FERC on Thursday established hearing and settlement procedures for a Louisiana Public Service Commission complaint against two Entergy subsidiaries (EL18-152).
The PSC alleged in a Section 206 complaint filed in May that System Energy Resources Inc. (SERI) and Entergy Services violated the filed-rate doctrine and FERC’s ratemaking and accounting requirements by billing ratepayers for the costs of the Grand Gulf Nuclear Power Station’s sale-leaseback renewals under a unit-power sales agreement between SERI and Entergy’s Arkansas, Louisiana, Mississippi and New Orleans operating companies.
Grand Gulf Nuclear Station | Entergy
FERC found the PSC’s complaint “raises issues of material fact that cannot be resolved based upon the record before us” and would be more appropriately addressed in settlement procedures. The commission set a refund date of May 18, 2018.
Louisiana’s regulators requested the hearing and asked that unjust and unreasonable costs be removed from billings.
The PSC’s complaint stemmed from SERI’s renewal of two sale-leaseback agreements in 2015 that dated back to 1988. The regulators said SERI originally sold to private-equity investors an 11.5% interest in Grand Gulf for $500 million and leased it back for 26.5 years. They said the original cost of the lease was $435 million with a net book value of $398 million, claiming SERI included the costs in its formula rate as rents for ratemaking purposes.
Galvez Building housing the Louisiana Public Service Commission | LA.gov
The PSC said SERI paid off the $500 million principal balance over the leaseback terms, which ended July 15, 2015, but ratepayers paid all of the costs except for an $11 million net-of-tax gain credited in rates pursuant to a 1991 settlement. SERI recovered $489 million plus interest paid to the lessor through its formula rate expense, more than the $398 million book value, the regulators said.
The PSC further argued that SERI double recovered the sale-leaseback costs by making capital additions to the 11.5% interest and separately charged ratepayers a return. SERI’s fair market value lease renewal cost of $17.2 million/year, which SERI has included in rates as rents since 1995, “constitutes double collection of the capital addition costs,” the PSC said. It asked FERC to exclude the lease payments from rates and to order refunds from the time of the sale-leaseback renewal or order another ratemaking adjustment.
The Louisiana regulators also asked the commission to investigate and ensure that consumers receive the entire benefit of a litigation payment SERI received for the Department of Energy’s failure to dispose of Grand Gulf’s spent nuclear fuel.
SERI, a wholly owned subsidiary of New Orleans-based Entergy, generates and sells nuclear power, primarily through its 90% ownership and leasehold interest in Grand Gulf. Entergy Services is a service subsidiary that provides accounting, legal, regulatory and other services to Entergy’s operating companies.
WASHINGTON — FERC Chairman Kevin McIntyre was absent from the commission’s monthly open meeting Thursday, citing his recovery following surgery for a brain tumor and a fall.
Commissioner Neil Chatterjee, who chaired the meeting, opened by reading a statement in which McIntyre apologized for his absence.
“I had fully intended to be present. However, my ongoing recovery prevents me from being here in person today,” McIntyre said.
“While my health situation has impacted my mobility, it has not impacted my ability to get the commission’s work done,” he added, citing 151 orders since the July open meeting, an agreement with the Pipeline and Hazardous Materials Safety Administration over LNG terminal permitting and the appointment of Administrative Law Judge Stephanie Nagel.
McIntyre also expressed gratitude “for everyone’s concern regarding my ongoing recovery.”
Chatterjee ended McIntyre’s statement with his own comment, saying “I know I speak for my fellow commissioners when I say that we wish the chairman the best in his continued recovery.”
McIntyre revealed in March that he had had surgery for a brain tumor and was undergoing treatment. Shortly before July’s meeting, the chairman disclosed that he had compression fractures in two of his vertebrae, causing severe back pain, and that he had fallen and injured his arm on July 4.
At the July 19 open meeting, McIntyre remained seated throughout, and it was apparent that he was in pain. (See “McIntyre Toughs it out,” FERC Says Farewell to Powelson.) The commission does not meet in August.
McIntyre also was absent at the commission’s annual reliability technical conference July 31.
On Sept. 11, FERC posted an episode of its “Open Access” podcast, in which McIntyre said he was “well on the mend, and I’m feeling better every day.”
“I also am happy to report that I have continued to work full steam ahead with my colleagues, my personal staff and the commission’s professional staff to ensure that the commission’s work continues unabated. In fact, the August break wasn’t much of a break.”
However, sources have told RTO Insider that the chairman is often absent from FERC headquarters and that meetings with him have been frequently rescheduled as a result.
When asked how often McIntyre has been coming into headquarters for work, FERC spokeswoman Mary O’Driscoll said Thursday, “I can’t answer that; I don’t know.” She was incredulous when asked whether the chairman had considered resigning because of his health issues. “What? Where is that coming from? No. I don’t know. No.”
Another spokesman, Craig Cano, declined to comment.
In another departure from normal proceedings, the commission did not hold a press conference after the meeting. Despite being repeatedly asked, O’Driscoll refused to give reporters a reason for this.
“From time to time we do not have briefings. So it’s not breaking with tradition. I’ve been here 11 years, and I’ve done it at least once with each chairman I’ve served. … I don’t know why you’re making a big deal about this. No briefing. OK?”
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.
SARATOGA SPRINGS, N.Y. — The evolving challenges of grid resilience and the past and future of New York’s Reforming the Energy Vision took center stage at the Independent Power Producers of New York’s Annual Fall Conference on Friday.
Since its 2014 launch, REV has fostered cultural change at both utilities and the Public Service Commission, said James Gallagher, executive director of the Smart Grid Consortium, a nonprofit group promoting the use of new technologies in New York’s electric power system. “There’s much more flexibility, more openness to change and more collaborating to partner with outside organizations.”
The issue of resilience remains central, but letting go of command and control has not been easy for the utilities as they struggle to incorporate increasing amounts of distributed energy resources, he said.
“The commission invited utilities to come in with what they call ‘Platform Service Revenue Incentives,’ where they would get rewarded for facilitating local markets,” Gallagher said. “No utility has yet to come forward with an incentive proposal.”
Gallagher met former PSC Chair Audrey Zibelman in Australia and asked her what one thing she would change about how the commission handled REV under her leadership.
“Her one regret was that she permitted and encouraged each utility to have their own [Distributed System Platform],” he said. “She would now make one uniform DSP across the state.”
IPPNY CEO Gavin J. Donohue said a key challenge in public clean energy policy is to continue prohibiting utilities from owning generation, for example, in New York’s Energy Storage Roadmap now nearing final approval by the PSC.
On Sept. 10, IPPNY filed comments with the commission regarding energy storage, asserting that “private investors have a greater incentive to lower costs than utilities under cost-of-service regulation,” and that transmission and distribution should be separated from generation to eliminate the potential for generation-owning utilities to exercise vertical market power “to the detriment of wholesale competitive electricity markets and consumers.”
Sergej Mahnovski, director of growth and innovation for California-based Edison International, said customer demand, as well as regulation, has driven renewable energy growth.
Mahnovski, who used to work in New York, also said utilities initially dismissed REV as overly complicated, but “I always felt that if 10% of REV worked, it would make a contribution.”
Questionable Benefits
Couch White attorney Kevin M. Lang said he doesn’t think the utilities have changed much under REV, and referred to the second set of Distribution System Implementation Plans filed in June this year.
“All Con Edison reported was what they did the past two years, no cost allocation, no looking forward,” Lang said. “REV was about avoiding $30 billion in infrastructure spending, but now it’s about everything. We’re seeing tens and hundreds of millions of dollars spent for questionable benefits.”
Con Ed’s Brooklyn-Queens Demand Management project was meant to avoid the expense of building a new substation, he said, but some analysts estimate that over its 50-year lifespan, the project might cost $4 billion more than just constructing the substation.
“Consumers will use less electricity, but the reason is because they can’t afford it,” Lang said. “Reducing carbon in the atmosphere is a laudable goal, but we need a sense of balance.”
Industrial companies are leaving New York because they can buy power for a fraction of the price in other states, he said.
Laurence M. Downes, chairman and CEO of New Jersey Resources, a natural gas distributor and developer of clean energy projects, shared his positive take on decades of working with state regulators. New Jersey Gov. Phil Murphy earlier this year appointed Downes as chairman of the state’s Economic Development Authority.
“Since the 1980s, New Jersey has launched a host of public policy initiatives related to environmental stewardship … and as a mainly downstream company, we have come away stronger after every one of those,” Downes said. “If it were not for those public policy initiatives, we would not be serving customers literally in every state in the union right now, being in the solar business and being the leader in energy efficiency.”
Electricity is treated as a commodity, but it’s a critical national resource, said Sherrell Greene, president of Advanced Technology Insights.
Greene served as director of nuclear materials programs at Oak Ridge National Laboratory, where he worked for 33 years before founding ATI in 2012.
“Grid resiliency is a classic case of a tragedy of the commons; everybody’s a stakeholder but nobody owns it, nobody controls it,” Greene said. “And resilience does not apply across the board. You may be resilient to a cyberattack, but not to an electromagnetic pulse event.” (See FERC Orders Expanded Cybersecurity Reporting.)
The electric power grid is one of the largest machines ever created, so changing it is a challenge, said Arunkumar Vedhathiri, director of New Energy Solutions at National Grid.
“All of a sudden I have a swimming pool pump that can talk to the grid,” Vedhathiri said. “Consumers are not sure what they want from an energy company, but if you put an interface in front of them, they suddenly have a whole different relationship to their utility.”
He recounted how while on a beach in India last month he got a text message from a colleague telling him to cut energy use on a high peak day. Vedhathiri logged into his thermostat account, changed the setting, and “saved the grid from halfway around the globe.”
NYISO Executive Vice President Richard J. Dewey said New York is home to the oldest power grid in the world, and therefore “has some of the oldest electric infrastructure, which is something to keep in mind as we try to modernize the grid.”
Many New York generating plants also are nearing the end of their design life, he said.
The ISO is “working to establish market rules to appropriately price and value the benefits that renewable resources bring to the grid,” and favors a market approach to achieve whatever resilience characteristics are needed, such as dual-fuel capability, Dewey said. (See NY Debates CO2 Charge for ‘Beneficial’ Load.)
Marc Chupka of the Brattle Group recounted the U.S. Department of Energy issued a lauded study of the grid in August 2017, only to be followed in September by a Notice of Proposed Rulemaking to support coal and nuclear plants, which FERC rejected 5-0 in January.
Whether or not the scenario of natural gas curtailments was raised as a “stalking horse” by coal supporters, the controversy did begin the perception of fuel security as a resource attribute, Chupka said.
Fuel security is a New England winter peak issue, said Rob Gramlich, founder and president of energy consultancy Grid Strategies.
“Here we are with another hurricane and the issue is power — not generation, but the distribution and transmission infrastructure,” Gramlich said. “People need to plan for that. Old reliability contingencies don’t include climate change threats.” (See NEPOOL Debates Fuel Security, Cost Allocation.)
Todd Snitchler, director of market development at the American Petroleum Institute, said his group disputes the notion of natural gas being a dirty fuel.
“Brattle helped us with analysis that showed natural gas scoring very well on efficiency attributes, and natural gas is the enabling fuel for many renewable energy resources,” Snitchler said. “Natural gas is not so much a bridge fuel as a foundational fuel.”
