Page 1246 – RTO Insider

November 7, 2017

AMP Questions $400M in Added PJM Tx Upgrades

By Rory D. Sweeney

PJM’s announcement on Thursday of plans to recommend more than $400 million in transmission upgrades — just weeks after the RTO’s Board of Managers authorized $1 billion in spending — sparked pushback from American Municipal Power, which said the RTO ignored questions about the effectiveness of several of the projects.

Staff plan to recommend adding the projects to PJM’s Regional Transmission Expansion Plan at the board’s Dec. 4 meeting.

AMP’s Ryan Dolan questioned PJM’s analysis of several of the reliability projects, arguing that the proposed solutions fail to address all issues at the nodes in question and will necessitate additional construction in the future. He was displeased that PJM plans to recommend the projects even though, he said, concerns were raised about their effectiveness from a “holistic planning” perspective at a sub-regional RTEP discussion the previous day.

“For some of these projects, basically … [PJM is] planning on making these recommendations no matter what comments were provided,” Dolan said. “I think it would be useful to give time between when we make recommendations to when the last review of a project is to ensure any of the comments … that were brought up … can actually be accounted for.”

American Municipal Power AMP transmission upgrades — Sims | © *RTO Insider*

PJM’s Mark Sims responded that all information underlying the RTO’s recommendation has been available throughout the planning process and that recommendations can change as additional information is added to the analysis.

“We’ve been transparent with all the steps along the way,” he said.

The $400 million in additional projects will be recommended as the result of a reliability analysis for the 2021/22 delivery year, Sims said. They include eight projects from the first RTEP proposal window for 2017, along with 13 projects that were previously identified.

transmission upgrades American Municipal Power AMP — Dumitriu | © *RTO Insider*

The recommendations also include one market efficiency project proposed by American Electric Power to address a thermal constraint on the Tanners Creek-Dearborn 345-kV circuit. PJM’s Nick Dumitriu explained that AEP’s $600,000 solution would upgrade equipment at the Tanners Creek station, removing price separation in the Duke Energy Ohio/Kentucky (DEOK) locational deliverability area in the 2020/21 Base Residual Auction Capacity Emergency Transfer Limit (CETL) study.

PJM rejected two other proposals for the same constraint that estimated costs at $4.9 million and $12.7 million.

RTO staff confirmed the upgrades will be included in the model for the 2021/22 BRA.

AMP has become increasingly critical of transmission spending in PJM. In September, the company released a report showing that more than half of the $24.3 billion in transmission spending in the RTO since 2012 were supplemental projects by transmission owners and were not needed to comply with RTO or federal reliability requirements. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)

November 7, 2017

MISO in ‘Good Shape’ for Winter Operations

By Amanda Durish Cook

CARMEL, Ind. — MISO expects to easily manage this winter’s anticipated 103.4 GW of peak demand with an estimated 142 GW of available capacity, stakeholders recently learned during a trio of meetings focusing on winter preparedness.

“We certainly can’t be complacent. … In winter, just like in every season, we have to be ready for anything thrown at us, but we’re prepared,” MISO Executive Vice President of Operations Richard Doying said during a Nov. 6 winter readiness workshop.

MISO peak demand winter reserve margin — Northern Indiana Public Service Co. crews make repairs after a late December storm in 2015 | *NIPSCO*

Using National Oceanic and Atmospheric Administration projections, MISO predicts this winter will be warmer than normal in its Central and South regions, while temperatures in the North region will be normal to below normal.

Darius Monson of MISO’s resource adequacy coordination group said the RTO’s winter reserve margin is expected to vary between 28.3 and 37.3% without factoring in outages.

“That’s a fairly good position to be in,” Doying said.

However, the reserve margin could range from 6.7 to 19.3% after taking possible outages into account, Monson said, compared with this year’s footprint-wide 15.8% planning reserve margin requirement. The RTO used historical outage data to predict winter outage levels anywhere from the more probable 23.3 GW, to 28.7 GW in a high load, extreme outage scenario. MISO might need to rely on behind-the-meter generation and demand response resources to meet peak demand under that scenario, Monson said.

The RTO does not predict any major constraints or thermal and voltage issues during the winter.

Engineer Katherine Hulet said MISO did not uncover any potential issues through its biannual Coordinated Seasonal Assessment. The study evaluates a variety of stressed conditions across the MISO footprint and identifies potential limitations and issues on the system for the upcoming winter.

Hulet said the RTO studied possible transmission contingencies, potential transfer contingencies, voltage stability and possible phase angle differences, but found no cause for concern.

“It really looks like MISO’s in pretty good shape. Not only are there capacity resources, but the transmission is in a position do well,” Reliability Subcommittee Chair Tony Jankowski said during a Nov. 2 conference call.

Jankowski asked if MISO is considering performing seasonal studies for shoulder periods. Hulet said seasonal studies will continue to be limited to summer and winter.

Jankowski urged operators to ensure all generators are in good repair. “Eventually that arctic air will make it into our footprint,” he warned.

Doying also said MISO is well-positioned for winter reliance on natural gas.

“We have access to just about all pipeline interconnections. Actually, most of the gas storage in the country is located within MISO,” Doying said during an Oct. 31 Markets Committee of the Board of Directors conference call. The RTO expects gas storage inventories nationwide to peak at 3.8 Tcf this winter, slightly below the five-year average, and prices to continue hovering around $3/MMBtu into winter.

Independent Market Monitor David Patton said MISO’s proximity to gas storage makes it easier to quickly ensure fuel supplies if a pipeline goes down, whereas the New England region doesn’t have such supply backups, requiring more Northeast generators to have dual-fuel capability.

“We’re ready until the next polar vortex presents a whole new realm of challenges,” MISO Chairman Paul Bonavia remarked jokingly.

November 5, 2017January 3, 2024

Weather Leaves Alliant Profit Down Despite Rate Hikes

Despite two rate increases that took effect earlier this year, Alliant Energy’s third-quarter results were down year over year because of mild weather this summer.

The Madison, Wis.-based company announced a quarterly profit of $174.3 million ($0.75/share), down from $179.7 million ($0.80/share) a year earlier. Alliant attributed the slump to mild conditions, higher depreciation expenses and higher energy efficiency cost recovery amortization at subsidiary Wisconsin Power and Light (WPL).

CEO Patricia Kampling said earnings would have been on target with earlier estimates had summer temperatures been on par with historical averages.

“This quarter, we continued to produce solid financial and operational results,” Kampling said. “With three quarters of the year behind us, I am pleased to report that our anticipated … temperature-normalized earnings for fiscal year 2017 are in line with the original midpoint of our 2017 earnings guidance. However, taking into account year-to-date temperatures, which resulted in an estimated 6 cents/share of lower earnings, we are updating 2017 adjusted earnings per share guidance to a midpoint of $1.93.”

Alliant provided year-end guidance between $1.89 and $1.97/share.

The earnings announcement follows regulatory approval of two Alliant rate hikes this year. Interstate Power and Light’s interim electric base rate increase was approved in April, while WPL’s electric and gas base rate increases were implemented in January. They will boost annual revenues by $102 million and $18 million per year, respectively. Also in January, Alliant discontinued WPL’s practice of offering winter rates that are lower than summer rates.

— Amanda Durish Cook

November 5, 2017

ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas

By Michael Kuser

New England will see its grid integrate more renewable resources and increase its reliance on natural gas-fired generation over the coming decade, according to ISO-NE’s 2017 Regional System Plan.

ISO-NE CAISO Natural Gas hybrid competitive retail solution — | *ISO-NE*

The plan, which forecasts power system needs through 2026, highlights increasing wind and solar penetration, flat load growth and fuel security concerns because of natural gas pipeline constraints. The forecasts are in line with those aired at a public hearing on the plan in September. (See ISO-NE Forecast Sees Flat Loads, More Solar, No Congestion.)

Declining Load, Increasing Retirements

With growing penetration of solar and energy-efficiency resources, the forecast shows the 10-year net energy for load decreasing from 126,786 GWh in 2017 to 119,680 GWh in 2026, a decline of 0.6% per year.

The 50/50 net summer peak forecast of 26,482 MW for 2017 declines to 26,310 MW for 2026. The 90/10 net summer peak forecast, which captures extreme heat waves, is 28,865 MW for 2017 and grows by 0.1% per year to 29,021 MW in 2026.

Retirements will likely be the key driver for new resources. From 2010 to summer 2020, power plant retirements will total approximately 4,800 MW, said the report, which notes that economic and environmental pressures are putting older oil, coal and nuclear generators at risk. Retiring resources are likely to be replaced by gas, wind and solar resources, resulting in a “hybrid” of renewable and conventional generation, the RTO said.

As of April 2017, nearly 13,000 MW of resources had applied to connect to the high-voltage grid, though the interconnection queue historically has had an attrition rate of 68% of the megawatts proposed. The most reliable and economic siting for new resources remains near load centers in southern New England.

Adequate Resources

The 11th Forward Capacity Auction, held in February 2017, procured sufficient resources to meet resource adequacy criteria through 2021, with about 264 MW of new generation, including 6 MW of wind, 5 MW of solar and 640 MW of new demand-side resources, including 515 MW of energy efficiency.

The regional net installed capacity requirement (ICR) is based on gross load and load reductions from behind-the-meter PV. The representative net ICR is expected to grow from 34,300 MW in 2022 to 35,700 MW in 2026, the report said.

Fuel Security Concerns

The report cites fuel security risks from the failure of the natural gas pipeline infrastructure to keep up with the growth in gas-fired generation, a particular concern during winter.

ISO-NE is conducting an analysis to quantify the region’s risk, the results of which will be discussed with stakeholders in 2018. The RTO delayed issuing the report in October following the Department of Energy’s proposal to subsidize uneconomic coal and nuclear generators. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)

Solar PV resources totaled 1,918 MW (nameplate capacity) at the end of 2016. The RTO projects that will more than double to 4,733 MW by 2026, producing about 6.2 GWh of energy that year. PV resources are estimated to reduce summer peak loads by 575 MW this year and by 1,035 MW in 2026.

New England has 1,300 MW of installed wind with about 5,400 MW more proposed as of April 2017. Massachusetts in July launched a solicitation for 400 MW in offshore wind, with proposals due in December.

The RTO sees the role of energy storage growing over the next decade as the technology’s costs decline. The region’s first grid-scale battery system, a 16-MW facility at Yarmouth Station in Maine, was placed online in 2016.

From 2002 and June 2017, the region spent $8.4 billion on 730 transmission upgrades to improve system reliability and reduce congestion. As of June 2017, an additional $4 billion in transmission investment for reliability was planned. The RTO expects the need for major transmission projects for reliability to decline through 2026 but said the integration of large-scale renewable energy resources could change that forecast.

November 5, 2017

FERC Denies Rehearing on ISO-NE Retirement Rule Changes

By Michael Kuser

FERC last week denied requests for rehearing of its April 2016 order that approved capacity market changes to prevent ISO-NE generation owners from retiring resources that are still economic (ER16-551-003).

The new rules changed how retiring generators declare their intention with de-list bids — the minimum capacity price that will keep the plant operating — and gave the RTO the power to keep a unit operating if needed for reliability.

ISO-NE said the changes were needed to prevent suppliers from retiring a generator to increase prices for the remainder of the supplier’s portfolio. It followed an uproar over the closing of the 1,517-MW Brayton Point plant in Massachusetts. (See FERC Approves Changes to ISO-NE Retirement Rules.)

In a July 2016 order, FERC also approved a 10% mitigation threshold allowing ISO-NE to substitute the Internal Market Monitor’s cost estimate in place of the supplier’s de-list bid if the Monitor found the supplier had overstated the operating costs of the plant by 10% or more.

Section 205 Rights

The New England Power Generators Association, Exelon and NextEra Energy Resources asked FERC to reconsider the initial order, saying the rule changes forced them to cede to ISO-NE their Section 205 rights to file rates with the commission.

FERC concluded that although the Tariff changes add steps to the bid review process, they do not fundamentally alter the process in a manner that infringes on the suppliers’ rights to file rates. “The Internal Market Monitor’s mitigation is an input into a market-based capacity auction governed by ISO-NE’s Tariff that generates the Forward Capacity Auction’s clearing price,” the commission said in its Oct. 30 order.

ISO-NE FERC Retirement Capacity Auction — | *ISO-NE*

The commission said “this market construct is distinguishable from a supplier’s right to file cost-of-service rates with the commission pursuant to Section 205 of the [Federal Power Act]. We reject petitioners’ implicit contention that ISO-NE does not provide a jurisdictional service and that the Forward Capacity Auction is the suppliers’, instead of ISO-NE’s, rate.”

The commission also disagreed with the generators’ assertion that FERC provided no evidence that ISO-NE’s proposal represented a balance between possible over-mitigation and the need to curb market power.

“On balance, we are persuaded that the need to address possible price distortion due to a retiring supplier potentially exercising market power to impact the market clearing price outweighs the risk of lower capacity prices resulting from possible over-mitigation,” the commission said.

Two-Run Clearing

FERC also rejected the generators’ complaint that the two-run clearing mechanism in the new rules — under which capacity needed to replace a retiring resource could receive a higher price — was discriminatory.

“To the extent that the second run yields a higher price than the first run, this would result from the Internal Market Monitor’s determination that a resource has sought to retire uneconomically,” the commission said. “Therefore, it is necessary to limit suppliers that cleared in the first run to that clearing price to ensure the auction’s competitiveness and protect consumers from the exercise of market power. We find this mechanism is necessary to ensure that non-retiring suppliers themselves are not unduly discriminated against due to a retiring supplier’s exercise of market power.”

The commission dismissed as moot the generators’ request that the mitigation threshold — which FERC’s April 2016 order required the RTO to add — “is in addition to, and not a substitute for, flexibility with respect to forecasts and other inputs of exit bids.”

The commission said its July order approving the threshold had already made that point clear.

November 5, 2017

FERC Approves ISO-NE Queue Clustering

By Michael Kuser

FERC last week approved ISO-NE’s proposal to cluster interconnection requests to relieve a backlog in the queue for northern and western Maine.

The revisions, effective Nov. 1, will allow the RTO to consider interconnection requests and allocated network upgrade costs in groups rather than individually.

The commission’s Oct. 31 order said that the changes “increase efficiencies, better inform the decisions of project developers and allow project developers to share the costs of the upgrades necessary to accommodate their interconnection” (ER17-2421). (See ISO-NE Files Cluster Study Rules; Window to Open in Nov.)

The RTO will use its new clustering procedure in addition to its “first-ready, first-served” serial interconnection request system. “When specific conditions are present in the ISO’s interconnection queue, the proposed methodology would allow two or more interconnection requests to be analyzed in the same system impact study and for developers to share costs for certain interconnection-related transmission upgrades,” ISO-NE said.

Together with the New England Power Pool’s Participants Committee and the Participating Transmission Owners Administrative Committee, the grid operator proposed implementing the clustering methodology first to address the queue backlog in Maine, where more than 5,800 MW of proposed resources, mostly wind, want to connect to the grid.

Long-Term Benefits

The commission rejected protests by RENEW Northeast, American Wind Energy Association, EDP Renewables and King Pine Wind, who argued it would be unjust and unreasonable to allow the clustering revisions to take effect before Massachusetts issues the results of its 2016 request for proposals. Owners of generation projects in northern and western Maine were among the respondents.

“Given the overall expected long-term benefits of the [revisions], we find that, on balance, it would be inappropriate to wholly reject the revisions to accommodate a subset of interconnection customers in the near term,” FERC said.

RENEW asserted that solicitations like Massachusetts’ determine which renewable generation projects are viable for interconnection construction and, thus, which projects execute power purchase agreements that include recovery of network upgrade costs. EDP said that ISO-NE could avoid such timing issues by aligning the implementation of the clustering with the timing of the Massachusetts RFP process.

NEPOOL responded that RENEW provided an alternative proposal in the stakeholder process to synchronize the interconnection cluster study process with the state’s energy procurement process, but only 40% of Participants Committee stakeholders favored the proposal.

The commission denied protesters’ request to delay implementation of the clustering revisions until 30 days after the results of the Massachusetts RFP are released. FERC also rejected protests that the misalignment between the cluster study process and state procurement processes would cause the first cluster to collapse because interconnection customers not selected for the RFP will withdraw from it. FERC noted that the RTO’s new rules “allow for full refund of the cluster participation deposit in such instances.”

The commission also was not persuaded by arguments that moving an interconnection customer that does not agree to join the cluster to the bottom of the queue is unjust and unreasonable.

“The clustering revisions appropriately aim to ensure that only those interconnection customers that are ready to move forward in the interconnection process participate in phase two of the cluster studies, [which] is consistent with the ‘first-ready, first-served’ approach that the commission discussed as a possible queue reform measure in RTO/ISOs as early as 2008,” the commission said.

November 5, 2017

FERC Approves CAISO Black Start Changes

By Jason Fordney

FERC last week approved CAISO Tariff changes to establish a process for selecting and procuring black start resources needed to restore segments of California’s transmission system in the event of regional outages.

Black start refers to the ability of a generating unit to begin operating without assistance from the electric grid. Such units are needed to restart other generation and restore the grid after widespread outages; they have certain requirements under the ISO’s Tariff.

CAISO FERC black start — CAISO needs additional black start capability in the San Francisco area

CAISO staff last year determined that additional black start capability was needed in the transmission-constrained San Francisco Bay Area, prompting staff to develop new procurement standards to be applied across the ISO. (See CAISO Board OKs Black Start, TAC Area, EIM Charter Measures.)

The changes reorganize and consolidate certain black start provisions, create rules for technical requirements and operating tests, and remove outdated provisions. They also designate the cost of incremental black start as a reliability cost and allocate it to the transmission owner in the area where the units are located (ER17-2237).

The new black start provisions entail significant involvement of the affected TO — in this case Pacific Gas and Electric — in drawing up technical specifications and vetting proposals from resources bidding into the solicitation. The ISO would have authority to accept or reject a TO’s recommended resources. PG&E supported the changes and cost allocation method.

Under the new rules, CAISO will use a cost-of-service approach to compensate selected resources, rather than provide a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.

FERC said the revisions improve the reliability and clarity of the Tariff.

“Because individual black start capacity resources do not benefit all parts of the system equally, it is just and reasonable to recover these costs from a participating transmission owner where the resource is located and serves the reliability need,” FERC said. No parties objected to the cost allocation, and the benefits were roughly commensurate with the costs, the commission said.

To comply with CAISO rules, black start generators must make a minimum number of starts, operate in standalone and parallel modes, be able to pick up load during start-up load, produce and absorb reactive power, and have communication and control equipment.

November 5, 2017

NRG Optimistic Despite Q3 Profit Decline

By Michael Kuser

A cool summer and the impact of Hurricane Harvey drove NRG Energy third-quarter earnings sharply lower, but the company still sees bright days ahead, according to CEO Mauricio Gutierrez.

NRG earned $171 million ($0.53/share) last quarter, compared with $402 million ($1.27/share) in the same period last year. Revenues were down 10.9% to about $3 billion.

Gutierrez said during a Nov. 2 earnings call that although the company is “on track” to transform itself through cost-saving measures, the third-quarter results led the company to lower its full-year earnings before interest, tax, depreciation and amortization (EBITDA) guidance to $2.4 billion to $2.5 billion from the previous $2.56 billion to $2.76 billion.

“In Texas we saw both a major hurricane and the coolest August since 2004, with cooling degree days 13% below normal, and in the Northeast, cooling degree days were on average 8% below normal for July and August,” Gutierrez said. He noted that ERCOT summer wholesale prices fell 43% below expectations. Mild weather across the East and in Texas eliminated any opportunity to benefit from scarcity pricing.

NRG attributed one-time financial impacts of $40 million to Hurricane Harvey, evenly divided between its generation and retail operations in Texas. About 80% of the company’s baseload generation on the Gulf Coast was available during the worst part of the storm, and 95% has been restored to date.

Brighter Side

NRG’s retail business continues to improve its operating efficiencies, customer acquisition and retention, which partially offset the impacts of milder summer weather, especially in ERCOT, Gutierrez said.

He said certain cost and margin enhancements will start impacting the company’s bottom line next year, as well as the sale of subsidiary NRG Yield and its renewables assets, which is expected to be completed this year and return up to $4 billion. The company continues to use excess cash to deleverage itself, he said.

“Since our second-quarter call, we have taken another $600 million of debt out of our capital structure, completing our 2017 capital allocation,” Gutierrez said.

He also pointed to improving market conditions in Texas as a particular bright spot for the company.

“Despite the absence of extreme weather this summer, ERCOT fundamentals remain strong. ERCOT’s 2017 peak load of 69.5 GW was up nearly 2% over the five-year average and came in just shy of the 2016 peak,” he said.

The recently announced retirement of more than 4 GW of generating capacity in ERCOT puts further pressure on a market with already strong fundamentals, Gutierrez said. Vistra Energy on Oct. 6 announced plans to retire three aging coal-fired units in East Texas with a combined capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices. (See Vistra Energy to Close 2 More Coal Plants.)

“For summer of 2018, these new retirements and asset delays alone will put ERCOT at the lowest reserve market on record, which is suspected to be somewhere between 10 and 11%,” Gutierrez said. “Other changes, such as delayed new builds and new industrial demand, could lower these numbers even further.”

But while the retirements are nudging up forward markets, prices are still below what is needed to justify new builds, he pointed out.

Calls to Action on Market Reform

In response to an analyst question about whether NRG would consider selling parts of its Texas portfolio, Gutierriez said, “Right now we’re very comfortable with our Texas portfolio.” He said the capability of NRG’s generation fleet aligns well with its retail loads.

But while the recent retirements are improving market health, ERCOT must do more to strengthen markets and should recognize the locational value of power plants, he said.

“Reliability and resiliency are important attributes to the grid, and we will continue to work with ERCOT to ensure that generators close to load centers are compensated for all the benefits they provide.”

Beyond the positive developments in ERCOT, Gutierrez said NRG sees several other “calls to action” occurring for market reform.

“As the power grid continues to undergo significant change — low gas prices, renewable penetration and attempts for out-of-market subsidies for uneconomic generation — regulatory bodies and other stakeholders are taking note,” Gutierrez said. “These have led to several significant catalysts, from the [Department of Energy] staff report on competitive markets and [Notice of Proposed Rulemaking], to PJM’s proposed market reforms. I cannot recall another time when there has been such urgency and reach across ISOs to improve competitive energy markets.” (See Market Summit Tackles Ongoing PJM Changes.)

Gutierrez said NRG has been optimistic about market developments in PJM, especially around the introduction of Capacity Performance.

Asked to rank the most promising areas for growth, Gutierrez responded that NRG aims to balance its generation and retail businesses and is focused on perfecting an integrated platform.

“A lot of the generation is going to be driven by our retail needs and how we grow retail, and a lot of our retail will be driven by where we have generation,” he said. “We’re still long in generation in PJM. We have a ways to go before we have a balanced portfolio like we have in Texas. … Just in terms of market structure, I would put PJM No. 1, New England No. 2 and New York No. 3.”

November 5, 2017

Eversource Q3 Earnings Flat on Mild Weather

By Michael Kuser

Eversource Energy last week reported third-quarter earnings of $260.4 million ($0.82/share), down nearly 2% from the same quarter in 2016. Earnings for the first nine months of 2017 were $750.6 million, up 5% from earnings of $713.1 million in the same period last year.

earnings Eversource Energy q3 weather — Lembo | *Eversource*

“The primary drivers of our [quarterly] results were higher electric transmission earnings being offset by lower electric distribution results,” Eversource CFO Phil Lembo told analysts in a Nov. 2 conference call.

A higher rate base boosted transmission earnings by 10.7% to $99 million, the result of the company investing $600 million in its transmission system this year through September, with just less than $1 billion planned for the full year, Lembo said.

He attributed a 7.4% drop in earnings for the company’s electric distribution and generation division to lower sales reflecting mild weather in July and August. Cooling degree days in Boston were down nearly 34% for the quarter compared with last summer and 8% below normal, he noted.

In addition to lower electric revenues, the company recorded higher property tax, depreciation and interest expense in the quarter, but was able to offset much of the negative impact by controlling costs, Lembo said. Eversource’s natural gas distribution segment posted a net loss of $6.2 million in the third quarter and earnings of $49.1 million in the first nine months of 2017, compared with a net loss of $7 million in the third quarter of 2016 and earnings of $51.9 million in the first nine months of 2016.

“For the long term, we continue to project 5 to 7% [earnings per share] growth,” Lembo said. “We are pleased with our results today and remain comfortable with our 2017 guidance, although I’d like to see some very cold weather in November and December, and that would really help us reach the higher end of our earnings range for ’17.”

Future Developments

Lembo noted that Eversource last month filed with the New Hampshire Public Utilities Commission to sell its remaining 1,200 MW of generation assets in the state for $258 million, and expects the two sales to be completed late this year or in early 2018. On the company’s proposed merger of subsidiaries NSTAR Electric and Western Massachusetts Electric Co., he said state regulators should issue a decision by Nov. 30 on the merger and grid modernization, and a decision on performance-based rate design by Dec. 29, with rates to become effective in January 2018.

Lee Olivier, Eversource executive vice president for business development, said the company’s Northern Pass transmission project achieved an important milestone Nov. 1 when utility subsidiary Public Service Company of New Hampshire filed a settlement agreement on the lease terms for most of the 192-mile route for the line.

“The settlement was reached with New Hampshire PUC staff and the Office of Consumer Advocate, the two principal intervenors in the case,” Olivier said. “We expect the New Hampshire PUC approval of the settlement by the end of the year. Taken together, we are very pleased with our current position in the siting process, with significant progress being made in all venues.”

Eversource has also partnered with Ørsted, formerly DONG Energy, to form Bay State Wind for the offshore wind solicitation in Massachusetts.

“We are preparing our bid into the Massachusetts offshore wind [request for proposals], which is due Dec. 20,” Olivier said. “Given the vast experience of Ørsted in European offshore wind and our knowledge of New England markets and transmission, we believe we will be able to submit a highly compelling set of proposals for review by the evaluators.”

November 5, 2017

MISO Planning Reserve Margin Climbs to 17% for 2018/19

By Amanda Durish Cook

MISO predicts the 2018/19 planning year will require a reserve margin just more than 17%, a figure that’s been steadily increasing over the years.

Based on its annual loss-of-load-expectation (LOLE) analysis, MISO expects the planning period to require a 17.1% reserve margin for installed capacity (ICAP) and 8.4% margin for unforced capacity (UCAP), the latter of which represents ICAP minus forced outage rates. The RTO will use the margins along with the latest load forecasts to create its enforceable planning reserve margin requirement before April’s capacity auction.

MISO LMP EIM governing body Synchronized Reserves — | *MISO*

Systemwide, MISO predicts it has about 150 GW of ICAP and almost 139 GW of UCAP to meet a nearly 126 GW expected peak demand for the June 2018-May 2019 period. The RTO’s planning reserve margin assumes the inclusion of 4,764 MW of firm UCAP and 2,331 MW non-firm UCAP from external resources.

MISO’s needed reserve margin has been on the rise since 2013. Last year, MISO predicted 15.8% for ICAP and 7.8% UCAP reserve margin for the 2017/18 planning year, up from 2016/17’s 15.2% and 7.6% values. (See MISO 2017/18 Planning Reserve Margin at Nearly 16%.) All local requirements increased from the 2017/18 planning year, the RTO noted.

Speaking during a Nov. 2 Reliability Subcommittee conference call, MISO senior engineer William Buchanan said the increase is primarily driven by an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO this year added a new modeling step to capture economic load uncertainty that increases the risk associated with high peak loads, also boosting the reserve margins.

Despite the yearly increases, MISO predicts reserve margins will begin to plateau. According to the LOLE analysis, they will largely hold steady because of similar forecasts over the next decade even as peak demand exceeds 129 GW by the 2023/24 planning year. The LOLE analysis found that through 2027, MISO’s ICAP reserve margin will fluctuate between 17.1 and 17.2% while the UCAP reserve margin will oscillate between 8.3 and 8.4%.