Page 1309 – RTO Insider

March 27, 2017

Tornadoes, Wind Generation Drive MISO Tx Congestion

By Amanda Durish Cook

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 board of directors wind output — | *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.

Real-time congestion in the quarter increased 48% over last year but dipped 21% when compared to fall, when outage rates were high in MISO South. (See IMM Report Highlights Outages, Wind Over-Forecasting.)

Wind Causes Congestion on PJM Seam

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.

March 27, 2017

Calif. Bill Would Introduce ‘Clean Peak Energy Standard’

By Robert Mullin

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.

“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.

March 27, 2017

ERCOT Reaches 50% Wind Penetration Mark

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 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.

— Tom Kleckner

March 24, 2017

EE, Renewables Flattening ISO-NE Demand for Next Decade

By Michael Kuser

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 Renewables passive demand resources — | *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.

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.

March 24, 2017

CAISO Sees Ups and Downs in Q4 Real-time Prices

By Robert Mullin

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 day-ahead market negative prices — 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.

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.

March 24, 2017

ISO-NE Nixes Keene Road Tx Upgrade

By Michael Kuser

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.”

March 24, 2017

Anemic Loads, Plentiful DR Boost MISO Summer Outlook

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.

“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.

miso reserve margin demand response — | *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.

— Amanda Durish Cook

March 23, 2017

FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible

FERC staff have greenlit — perhaps temporarily — PJM’s proposed Tariff revisions to allow increased participation from seasonal resources just in time for the RTO’s Base Residual Auction in May (ER17-367). The order remains subject to refund and further FERC action.

The proposals had been on a 60-day clock that would have allowed them to go into effect on March 24, but staff’s order keeps the door open for additional commission review once it regains a quorum of commissioners. (See “Loss of Quorum Means Filings to Become Effective Unless FERC Staff Acts,” PJM Market Implementation Committee Briefs.)

ferc pjm seasonal resources — Mehoopany Wind Farm | *Old Dominion Electric Cooperative*

The changes relax current rules prohibiting seasonal resources from aggregating across locational deliverability areas. The proposal also provides for additional winter capacity interconnection rights (CIRs) and modifies rules for measuring demand response performance in the winter.

PJM sparked controversy about a highly debated issue among stakeholders when it unilaterally filed the revisions with FERC in October under Section 205 of the Federal Power Act. The commission issued a deficiency notice in December, which PJM replied to in January. (See FERC Wants More Detail on PJM’s Seasonal Capacity Plan.)

While the order notes that protesters argued that PJM’s proposal was “an insufficient solution to the larger problem of the costly and inefficient nature of eliminating stand-alone sub-annual resources,” it nonetheless granted the effective dates PJM proposed: Jan. 19 for winter CIRs and June 1 for DR revisions. Requests for rehearing must be filed within 30 days.

– Rory D. Sweeney

March 22, 2017

PJM Board Disputes UTC Trader’s Accusations

By Rory D. Sweeney

The PJM Board of Managers responded on Monday to accusations leveled by XO Energy in February, defending the grid operator’s practices and denying the up-to-congestion trader’s request that the board disregard rule changes on uplift recently endorsed by stakeholders.

In a long and strongly worded letter to the board, XO President Shawn Sheehan accused PJM staff of having bias against financial-sector stakeholders and actively working to undermine their interests. He was specifically concerned with how the process played out in the Energy Market Uplift Senior Task Force, which recently proposed a phased response to uplift issues. Those proposals were eventually endorsed at both the Markets and Reliability and Members committees. XO had asked that the board not act on the endorsements pending the outcome of FERC’s recent Notice of Proposed Rulemaking on uplift issues. (See UTC Trader Displeased with PJM’s Handling of Uplift Rule Changes.)

PJM CEO and board member Andy Ott responded to Sheehan’s claims in a much more reserved tone March 20, suggesting that Sheehan could meet with Dave Anders, the RTO’s director of stakeholder affairs, to discuss his concerns further. Ott defended the RTO’s stakeholder procedures, noting that it provided technical experts that offered “a significant amount of objective technical analysis” throughout the yearslong development of proposals from the task force.

“PJM’s role is to ensure the market remains efficient and competitive, and to provide analysis and justification if they believe certain market inefficiencies should be addressed,” Ott wrote. “I appreciate that some PJM stakeholders disagree with PJM’s conclusions in this regard, but such disagreements do not make PJM biased or negative toward any particular stakeholder group.”

Sheehan had suggested that PJM staff pushed stakeholders into approving the proposals and didn’t provide enough opportunity for engagement, but Ott noted that the process had been going on for more than three years.

“Clearly, abundant opportunity has been afforded to all stakeholders, including the financial community, to express views, persuade others and offer alternatives,” he wrote. “I can find no basis to adopt the extraordinary remedy you have suggested, which would table and disregard the expressed preferences of a very sizeable majority of the PJM members.”

The MRC and MC endorsed proposals for phases 1 and 2 of the uplift response. Proposals for a third phase are still being discussed at the task force level and haven’t been brought for discussion at any of the standing committees.

March 22, 2017

CAISO to File ‘Expedited’ Black Start Plan in May

By Robert Mullin

CAISO staff expect to submit a proposed black start procurement proposal to the Board of Governors in May, officials said Tuesday.

The ISO launched an accelerated procurement effort in January after identifying the need for additional black start resources in the transmission-constrained San Francisco Bay Area. (See CAISO Kicks Off Effort to Procure Black Start Resources.)

CAISO kicked off the black start procurement initiative to obtain resources equipped to restore the transmission system in the San Francisco area in the event of a blackout. | *SF Travel*

“I’m not expecting [that] we’re going to have significant Tariff changes for purposes of this initiative,” Andrew Ulmer, CAISO director of federal regulatory affairs, said during a March 21 call to discuss a draft final proposal that deviated little from the approach laid out in the initial proposal. (See CAISO Proposes TO-focused Black Start Procurement.)

Ulmer added that the ISO hoped to make draft Tariff language changes available to stakeholders ahead of the board vote.

The black start initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which required transmission operators to draw up plans for system restoration in the event of widespread blackouts.

The ISO’s plan envisions the significant involvement of an affected transmission owner in selecting a black start resource, both in drawing up technical specifications and vetting proposals from those resources that bid into the solicitation.

Based on stakeholder feedback, CAISO settled on a cost-of-service approach to compensating the resource, rather than providing a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.

The payment would allow for recovery of capital and fixed operations and maintenance costs plus a “reasonable margin” for the resource owner, according to Scott Vaughan, lead grid assets manager at the ISO.

The proposal calls a resource to be contracted under a three-party agreement between the ISO, the local TO and the resource’s owner.

Paul Nelson, electricity market design manager at Southern California Edison, sought more details about the nature of the agreement — specifically the extent of the TO’s responsibility.

Ulmer explained that CAISO expects that any black start resource procured under the process would not only become part of the ISO’s system restoration plan but that of the TO as well.

“It makes sense to us to have a three-party agreement with ISO, the black start resource and the participating transmission owner … ensuring we have evidence that we secured the capability for the [NERC] reliability standards.”

“So … there’s three roles — the ISO, the black start resource and the transmission — and all three in conjunction need to provide certain services and responsibilities, and the contract will lay out what those are and who’s responsible for the roles and responsibilities and the costs,” Nelson offered.

“Yes, that’s correct,” responded Ulmer, adding that in April, CAISO intends to release a sample contract for stakeholder review.

CAISO also plans next month to publish draft technical specifications for black start resources, followed by a stakeholder meeting on the subject during the second half of May. During the first half of June, the ISO expects to issue a request for proposals for resources in the San Francisco area.

Stakeholders should submit comments on the black start draft final proposal to the ISO by April 4.