FERC and the Pipeline and Hazardous Materials Safety Administration on Thursday celebrated their agreement to coordinate the siting and safety reviews of LNG export facilities, saying their Aug. 31 memorandum of understanding will speed the process and make it easier for applicants.
FERC has authority under the Natural Gas Act for authorizing LNG terminals while the Department of Transportation’s PHMSA is responsible for establishing minimal safety standards under the Pipeline Safety Act of 1979.
In the past, FERC staff made preliminary determinations on whether a proposed LNG project could comply with DOT standards, FERC General Counsel James Danly said during a briefing at Thursday’s open commission meeting. But he said the process became problematic with the growing number of applications for LNG export terminals, which are more complex than import facilities.
“This required an extremely iterative process with multiple requests for information from the applicants and back and forth with PHMSA. The MOU that we’ve just signed is going to end that duplicative and iterative process, and now … the experts on this subject — PHMSA — are going to be the ones who make that preliminary determination,” Danly said.
The agreement should allow FERC to accelerate its review on a dozen pending applications, Danly said, “potentially allowing FERC to act by early 2020 on projects capable of exporting over 8 Tcf per year.”
“The numbers involved in the LNG industry are astounding,” said PHMSA Administrator Howard Elliott, who also appeared at the meeting. “A single export facility can deliver an economic impact of $10 billion or more per year, and strong demand from the Asia-Pacific region looks to likely drive those numbers higher over time.”
Commissioner Neil Chatterjee praised the agreement but said FERC should do more, suggesting the commission consider adding a regional office in Houston and boost salaries to make them competitive with industry “to improve retention and recruiting of top-tier engineers and attorneys.”
The U.S., which last year became a net exporter of natural gas, is shipping gas to more than 25 countries, largely through its two operating LNG export terminals, Cheniere Energy’s Sabine Pass in Louisiana and Dominion Energy’s Cove Point in Maryland. The Department of Energy is considering about 25 applications for LNG exports to countries lacking free-trade agreements with the U.S.
Dominion Energy’s Cove Point LNG terminal is the second operating export facility in the U.S. | Dominion Energy
“If the U.S. can ensure that adequate LNG export infrastructure is in place to meet that demand, it could mean thousands of additional jobs across the U.S.,” Chatterjee said. “But if we miss the window of opportunity because of bottlenecks in FERC’s LNG export facility application review process or because FERC lacks the resources to complete its review process in a timely fashion, those foreign trading partners will be looking elsewhere for their natural gas.”
Although there is a consensus that exporting too much domestic natural gas could expose U.S. consumers, industrial users and electric generators to much higher world prices, there is no agreement on what that tipping point is, or how soon the U.S. could get there. (See Enviros, Industrials Challenge DOE Study on LNG Exports.)
ST. PAUL, Minn. — MISO on Tuesday unveiled an annual transmission plan consisting of 434 transmission projects valued at $3 billion.
This year’s proposal so far contains 85 more projects and about $100 million more in investment than the 2017 MISO Transmission Expansion Plan, which in its final form consisted of 349 projects at $2.9 billion.
MTEP 18 breakdown | MISO
MTEP 18 includes 85 baseline reliability projects at $607 million, 16 generator interconnection projects at $88 million and two transmission delivery service projects at about $290,000. But like last year’s plan, most projects fall under MISO’s “other” designation: those decided on by transmission owners that are not eligible for cost allocation and represent replacement of aging infrastructure, construction because of further reliability needs and modifications made for environmental purposes. The RTO this year is recommending 340 other projects at slightly more than $2.3 billion.
Most expensive MTEP 18 projects | MISO
In-service dates for the projects range from 2018 to 2027. Almost half are transmission line upgrades while 39% are substation projects. New transmission line projects represent just 6% of the projects.
Foxconn and Mackinaw
Among the priciest projects on the MTEP 18 list is the $140 million interconnection to plug Foxconn’s $10 billion plant into We Energies’ network in southeastern Wisconsin. MISO expedited its review of the project in February at the request of developer American Transmission Co. (See MISO Fast-Tracks ATC Foxconn Project Review.)
MISO is setting aside more time to discuss an equally costly project: ATC’s proposal to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas after two submarine cables were damaged in April, most likely by a passing vessel. ATC said one of the cables was rendered permanently inoperable. (See ATC Restores Tx Link Between Michigan Peninsulas.)
MISO Executive Director of System Planning Aubrey Johnson said further stakeholder discussion is needed to explore alternate proposals to the project.
“We expect to have a recommendation prior to December,” Johnson told the System Planning Committee of the Board of Directors during a Sept. 18 meeting.
TMEPs on the Way?
MISO executives said their final MTEP recommendation could contain targeted market efficiency projects (TMEPs), a smaller interregional project category MISO and PJM created in 2017. The RTOs are currently conducting a TMEP study and plan to submit project recommendations for approval by their respective boards in October. (See MISO, PJM Plan 2 Studies for Seams Projects.)
Market Congestion Planning Study
This year’s market congestion planning study identified three projects for possible MTEP inclusion: the $11 million rebuild of a 161-kV line in southern Minnesota; a $2 million, 138-kV reactor project in eastern Wisconsin; and a $16 million upgrade to a 161-kV line in southwestern Indiana. None of the projects passed MISO’s 345-kV threshold to qualify as a cost-shared market efficiency project, so if they proceed, all three will be considered “economic other” projects that don’t qualify for regional cost allocation, meaning costs are assigned locally.
At the meeting, some MISO directors asked why the range of projects resembles past MTEPs when the RTO is paying so much attention to portfolio evolution. They asked whether MISO should be presenting MTEPs that contain a different mix of transmission projects to support a changing generation mix.
MISO Vice President of System Planning Jennifer Curran said the RTO only recommends economic transmission with reasoned business cases that show benefits across multiple future scenarios. She added that MISO’s 2011 slate of multi-value transmission projects was designed with future needs in mind and is still reaping benefits. (See MISO Triennial Review Shows Multi-Value Project Benefits.)
Director Todd Raba asked if MISO is still justified in using its “limited fleet change” MTEP future, the 15-year scenario used to gauge project value in a hypothetical footprint where the RTO’s coal use remains strong and renewable generation remains a minority. The limited change fleet future is one of four futures MISO currently uses.
“We seem to have moved beyond that now,” Raba observed.
“Limited fleet change is not what we’re seeing right now,” Curran acknowledged, adding that MISO has most likely shifted to its continued fleet change future by now.
“We’ve got a lot of resource shift in front of us,” she added, pointing out that MISO’s 90-GW generation interconnection queue is dominated by renewable generation.
A final version of MTEP 18 will go before the board for approval in early December. MISO will hold a Nov. 13 conference call of the board’s SPC to discuss a more complete MTEP 18 and stakeholder reactions to the portfolio.
ST. PAUL, Minn. — A systemwide emergency, market innovations and the relatively calm summer conditions on the grid topped executive discussions at MISO’s Board of Directors meetings this week.
A Sept. 18 meeting of the Markets Committee of the Board of Directors began with an initial look into MISO’s Sept. 15 declaration of emergency conditions, issued just one a day after the RTO released a forecast showing a 19% chance of such an occurrence at least once this fall. (See MISO in Conservative Ops After Emergency Declaration.)
“Our fall outlook noted the potential for tight conditions, and that has indeed … been the case since Saturday,” MISO Executive Director of Market Operations Shawn McFarlane began.
At the time of the meeting, MISO was still under conservative operations, which remained in effect until Sept. 19.
McFarlane said the emergency was the result of high temperatures and the ramping up of planned fall outages, and noted that MISO lost a “significantly large” unit on Sept. 14, followed by the loss of smaller units the next day. As a rule, MISO does not reveal which companies experience unplanned outages, although Entergy reported that its Grand Gulf Nuclear Station on the Mississippi-Louisiana border went offline Friday because of feedwater system issues.
MISO made about 600 MW of emergency energy purchases during the event and for about 15 minutes exceeded its 3,000-MW north-to-south sub-regional contract limit on the SPP line linking its North and South regions.
However, McFarlane stressed that MISO coordinated with SPP and other parties to the contract ahead of the high flows.
“We will emphasize that we communicated with SPP and others ahead of time,” he said.
MISO Executive Director of Energy Rob Benbow said the RTO made emergency purchases from both SPP and Southern Co. He said that although communications regarding the purchases were effective, some Southern operators were confused about MISO’s process and that the RTO will reach out to company staff to better clarify processes.
Benbow also said MISO brought in extra staff ahead of the event to oversee the system.
In his chairman’s report at the Sept. 20 Board of Directors meeting, Director Michael Curran praised SPP, Southern and the Tennessee Valley Authority for assisting MISO South during the emergency.
“It was a lot of good things at the seams. We have very good neighbors,” Curran said.
He also added a warning about thin reserves and increasing outages: “It’s not going to be just a weather pattern. … This is going to be the new normal.”
‘Missed’ Forecast
McFarlane said the determining factor in the emergency conditions was a MISO forecast that missed the mark by about 7% of actual conditions.
“A lot of others had difficulty forecasting the heat. It’s not an excuse, but many underestimated the high loads. … I would put this in our top three or four forecast misses. It was a significant miss since we began forecasting in 2005,” McFarlane said.
“This is one of seven forecasts where we missed it by 5% or more,” said MISO President Clair Moeller, adding that most of the midcontinent failed to accurately predict the heat.
Because the forecast became inaccurate so quickly, many units with long lead times could not respond in time, Moeller noted. CEO John Bear added that more fast-start resources will be needed as the generation fleet evolves.
McFarlane also said demand response was difficult to access during the event because of rapid heating and the fact that load-modifying resources aren’t obligated to offer beyond the summer months.
“This is an advertisement for Resource Availability and Need,” McFarlane said, referring to MISO’s initiative to change load-modifying resource and outage coordination rules. (See MISO Moving to Combat Shifting Resource Availability.)
Moeller said MISO is also examining how it plans for system conditions in light of the emergency.
“We’re doing something you shouldn’t do. We’re using historic performance to predict future performance. The question is how to adjust our math,” Moeller said. “The worst thing you can do to a gas pipeline is not give notice and take gas, and that’s what we love to do, not give notice and take gas.”
WPPI Energy’s Valy Goepfrich took the microphone at the board meeting to urge MISO leadership to “R-E-L-A-X.” She said that MISO’s supply has exceeded load for years, and that the RTO and utilities are only experiencing bumps in learning how to effectively balance a more equalized supply-to-load ratio.
Market Innovation
Richard Doying, executive vice president of market development strategy, said MISO is currently researching new distributed resource integration models and how it can use historical data to better compute and manage transmission constraints. The RTO is also continuing ongoing research into how renewable penetration changes the operations and economics of the grid, he said. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
Doying said in order to truly develop MISO’s market, RTO staff need to contemplate rebuilding the current system from scratch. He said if MISO were able to revisit 2004 knowing what it knows now, the markets system would have looked very different.
“We probably would have built a very different set of operating procedures,” he said.
MISO is also expanding its overall use of market improvement pilots and simulations, where it can test a full-scale change without impacting the grid, Doying said.
Director Thomas Rainwater urged leadership not to get stuck in a single line of thinking in market innovation, reminding the room that Betamax was once cutting-edge.
Doying said MISO’s ongoing market platform replacement will be flexible enough to accommodate a wide range of future market styles. He said the RTO will release a revised market strategy document in 2019.
However, Independent Market Monitor David Patton said market development should be an “evolution, not revolution,” and told RTO leadership to focus more on the efficient pricing of energy.
Solid Summer Performance
Despite last week’s emergency conditions, MISO said it was able to manage a relatively calm summer.
“There were a few operational challenges and overall — very benign. Nothing like the last few days,” McFarlane said.
“High level summary: It was hot,” he joked.
MISO’s system peaked in late June at 121.6 GW, about a month ahead the usual summer peak, McFarlane said. The RTO had predicted a 125-GW peak. Load averaged 86.6 GW, compared to 82.7 GW during last summer.
Patton said the heat caused a jump in energy prices over last summer, with prices averaging $31.12/MWh over the season, up 8.1% from 2017.
The loss of a 500-kV line in MISO South over June 3-4 highlighted the need to develop a 30-minute reserve product, according to Patton. The line trip caused transmission violations that were priced at $4,000/MW of flow, causing the Louisiana hub price to jump to $2,500/MWh for about an hour-and-a-half late on June 3, he said.
MISO also experienced its lowest wind output in the footprint ever on July 29: 1 MW out of about 18 GW of total wind capacity in the footprint. McFarlane said the RTO and the media often call attention to maximum wind output and wind records but don’t often highlight low wind generation and wind output volatility.
“What are the lessons then?” Rainwater asked.
“We have to be prepared for almost anything. If anyone has a better answer, let me know,” McFarlane said.
PJM’s Independent Market Monitor has declined to budge from its position that the RTO allow market participants to use its opportunity cost calculator, arguing that it would be consistent with other RTO verification processes.
The Monitor suggested that PJM has two options. The first is to maintain the status quo in which stakeholders are required to choose their own values using PJM’s calculators and risk being referred for disciplinary action at FERC — the situation that brought the issue to a boil in August
The Monitor’s preferred process would require market participants come to agreement with it on an opportunity cost that it verifies is competitive before submitting it for PJM approval. All parties retain the right to petition FERC if they don’t agree with the final result. That would result in a practice consistent with the process PJM already uses for verifying cost-based offers, the Monitor said.
“The IMM requests that PJM clarify its preferred review process for opportunity cost calculations,” the Monitor wrote. “The IMM recognizes that PJM can impose the first option. The IMM recommends the second option. … The IMM routinely informs market participants that if its use of the PJM calculator results in an opportunity cost greater than that calculated by the IMM that the IMM is required by the Tariff to raise the issue with FERC.”
The two parties’ yearlong standoff was brought to a head at the August 23 meeting of the Markets and Reliability and Members committees, where stakeholders threatened to advance Tariff revisions that would require PJM to accept the Monitor’s calculator. PJM had announced earlier in the month that it would only accept opportunity cost calculations using its calculator after staff realized that in “the latter part of 2016” results between the two calculators, which had produced consistent results since 2010, began to diverge substantially. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.)
In its Sept. 16 response, the Monitor said that divergences likely began in 2011 when it “enhanced” its calculator with an “optimization solver … to correctly model rolling constraints.” The Monitor says it outlined the differences between the calculators in meetings with PJM and as part of special sessions of the Market Implementation Committee.
The Monitor’s response included its oft repeated criticism of PJM’s calculator.
“PJM’s opportunity cost calculator demonstrably does not produce accurate results over the entire range of possible scenarios faced by real units. … The IMM has discovered that market participants have made mistakes related to input assumptions that significantly affected the outcomes. … PJM does not review the inputs to its calculator used by participants,” the Monitor wrote. “PJM does not approve the results of its own calculator. Yet PJM states that PJM’s calculator is the standard for evaluating opportunity costs.”
The Monitor said it holds “detailed discussions” with market participants about opportunity cost calculation inputs and results and that it has modified its view of specific calculations considering details provided by participants.
“The IMM has made mistakes. The IMM does not claim that the IMM model is perfect,” the Monitor acknowledged. “While it is important to have a complete and accurate model, opportunity cost calculations require case-by-case analysis and are not a simple matter of just running a model.”
RENSSELAER, N.Y. — A carbon charge would only slightly impact New York’s wholesale energy prices over the coming decade, with any increase offset by benefits, a new report commissioned by NYISO says.
“If you add a carbon charge, LBMPs are going to increase, and they do,” said Sam Newell of the Brattle Group, who on Monday presented a draft study of carbon pricing impacts to the state’s Integrating Public Policy Task Force (IPPTF). The analysis is based on the ISO’s straw proposal issued in May.
This chart shows the broad framework for analyzing the effect of a CO2 charge on the wholesale energy market. | The Brattle Group
“The effect of higher LBMPs on customer costs, however, is partially or fully offset by several factors,” Newell said. “Customer credits from emitting resources offset about 60% of the price increase, then you’ve got other potential benefits such as lower prices for renewable energy credits (RECs) and zero-emission credits (ZECs), increased value of transmission congestion contracts, a shift of renewable resources to regions with higher CO2 emissions to displace and other changes to the supply mix.”
The Sept. 17 discussions were part of issue “Track 5” in the group’s five-track effort to price carbon emissions. Brattle will present the final version of its customer impact analysis to the IPPTF on Oct. 15.
Key Assumptions
The study’s base case scenarios cover 2020, 2025 and 2030, and the study projects the carbon charge will spur the highest cost early on: a 2.2% increase in 2020, followed by a 0.04% increase in 2025 and a 0.01% decline at the end of the next decade.
This chart shows the key assumptions for each of the study years in the report. | The Brattle Group
The base cases reflect “most likely” conditions, supply and demand conditions and existing policies, including the Clean Energy Standard and Regional Greenhouse Gas Initiative, Newell said.
The conclusions are similar to those of the first Brattle Group report, released in August 2017, on pricing carbon into generation offers and reflecting it in energy clearing prices. The main difference between the two reports is that now Brattle has studied three years (2020, 2025 and 2030) and has used GE-MAPS to model the effects of carbon charges on unit commitment, dispatch, prices, settlement and emissions, Newell said.
Several stakeholders wanted to know more about the assumptions used in the report and asked if the ISO would make a more technical report available.
“Nothing is secret,” Newell said.
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, confirmed all data, methodologies and key assumptions would be made available to stakeholders as soon as possible, with an expected availability date around the beginning of October.
Andrew Antinori, senior director of the New York PowerAuthority’s (NYPA) Market Issues Group, said it did not make sense to focus on the higher price increase listed for 2020 ($0.38/kWh) because NYISO recently concluded carbon pricing would not be implemented any earlier than the second quarter of 2021.
Antinori asked if the price would be lower if the study started with 2022, the first full year, but Newell would only say the price increase for that year would fall between those of 2020 and 2025.
NYPA Concerns
Mark Reeder, representing the Alliance for Clean Energy New York, said NYPA sales should be accounted for in the study because many of its customers pay a low non-market price. Therefore, an increase in NYISO market price doesn’t translate into a one-for-one increase in the prices paid by NYPA’s end users.
Warren Myers, DPS director of market and regulatory economics, said, “Whenever we first saw a waterfall chart, NYPA was so complicated, one of our first concerns was we wanted to see a consistent set of analyses of non-NYPA customers.”
This waterfall chart breaks down a carbon charge’s effect on wholesale energy prices. | The Brattle Group
The study assumes all customers are fully exposed to the LBMP, so it overstates customer costs to the extent NYPA does not, Newell said. “We didn’t include [NYPA] because it would have been quite messy to try to account for it.”
Mark Younger of Hudson Energy Economics said, “NYPA also does market-based sales for a certain amount of energy, and doing this creates a windfall for a state agency, which presumably goes to New York State residents,” possibly to be used for their benefit.
“Our analysis did not consider any special effects on NYPA,” Newell said.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said profits on market-rate sales would likely incent more such sales, not more low-cost contracts for industrial customers.
Antinori said, “It’s not fair to say ‘windfall’ when discussing NYPA revenues as if no other generator gets such a benefit from a carbon charge.”
Mager said the study might be overstating savings on REC prices: “You identified this in your original report, that it’s not one-to-one price savings.”
Newell said, “There are a number of ways to structure this so there’s no risk on suppliers and you get one-on-one benefits to renewables … We’re using load forecasts that decline by six terawatt hours every five years.”
Environment and Reliability
Tariq Niazi, ISO senior manager and Consumer Interest Liaison, was scheduled to present an analysis of consumer impacts from a carbon charge but got bumped from the lineup due to the length of time spent on the Brattle study.
According to the report, to be presented at next week’s IPPTF meeting, adding a carbon charge would reduce CO2 emissions approximately 3% by 2030 and cause only limited fuel switching; most emission reductions would result from dynamic effects such as renewable shifts, nuclear retention and price-responsive load.
The report also says pricing carbon would spur investment in renewables, supporting reliability, and the ISO intends to develop a calculation using marginal units to estimate the LBMP carbon impact.
Bouchez informed stakeholders of a revised task force schedule, which foresees the presentation of a carbon pricing proposal and recommendations on Dec. 17. The task force next meets Sept. 24 at NYISO headquarters.
A coalition consisting of environmental advocates, zero-emissions generators and Illinois’ consumer advocate has developed a set of principles they say will “protect the cost-effective achievement of state policy goals to the extent possible” under FERC’s ordered redesign of PJM’s capacity market.
While the document doesn’t address applicability of PJM’s minimum offer price rule (MOPR), which sets floors for subsidized units’ capacity offers consistently above clearing prices, it does argue any unit subject to the MOPR should be eligible for the resource-specific fixed resource requirement (FRR-RS) FERC suggested in its order.
The principles also call for the FRR-RS to indicate as clearly and as early as possible whether state programs would be subject to the MOPR, along with providing a transition period so states can enact any laws they deem necessary. However, the document reiterated demands the FRR-RS also preserve states’ abilities to achieve clean energy policy goals.
The Natural Resources Defense Council’s Miles Farmer said that “part of it is to push PJM in this direction as well,” pointing out PJM’s proposal has progressively moved toward the principles, and “to make sure that FERC follows through on FRR-RS.”
The signatories “were all talking to each other around these PJM meetings, and we realized it makes sense to develop these shared principles,” he said, though he declined to offer specifics about who approached whom first.
Several stakeholder groups have proposed market redesigns, which stakeholders have been examining as part of special sessions of the Markets and Reliability Committee on the issue. (See PJM Unveils Capacity Proposal.) While the coalition is not advocating for any specific proposal along with the principles, many of the signatories support a proposal being represented at the meetings by consultants Rob Gramlich of Grid Strategies and James Wilson of Wilson Energy Economics.
Exelon’s Quad Cities nuclear facility, which benefits from Illinois’ zero-emissions credit program. | Exelon
An Exelon representative confirmed the proposal is endorsed by “a large coalition of odd bedfellows,” including the NRDC, Citizens Utility Board of Illinois, Sierra Club, Office of People’s Counsel for the District of Columbia, American Council on Renewable Energy, Exelon, Mid-Atlantic Renewable Energy Coalition, Talen Energy and Public Service Enterprise Group. All but PSEG are signatories of the principles document, which also includes the American Wind Energy Association.
Farmer said the principles have just been published and are expected to gather wider support as they become better known, adding no conclusions should be drawn from anyone who hasn’t signed on yet.
The proponents are all interested in PJM giving states capacity credit for units they subsidize to achieve state policy goals, such as procuring renewable and zero-emissions resources, and declare as a principle the credits should be applicable on a one-for-one basis.
For a unit to be eligible for FRR-RS election, it would need to be removed from the auction with a corresponding amount of load. The principle calls for making election at least four months prior to a Base Residual Auction and would need to be confirmed by a load-serving entity or state power authority at least 30 days before the auction.
Owners could also elect portions of units to be FRR-RS, and there would be no minimum length of time the unit would need to remain elected. Those units would continue to be Capacity Performance resources subject to PJM’s performance requirements and financial consequences.
“I take FERC at its word that it’s going to implement FRR-RS, but it still needs to do so in a way that’s workable so all the FRR-RS capacity is actually credited because setting this all up is not trivial and needs to be done with care,” Farmer said.
FERC on Tuesday granted Mexican wholesale marketer CFE International’s request to sell energy, capacity and ancillary services at market-based rates, clearing the way for the company to compete in U.S. power markets (ER18-1778).
The commission noted CFE International would place itself under FERC’s jurisdiction as a public utility and accepted its market-based rate authority, effective July 1. It also agreed with the company’s request for certain waivers and blanket authorizations commonly granted to market-based rate sellers.
Houston-based CFE International was formed in 2015 to market energy commodities. Its only member is Comisión Federal de Electricidad (CFE), the Mexican government-owned electric utility.
FERC ruled CFE International, as it requested, meets the criteria to be a Category 2 seller in the Southwest region (primarily California, Arizona and New Mexico) and a Category 1 seller in the Central, Southeast, SPP, Northeast and Northwest regions.
FERC will review Category 2 market-based rate sellers using the above regions every three years according to a rotating schedule. | FERC
FERC created the two categories in 2007 with Order 697. Category 1 sellers are wholesale power marketers or producers that own or control 500 MW or less of generation capacity in aggregate per region; do not own, operate or control transmission facilities, other than interconnection facilities; are not affiliated with transmission owners in the same region as the seller’s generation assets; are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and do not raise other vertical market power issues.
Category 2 sellers are those that don’t fit into Category 1 and are required to file updated market power analyses.
CFE International had to clear FERC screens for horizontal and vertical market power. The commission agreed with the company’s claim that neither it nor its affiliate owns, operates or controls generation capacity in the United States but that CFE owns or contracts with capacity in Mexico. The company said its affiliated generation in Mexico could transfer up to 800 MW to the United States via two interties connected to CAISO, making that market the appropriate one to analyze its horizontal market power.
To pass the vertical power screen, CFE International had to show it had an open-access transmission tariff (OATT) on file or a FERC-approved waiver. Because CFE owns, controls or operates transmission facilities in Mexico that can be used by competitors to reach U.S. markets, CFE International had to prove its affiliate had a tariff or offered “comparable, non-discriminatory access” to its facilities.
The company noted CFE does not control or assign access to its facilities or Mexico’s transmission system, arguing all market participants receive access to the system because of their participation in the energy and ancillary services markets managed by the National Energy Control Center (CENACE) ISO. CFE International said participants could provide transmission service over the interties if CENACE cleared their bids in the day-ahead market.
FERC agreed with CFE International that network service in Mexico is comparable to the services provided under the pro forma tariff (OATT) in the United States.
There are three other interties between Mexico and the United States, all through ERCOT. Texas’ Public Utility Commission, which has jurisdiction over ERCOT, said it saw no issue with the order, pointing to a July ruling by FERC easing concerns over potential federal oversight. (See FERC OKs DC Tie Operations Between Texas, Mexico.)
An SPP spokesperson said the ruling won’t have an effect on its markets. He said, technically, CFE International could have already been making offers into the markets.
MISO declared a maximum generation alert at noon Monday, saying tight reserve levels amid forced outages, hotter-than-expected temperatures and higher-than-forecasted load could prompt emergency procedures.
The action followed a string of notices and alerts over the weekend. On Saturday, the RTO ordered conservative operations for its entire footprint until midnight Wednesday.
Load hit 112,907 MW at Monday’s 4 p.m. peak. Real-time LMPs ranged from $22/MWh in Minnesota to $82/MWh in Michigan.
MISO peak load and pricing on Sept. 17 | MISO
Last week, MISO said it had prepared for summertime conditions in September, in keeping with trends over the last three years. At the time, some stakeholders expressed doubt over the 19% probability the RTO gave itself of entering emergency procedures at least once this fall, with some saying the chance of an emergency was greater. (See MISO Sees Small Chance of Fall Emergency Procedures.)
Beginning on Saturday, MISO requested that generation and transmission owners defer or cancel all nonessential maintenance outages, asking that utilities reach out to coordinate returns to service.
In a Sept. 15 tweet, MISO said it was monitoring conditions in a hotter-than-usual MISO South, where Entergy issued public appeals to conserve energy on behalf of the RTO. Entergy said it was experiencing a “critical” shortage of electricity. MISO’s declaration of a maximum generation event requires members to make public conservation appeals and allows the RTO to make emergency power purchases to avoid load shedding.
“We appreciate our customers’ help in meeting power needs during this time by turning off all non-essential lighting, appliances and electronics as well as raising thermostats to 78 degrees. If possible, reduce use of water heaters, electric ovens, washing machines and dryers,” Entergy asked. The company eventually terminated the appeal for conservation at 6:30 p.m., hours earlier than MISO’s original prediction of 11 p.m.
19% Chance
At the Sept. 13 Market Subcommittee meeting, MISO officials said they had sufficient resources to cope with unseasonably warm conditions again this fall.
The RTO estimated a 19% chance that it would invoke emergency operating procedures to call on load-modifying resources (LMRs) this fall. Those resources are not obligated to respond when called upon after Sept. 1. MISO expects to have about 11.8 GW of available LMRs, based on availability forecasts provided by resource owners.
The RTO forecast a 110- to 120-GW peak load for September and said it prepared for loads more in line with summer conditions. The National Oceanic and Atmospheric Administration predicts above-normal fall temperatures for the MISO region.
“September generally aligns more closely with summer system conditions, at least for the last few years,” said Jeanna Furnish, MISO manager of outage coordination.
Furnish said MISO has so far this month experienced loads topping out at 114 GW, within about 1 GW of peak fall loads over the last three years.
For the last four years, MISO’s actual fall peak load has trended about 5 to 9 GW higher than load-serving entities have forecasted in 50/50 probability forecasts.
Furnish said MISO expects a 10- to 15-GW increase in planned outages from the end of September to the end of October, when load is projected to be lower. Navigating the outages will be “challenging, but manageable,” similar to the RTO’s experience in recent years.
After some stakeholders expressed confusion over the 19% statistic, MISO Executive Director of Market Development Jeff Bladen clarified that the RTO is not saying it will spend 20% of the fall in emergency operating procedures.
“There’s a 20% chance that we will go into emergency operating procedures at least once this fall,” he explained.
Some stakeholders wondered if MISO’s prediction was optimistic. Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out NOAA predictions of a 40 to 60% chance of a major storm forming in the Gulf of Mexico last week.
During the meeting, stakeholders also received an emailed capacity advisory notice for a possible shortage on Sept. 17 owing to outages and residual weather conditions from Hurricane Florence. MISO rolled out the new notification system in August for situations when its all-in capacity is forecast to be less than 5% above operating needs. (See “New Notification System,” MISO Moving to Combat Shifting Resource Availability.)
CARMEL, Ind. — MISO plans to hold a final Order 841 workshop on Oct. 10 to complete its collection of stakeholder opinions on its storage participation model, which will include an agreement for distribution-level storage but leave storage dispatch optimization to a later filing.
Here’s what the RTO has decided thus far.
Pro Forma for Distribution-connected Storage
MISO’s draft pro forma agreement for storage connected at the distribution level requires storage:
Be registered and modeled in MISO;
Secure agreements with distribution facilities so energy can be delivered to the MISO transmission system;
Be able to receive MISO operating instructions; and
Provide MISO with facility measurements and settlement meter data.
The agreement also specifies that MISO will make sure a storage resource owner isn’t charged twice for energy when it pays retail rates for wholesale charging. MISO said it will exclude the charging energy from wholesale rates in its settlements.
During a Sept. 13 Market Subcommittee meeting, Coalition of Midwest Power Producers CEO Mark Volpe asked if the agreement opens an avenue for distribution-connected storage assets to avoid MISO’s interconnection queue.
“This is not a way to circumvent the interconnection queue,” Director of Market Design Kevin Vannoy said.
“So you’re saying that distribution-level storage must go through the interconnection queue?” Volpe asked.
“I don’t have a definitive answer for that,” Vannoy responded.
Consumers Energy’s Jeff Beattie pointed out that many qualifying facilities that utilities must purchase power from under the Public Utility Regulatory Policies Act are connected at the distribution level.
Canned Corn
The Energy Storage Association’s Rao Konidena, formerly a MISO adviser, brought a can of corn with him to the MSC podium.
Storage, he said, is like a can of corn.
“We know what’s in there; we know how it’s used,” he said. MISO’s remaining piece is finalizing storage rules for an asset whose purpose is already understood. He said storage owners should be able to toggle hourly between offering energy and ancillary services and have the option to self-dispatch.
Konidena said storage asset owners must be able to enter offline mode without fear of being cited for physical withholding. “We need to have enough clarity to know that asset owners will not be penalized as they come back online,” he said.
No Optimization Yet
MISO is not ready to optimize storage resources’ energy schedules in the day-ahead or real-time markets. That means the RTO won’t pick the best and most economic hours for a battery or other storage resource to charge or discharge.
MISO said it will commit and dispatch storage respecting minimum and maximum charge limits and any self-scheduled offers. But it said its unit commitment calculations cannot be easily changed to optimize storage in charge/discharge or continuous modes across multiple periods.
Vannoy said participation must be accommodated per Order 841, but MISO should not have to change existing market services to accommodate storage. He also said FERC’s order has already suggested that storage resources will represent their energy limitations through offer prices.
“We don’t see it as a requirement of 841 that we change our optimization calculation,” Vannoy said. “We’re taking this into our research and development, and it will become more important as storage becomes more prevalent. But right now, we’re not prepared given the timeline, nor is it required in our mind.”
Storage Capacity
Meanwhile, MISO is moving forward on a multistep capacity determination process for storage resources.
The process involves a test verifying the storage facility’s capacity and its transmission deliverability. The resource must provide quarterly reports to MISO’s generating availability data system (required for storage resources 10 MW and up). The RTO will use the data to calculate an equivalent forced outage rate, installed capacity and unforced capacity for the resource.
Storage resources that are designed with limited output availability will also have to submit a day-ahead must-offer for at least four continuous hours covering the two hours before the peak, the peak hour and the hour following the peak hour. MISO forecasts its daily peak hour seven days in advance.
“It’s not really unique to storage capacity resources,” Senior Adviser of Capacity Market Administration Rick Kim said of the proposed accreditation process during a Sept. 12 Resource Adequacy Subcommittee meeting.
But Customized Energy Solutions’ David Sapper said the storage must-offer rule for use-limited resources might be too restrictive for an RTO that is trying to place more emphasis on supply flexibility in an environment where a peak risk can occur in during several different hours, not just the summer peak hour that MISO currently plans around. (See MISO Looks to Members for Load Forecasting Ideas.)
“It ignores the operational characteristics of storage,” Sapper said.
Vannoy pointed out that the use-limited description is an optional designation, left up to the owners of storage resources. He said even use-limited storage resources are free to offer for 24 continuous hours.
MISO plans to introduce draft Tariff language for storage capacity credit at next month’s MSC, Kim said.
PJM saw its frequency drop to 59.903 Hz at 3:49 p.m. as its area control error fell 2,942 MW below its target. The RTO said the incident resulted from multiple unit trips, non-approved real-time security-constrained economic dispatch (RTSCED) cases, a drop in Eastern Interconnect frequency and poor synchronized reserve response.
Staff made recommendations for all but one of the causes. Removing ambiguity in operating procedures regarding parameter-limited schedules would address units called online that didn’t respond. Analyzing unit-tripping trends would help determine why multiple units tripped. Creating a procedure that helps dispatchers decide whether RTSCED data is valid based on system conditions would address why the RTSCED cases weren’t approved during the incident.
PJM also plans to stop approving time error corrections during emergency procedures or frequency excursions, which it said can exacerbate problems.
“It takes several hours at a lower frequency to get that time error back; there’s kind of an inherent risk whenever [you] go off 60 Hz,” PJM’s Donnie Bielak said. He added that simply scheduling time error corrections at night also isn’t a good idea because it would push units into minimum-generation operations that don’t allow them full flexibility to respond to other system changes.
Bielak said an unexplained drop in frequency across the entire Eastern Interconnection accounted for half of the problem.
“We’re certainly looking to get to the bottom of that,” he said.
PJM’s Jim Snow presented the RTO’s preliminary project budget for 2019, which anticipates spending approximately $42 million on capital expenditures. The vast majority — approximately $39 million — will go to existing assets, including applications, systems reliability, replacements, facilities and infrastructure.
In response to a stakeholder question, Snow said about $4.4 million in projects were considered but deferred, including hardware replacements, enhancing existing monitoring tools, automating the Regional Transmission Expansion Plan and other corporate reports, implementing soak time by adding generator ramp time to day-ahead markets, and implementing a tool to register energy efficiency and non-retail behind-the-meter generation.
“This is part of a larger process,” Snow said.
At a separate presentation before the Planning Committee later in the week, Snow confirmed that the budget can be revised to address any issues that arise that require commitments from PJM.
“I would tell you if FERC issued an order, we would go back and reprioritize,” he said.
The response satisfied Greg Poulos, the executive director of the Consumer Advocates of the PJM States.
“I want to make sure there’s enough resources allocated to the Planning Committee to make sure they can get their job done,” he said.
PJM’s Christina Catalano introduced two changes to reactive transfer interfaces, which the RTO uses to control voltage contingencies associated with high transfers during transmission outages.
The Central Pennsylvania interface, which includes the Lackawanna-Hopatcong, Sunbury-Juniata and Susquehanna-Wescosville 500-kV lines, was modeled to accommodate an increase in gas-fired generation in the region and planned maintenance outages on the 500-kV system. One such outage is planned for Oct. 16-20.
Catalano said staff anticipate the interface only becoming significant during the outage in case a second transmission line goes out. PJM’s Paul McGlynn said “additional contingency would go beyond any criteria we have.”
In the Western Interface, staff are adding the new Vinco substation near Conemaugh on the 500-kV line to Hunterstown. It will become effective when the Vinco substation is energized, which is expected on Oct. 16. Because of its proximity to the Conemaugh substation, staff expect minimal impact.
