WESTBOROUGH, Mass. — ISO-NE planners will make a several changes in their procedures in 2017, including revisions to Planning Procedure 3, incorporating probabilistic planning, a review of how the RTO identifies Bulk Power System (BPS) assets and a streamlined method of developing models, Director of Transmission Planning Brent Oberlin told the Planning Advisory Committee last week.
The process changes and the incorporation of updated load, energy efficiency and photovoltaic forecasts may have a significant impact on both the system’s identified needs and their year of need, Oberlin said.
Responding to stakeholder concerns about too much time being required for ISO-NE to complete needs assessments, Oberlin said that planners will move from a work flow based on serial preparation to one based on parallel modeling.
“We’re stealing from PJM here, which has inspired us to create generic case studies to look at all of New England at once rather than state by state,” he said at the March 22 meeting. “Right now, our start-to-finish case study process takes six months.
“After we talked to PJM, [we] kind of hit [ourselves] in the head” for not making the change sooner, Oberlin said. The current process is “serial, it’s slow and I don’t think it’s effective.”
ISO-NE plans to create a “library” of generic cases and study files for use in the future. Once the RTO and its transmission and other facility owners update the system topology data, the generic cases and study files will be updated with the latest load, energy efficiency, photovoltaic and resource data and posted for stakeholder review.
The RTO also is comparing its assumptions for classifying assets as BPS with those of other transmission operators in the Northeast Power Coordinating Council (NPCC). “It’s not lost on us that New England has more than half of the BPS classified substations within the NPCC, so we may revise the definition of what is a BPS,” Oberlin said.
The changes to Planning Procedure 3, which took effect Feb. 10, reduced the types of contingencies required for second contingency testing, limiting them to those with the greatest potential to impact the identification of system needs.
No longer required to be tested as the second contingency: the loss of two adjacent circuits on a multiple circuit tower and a permanent phase-to-ground fault with breaker failure. These second contingencies must still be tested under NPCC requirements, but solutions will be required only when the problems impact BPS facilities.
After more than a year of work with the PAC, the RTO will begin incorporating probabilistic dispatch methods in late spring, starting with the inclusion of probabilistically based local dispatches in the base system conditions used in needs assessments. The use of probabilistic methods will likely increase in the future, Oberlin said.
Eversource Towers Show Their Age
Eversource Energy engineering manager John Case showed slides of rusting steel and deteriorating concrete foundations to prove the need for replacing four aging towers carrying transmission lines over the Thames River in Connecticut.
Part of rusted transmission tower | Eversource
About half a mile of the 1410/100 lines from Montville to Gales Ferry Junction shares double-circuit steel lattice towers that straddle the river at the Montville-Ledyard border.
“These structures were constructed in 1921 and have exceeded their planned life, and may have done [so] before I was born,” Case said to laughter. “And I am not a young man.”
Recent inspections of the structures revealed severe degradation of the foundation, towers and hardware. The four towers will be replaced with six galvanized steel poles at an estimated cost of $8.5 million (-25%/+50%).
NEW ORLEANS — A debate over the fairness of the postage stamp cost allocation method and how to quantify transmission benefits took center stage at the MISO Advisory Committee’s quarterly hot topic discussion.
MISO Vice President of System Planning and Seams Coordination Jennifer Curran noted that the RTO has not changed cost allocation rules since the integration of MISO South.
“Are there benefits that are no longer relevant? Are there benefits that we haven’t even realized yet? These questions are critically important,” Curran said during the March 22 discussion.
As part of a review of its cost allocation procedures, MISO is considering lowering the 345-kV threshold on market efficiency projects and replacing the footprint-wide postage stamp rate with a method that assigns costs to benefiting transmission pricing zones. It is also seeking to identify other economic benefits in addition to production cost savings, including eliminating the need for future fixes by pursuing a long-term project over a short-term project and projects that aid planning reserve margins. (See MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017.)
Curran said she didn’t expect unanimous sector support on any revised cost allocation procedure, but there is some consensus within sectors. “The biggest challenge we face is a common definition given the challenges we face,” Curran said.
Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, introduced the topic, saying it was “incredibly hot and had incredible significance.” She then cued the O’Jays’ “For the Love of Money,” eliciting applause.
Transmission Owner sector representative Matt Brown of Entergy pointed out that MISO changed aspects of its transmission cost allocation in 2003, 2007, 2009 and 2012. “This is not a static set of rules, and MISO has shown the ability to change and adapt,” Brown said. But he said that “experimental” changes should not be made to MISO’s “mature” cost allocation process.
“There is a lot that works with what we have now, and I caution everyone not to lose sight of that,” Brown said.
Northern Indiana Public Service Co.’s Paul Kelly cautioned MISO against “speculating” on transmission benefits, saying they should be represented with an equation that can be repeated across projects.
WEC Energy Group’s Chris Plante said most in his Transmission Dependent Utilities sector support a postage stamp rate because many benefits of transmission projects are not quantifiable or are realized later.
“Today’s reliability project could be tomorrow’s multi-value project,” Plante said.
Brown said the TO sector is not interested in pursuing a postage stamp allocation, which assesses a uniform rate on all MISO transmission owners, simply for the sake of benefits that may be missed. “If you can’t measure it, it’s not a benefit that should be considered. Benefits need to be demonstrable, repeatable and non-duplicative,” he said.
Thomas: Postage Stamp not Always Best
Arkansas Public Service Commission Chairman Ted Thomas, the delegate for the Regulatory sector, said MISO should conduct extensive analysis before implementing any change.
“The business is changing, but modeling is changing too, and we have more operational history. If there need to be sub-zones — better ways of how a true beneficiary pays — then we need to do that,” Thomas said.
Thomas also said postage stamp allocation is not always the most equitable method. “Let’s not use a postage stamp when we can’t figure [benefits] out. Let’s go back to the lab and figure it out,” he said.
MISO Director Michael Curran said he understood stakeholder frustration if too many benefits are swept into a “common good” category and applied on a postage stamp basis.
Plante said that while MISO’s modeling has improved and can identify a beneficiary “right down to a point of delivery,” the modeling is only as good as the assumptions on which it is based, including forecasting natural gas prices and impacts of future regulations.
Public Consumer sector representative and attorney Kevin Lemley said postage stamp allocation fails to recognize that non-transmission alternatives can solve some problems.
ITC Holdings’ Devin McMackin said MISO’s list of project types is probably too “rigid” and said he supports more flexibility or an expansion of project types.
Allocation by Project Type
MISO’s allocation procedures vary by project type:
Costs of market efficiency projects 345 kV and above are split 80% to local resource zones based on benefit and 20% to load through postage stamp.
Generation interconnection projects above 345 kV assign 90% of costs to the interconnection requestor, with 10% allocated to load on a postage stamp basis.
Multi-value projects are allocated entirely to load via postage stamp.
Baseline reliability projects are allocated entirely to local pricing zones.
Projects arising from transmission service requests are paid for by transmission customers, but the transmission owner can elect to roll costs into local pricing zone rates.
Participant-funded projects are left out of cost allocation procedures entirely, and projects not eligible for allocation can be recovered through a zonal transmission rate.
| MISO
Plante said cost allocation needs to be resilient, able to survive an expanding footprint and shifting resource mix. Stakeholders again brought up MISO’s hourglass-shaped footprint and constrained MISO South interface, which some maintain precludes a benefits ratio from being applied to the footprint uniformly.
Alliant Energy’s Mitchell Myhre, representing the TDU sector, said adjusted production cost benefits should remain the primary metric when deciding allocation. All other benefits should be secondary considerations in cost allocation, Myhre said.
Director Paul Bonavia asked for a future session between the board and MISO staff on a preliminary cost allocation proposal.
‘Rough Justice’
Director Curran urged MISO and stakeholders to create a proposal, citing an adage: “‘Done is better than perfect.’”
Several stakeholders said that any cost allocation revision that MISO files with FERC would be an example of “rough justice,” meaning it would be generally fair but not acceptable to all parties.
MISO stakeholders are discussing possible allocation changes in the Regional Expansion Criteria and Benefits Working Group (RECBWG). Group chair Carolyn Wetterlin said the working group is considering simplifying its name to the Transmission Cost Allocation Working Group.
A day earlier, during a presentation on the 2017 MISO Transmission Expansion Plan (MTEP 17) at the March 21 Markets Committee of the Board of Directors, Director Phyllis Currie asked what MISO’s biggest challenge is when it comes to transmission planning.
“At the end of the day, I think it comes back to who pays,” Jennifer Curran said.
Director Mark Johnson asked for a review of MTEP-approved projects to determine if their projected cost benefits had been realized. Curran said MISO could collect that information.
Director Thomas Rainwater said he liked the idea of cost allocation post mortems, in which MISO staff would examine whether transmission benefits are being distributed as they were estimated.
NEW ORLEANS — MISO Independent Market Monitor David Patton last week used PJM’s proposed pro forma pseudo-tie agreement to renew his call for an end to pseudo-ties.
On March 9, PJM made a Section 205 filing with FERC to add criteria for accepting pseudo-ties (ER17-1138). PJM would require that it have dispatch control over new and existing pseudo-ties from NYISO and MISO. (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)
On Thursday, PJM officials delayed a stakeholder vote on the agreements. (See related story in PJM Markets and Reliability and Members Committees Briefs.)
Having NYISO units dispatched by PJM — which may not be fully aware of all the ISO’s data — is not a sound idea, considering New York’s transmission congestion, Patton said. He added that at least 18 units in MISO would be dispatched by the other RTO in the 2017/18 planning year beginning June 1. PJM currently dispatches 13 MISO units.
“It’s very inefficient. … It’s just a terrible idea,” Patton told the Markets Committee of the Board of Directors on Thursday.
Patton said PJM’s filing signals a good time for MISO to again propose replacing pseudo-ties with a firm capacity delivery procedure. MISO’s proposal would guarantee the delivery of the capacity purchased by PJM by the host RTO scheduling a firm export in the real-time market and having the external capacity supplier settle the export with both RTOs. Patton said MISO’s proposal is an “attractive” idea. (See “MISO IMM Warns Again of PJM Pseudo-Ties,” MISO Market Subcommittee Briefs.)
MISO Director Michael Curran said the creation of pseudo-ties itself was an “emotional response” to manage electricity flows from different balancing authorities in the early days of RTOs. “It’s difficult to try to get this to work, because it never worked in the first place. It sounds like it’s coming to a critical point here, and we’ll have to work with New York to bring some sanity to the situation,” Curran said.
Patton said MISO and NYISO might face resistance from PJM because PJM staff and stakeholders generally view the pseudo-tie concept as a way to maintain control of the quality and reliability of the generation on its system.
“I wouldn’t be opposed to a megawatt limit” on the volume of exports from MISO to PJM, Patton added.
Curran did not let the comment go unnoticed. “I’m shocked by that. You’re a fundamentalist, and suddenly you’re in favor of limits,” Curran said lightheartedly. “I’d hate to see you close the borders.”
Director Barbara Krumsiek asked which of PJM’s neighbors support the RTO’s proposal.
“That’s a good question,” Patton said laughing. He added that NYISO has no pseudo-ties with PJM and would most likely want to keep it that way.
Director Baljit Dail asked when the pseudo-tie issue might be solved.
Richard Doying, MISO executive vice president of operations and corporate services, said resolving the issue would be a long-term project. He said MISO would consult both its Monitor and stakeholders before proposing a Tariff solution to FERC.
NEW ORLEANS — MISO experienced a quiet winter, aside from early February tornadoes in Louisiana and high congestion charges from a MISO-PJM constraint.
Demand peaked at 100 GW, about 9 GW below MISO’s all-time winter peak during the 2014 polar vortex.
“We had a relatively mild winter and that turns into relatively mild operating conditions,” MISO Executive Director of Market Design Jeff Bladen said during a quarterly operations report at the March 21 Markets Committee of the Board of Directors meeting.
Average LMPs rose to $28/MWh from $21/MWh last year as gas prices rose 55% year-over-year, Markets Committee Chair Paul Bonavia said. He said MISO’s plentiful wind output kept prices from ticking further upward.
Independent Market Monitor David Patton said the most significant event in the quarter was a series of tornadoes in Louisiana on Feb. 7 that resulted in multiple transmission outages and pushed Louisiana Hub prices above $1,000/MWh for three hours. The storms led to $19 million in real-time congestion.
Patton said the storms caused real-time prices to be 30% higher than day-ahead prices for all of February.
“An event like this can cause a huge spike in balancing congestion charges,” Patton said. Balancing congestion charges, which normally average $1 million per month, totaled $11 million.
| MISO
Bladen said the weather incident caused MISO’s monthly market efficiency metric to increase by $15 million. “The impact was appreciable due to the outages,” Bladen said.
Director Baljit Dail expressed worry that an “act of God” caused such havoc on MISO’s markets, and said the Human Resource Committee of the Board of Directors could look into purchasing insurance against it. “When you consider the world we live in, more of these severe weather events will happen,” he said.
“We certainly do quite a bit to prepare for these severe conditions,” Bladen replied.
Director Michael Curran asked if approved transmission projects in Louisiana would help relieve congestion in future emergency conditions. MISO staff agreed that they would.
Not all of MISO’s winter real-time congestion could be attributed to severe weather. Most congestion occurred along the MISO-PJM seam and was caused by transmission outages and high wind output, Patton said.
A single MISO-PJM market-to-market constraint alone accounted for $40 million worth of congestion and was “difficult to manage because it is dominated by PJM resources,” Patton said. On Feb. 7 — coincidentally the day of the tornadoes — MISO transferred control of the constraint to PJM, “reducing congestion on the constraint and improving the dispatch,” according to Patton.
The Monitor said he would like to see MISO, PJM and SPP become more active in transferring monitoring of constraints “but it requires agreement and improved processes.” There are a number of cases where the non-monitoring RTO has all of the transmission loading relief on a flowgate, he said.
Patton also said there are several instances in which MISO and a neighboring RTO have to manually control flowgates, which is not as efficient.
“We feel the RTOs should develop better software and procedures” to switch control of the constraint to the RTO with the most relief, Patton said.
A jump in wind production also contributed to higher congestion in the quarter. Wind output rose 21% from the fall and 20% over last winter as MISO set an all-time wind output record of 13.7 GW on Dec. 7, beating the previous 13.3-GW record set in late November.
Patton said wind output contributed to $47 million of real-time congestion costs. He said the increase in wind output was most significant near the MISO-SPP seam where MISO wind resources are plentiful. SPP had difficulties controlling power flows from MISO into SPP.
“We get into situations where it’s difficult because we have a lot of wind resources that whip the flows around,” Patton said, adding that SPP sometimes will control the flows manually, which is more expensive.
“When your neighbor is dominating the constraint, you should hand the constraint over. SPP in particular has been resistant to this. PJM has been more willing to do this than SPP,” Patton said.
He said MISO and SPP should continue to work together to address monitoring control of constraints rather than “abandon economic coordination.”
MISO and SPP are working together on transfers of monitoring control and hope to agree on a smoother process later in the year, MISO staff said.
A top California lawmaker last week introduced a bill that would require the state’s utilities to meet an increasing amount of their peak energy demand with renewable resources and energy storage systems.
The proposed law would set a “clean peak energy standard” to reduce the reliance on flexible, gas-fired peaking plants to meet peak ramping needs as the state seeks to obtain 50% of its electricity consumption with renewable energy resources by 2030 (AB 1405).
State Assembly Speaker Pro Tempore Kevin Mullin (D), the bill’s sponsor, said that while California’s renewable energy and ambitious greenhouse gas reduction goals are “laudable,” they are “ultimately incongruous in the absence of a policy framework and new market mechanisms” that would allow CAISO to manage the impacts of increasing renewable penetration on the grid.
Mullin
“As more renewables are built toward the 50% [renewable portfolio standard] goal, more fossil fuel power plants will be built to provide flexibility and reliability, which is incompatible with the GHG reduction and cost-effective goals,” Mullin said in a statement.
The legislation defines a four-hour “peak load” time period that includes the hour leading up to, and two hours following, the hour of peak demand.
The law would require the California Public Utilities Commission to determine by Dec. 31, 2018, the percentage of “clean peak resources” — renewables and storage — being used by each of the state’s utilities to serve demand during the peak load period.
Each utility would have to meet increasing clean peak targets every three years beginning in 2020 and reaching 40% in 2029. The first year of the program would entail a 5% increase in such resources. Utilities would be required to meet the minimums for at least 15 days every month.
The rules would also apply to the state’s publicly owned utilities, which are not subject to CPUC oversight.
Use of clean peak resources would be subject to CAISO-approved measurement standards, while the CPUC would be charged with devising an “appropriate mechanism” for determining compliance with the clean peak standard, which could include a program of tradeable credits.
The bill also requires the PUC to consider developing other targets that would encourage the use of clean peak resources to provide additional flexibility and ancillary services.
A similar but less comprehensive bill has been introduced into the State Senate.
SB 338 would require the CPUC and California Energy Commission to consult with CAISO and “establish policies or procedures to ensure that electrical service providers meet net-load peak energy and reliability needs while minimizing the use of fossil fuels and utilizing low-carbon technologies and electrical grid management strategies.”
Under the Senate bill, “net-load peak energy” is defined as a daily period of three hours in which the last hour represents the interval of highest demand. The bill would permit the use of demand response and energy efficiency measures, in addition to renewables and energy storage.
ERCOT set a new record for wind penetration last week when it hit 50% at 3:50 a.m. March 23. The ISO was generating 14,391 MW of wind energy at the time.
The Texas grid operator reported a peak load of 45,257 MW that afternoon. Wind was responsible for 15,477 MW at its peak that day.
| ERCOT
ERCOT has produced as much as 16,022 MW of wind generation, which happened on Christmas last year. It manages more than 17 GW of wind energy and has 28.6 GW of proposed wind capacity in its interconnection queue.
The ISO had been in competition with SPP to see which would be the first North American grid operator to reach 50% penetration. However, SPP eclipsed that barrier Feb. 12 and has established several new records since then, the last coming March 19 when it reached 54.22% penetration with 12,078 MW of wind energy.
SPP has 16 GW of installed wind capacity and another 21 GW in the interconnection queue.
WESTBOROUGH, Mass. — Energy efficiency, lower economic growth and burgeoning home solar installations will reduce ISO-NE’s net load through at least 2026, Manager of Load Forecasting Jon Black said Wednesday.
While the region’s gross annual load is expected to rise by 8.5% to 152,593 GWh by 2026, load net of behind-the-meter solar and passive demand resources will drop 5.2% to 120,181 GWh. “There were no methodology changes in the [gross load] forecast since last year,” Black told the Planning Advisory Committee on March 22. “It’s just refreshes of the data.”
| ISO-NE
The region’s weather-normalized net electric consumption declined 1.5% in 2016 versus 2015, according to the RTO’s draft 2017 Capacity, Energy, Loads and Transmission energy and summer peak forecast. The completed forecast will be published by May 1.
Compared to last year’s forecast, the new report projects the 2025 annual energy demand will be 3.9% lower. The summer 50/50 forecast is approximately 3% lower, while the 90/10 forecast is 2.7% lower.
| ISO-NE
Reasons for the drop include a 15% increase over last year’s forecast in projected behind-the-meter solar for 2025 and an 11% increase in projected energy efficiency, the latter due to a revised production cost escalation methodology.
The grid operator projects approximately 2,444 MW of PV development over the coming decade, for a total of 4,362 MW in 2026.
Black said that they are now getting more granular data on load reduction because of PV after increasing the number of installations monitored from 1,200 to 9,000. The RTO counts distributed solar — those less than 5 MW — as reducing net load.
Passive demand resources climbed 11% last year to 14,380 GWh. Passive demand resources include the use of energy-efficient appliances and lighting, “smart” cooling and heating technologies that cycle air conditioners on and off, and measures to shift electricity use to off-peak hours.
Paul Peterson of Synapse Energy Economics asked RTO officials about the projected annual increases in PV resources. The report shows a 445-MW increase in 2017 PV versus 2016, a 23% jump.
“The PV is going to eat up large number of megawatt-hours. That will affect generation developers. If the pie continues to shrink, it becomes very difficult for generators to earn the same amount of revenue from energy sales,” Peterson said. “Generators need to know if solar will be five, six or eight thousand megawatts in 2026. Will the trend accelerate?”
“There’s a lot of uncertainty over that, around when this stuff becomes economic,” responded Black. “A lot depends on rate structuring. We’re waiting for clearer signals.”
ISO-NE officials told Vermont legislators in January that the capacity market “will be an important revenue-balancing mechanism to ensure resource adequacy as renewable resources drive down revenues in the energy market.”
Black said expectations of lower economic growth were based on a Moody’s Investor Service’s forecast that predicts New England’s share of the U.S. gross domestic product declining from more than 5.7% in 2000 to just more than 5% by 2026.
CAISO’s real-time market experienced an uptick in volatility during the fourth quarter of 2016, as five-minute prices at times spiked to well above day-ahead and 15-minute levels on unexpected variability in output from solar resources.
On the flip side: Solar generation increasingly sent mid-day prices into negative territory during the quarter, a trend that the ISO’s internal Market Monitor says is continuing into this year.
CAISO’s Q4 negative prices occurred most frequently during mid-day, the period of highest solar output. | CAISO
“November did see a fairly high frequency of prices above the $250 level in the five-minute market,” Gabe Murtaugh, a senior analyst with the ISO’s Department of Market Monitoring, said during a March 22 call to discuss his group’s quarterly market issues report. “You’d have to go back to the beginning of 2015 to see this frequency.”
In November, real-time prices surged to $250 or higher during nearly 1.5% of intervals, compared with fewer than 0.4% of intervals during the same period in 2015. Prices hit $750 or more during 0.6% of intervals, up from 0.3% a year earlier.
Murtaugh attributed the prices spikes to more cloud cover than was forecast by CAISO, translating into lower solar output than was accounted for in the day-ahead market during specific intervals. The ISO was forced to move up the bid stack to secure higher-priced resources in real-time to cover the shortfall — especially during the afternoon ramp as solar resources began to reduce output.
“This outcome resulted in part from a combination of solar deviations and tight supply conditions during intervals when system ramping needs were greatest,” the department said in its report.
Contributing to the price discrepancies between the five- and 15-minute markets were differences in the solar forecasting methodologies used for each, an issue the ISO addressed through changes to its forecasting software in December.
Still, instances of high prices during the fourth quarter were “fairly irregular,” according to Murtaugh. More frequent were intervals of negative prices, the Monitor noted.
The department observed negative prices during 4.7% of intervals during the five-minute market and 1.8% of those in the 15-minute market. By comparison, during the same period a year earlier, negative prices occurred in 2% and 1% of five- and 15-minute market intervals, respectively.
The last quarter of 2016 also saw five-minute prices go negative nearly 20% of the time during the 10 a.m. interval — the beginning of the mid-day period most subject to solar-drive price dips.
Graph shows that CAISO Q4 real-time prices consistently outpaced those for the day-ahead and 15-minute markets during the afternoon ramp. | CAISO
Nearly all of the negative prices were the result of the ISO’s market mechanisms — and not the result of out-of-market operations to curtail output.
“These are conditions where an economic downward dispatch is issued to a unit with a negative marginal cost, so negative marginal cost units are setting the marginal price in the system,” Murtaugh said. “This is a solution that is arrived at from the market optimization and it’s similar to any other solution that we would see in the market during other times of the day when marginal costs are set at a marginal level.”
The Monitor’s data showed that most of the negative prices held to a range between $0 and -$50/MWh.
Carrie Bentley of Resero Consulting wondered where most of the negative prices clustered — closer to $0 or $50?
“Off the cuff, it tends to be more clustered between the $0 and $25 range,” Murtaugh responded. “That typically tends to be the amount of tax incentives that are given out on a per-megawatt-hour basis to solar facilities and wind facilities — and those tend to be the ones we see setting the price more frequently.”
Murtaugh also offered call listeners a “teaser” regarding the first quarter: “For the data that we’ve already looked at in 2017, the [negative price] numbers are fairly high for the first quarter as well.”
Wei Zhou, a senior project manager with Southern California Edison, probed Monitor staff about an observed increase in negative prices in the ISO’s day-ahead market this year.
“What’s the expectation for the frequency of negative pricing in the day-ahead market?” Zhou asked.
Keith Collins, CAISO manager of monitoring and reporting, called the development an “improvement” that would allow the ISO to better align resource commitments in the day-ahead market with actual conditions in real-time, decreasing the potential for oversupply.
“So shifting [negative prices] to the day-ahead is not necessarily in and of itself a bad thing, but it’s not a trend that was observed prior to the last few weeks,” Collins said, adding that it was a topic that could be covered in a future Market Performance Planning Forum.
WESTBOROUGH, Mass. — Transmission developers will have to wait a bit longer for ISO-NE’s first competitive project.
The RTO told stakeholders Wednesday that it will not issue a request for proposals for the Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. The grid operator had explored the project as a way to release pent-up wind resources in Maine.
Rollins Wind Farm in Maine | Reed & Reed, Inc.
Director of Transmission Planning Brent Oberlin presented his staff’s analysis to the Planning Advisory Committee on March 22, confirming preliminary results released in December. (See ISO-NE Study Sees Little Savings from Keene Road Tx Upgrade.)
The study showed increasing the Keene Road export limit from 165 MW to 195 MW would save $1.37 million in production costs annually over a 10-year period. Raising the interface export capacity beyond 195 MW would result in very small additional savings. ISO-NE estimated a total project cost of $7 million to $10.4 million.
Detail of Keene Road Constrained Area | ISO-NE
The upgrade would have been eligible for competitive bidding under FERC Order 1000. ISO-NE has yet to implement a request for proposals under the order.
The New England States Committee on Electricity (NESCOE) said the upgrade isn’t worth the cost to consumers.
“First, consumers would fund ISO-NE’s first-time work to implement an RFP and evaluation process,” NESCOE said in comments filed with the RTO last month. “Second, as required by the Tariff, consumers would also have to pay for the incumbent transmission owner to develop a backstop solution. Those unavoidable costs have to be considered in the context of a very small project for which there is no present indication that an economic solution exists.”
Aleks Mitreski of Brookfield Renewable filed comments saying his company “strongly supports” the project. “In addition to production savings, there would be significant added benefits in the added production of non-emitting [megawatt-hours] that would contribute toward meeting state policy goals and GWSA (Global Warming Solutions Act) targets,” he wrote.
Jeff Fenn of SGC Engineering, representing Emera Maine, also questioned Oberlin. “It’s not entirely true that no one has come forward with a solution” for the Keane Road bottleneck, he said.
The Keene Road interface is the 115-kV system that is left after the loss of the Keene Road 345/115-kV autotransformer, Fenn told RTO Insider after the meeting. The interface can be overloaded by the locally connected 115-kV generation, causing a voltage violation upon loss of the autotransformer.
Fenn said the problem could be solved by eliminating some of the generation post-contingency.
One method would be relocating one of the generator leads such that it was lost with the loss of the autotransformer. An alternative would be a generation rejection special protection scheme.
Fenn said either solution would cost less than $500,000, “therefore well within the payback as defined by the ISO economic study. In addition to this, it is probable that one of the generators in the area would be willing to fund the change as the benefit to them would provide a rapid payback.”
However, Fenn said the RTO “determined that the line relocation smelled too much like an SPS, and as such was not allowed to be considered. They also refused to consider the SPS alone as a solution.”
NEW ORLEANS — MISO expects a 19.2% planning reserve margin this summer, well above its 15.8% requirement, and a percentage point above its projection last year, despite predictions of higher-than-normal temperatures.
The figure is also higher than the prediction of 17.4% in the RTO’s resource adequacy survey with the Organization of MISO States. The RTO said the difference was the result of negative load growth and more demand response resources.
| MISO
“We’re seeing a decline in load forecasts and an increase in demand response,” explained MISO Vice President of System Operations Todd Ramey at the March 21 Markets Committee of the Board of Directors meeting.
Independent Market Monitor David Patton said his monitoring staff has calculated a similar percentage.
The RTO relied on data from the National Oceanic and Atmospheric Administration to calculate summer readiness; the agency forecasts higher-than-average summer temperatures in the footprint, with MISO South experiencing the most significant temperature spikes.
| NOAA
Based on the forecast, the RTO expects a 125.1-GW peak demand with 149.1 GW of supply on hand to meet it. Last year, the RTO anticipated a 125.9-GW peak demand and said it had 148.8 GW at the ready for an 18.2% reserve margin. The RTO’s 24 GW worth of reserves are higher than last year’s 23 GW, and beats the requirement by 4.2 GW.
MISO will reveal final reserve margin numbers at a summer readiness workshop sometime in May.
