Page 1161 – RTO Insider

June 18, 2018

American Market Architect Reflects on Mexico’s Reforms

By Tom Kleckner

MEXICO CITY — So what drove a nice kid from Chicago — a “regular American” with a minimal knowledge of the Spanish language — to move to Mexico and not only make his home there, but help design the country’s deregulated electricity markets?

“I really had no link to Mexico,” said Jeff Pavlovic, the nice-kid-turned-40. “After looking at the whole world, I figured electricity is a very important industry, and I could make a very big impact. If you can make electricity cheaper, you can change the economy.

“I saw Mexico as a great opportunity, as a place that hadn’t embraced market principles in the electric industry,” he said in a recent interview. “It was a long shot. You’re making a big bet on major change. If I could help change the electric markets in Mexico, I thought that could have as big an impact on the world as anything. I just thought about it and came to Mexico.”

Simple as that. Pavlovic obviously has an analytical mind. The son of a teacher, he also has the academic pedigree to match his entrepreneurial spirit. He picked up economics and math degrees from Duke, an MBA from Stanford and, after moving to Mexico in 2008, a master’s in economics from the Centro de Investigacion y Docencia Economicas (Center for Economic Research and Teaching).

Pavlovic, who spent a few months studying Spanish before moving to Mexico, is now fully bilingual. “I thought my Spanish was good enough, but it took three or four years before I could really communicate,” he said.

Fortunately, Pavlovic found himself in the right place at the right time. He was in Mexico, where the state-run electric monopoly doesn’t have “51 state governments deciding the rules.”

And though he admits it was a longshot, Pavlovic’s expertise in unbundling electric utilities as a financial consultant and in generation control and dispatch for Xcel Energy landed him several different positions with the Ministry of Energy (SENER) and the Federal Electricity Commission (CFE), Mexico’s national utility. In 2011, he took a position as general director of generation, conduction and energy transformation with SENER, just as the push for electric reform, driven by the need for more efficient generation and lower prices, began in 2012.

“Very good timing. I thought it would happen six years later than it did,” Pavlovic said, referring to Mexico’s single, six-year presidential terms. “When I was dreaming of this, I didn’t think I’d be in government writing the rules. I thought I’d be on the sidelines, maybe in some private company sending suggestions that would mostly be ignored. Being in the middle of the process was better than anything I dreamed of.”

Big Designs, Slow Progress

Anxious to make the sector “more efficient and reduce costs,” Pavlovic said he and the market-design team borrowed textbook principles and elements from RTOs in the U.S. “We wanted a Day 2 settlements market at least. We wanted nodal prices,” he said. “We followed MISO and PJM in letting the system operators make the commitment decisions.”

Mexico began its incremental rollout of market reforms in 2014, but progress has been slow and halting. The financial transmission rights market has been delayed until 2019, frustrating participants who have complained about a lack of liquidity. The first midterm capacity auction in February cleared only one transaction, Enel’s 50-MW purchase from Spain’s Global Power Generation, leading one observer to say, “Whenever a bilateral agreement is signed, [the market] has a party.”

Market participants have complained about the market’s lack of transparency, exemplified by the confusion around transmission retail rates that led to a new, transitory methodology. Rate increases will be phased in through 2018 while a permanent solution is developed.

Some market participants have given themselves six months to see how the market shakes out and “grows legs,” as one player said during the recent Gulf Coast Power Association market conference in Mexico City, before jumping headlong into the market.

Pavlovic left the government last year, forming his own generation asset firm, Bravos Energia, and taking his message on the speaking circuit. (See “Market Architect Calls for Increased Transparency,” Overheard at the GCPA Mexico Electric Power Market Conference.)

Asked about his reaction to how the market has developed, Pavlovic said he believes the market design “was mostly efficient.”

“A perfectionist can always find things that could have been done better, but in the big picture, I was happy,” he said. “The way the powers were separated among the government authorities was right. The implementation has had some very good early successes with the short-term market, the auctions, the capacity market. I was pretty satisfied, but always conscious of things not going as well as I had hoped.”

mexico Bravos Energia Jeff Pavlovic — | *Bravos Energia*

Pavlovic pointed out that several market pieces — FTRs, virtual trading and a fully functional real-time market — still need to be implemented.

“Most of the [market’s] weaknesses are caused by the environment the market operates in,” he said. “How many participants are there? What kind of positions do those participants need to take?”

Pavlovic said many market participants can’t take large positions because of the lack of private generation assets in operation and uncertainty over regulated transmission rates.

“A lot of auction projects are under construction, but the market suffers from the lack of a dynamic retail market,” he said. “It’s a chain of cause and effect. With no retail market, the speed of investments is slowed down.”

A New Wave

When Pavlovic rejoined the private sector, his biggest worry was whether the market reform’s unbundling of CFE’s generation, distribution and retail businesses would hold. It hasn’t. During his GCPA keynote, he said the former monopoly continues to combine the financial accounting for its several subsidiaries.

“It’s not turning out to be as strong a separation as we had hoped for,” Pavlovic said. “They are the big player in the market, but I don’t think they have built the systems or generated the knowledge to be able to use the market as a tool to hedge their risks. If they were using those markets, then there would be a lot more liquidity, a lot more price discovery, and that would bring in a lot more participation from private companies.”

Complicating matters is the country’s July 1 presidential election. With presidents and their administrations limited to a single-six year term, governmental work naturally slows to a crawl in the months before the election. This year, populist Andres Manuel Lopez Obrador holds a 26-point lead over his two opponents from the traditional ruling parties.

Obrador’s energy platform includes increasing hydroelectric generation and preventing the retirement of 16 GW of thermal generation, without allowing their modernization, repowering or conversion to cheaper fuels. He is also calling for a million small renewable plants for residential users and the services sector.

“It’s dangerous, because those [hydro and thermal] investments could crowd out more productive and efficient investment from the private sector,” Pavlovic said. “The rest of his proposals are not going to have a big impact on the market. He’s not talking about undoing the power market, he’s not talking about the states taking over private assets. It doesn’t look like there’s a very big downside to be worried about.”

Pavlovic’s greater worry is about the industry’s regulation. The Energy Regulatory Commission (CRE) consists of seven commissioners serving staggered seven-year terms. Every New Year’s Day, a new commissioner joins.

“The big risk is whether they will nominate competent technical leaders to regulate the electrical sector,” Pavlovic said. “There’s still a lot of work to be done, in the regulation and implementation of the market. You need competent technocrats and technical leaders in the power sector.”

Still, Pavlovic draws hope from the growing number of participants in the market’s capacity auction.

“There is a new wave that will come in,” he said during the GCPA conference. “I think the market will continue to get deeper and help us exercise influence over the policy.”

June 18, 2018

New York Public Service Commission Briefs: June 14, 2018

Electric reliability in New York state declined last year compared to 2016 because of a severe wind storm in March, Department of Public Service staff told the Public Service Commission on Thursday.

Excluding weather-related outages, overall interruption frequency — the main metric DPS staff use — improved slightly, according to their annual report on reliability. However, some service areas saw longer interruptions, and others saw an uptick in tree-related outages compared to other causes (18-E-0153).

A severe wind storm in early March 2017 downed distribution lines in Rochester, N.Y. | *NY PSC*

But while it led to record wind generation in NYISO, the March storm, with gusts up to 70 mph, easily downed distribution lines in upstate New York. (See “NYISO Sets Wind Energy Record in March,” NYISO Management Committee Briefs.)

The three upstate utilities — National Grid, Rochester Gas & Electric and New York State Electric and Gas — collectively reported about 284,000 outages in their service territories as a result of the storm. A DPS investigation found that RG&E and NYSEG did not follow their emergency response plans, leading to longer outage times, and the utilities have filed a joint proposal with the PSC to settle staff’s alleged violations for $3.9 million.

Staff expect reliability to only worsen because of severe weather. “The weather events dominating the headlines recently indicate weather patterns are producing more frequent and powerful events,” they said. “As a result, this reliability category is expected to decline given the number of significant weather events that have occurred in 2018.”

New York has already experienced several unusually powerful storms this year, including January’s bomb cyclone, a series of March nor’easters, a spate of severe thunderstorms on May 15 and a tornado on May 3.

Pipeline Safety Efforts Improve

Meanwhile, pipeline safety improved overall last year, as local distribution companies improved their damage prevention, emergency response and leak management efforts (18-G-0260). The number of reported damages to natural gas pipelines in the state decreased slightly, from 1,565 to 1,562.

The DPS measures LDCs’ damage prevention by tallying up damages resulting from certain actions, such as mismarking areas or contractors failing to notify LDCs of excavation activities. By this standard, damage prevention improved by 22.5%.

The LDCs’ ability to respond to emergencies within 30, 60 and 90 minutes all improved, staff said. Additionally, the utilities reduced their backlog of leaks by 2,354, or 13.4%.

Staff also presented reports on electricity safety (18-E-0279) and customer service (18-M-0267).

Separately, as part of its consent agenda, the PSC approved a $1.98 million settlement by National Grid for a 2015 pipeline explosion on Long Island that destroyed a house and severely injured two people inside (15-G-0298). A staff investigation found the company failed to disconnect gas service to the house after a resident request.

Central Hudson Rate Increase Lowered; Burman Dissents

The PSC voted 3-1 to approve a $36.4 million electric and gas rate increase for Central Hudson Gas & Electric, 57% below what the utility initially requested (17-E-0459, 17-G-0460).

Empire State Plaza, where the New York PSC meets

Under a joint proposal with DPS staff, Central Hudson agreed to increase its rates over three years, instead of all at once. Eligible low-income customers will also see a 65% rate decrease under the plan.

“The progressive plan that was adopted — endorsed with complete stakeholder support by environmental groups, large business customers and the largest municipality in the region — includes a nation-leading affordability policy that substantially lowers bills for most low-income customers,” Chair John B. Rhodes said in a statement.

Commissioner Diane Burman spoke for more than half an hour explaining the many reasons for her “clear ‘no’ vote.” But she said the single issue that tipped the scales for her was a $264 credit to customers who install geothermal HVAC systems, which the commission says are more energy efficient and emit less carbon.

“We always say that we’re fuel-neutral [and] technology-neutral … here, we would not be,” Burman said. “And there’s no explanation to me why except that it was agreed to in the joint proposal.”

— Michael Brooks

June 18, 2018

MISO Nixes LSE Load Forecast Plan

By Amanda Durish Cook

CARMEL, Ind. — MISO has called off a proposal to rely on data from its load-serving entities to compile its own long-term load forecast, stakeholders learned last week.

The RTO will instead continue to use independent load forecasts (ILFs) prepared by Purdue University’s State Utility Forecasting Group but with a twist: It will now order four versions of the forecast, each tailored to one of the futures used to inform MISO’s annual Transmission Expansion Plan.

MISO LSE load-serving entities load forecasts — Lawhorn | © *RTO Insider*

“After careful consideration of the comments and proposals by stakeholders, MISO will begin to use the independent load forecasts to develop futures-specific load and energy forecasts for MTEP 20 and beyond,” John Lawhorn, MISO senior director of policy and economic studies, told stakeholders at a June 13 Planning Advisory Committee meeting.

Lawhorn said “consistency and clarity, not necessarily increased precision,” prompted the decision, and he stressed that MISO will continue to use LSE forecasts to plan for resource adequacy.

The expanded independent forecast is “for transmission planning purposes only,” Lawhorn said.

“I know we’ve been talking about the ILF for the past five years, with more discussion in the past eight months,” he said.

The change to an LSE-based forecast would have required MISO’s 140-plus LSEs to annually assemble four different 20-year load forecasts to fit with each of the MTEP futures, an unpopular proposition with many stakeholders. (See Advisory Committee Steps up Criticism of MISO Forecast Plan.)

The LSEs themselves were mixed over whether they would be able produce their own 20-year forecasts. An April survey generating responses from one-third of LSEs representing about two-thirds of load showed that LSEs estimated the costs of putting together forecasts would be anywhere from “minimal” to a few hundred thousand dollars, Lawhorn said.

“Costs were all over the map from that perspective, whether they already had a load forecasting group or not,” Lawhorn said in April.

Stakeholders at last week’s meeting asked whether MISO has a plan to monitor its ILFs and compare them with actual loads after the fact.

Lawhorn said although it’s difficult for MISO to line up all variables to compare forecasted load to actual load, Purdue’s own analysis has shown its forecasts “trend well” with actual load in the long term.

Other stakeholders expressed concerns that MISO had no specific plan to hold the ILF to a standard of accuracy.

WPPI Energy’s Steve Leovy said he would have liked MISO to hold more discussion with stakeholders before deciding on the ILF, adding that a single survey of LSEs was inadequate to collect opinions. Organization of MISO States Executive Director Tanya Paslawski said she was likewise concerned about MISO’s short comment period and scant communication about its decision. She noted she would take her concerns to her Board of Directors.

‘Post-capacity’ Planning

MISO said it makes sense for the ILF to be tailored to MTEP futures because energy usage is increasingly driving transmission planning, shifting away from capacity-based planning that relies on an annual system peak. The RTO says it will increasingly experience peaks that can occur during any hour of the year.

“It’s a shift that we’re seeing from a capacity-planning paradigm to an energy-planning paradigm … as we move to more facilities that are small and local. Energy delivery is becoming the driver of a robust transmission system. Moving energy around the system becomes more important as the resource mix changes,” Lawhorn said, pointing to MISO’s 93-GW interconnection queue, which includes 80 GW of potential renewable sources. “This is portending to be a major shift in our system.”

June 18, 2018

ISO-NE Planning Advisory Committee Briefs: June 13, 2018

MILFORD, Mass. — ISO-NE forecasts a net installed capacity requirement (ICR) value of 34,000 MW for capacity commitment period 2023/24, a 275-MW increase from the 33,725 used in February’s Forward Capacity Auction 12 for 2021/22, officials told the Planning Advisory Committee on Wednesday.

The net ICR is forecast to rise by 200-MW increments each period to 34,800 MW for 2027/28 with capacity margins dropping to 15% from 16.7% for 2021/22.

The forecast uses the same capacity and transmission transfer capability assumptions used to develop ICR values for FCA 12 but with the 2018–2027 Forecast Report of Capacity, Energy, Loads and Transmission (2018 CELT) load forecast. The FCA 12 values were based on the 2017 CELT, system planning engineer Manasa Kotha told the PAC. (See ISO-NE Capacity Prices Hit 5-Year Low.)

The RTO modeled three capacity zones for FCA 12: the Southeast New England (SENE) import-constrained capacity zone comprising Northeast Massachusetts (NEMA)/Boston, Southeast Massachusetts (SEMA) and Rhode Island; the Northern New England (NNE) export-constrained capacity zone comprising Maine, New Hampshire and Vermont; and the Rest-of-Pool capacity zone comprising Connecticut and Western/Central Massachusetts.

Comparisons of the 2018 and 2017 CELT load forecasts show that while overall New England load decreased, load in the SENE sub-areas has increased, as it did last year, Kotha said.

Comparison of 2017 and 2018 Net ICR Forecasts (MW) | *ISO-NE*

The increase is attributable to the Massachusetts economy continuing to grow faster relative to the other New England states, she said.

As part of its review of ICR assumptions for Operating Procedure No. 4 conditions (action during a capacity deficiency), the RTO has proposed using 700 MW of minimum operating reserves in the ICR model, an increase of 500 MW over the long-term assumption of 200 MW previously used. The new 700-MW assumption will be used in FCA 13 ICR calculations, Kotha said.

Future Locational Reserve Needs

ISO-NE foresees reserve needs in NEMA/Boston to be in the range of 250 to 700 MW for summer 2019 and 250 to 400 MW for winter 2019, Fei Zeng, technical manager for resource adequacy, told the PAC.

The RTO developed future representative operating reserve needs for the current reserve zones in NEMA/Boston, Southwest Connecticut (SWCT) and Greater Connecticut for summer and winter for study period 2018-2022. The actual requirements reported for 2018 are based on historical data of the last two years.

Investment of New England transmission reliability projects by status through 2022 (numbers represent project quantities) | *ISO-NE*

The forecasts did not consider the impacts of Footprint Power’s new 674-MW combined cycle power plant in Salem, Mass., “which when it goes into service by the end of the year is expected to have an impact on the following year’s calculations,” Zeng said.

Together with upgrades in the greater Boston area, the new Salem Harbor Station will help eliminate the local reserve needs for the study period, Zeng said.

In SWCT, the grid operator expects Competitive Power Ventures’ Towantic Energy Center, which began generating last month, to help reduce local reserve needs to a minimum level for summer 2019. With the assumed addition of Bridgeport Harbor 5, and the SWCT transmission upgrades, forward reserve requirements are expected to be zero for the remainder of the study period. (See related story, CPV: Subsidies — not Gas Shortages — Challenge for New Plants.)

CEII Presentations Describe Aging Infrastructure

The PAC heard five presentations on regional transmission infrastructure, which collectively described the rust in New England’s rustbelt. All five presentations were classified as containing critical energy/electric infrastructure information (CEII).

However, one stakeholder pointed out that much of what the classified material detailed would be visible to any interested commuter in the region. The needed replacements range from vintage control room equipment to brown glass insulators to replacing rusting towers.

Pradip Vijayan, ISO-NE senior engineer for transmission planning, updated the PAC on results from the SWCT 2027 needs assessment, as well as one project related to an older needs assessment for Greater Hartford/Central Connecticut.

Christopher Malone, Avangrid manager for Connecticut transmission planning, presented railroad corridor transmission line asset conditions. Maintenance of century-old catenary structures over the railroad is complicated by railroad control of 22-kV feeder/signal conductors.

Eversource Energy system planning manager Shaun Moran presented on challenges with the infrastructure in Eastern Massachusetts that carries much of the load for Cape Cod.

Kelly Csizmesia presented on behalf of National Grid’s New England Power unit, which operates transmission facilities in every regional state except Connecticut.

Transmission Projects and Asset Condition Update

Jon Breard, ISO-NE associate engineer for transmission planning, presented an update on the Regional System Plan regarding transmission projects and asset conditions, noting that seven new transmission projects totaling $146.8 million have been placed in service since the last update in March.

The RTO estimates about $1.74 billion in active reliability projects are underway now, compared to $1.9 billion in March.

Regarding asset conditions, the RTO reported one new project (the $6.3 million replacement of the Montville 16X transformer in Connecticut), and three projects placed in service since the last update in March, including: the installation of two 40-MVAR reactors on the Scobie 115-kV bus in New Hampshire ($4.7 million); replacement of the Salem Harbor Substation 115-kV oil circuit breaker ($4.6 million); and the 1231/1242 structure replacement project in Massachusetts ($8 million).

— Michael Kuser

June 18, 2018

6 Projects for ISO-NE’s 1st Clustered System Impact Study

By Michael Kuser and Rich Heidorn Jr.

MILFORD, Mass. — Only six of 32 interconnection requests studied by ISO-NE in its initial test of its new queue clustering methodology have moved on to the next stage of the process, all of them in western Maine.

The six interconnection requests, totaling 691 MW, will be included in the RTO’s first cluster system impact study (SIS), Al McBride, director of transmission strategy and services, told the Planning Advisory Committee last week.

ISO-NE implemented the clustering methodology to address the queue backlog in Maine, where more than 5,800 MW of proposed resources, mostly wind, want to connect to the grid.

iso ne maine system impact study sis — Bingham Wind Project | *NovatusEnergy*

The process allows for two or more interconnection requests in the same area to be analyzed together and to share costs for required transmission upgrades when none of the requests can interconnect without the use of common new infrastructure rated at 115 kV AC or HVDC.

The first Maine Resource Integration Study (MRIS) concluded that the RTO could connect nine Northern Maine requests totaling 1,118 MW and 23 western Maine requests totaling 777 MW with about $1.83 billion in transmission upgrades. The upgrades included a second 345-kV Coopers Mill-Maine Yankee 392 line — which both clusters required — at a cost of $108 million.

With constraints on the system, “we found ourselves hitting a ceiling of around 1,800 MW” in interconnection requests able to be accommodated, “which is a significant addition to the Maine transmission system,” McBride said.

Projects had 30 days after posting of the MRIS on March 12 to inform ISO-NE of their intention to move on to the clustered SIS process.

None of the Northern cluster projects — whose upgrades would have totaled $1.36 billion, including the second 392 line — agreed to proceed.

Seven of the 23 western Maine requesters sought to be included in the cluster SIS, but one, for 1,200 MW, was not permitted because it exceeded the capacity of the “cluster-enabling transmission upgrades.” It will be studied separately.

Costs of the upgrades for the western projects, including the second 392 line, were estimated at $575.5 million. The other upgrades include a new 345-kV line from a new substation near Johnson Mountain to the existing 345-kV substation at Larrabee Road.

Second Study Planned

The RTO is planning a second MRIS to evaluate upgrades needed to accommodate an additional 22 interconnection requests, including about 1,350 MW in Somerset and Franklin counties and about 2,300 MW in Aroostook and Penobscot counties.

McBride said the study will consider new HVDC transmission connecting to the southern part of the RTO’s system, connecting either radially to proposed generation or to the existing network.

The RTO asked stakeholders to email feedback on the proposed study scope to PACmatters@iso-ne.com by July 13.

It hopes to complete the study within 12 months.

“We would be very reluctant to study major transmission proposals, from $500 million to $1 billion, that provide only minimal interconnection capability,” McBride said.

June 17, 2018

CEC Approves $10 Million for Microgrids

By Jason Fordney

Sacramento, Calif. — The California Energy Commission on Wednesday approved $10 million in grants for two microgrid projects, including one that represents a new form of partnership between investor-owned utilities and a community choice aggregator.

The commission in a 4-0 vote approved $5 million apiece in grants for microgrids at California Redwood Coast-Humboldt County Airport and at Santa Rosa Junior College in Sonoma County. The CEC said the airport project enables further research into microgrids and many value streams, including demonstrating the ability for CCAs to work with utilities to maintain reliability, offsetting electricity costs, integrating microgrids into CAISO operations, generating data and producing ancillary benefits at the remote location.

California Energy Commission left to right: Karen Douglas, Chairman Robert Weisenmiller, Andrew McAllister, and Janea Scott (David Hochschild absent) | © *RTO Insider*

The solar/storage project at the coastal airport will “represent the first multi-customer, front-of-the-meter microgrid with renewable energy generation owned by a CCA and the microgrid circuit owned by an IOU.” Redwood Coast Energy will own the generation while Pacific Gas and Electric will own the distribution circuit, with Schatz Energy Research Center leading the project.

The airport facility consists of two ground-mounted solar PV arrays, one a 250-kW array configured for net energy metering service, and the other a 2-MW, 6-acre array for wholesale power sale. It also features a 2-MW/8-MWh lithium ion battery storage system and will additionally power a U.S. Coast Guard station. It will add resilience to 18 accounts on PG&E’s Janes Creek 1103 distribution circuit and is seen as providing a roadmap for microgrid development, the CEC said.

The Santa Rosa project will be 136,000 square feet of rooftop solar on two existing parking structures and two 1-MW lithium-ion battery systems. Other subcontractors and vendors include the California Center for Sustainable Energy, PXiSE Energy Solutions, WorleyParsons, SunPower, STEM and nine other subcontractors to be announced.

Chairman Robert Weisenmiller on Wednesday said the CEC has been communicating with utilities and the Public Utilities Commission about making microgrids a priority in high fire-risk areas to help maintain resilience and reliability.

“It is time to move more toward the future in this area,” Weisenmiller said.

Commissioner Andrew McAllister said: “I think this is absolutely a valid thing to be doing,” but he called for “realism” as microgrids are developed. “Part of the challenge is to figure out and learn where they are really needed. … The goal isn’t necessarily for the whole distribution grid to be a complete assembly of microgrids.”

The projects were funded through the latest round of solicitations of the Electric Program Investment Charge (EPIC), a retail ratepayer surcharge. (See California Awarding $45 Million for Microgrids.) The program has funded hundreds of projects, approaching $500 million in awards.

The CEC also approved:

Building energy efficiency standards for Marin County that will require all new single-family residences less than 4,000 square feet to be all electric or, if mixed fuel, to reduce energy consumption by 15%, or 20% below the 2016 standards if a PV is included. New low-rise multifamily residential will be required to be all electric or reduce energy consumption by 10%, or 15% if a PV system is included. New high-rise multifamily residential and new nonresidential construction will be required to be all electric or reduce energy consumption by 10%.
A $1.5 million, 1% interest rate loan for energy conservation measures for the city of Weed for city-owned sites.
A $260,000, 1% interest rate loan to San Diego County to install demand-controlled ventilation and more efficient interior and exterior lights at a nursing facility.

June 17, 2018

MISO Planning Subcommittee Briefs: June 12, 2018

CARMEL, Ind. — MISO is seeking stakeholder input as it develops a conceptual study to determine how to incorporate the impact of transmission outages into its economic planning models.

MISO said transmission and generation outages are “a major contributing factor of market price volatility.” While the RTO includes concurrent generation outages in its economic model, it does not model concurrent transmission outages, though it said a 2014 exploratory study showed that transmission outages could increase system congestion by about 66%.

“Transmission outages, planned or forced, can cause redispatch of the generation. They have economic consequences,” it said.

Speaking at a June 12 Planning Subcommittee meeting, MISO adviser Ling Hua said the RTO is gathering information to create modeling options for transmission outages and evaluate their trade-offs. Its study examines transmission outage modeling based on either: historical outages; a Monte Carlo-style simulation based on statistics gathered from historical outage data; a systemwide transmission facility derate of 5 or 10%; or use of still undefined research to establish an adjusted production cost adder in the model.

Using 2016 data on 2,000 planned and forced transmission outage events on 115-kV or above facilities lasting longer than five days, the RTO said it could conservatively model about 1,460 transmission outage events in one 2017 Transmission Expansion Plan future model based on a historical outage modeling method.

Hua also said that while both the derate and adjusted production cost adder can capture the systemwide average impact from transmission outages, they fail to account for locations of transmission outages. The historical and Monte Carlo options are more labor-intensive to put together, he said.

American Transmission Co.’s Chris Hagman thanked MISO for investigating the four approaches for stakeholders and said it was important for the RTO to plan for the impact of transmission outages.

MISO Transmission Planning Engineer Amit Rao asked stakeholders to provide their reactions to the four approaches and additional modeling suggestions by July 9.

New Benefit Metrics

MISO is continuing a discussion on which benefits metrics it should account for regarding new transmission projects, as it prepares a plan to prioritize projects that avoid costly investment or reduce settlement costs on its contract path with SPP. (See Stakeholders Debate MISO Cost Allocation Plan.)

The RTO is proposing that new market efficiency projects (MEPs) that would eliminate the need for proposed MTEP reliability projects to include the value of those reliability projects in their estimated costs. The avoided cost benefit — and cost allocation — would then be spread among pricing zones where the reliability projects would have been built. The RTO plans to review all avoided projects with transmission owners.

But Customized Energy Solutions’ Ginger Hodge said she was worried about transmission owners under- or overstating the planning-level cost estimates that inform the benefit metric. She asked the RTO to conduct a historical analysis comparing TO cost estimates at the MTEP planning phase to actual costs to better determine the average variance between estimates and actuals. Hua said MISO could look into the possibility.

MISO also plans to value MEPs based on their ability to reduce annual payments to SPP for flows above the contract path capacity between MISO Midwest and South, but Hua said eligible MEPs eligible would have to physically connect the two regions. For every megawatt that an MEP increases the MISO contract path, the payment structure in the MISO-SPP agreement will be reduced by $667/MW-month, Hua said. She said the benefit would be calculated as an annuity from the in-service date over a 20-year asset life.

The benefits would be distributed to local resource zones using the load-ratio share cost allocation approach already outlined in the settlement agreement for market settlement costs, Hua said.

Hua asked for stakeholder feedback on the two proposed benefit metrics through July 2. She said the RTO would finalize the new benefit metrics for a Tariff filing in August.

Matching Modeling with Proposed Retirement Process

MISO is working to update its modeling to comply with a new generator retirement process recently filed with FERC.

The new retirement process filed last month proposes to place all generation owners submitting an Attachment Y retirement notice into a catch-all three-year suspension period (ER18-1636). Suspended units would maintain their interconnection rights for the full three years unless they formally decide to retire. After three years without a return to service, the units are presumed retired and MISO dissolves their interconnection rights. (See MISO Readies Retirement Change.)

miso transmission outages economic planning — Jehring | © *RTO Insider*

MISO will update its dispatch assumptions to match the new process by modeling a suspended unit as initially offline for the first three years, but assumed to be participating in dispatch after three years, unless the unit is retired. Patrick Jehring, of the RTO’s expansion planning group, said more than half of generation owners submitting an Attachment Y notice decide to immediately retire.

Jehring said MISO modeling is in “limbo” for those three suspension years, but modeling must assume that suspended units will return to service, based on the Tariff.

He noted that the RTO doesn’t foresee granting conflicting interconnection rights — a concern voiced by some stakeholders in prior meetings — because its interconnection process requires that it conduct a deliverability analysis for proposed generation projects, which would flag any issues.

Generators Miss 1st Pass in Under-frequency Study

transmission outages economic planning miso ferc — | *MISO*

MISO will complete a NERC-required under-frequency load shedding study by fall, and, at first blush, a few generators have more work ahead to comply with one frequency requirement.

The study is required once every five years, and the RTO last conducted one for MISO Midwest in 2013. The RTO is studying seven under-frequency load-shedding islands in the region.

Anton Salib of the RTO’s expansion planning group said the frequency performance of the seven islands meets most requirements of NERC Standard PRC-006-3, although a few generators might need to take steps to ensure they don’t exceed 1.18 V/Hz per unit for more than two seconds and 1.1 V/Hz per unit for more than 45 seconds at each generator bus.

An initial examination showed that four of the seven islands’ frequency performance exceeded the NERC requirement: Michigan’s Lower Peninsula; “Gateway” in parts of Illinois and Missouri; ATC-A in Wisconsin and part of Michigan’s Upper Peninsula; and Local Resource Zone 1 in the Dakotas, Minnesota, Wisconsin and a small portion of Montana.

Salib said MISO will finish the study and present results in time to meet the October deadline.

Examining 7 Transfers for MTEP 18

MISO has begun a transfer analysis as part of its MTEP 18, due to be revealed in early December.

The analysis examines whether the RTO can reliably transfer energy and identifies potential future system weaknesses or limiting transmission facilities under NERC standard FAC-013-2.

MISO this year will study seven transfers:

Manitoba Hydro to MISO’s northern region;
MISO South to SPP;
MISO’s Central Region to the Associated Electric Cooperative Inc. territory;
MISO’s North and Central regions to MISO East in Michigan;
PJM North Illinois to PJM Ohio; and
A two-way transfer to and from MISO’s Central Region to the Tennessee Valley Authority.

Senior Expansion Planning Engineer Scott Goodwin said the RTO will post the final report of its analysis by Nov. 1.

— Amanda Durish Cook

June 17, 2018

Botkin Makes First Appearance on Texas Commission

Shelly Botkin enjoyed a relatively quiet debut on the Public Utility Commission of Texas last week, sitting through a 15-minute open meeting devoid of any major decisions.

shelly botkin ercot puct — Botkin | *AdminMonitor*

Appointed to the three-person commission on June 11 by Gov. Greg Abbott and sworn in two days later, the former ERCOT communications and governmental relations director smiled often at friends in the audience and seconded motions for approval. (See ERCOT’s Botkin Named to Texas PUC.)

“With that, your first meeting is over,” PUC Chair DeAnn Walker said to Botkin as she adjourned the June 14 meeting to the room’s applause.

Walker Calls for Attention to Details During Summer

Walker opened the meeting with a plea for normalcy during the summer months, when demand will be high, ERCOT’s reserve margin low and energy prices potentially poised to spike.

Already, the market has seen the collapse of Breeze Energy on May 30, the first retail electric provider (REP) to go out of business since 2014. ERCOT staff told the Board of Directors June 12 that the retailer defaulted on its collateral obligations to the ISO.

Mark Ruane, ERCOT’s director of settlements, retail and credit, said that when Breeze “failed to cure that breach,” the ISO began a transition of its nearly 10,000 customers to their providers of last resort: other REPs.

“While I think it went smoothly, I think it could go smoother in the future,” Walker said, thanking Oncor for managing the transition. “They waived all the deposits. I think that was very helpful too.”

ERCOT is holding a workshop June 21 to discuss lessons learned from the Breeze transition.

“My focus is making sure consumers get to choose who they get to take service from and do it in a timely manner,” Walker said.

PUC to Intervene in FERC Dockets

Following its executive session, the PUC moved to intervene in three dockets currently before FERC:

NextEra Energy Transmission’s request to buy a 30-mile transmission line in East Texas owned by Rayburn Country Electric Cooperative. NextEra plans to transfer functional control of the line to SPP (EC18-97).
Entergy’s waiver request to allow its operating companies to reflect recent tax law changes in MISO’s formula rate templates (ER18-1721).
MISO’s proposed Tariff modifications governing the treatment of generation retirements and suspensions (ER18-1636).

— Tom Kleckner

June 17, 2018

Duke, ODEC Rebuffed on Polar Vortex Gas Refunds

By Rory D. Sweeney

Duke Energy and Old Dominion Electric Cooperative have likely struck out on trying to recoup millions of dollars in “stranded” gas costs they say PJM forced them to incur during the 2014 polar vortex.

The D.C. Circuit Court of Appeals on Friday ruled that FERC was justified when it denied the companies’ reimbursement requests in 2015, rejecting separate petitions for review (16-1133, 16-1111). (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

Duke and ODEC had argued to FERC that they were owed compensation when PJM ordered them to be ready to run even as the cold snap sent gas prices soaring. Duke purchased $12.5 million worth of natural gas for its Lee plant in Illinois, only to have it not called on in real time. The company was able to resell some of its gas and sought $9.8 million in restitution.

ODEC complained that it was due nearly $15 million because PJM canceled multiple dispatches that left gas it had purchased for its plants unused. It also said its plants’ operating costs on Jan. 23, 2014, exceeded what it could recover in the day-ahead market because of the $1,000/MWh offer cap at the time. The co-op asked the commission to extend to Jan. 23 the waiver FERC granted PJM on Jan. 24, which allowed capacity resources to receive make-whole payments if their costs exceeded the offer cap.

FERC denied the request, saying PJM’s Tariff didn’t allow it and that ODEC’s ratepayers lacked sufficient notice that the approved rate was subject to change. The court upheld FERC’s decision, dismissing ODEC’s arguments that it could charge a market-variable formula rate and that customers received sufficient notice from an announcement PJM posted that it would seek commission approval for certain generators to exceed the rate cap.

“Close, but no cigar,” the court said of the formula rate argument. ODEC failed to identify Tariff provisions specifying such a rate or an instance in which utilities refunded overbillings back to customers, a bidirectional condition that would exist under formula rates. Additionally, “to toss that [$1,000/MWh rate] cap aside after the fact just because it did exactly what a cap is supposed to do — serve as a firm ceiling on market prices — would retroactively rewrite the terms of the filed rate,” the court said.

ODEC’s argument that PJM’s announcement qualified as sufficient notice “fails at every step,” the court said, noting that it wasn’t filed at FERC as required for rate changes.

The court also sided with FERC on Duke’s request, in which the commission concluded that PJM’s conversations with the company did not constitute an order to purchase expensive gas.

ODEC Duke Energy Polar Vortex PJM — | *Monitoring Analytics*

FERC determined that PJM operators told the generators “to do whatever needed to be done to fulfill its Tariff obligation” but “said nothing about when to purchase natural gas, at what price to purchase the gas, how to bid into the market or to take any action beyond that which Duke is otherwise obligated to take under the Tariff: to purchase natural gas to be prepared to run its units.”

The court conceded that “the record may well be subject to other interpretations,” including those preferred by Duke.

“But our task is not to assess whether Duke’s interpretation of the record is fair,” the court said. “Just the opposite: We must accept FERC’s interpretation unless unsupported by substantial evidence. And Duke has given us no basis for believing that a ‘reasonable mind’ would not find the evidence here ‘adequate to support [FERC’s] conclusion.’”

June 17, 2018

Plan Would Reduce PJM Capacity Curve Through Peak Shaving

By Rory D. Sweeney

PJM hopes to reduce its capacity market demand curve by including peak shaving among the variables used to develop its load forecast.

Andrew Gledhill, senior analyst of resource adequacy planning, explained the proposal at a meeting last week of the Summer Only Demand Response Senior Task Force (SODRSTF). It has the potential to reduce reliability requirements — and subsequently the variable resource requirement demand curve — by hundreds of megawatts.

PJM would start by adjusting historical loads back to 1998 through a formula that assumes perfect previous curtailment compliance. The program would be assumed to have been enacted every time a predetermined temperature-humidity index (THI) threshold was reached. THI has a strong correlation with loss-of-load expectation, the RTO said.

Each event would have been six hours from 1 to 7 p.m. on a non-holiday weekday. The events would have occurred any time between May and October, but “we don’t have a lot of high-THI events that occur in May, September and October, so … these are most likely to occur in June, July and August,” which account for the six highest load hours in the RTO, Gledhill said.

Adjusting the Model

The current method identifies the gross load for a delivery year and regresses for the forecast based on variables, including economic, weather and end-use changes.

“But there’s no variable in there for peak shaving,” Gledhill explained, so it would have been included only by reducing the gross load.

pjm load forecast peak shaving — | *An example from PJM of the potential impact to the VRR curve in ATSI’s transmission zone.*

Some stakeholders voiced concerns that requiring commitments to last six hours was a high bar that would reduce offerings into capacity auctions, but others urged them to take a holistic view.

“We have to look at what PJM’s need is, not simply what the easiest program or the most customer-friendly program would be,” GT Power Group’s Dave Pratzon said.

Staff said the six-hour time frame is intentional because it mitigates peak shifting. They noted that the curtailments have already been factored into forecasts. PJM would only be looking for compliance, but these would not be RTO programs.

“The load forecast has already reflected the benefit of reduction of load when THI trigger is hit,” PJM’s Tom Falin said. “The intent of this is to improve the load forecast. … We’ve already assumed a certain amount of behavior, so it has to continue in the future, so the forecast can remain consistent.”

Impact

PJM’s analysis showed that only a percentage of the cumulative peak shaving would impact the load forecast because of the peak simply shifting to another hour. For most transmission zones, the impact shrinks as the amount of shaving increases, staff found. For example, 100% of the megawatts in a 2% shave would impact the forecast in the Penelec zone, but less than 40% of the megawatts in a 10% shave would impact the forecast in East Kentucky Power Cooperative’s zone.

It would have even less of an impact on the reliability requirement, though it would still be significant. PJM found that, given a 6% peak shave, the reliability requirement would be reduced by anywhere from 30 to 85% of the shaved megawatts.