates were binding for 327 hours in August, resulting in $788,835.60 in M2M payments to MISO. That was reduced by $257,098.85 for permanent flowgates binding for 127 hours in SPP’s favor.

SPP still has as healthy balance of almost $51.4 million in M2M payments since the process began in March 2015.

— Tom Kleckner

October 14, 2018

ERCOT ‘more than Sufficient’ on Reserves

ERCOT’s current market design “will support more than sufficient reserve margins,” according to a draft report the grid operator filed on Friday with the Texas Public Utility Commission.

The report by The Brattle Group estimates a market equilibrium reserve margin (MERM) of 10.25% under projected 2022 market conditions.

ERCOT puct brattle group reserve margins — PUC Commissioners (left to right) Shelly Botkin, DeAnn Walker and Arthur D’Andrea | *ERCOT*

“This estimate should not be interpreted as a precise forecast for 2022 or any other particular year, but as a reasonable expectation around which actual reserve margins may vary as market conditions fluctuate,” Brattle said. “Low reserve margins cause high energy and ancillary service prices and attract investment in new resources, and investment will continue until high reserve margins result in prices too low to support further investment.

“This is much lower than historical reserve margins, but close to the reserve margins from ERCOT’s latest resource adequacy reports,” the report added. ERCOT’s reserve margin was 10.9% for summer 2018 and is projected at 11% for 2019.

Brattle also calculated a 9% economically optimal reserve margin (EORM), the point at which the marginal costs and marginal benefits of adding capacity are in balance. “The economic optimum occurs at the reserve margin that minimizes societal costs net of all supply costs and the lost value from any disruptions in electric service,” Brattle explained.

The report was submitted as part of the PUC’s review of ERCOT’s reliability standard (Project No. 42302) and its performance during the summer’s tight conditions (Project No. 48551).

The report notes MERM is a relevant measure because ERCOT does not have a resource adequacy reliability standard or reserve margin requirement, unlike other systems in North America. ERCOT’s reserve margin is “ultimately determined by suppliers’ costs and willingness to invest based on market prices, where prices are determined by market fundamentals and by the administratively-determined operating reserve demand curve [ORDC] during tight market conditions,” the report’s authors said.

Brattle worked with Astrapé Consulting to model ERCOT’s wholesale market design and projected system conditions for 2022, simulating “a range of possible reserve margins under a range of weather and other conditions.”

The report noted that the market equilibrium of 10.25% is greater than the economically optimal level by 1.25%. “Based on these results, we conclude that the current market design will support more than sufficient reserve margins from an economic perspective,” Brattle said. “The market equilibrium is higher than the economic optimum because the ORDC as currently designed sets prices higher than the marginal value of energy during scarcity conditions.”

The authors cautioned that “an important uncertainty” in the study is the likelihood of extreme weather. The base case gave all 38 years of historical weather an equal probability of occurring for the 2022 simulation. Assigning 10% weight to each of the last 10 weather years and ignoring the other 28 years would increase the equilibrium reserve level by 1.5% “due to the higher energy prices in these years,” Brattle said. “However, it would increase the number of scarcity events, resulting in similar reliability.”

The report’s results for both the market equilibrium and economically optimal reserve margins were 1.25% lower than found in a 2014 study. Brattle said low gas prices, higher renewable penetration and updated assumptions on generators’ forced outages and weather contributed to the change.

Brattle will present its study results during ERCOT’s Supply Analysis Working Group meeting on Oct. 19. The report will also likely be used in an Oct. 25 PUC workshop on the grid operator’s summer performance.

ERCOT will accept stakeholder comments on the report through Nov. 26.

WETT Faces Full Rate Case

During an abbreviated open meeting Oct. 12, the PUC moved to open a rate case for Wind Energy Transmission Texas (WETT), which staff said earned an excess $16.4 million last year.

The commission’s action gives the company 120 days to file revised rates, although staff is hopeful a settlement agreement can be reached before then (Project 48158).

WETT had a 12.43% return on equity in 2017, above staff’s estimate of 9.60%. WETT reported a year-end 2017 capital structure of 53% debt and 47% equity, while the PUC said a 60/40 mix is appropriate for transmission-only utilities. “If WETT’s actual capital structure were instead 60% debt and 40% equity, its reported level of 2017 return dollars would have generated an even higher ROE of approximately 14.1%,” staff said in a memo.

PUC Approves Cleco Acquisition of Gas Unit

The PUC’s consent agenda included approval of Cleco Cajun’s acquisition of NRG South Central Generating’s 100% interest in Cottonwood Energy. Cottonwood owns a 1,263-MW gas-fired generation facility, interconnected with MISO, along the Louisiana border in Southeast Texas (Docket No. 48266).

The acquisition is part of Cleco’s $1 billion acquisition of NRG’s eight power plants (3,555 MW) and contracts to provide wholesale power to nine Louisiana cooperatives, five municipalities in Arkansas, Louisiana and Texas, and one investor-owned utility. (See NRG Selling Renewables, Other Assets for $2.8 Billion.)

Louisiana-based Cleco would own the Cottonwood facility, but the project will be leased back to NRG, which will have full operational control until May 2025.

Commission to Intervene in MISO FERC Docket

The commissioners agreed during their closed session to intervene in a FERC docket involving MISO’s cost allocation methodology for targeted market efficiency projects with PJM (EL18-2514). (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

The PUC also agreed to have Executive Director J.P. Urban coordinate with the Texas Commission on Environmental Quality in providing comments on EPA’s Affordable Clean Energy rulemaking (EPA-HQ-OAR-2017-0355), its proposal to replace the Obama administration’s Clean Power Plan.

Commissioner Arthur D’Andrea drew laughs when, referring to the EPA’s naming convention, he said, “We should adopt a system like that.”

— Tom Kleckner

October 12, 2018

ERCOT Board Approves $53.3M Economic Tx Project

ERCOT’s Board of Directors on Tuesday unanimously approved the grid operator’s first economic project in three years, a $53.3 million transmission upgrade in West Texas, despite concerns it doesn’t address reliability issues.

ercot bearkat transmission upgrade — Bearkat Area Transmission | *ERCOT*

Staff recommended Wind Energy Transmission Texas’ (WETT) Bearkat area project as the “most cost-effective solution” to address congestion near Odessa. The region’s wind generation has been bottled up by a lack of adequate transmission, resulting in congestion more than half the time, staff said.

Director Clifton Karnei, who represents the cooperative market segment, referenced the state’s Competitive Renewable Energy Zones (CREZ) initiative in expressing his unease about the board making “mini-CREZ” decisions. CREZ resulted in the construction of 2,800 miles of new transmission facilities, delivering West Texas wind energy to the state’s urban centers at a cost of $7 billion.

“We built all the CREZ lines that raised transmission costs. People are concerned about transmission costs being high, yet here, we’re adding another transmission project that’s not needed for reliability,” Karnei said. “We’re doing it because we have all this wind in a constrained area that is being derated. So when we run the production cost model, that’s when it shows the net societal impact. It makes me feel very uncomfortable.”

ERCOT’s analysis found the Bearkat project would produce $400 million in 30-year net savings, based on its economic planning criteria. Staff evaluated nine upgrade alternatives, all of which passed the criteria.

Asked whether the area would require a reliability project in 10 years should the board reject staff’s recommendation, Fred Huang, ERCOT manager of regional planning, said it’s difficult to project future load reliability without doing a study.

“Without this project, we expect to continue to see congestion in this area,” he said. The Bearkat area has 1.5 GW of wind energy already in operation or planned.

Unaffiliated Director Peter Cramton pointed out that building transmission for only reliability reasons would forego potential economic gain.

“It seems like this makes sense for reliability and social economic benefits to be included as a reason to do transmission projects. There aren’t going to be the private incentives for somebody to build this,” he said. “In a first best world, the private incentives would be aligned with the social incentives, and we would just let the market work, but it seems transmission is an area where we can’t completely rely on the market.”

Karnei was able to find comfort in ERCOT’s Protocols and their reliability and economic criteria.

“If we are to follow Protocols, it appears to me we need to endorse this project,” he said.

“This analysis supports the consistent regulatory framework we have in place,” ERCOT Legal Counsel Chad Seely said, reinforcing Karnei’s statement.

ERCOT updated its economic planning criteria in 2012, following the Texas Public Utility Commission’s removal of a consumer benefit test from its economic criteria for certificates of convenience and necessity.

The Bearkat project comprises two new 345-kV bays and a 27-mile, 345-kV single-circuit line on double-circuit-capable structures. ERCOT’s Technical Advisory Committee endorsed the project last month. (See “TAC Endorses $53.3M Economic Project in West Texas,” ERCOT Technical Advisory Briefs: Sept. 27, 2018.)

October 12, 2018

MISO Monitor Reiterates Call for Capacity Deliverability

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Independent Market Monitor urged the RTO and stakeholders Thursday to require that planning resources have firm transmission to ensure they can deliver their full installed capacity.

In its State of the Market report issued in June, the Monitor said that MISO’s deliverability requirements are too lenient because resources with energy resource interconnection service must only secure firm transmission for its unforced capacity values, which are about 5 to 10% less than their full installed capacity levels. (See 7 New Recommendations from MISO IMM.)

“It’s being relied on but it’s not deliverable,” Potomac Economics’ Michael Chiasson said during an Oct. 11 Resource Adequacy Subcommittee meeting. “It’s clear to us that the [loss-of-load-expectation] study is assuming resources will be deliverable to their installed capacity value.”

Chiasson said MISO’s current practice means as much as 1,400 MW procured in the 2018/19 Planning Resource Auction may not have been deliverable. He also acknowledged that some resource owners may have purchased more firm transmission service than MISO requires.

Chiasson said the rule change can be made with little economic impact to the PRA.

“The concern is more the potential reliability impacts, which could be serious,” Chiasson said.

While roughly half of the about 190 resources contributing to the possible shortfall impact 2 MW or less of capacity, 23 of the resources could each affect 20 MW or more.

Chiasson pointed out that MISO currently requires full deliverability for resources with network resource interconnection service, leading Consumers Energy’s Jeff Beattie to say the RTO was giving unequal treatment to the two groups of generators.

MISO Director of Resource Adequacy Coordination Laura Rauch said that the RTO generally agrees with the recommendation, which could result in a change to how it accredits capacity resources. The RTO is expected to formally respond to the State of the Market report by Oct. 17.

Some stakeholders said that the benefits of the more stringent requirement wouldn’t be significant enough to justify more spending on transmission rights.

But Chiasson said if planning resources decide not to pay for more transmission rights, MISO could simply disqualify the portion of their installed capacity that cannot be guaranteed deliverable.

October 12, 2018

PJM CEO Ott Briefs Senate Committee on Black Start

By Michael Brooks

WASHINGTON — PJM CEO Andy Ott emphasized the importance of fuel diversity for grid resilience to U.S. senators Thursday, but he cautioned against government intervention in the RTO’s markets to bail out specific resources.

grid resilience andy ott pjm fuel diversity black start — PJM CEO Andy Ott | © *RTO Insider*

Appearing before a Senate Energy and Natural Resources Committee hearing on black start capability, Ott acknowledged that the question of whether the grid was becoming too dependent on natural gas was a legitimate one. But, he said, “I do want to clear up some misconceptions about black start resources. Coal and nuclear generators are generally not black start. Black start resources tend to be flexible, smaller units, like gas units or … hydro resources.”

PJM has said the announced retirements of coal and nuclear plants do not pose any short-term threat to reliability, which Ott repeated Thursday. A fuel security study, examining at what point those retirements would cause PJM to violate its reliability requirements, will be released Nov. 1, he said. (See Stakeholders Debate PJM Fuel Security Scope.)

Instead, Ott is more concerned about “a single point of failure”: Some black start resources are only gas-fired, without dual-fuel capability. In July, PJM stakeholders approved an issue charge to work on black start fuel assurance, and Ott told reporters Thursday he expects the RTO to file proposed changes with FERC early next year. (See “Manual Revisions Approved,” PJM MRC/MC Briefs: July 26, 2018.)

“The reality check is it becomes more expensive when you ask for more fuel diversity,” Ott told senators.

But, “as long as you identify the service and don’t fall into the trap of saying ‘I want a specific technology and I want to save a specific type of plant,’ then it becomes a little less expensive.”

grid resilience andy ott pjm fuel diversity — Juan Torres of the National Renewable Energy Laboratory; Utilities Technology Council CEO Joy Ditto; North American Transmission Forum CEO Thomas Galloway Sr.; and Timothy Yardley of the University of Illinois Urbana-Champaign. | © *RTO Insider*

Sen. Joe Manchin (D-W.Va.) nearly paraphrased Ott’s words later, saying he was concerned about the closures of coal plants in his state. Ott repeated that PJM has determined that the units slated for retirement would not impact reliability and pointed to its coming fuel security study.

“And so we’ll be able to say we’ve actually looked at this analytically, looked into the future,” Ott said.

Manchin responded by saying he supported President Trump’s directive to Energy Secretary Rick Perry to order RTOs and ISOs to forestall the closure of a designated list of plants for two years under the Defense Production Act of 1950.

The directive — which Trump issued in June — “makes sure that we keep the best of the best as far as coal-fired plants and nuclear plants that are up to specs and have the latest of technology in operation for at least two years until you can get through this,” Manchin said. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)

“Because a lot of analytical [sic] is going on right now,” the senator continued, “and if this all comes down, and these retirements continue at an accelerated rate, I continually believe that the grid is going to be jeopardized and the security of our nation is going to be jeopardized.”

“We do have time, should we find a problem, to take action within our system,” Ott replied. “Instead of the federal government stepping in, allow us to complete our analysis.”

Ott did tell the committee that he would like to see FERC wrap up its work on its resilience docket, which it commenced in January after rejecting the Energy Department’s proposal to compensate plants with 90 days of on-site fuel.

“My desire would be for FERC to get the message that we do need their assistance, and I think any forum I can have that discussion in, I will,” he told reporters after the hearing. “We just really need to move forward.”

On Oct. 5, the Washington Examiner reported that the administration may be backing off the Defense Production Act order, as the White House has been struggling with its legal justification and received pushback from conservative organizations such as the R Street Institute and Heritage Foundation.

October 12, 2018

MISO Offers Storage Proposal, Promises to Exceed Order 841

By Amanda Durish Cook

CARMEL, Ind. — MISO this week offered its detailed energy storage participation proposal for a final round of stakeholder inspection while promising to introduce more new market rules in the future.

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

At a special Oct. 10 joint meeting of MISO’s Planning Advisory Committee and Market, Reliability and Resource Adequacy subcommittees, Director of Market Design Kevin Vannoy took the podium with a nod to the RTO’s long-running anecdote likening storage to a can of corn that must be opened and its use decided on.

“We’ve managed to open the can of corn and find that it’s a can of beans,” he joked.

Vannoy said stakeholders were instrumental in MISO crafting a compliance plan that meets the 76 requirements laid out in FERC’s sweeping Order 841.

“We think we have a solid definition of electric storage resources. The input we’ve got from stakeholders definitely helped us define compliance and will help us beyond Order 841. It’s going to help us with this generation of storage resources and the next generation of storage resources,” Vannoy said.

Pavan Addepalle, of MISO’s market engineering group, said the RTO envisions going beyond its current market storage definitions — ESR Type I and ESR Type II — to create third and fourth definitions.

MISO has put out a final call for suggestions on Order 841 compliance and will continue to vet the proposal in November before the Dec. 3 federal filing deadline.

The proposed rules stipulate that storage resources commit to the market through four main modes, including discharging, charging and continuous modes, and an outage status mode. The first three modes carry must-run designations and will be cleared between a resource’s minimum and maximum discharge limits.

MISO said it will also allow for emergency discharging and charging commitment modes, and an “available” status similar to that of an offline generation resource. However, stakeholders at the meeting asked MISO to consider compressing the separate emergency charging and discharging modes into a single commitment mode. The RTO had proposed that emergency charging be used to consume power during minimum generation events while emergency discharging would inject power during maximum emergency events.

For metering purposes, electric storage withdrawals from the grid will be treated as negative generation and categorized as wholesale electric storage withdrawals, while injections will be treated like MISO’s existing energy injections. MISO will also hold storage performance to the new uninstructed deviation threshold due to be filed with FERC later this month. (See “Final Uninstructed Deviation Proposal,” MISO Market Subcommittee Briefs: May 10, 2018.)

MISO also said that “technically capable” storage is eligible to provide reactive supply and voltage control and black start service. The RTO said it will propose minor Tariff revisions to include references to storage in the wording. Indianapolis Power and Light earlier this month asked FERC to order MISO to include black start service in its current storage participation model (ER17-1376).

The proposal also includes a pro forma agreement for storage connected at the distribution level to participate and a multistep capacity determination process and capacity obligations for storage resources. (See MISO Closing in on Storage Participation Plan.)

What the Proposal Won’t Do

The proposal does not call for MISO to manage the state-of-charge for storage resources or optimize their energy schedules in the day-ahead or real-time markets. (See “No Optimization Yet,” MISO Closing in on Storage Participation Plan.) Instead, market participants will manage state-of-charge through their bid parameters, although MISO will offer real-time hourly offer overrides for storage owners with “valid reasons.” The compliance plan also does not address distributed energy resource aggregation or participation outlines for hybrid storage and generation pairings, an issue that MISO’s Energy Storage Task Force is currently assessing. (See New Direction for MISO’s Energy Storage Task Force.) Vannoy said MISO will likely soon take up a DER participation model in anticipation of a likely FERC order on the issue.

Stakeholders asked if MISO’s Order 841 proposal risked FERC’s rejection because it only provides for making commitments for discharge but not charging.

Vannoy said MISO strongly considered the notion, but it decided that because the owner currently controls the state of charge, and the RTO isn’t yet prepared technologically to optimize energy scheduling for storage, commitment for discharging only was the best route.

“That’s a capability of the resource, not a service we offer. That’s not to say we won’t offer it in the future,” Vannoy said.

DTE Energy’s Nick Griffin suggested that MISO’s FERC filing should include an explanation of its technological limitations to improve its chances of acceptance.

Market Monitoring

After extensive consultation with Potomac Economics, its Independent Market Monitor, MISO decided that storage will be mostly subject to existing Tariff mitigation rules: offers should reflect known capabilities of the resource, revenue sufficiency guarantee eligibility will be revoked when a storage resource is discovered gaming make-whole payment mechanisms and anticompetitive conduct will be met with a Section 205 filing to seek mitigation measures.

MISO added that an electric storage resource “should not manage its state of charge in a manner inconsistent with its physical and operational characteristics.” It also said mitigation measures will not apply when electric storage resources derate to provide capacity, with such behavior not considered physical withholding.

Potomac’s Michael Chiasson said the Monitor doesn’t foresee major mitigation measures unless storage resources contribute to binding transmission constraints.

“I expect a lot of these resources to be relatively small. … They’re not going to have a lot of market power,” Chiasson said. “We don’t want to come down on a half-megawatt. We want to have a hospitable environment for these technologies to enter the market.”

Chiasson added that the Monitor would consider additional mitigation measures if it begins observing manipulation from storage resources.

“We’re hesitant to jump in too tightly. … We don’t want to slow someone down that doesn’t have market power,” Chiasson said. “We’re happy to have the new entrants.”

But Customized Energy Solutions’ John Fernandes said that MISO storage resources might be perceived to be withholding when batteries manage their “state of health” — different than the state of charge — when batteries are stopped to “cool off” after an active period to avoid deteriorating the life of the battery.

“There’s still a lot of gray area when it comes to this physical withholding,” Fernandes said.

Vannoy said a storage facility going unavailable to preserve itself would probably fall under a reasonable motive to stop offering into the market.

October 12, 2018

Western Regionalization ‘No-brainer,’ PJM CEO Says

By Robert Mullin

UNION, Wash. — PJM is leaving the door open to developing an organized market in the Western Interconnection, despite the downfall of its initial partner in the effort, Peak Reliability.

NIPPC caiso western regionalization andy ott peak reliability — PJM’s Andy Ott addressing NIPPC annual meeting attendees. | © *RTO Insider*

And some of the region’s utilities are also interested in continuing the effort, according to PJM CEO Andy Ott.

“We continue to stay interested in the West,” Ott said Monday, speaking at the Northwest & Intermountain Power Producers Coalition’s (NIPPC) annual meeting. “We’re still highly engaged — mostly not in the Northwest these days, but mostly in the Southwest.”

Ott said PJM used Peak to gain an understanding of the issues in the West and get introductions to the region’s market participants.

“But frankly, we feel we do have those introductions and we still are here and having discussions with folks,” he said.

Ott offered that regionalization is a “no-brainer” for the West, and then slipped into what sounded like a not-so-subtle pitch for having his RTO help lead the way in that effort.

“What we are about is to say, ‘Look, markets are a tool.’ Regionalization is a means to create a more efficient utilization of the grid in the West,” Ott said. “Our expertise is in coordinating markets in the East. Essentially, we did it a certain way. We realized [in the West] that it’s not the same scope. You don’t need capacity markets out here. We recognize that. Energy markets, transmission planning, regional operation, market-to-market coordination — those are the kinds of things and expertise we bring.”

Ott acknowledged that the West is already experiencing a fair volume of trading, both through the Western Energy Imbalance Market and bilateral trades. But he said those options seem to be “significantly understating” the value of ramping, flexibility, firm energy and storage — echoing the complaints of Northwest hydroelectric producers who say that CAISO and the EIM undervalue the capabilities of their highly flexible resources.

The CEO said the situation is a failure of price formation.

“Price formation is fundamentally one of the key features of an electricity market. We have to get prices so that people feel they’re being fairly treated,” Ott said. “We came in understanding that we need to get an appreciation of the special cases in the region. We tried to do that. I have folks who’ve spent a fair amount of time to understand the different drivers, because they are different from what we have” in the East.

Ott suggested that Western market participants outside California collaborate to hash out their own approach to price formation — within their own organized market — and then reach out to CAISO and ask: “‘Here’s what we think. What do you think?’

“I don’t think that conversation is happening. At least it’s not happening systematically, but I hope it will,” he said. “If we can be a catalyst to at least provide that conversation, we would love to do that.”

Ott said the idea that Western utilities must choose between developing a new market and engaging with the EIM or CAISO is “a fiction.” A “viable alternative” would be for other parts of the region to stand up a market with its own governance structure and price formation principles and then engage California through market-to-market coordination.

“It looks a lot like EIM, but it’s under different sets of rules,” Ott said. “You still have trading, and in fact you still have very efficient trading. In fact, we do this between PJM and New York; we do it between PJM and MISO. We even do it between PJM and part of the South where they don’t even have organized markets, but we have protocols.”

Clay Norris, power section manager with publicly owned Tacoma Power, asked Ott to elaborate on lack of engagement with the Pacific Northwest.

“I’ve had little interest from parties in the Northwest,” Ott said. “Most of them say, ‘We’re resigned to the fact that we’re headed in a certain direction so we really don’t have time to talk to you.’”

Ott added that Southwest utilities had previously taken the position that they must choose between working with PJM on a new market or committing to the EIM, and they focused on the latter to avoid “creating too many waves.”

“But more recently the conversation has been that [Southwest entities are saying], ‘We’re seeing some things that don’t look so good, so we want to talk to you again,’ and so they reached back out and said, ‘We’re willing to re-engage in the conversation,’” Ott said.

“We are having these conversations. Whether they go anywhere is still an open [question].”