PJM stakeholders at Wednesday’s Markets and Reliability Committee meeting endorsed a series of temporary manual changes regarding minimum fuel requirements during emergency operations.
The RTO said the revisions to Manual 13 were based on fuel availability issues hitting companies and countries around the world and are aimed at maintaining reliability in the face of possible extreme weather conditions.
The changes, which were endorsed in a rare same-day first read and vote at the MRC, state that PJM may request a generation owner to move steam units, which are mostly coal-fired, into the maximum emergency category if their remaining run time falls below 240 hours, or 10 days. The units could be restricted from operating during that time unless required to meet reliability needs for the grid.
Units could remain in maximum emergency status until their fuel inventory rose above 21 days, or 504 hours. The designation would only be implemented to address concerns with local or regional reliability resulting from fuel supply shortages.
The previous run-hour threshold for maximum emergency was 32 hours.
Mike Bryson, PJM’s senior vice president of operations, said the RTO recognized it was “unusual” to ask for a first read and endorsement of a manual item on the same day at the MRC, but it was important to act now instead of during next month’s MRC meeting because waiting would “make the inventory issue worse.”
The RTO started hearing about fuel supply issues in August, Bryson said, with rising natural gas prices and limited coal inventories. He said it has conducted data requests with units to “get a handle” on current fuel supplies.
“PJM is concerned, both on the industry-wide issues and general inventories, particularly of coal, going into the winter,” Bryson said.
The changes are only temporary, Bryson said, focusing on the 2021-2022 winter season. PJM is looking to have stakeholder discussions to examine “longer-term tools” to implement for fuel security issues.
Bryson said PJM realizes that it’s the generator’s responsibility of “managing this risk” of fuel security and have “heard that clearly” from the generators the RTO has talked to about supplies.
“We do recognize this may not be the ideal tool, but it is something we can implement prior to winter operations without a waiver or FERC filing,” Bryson said. “We think it’s important that we have an additional tool going into the winter.”
Chris Pilong, director of PJM’s operations planning department, said the manual revisions are a “reliability backstop” and the “last tool we potentially have” in case of a fuel shortage emergency. The changes wouldn’t be used as the primary tool for PJM to manage fuel inventories, he said, but the RTO wanted to take every possible action to ensure reliability this winter. “Given the escalation of the concerns we’ve been hearing have ramped up significantly over the last few weeks, we feel it very prudent to take action immediately to make sure we’re prepared.”
The manual changes were partially a result of lessons learned from the February winter storm’s impacts in Texas.
Stakeholder Opinions
Though they ultimately approved them, stakeholders raised several concerns about the changes, saying they could impact current market incentives or exempt affected generators from performance requirements and penalties.
Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), said she appreciated the “reliability imperative” in the changes, but the ICC viewed them as “pretty significant” without much time to debate the ramifications.
Bruce said they presented potential “concerns” for portfolio owners on transparency issues. She asked if the changes involve a “discretionary action” if a resource “can be placed” into max emergency or if it “will be placed” at PJM’s direction.
“In my mind, they’re two very different scenarios,” Bruce said.
Pilong said the language was developed to be on the “flexible side,” as in depending on the situation. He said the 10-day provision allows PJM to have discussions with the resource owner to determine if there are concerns about reliability or the ability to replenish fuel.
“It’s very evident that not every situation falls nice and neatly into the perfect, same box,” Pilong said.
Jeff Whitehead of Eastern Generation said stakeholders have spent a lot of time discussing fuel security issues over the last few years in PJM. He said he had the sense similar fuel shortage scenarios had been examined.
Whitehead said it may be necessary for PJM to come back with more education on emergency scenarios and seasonal fuel security issues.
“I’m a little surprised we’re here, frankly,” Whitehead said.
New Jersey’s mass transit agency, NJ Transit, approved a $9.5 million purchase of eight electric buses Wednesday to be deployed in a South Jersey environmental justice area as part of the agency’s effort to convert its fleet of more than 3,000 buses to zero-emission by 2040.
The first of the 40-foot buses, made by Canadian manufacturer New Flyer of America, are expected to arrive in the second quarter of 2022, with subsequent arrivals spread out over a year. They will serve routes out of the Newton Avenue Bus Garage in Camden. The garage is undergoing an extensive renovation for use as a pilot project for electric buses to evaluate the performance, operating range, reliability and other factors of the buses.
The purchase contract includes an option to purchase another 75 buses, according to a statement from the agency.
Cedrick Fulton, vice chairman of the NJ Transit board of directors, called the purchase a “historic action.”
“This is just the start of a next-generation bus network that will be greener, more sustainable and more equitable,” he said.
Legislation signed by Gov. Phil Murphy in January 2020 requires zero-emissions buses to account for 10% of any new fleet purchases by NJ Transit after December 2024 and all new buses purchased by the agency to be electric by 2032. The agency in May put out a request for proposals to convert all its garages to zero-emission.
Environmental groups such as Environment New Jersey, as well as New Jersey Policy Perspective, a Trenton-based think tank, have encouraged the state to accelerate the introduction of electric buses, citing the environmental and health benefits reaped from the move. (See Environmentalists Call for Faster Transition to Electric Buses in NJ.)
Hayley Berliner, clean energy advocate for Environment New Jersey, told the NJ Transit board during its meeting Wednesday that the agency will find it hard to meet its zero-emission bus goals without significant state and federal funding. She called for the state to create a “dedicated source of funding” for the agency’s bus program.
The Federal Transit Administration in June awarded NJ Transit $5.15 million for the purchase of four zero-emission, 60-foot articulated buses to serve the agency’s Hilton garage in North Jersey, with routes into Newark, another environmental justice area. The garage is also slated to be converted soon to serve electric buses, and the agency also is planning to buy another eight 40-foot electric buses for use there, according to a presentation prepared for Wednesday’s meeting.
Louisiana regulators this week said they will split with MISO if their ratepayers are forced to fund major transmission built in the northern reaches of the RTO’s footprint.
During a Wednesday meeting, Louisiana Public Service commissioners cited concerns over an “offset” of the value MISO can provide to southern ratepayers, if it expects them to shoulder future transmission costs in the Midwest region.
A PSC consultant said the grid operator’s long-range transmission plan’s primary function is to support large-scale wind farms and solar arrays, not accomplish future reliability as the RTO claims.
“These front projects are being referred to by MISO as reliability projects,” said Stone Pigman attorney Noel Darce, charged with filing a report on the plan to the commission. “They are primarily designed, however, to allow large quantities of wind resources located in the northwest portions of MISO to be delivered across the MISO footprint.”
Darce said generators in MISO South could be forced to pay for the delivery of other energy sources “to the benefit of states” with lofty renewable energy goals.
MISO has said it could soon recommend up to $30 billion in construction for new transmission as part of its long-range transmission plan, with as much as an additional $100 billion of investments to follow. The RTO has long said it needs more transmission to avoid reliability violations as it faces mounting thermal plant retirements, rising renewable energy use, and a growing reliance on electrification.
Facing recalcitrance from its southern members, MISO decided to first study and recommend long-range projects in MISO Midwest. Planners said they’ll address MISO South’s needs in 2022.
Commissioner Eric Skrmetta said he favors giving MISO a one-year notice to remove Louisiana from membership if the transmission plan contains cost sharing between the RTO’s subregions. He also said he would author a motion to begin the exit process in November, if MISO moves forward with its provisional postage stamp allocation plan.
Some members have said separate but equal cost allocations between MISO Midwest and MISO South will keep the subregions electrically isolated and hinder stronger transmission links between the two. The RTO’s executives have said they could perform a five-year review of long-range projects in MISO Midwest to see if they delivered quantifiable benefits to the South. (See MISO Hopes Bifurcated MVP Cost Allocation Will be Temporary.)
Skrmetta Vows Supreme Court Battle
“We have arrived at the moment where the cost of transmission is going to outweigh the value benefits provided under the market,” Skrmetta said. “We are going to be a member of an organization that is simply going to be burdening our ratepayers with costs.”
Skrmetta said he wasn’t interested in supporting a “tremendous amount” of wind generation in MISO Midwest that was built on production tax credits.
“I remember that an old guy told me, ‘God invented water, but he forgot to lay the pipes,’” he said. “So that’s what makes water companies make money. So, it’s the same thing with this. They’ve gotten free windmill assets and now they want the ratepayers to pay for the transmission from these stranded wind assets.”
He characterized MISO as a “transmission owners’ club” And said state commissions “are looked on as a nuisance.”
“We went through a very extensive, I guess, engagement period and we got married and — all of sudden — things changed,” Skrmetta said of Louisiana’s MISO membership experience.
Louisiana and other MISO South states could join other markets that don’t have a transmission component, Skrmetta said. He said he was prepared to pursue a lengthy court battle for the right to leave MISO.
“We’ve been told by some people in this organization that FERC is never going to let us go. I will let the Supreme Court of the United States tell us we can’t go before I’m going to see ratepayers in this state see a 7%, 8%, 10% immediate increase,” Skrmetta said. “We have been either duped, or we’re being mistreated, or we have been looked at like we’re somewhat less intelligent than our friends up north.
“Either this is going to be a value proposition for ratepayers and for generators and for transmission owners in an equal and balanced situation, or it’s not going to be anything for us,” Skrmetta said. “Everyone floats on a rising tide … but when we’re going to be holding the anchor, and they’re going to be staying on the boat, that is not fair to the ratepayers of this state.”
“I want to be very careful about how we move forward,” Commissioner Lambert Boissiere said. A MISO split could have huge implications on how Louisiana transmits power, he said, urging the state’s utilities and power producers, commission staff and the RTO to work together.
PSC Chairman Craig Greene said an organized wholesale market is a “necessity” for Louisiana.
“Before we divorce one, we need to know which one we’d be going to because it’s important to have the benefits that an organized wholesale market brings,” he said.
But Greene also said it’s “laughable” that MISO can’t single out more specific benefits beyond a postage-stamp allocation.
MISO: Tx Costs Pale Compared to Generation Costs
MISO responded by saying its long-range planning is aimed at accommodating members’ integrated resource plans and most announced carbon-reduction goals by utilities and states.
Spokesperson Brandon Morris said staff has conservatively estimated $135 billion in new generation resources will come online over the next 20 years across the footprint. He said MISO’s initial $30 billion price tag represents just 20% of the planned generation investment.
“This is the investment needed to enable the projected generation costs, which will far outweigh the transmission costs,” Morris said in an emailed statement to RTO Insider.
But Darce recommended a “deceleration” of MISO’s approval goals for projects.
“MISO was in a rush to approve the transmission in this first tranche of transmission projects in March of ’22, and it didn’t want to wait any longer to make a cost allocation filing. This process has all moved quickly in MISO and it’s been changing in the last few months and in the last few weeks,” he told commissioners. “Staff is concerned that the rush to approve these projects by March of 2022 is a self-imposed and artificial deadline and is not leaving enough time for the projects to be vetted [or] the cost allocations to be fully understood.”
Darce said MISO’s proposed 1:1 benefit-to-cost ratio threshold for projects remains too low and that MISO South’s recommended 1.25:1 ratio is more appropriate. He said the RTO rejected MISO South’s cost-allocation proposal “without any real stakeholder discussion.” (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)
“Staff believes that large, expensive projects built based on projections of need decades into the future should not be made with the hope that a dollar spent will return a dollar of benefits,” Darce said.
Darce added that the commission isn’t opposed to renewable energy or long-term transmission planning decisions made for reliability or economic reasons. But he said the cost of a long-range portfolio is a “major concern.” He said costs could exceed the $130 billion top-end estimate.
“The financial impacts of that construction, even over a footprint as large as MISO’s, would be enormous,” he said.
Some MISO South stakeholders have argued that the postage stamp cost allocation would effectively bring Entergy’s system agreement back from the dead.
The utility’s allocation of production costs among its half dozen operating companies under its multistate system agreement has been a source of conflict and complaints for more than a decade. Before 2015, the companies functioned as one system, although each had different operating costs. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company so that no operating company had production costs more than 11% above or below the system average.
The upcoming months should be easier on the U.S. energy sector than the “particularly challenging” winter of 2020-2021, according to FERC staff presenting the commission’s 2021-2022 Winter Energy Market and Reliability Assessment on Thursday, though they warned that severe weather like February’s winter storm remains unpredictable.
Presenting the report at FERC’s monthly open meeting, Patricia Schaub of FERC’s Office of Energy Policy and Innovation noted that temperatures are expected to be above the 30-year average across most of the U.S., according to the National Oceanic and Atmospheric Administration, with a “small probability that this winter will be slightly colder than last winter.”
Positive Temperature Forecasts
Winter 2021-2022 temperature forecast from the National Oceanic and Atmospheric Administration. Above: the three-month outlook for November through January. Below: the outlook for December through February. | NOAA
More detailed figures in the report show NOAA projecting a 70 to 80% chance of above-normal temperatures in Arizona, New Mexico and West Texas, and a 60 to 70% chance of above-average temperatures in New England, the Southeast, the Gulf Coast and the Southwest, including California. In the Carolinas, the Ohio River Valley, the Midwest, Ozarks, Rockies, Northern California and Southern Oregon, NOAA assess a 50 to 60% likelihood of above-normal temperatures, while the Upper Midwest and “some of the Northwest” have an equal chance of being below or above normal.
These predictions are stronger than those in last year’s report, in which the likelihood of above-average temperatures in most regions was less than 50%, and the report noted that higher winter temperatures “typically imply lower-than-average demand for electricity and natural gas. (See COVID-19, Weather Drive FERC Winter Outlook.)
However, the memory of February’s winter storms, which left hundreds of people dead and caused billions of dollars in damages in Texas and the Midwest, led the report’s authors to temper their optimism with warnings about “severe cold weather events that drive up energy demand.”
“Last year’s NOAA forecast showed an even greater probability of milder conditions in regions that were ultimately affected by the February 2021 winter storm,” the report said. “Forecasts for arctic oscillation … are only available 14 days ahead of time, making it difficult to forecast far in advance whether a similar winter storm event will happen again this year.”
Speaking at Thursday’s meeting, Matthew Adeleke of FERC’s Office of Electric Reliability emphasized the need to be prepared for the worst and — with the support of Chairman Richard Glick and the other commissioners — reiterated the preliminary recommendations from the commission’s joint inquiry with NERC into February’s storm. (See FERC, NERC Share Findings on February Winter Storm.) That report advised generator owners to:
identify and protect cold weather-critical components and systems for each generating unit;
design new or retrofit existing generators to operate to specific ambient temperatures and weather based on extreme temperature and weather data;
take into account the effects of wind and precipitation in winterization plans;
create corrective action plans for generator owners that experience freeze-related outages; and
ensure the system operator is aware of the generating fleet’s operating limitations so that they can plan mitigation actions.
Outside of the chance of severe weather, however, FERC’s assessment portrayed the grid as adequately prepared for normal conditions. Data from NERC, RTOs and ISOs show that anticipated reserve margins (the available electric generation capacity in excess of expected peak demand) exceed reference reserve margins for all markets and regions. SERC-East, which encompasses North and South Carolina, reported the lowest reserve margin with expected reserves of 26%, but this is well above the region’s reference level of 15%.
The report cautioned that “reserve margins are not guarantors of reliable operations,” which can be affected by many factors such as fuel availability and the performance of intermittent generation resources like wind and solar. The latter is especially important as wind and solar resources represent the vast majority of generation capacity added in ERCOT, the area most affected by February’s cold snap, and where nonfunctioning wind turbines contributed to the generation loss during the storm. (See ERCOT Focuses on Restoration, not Blame.)
NERC is predicting that net demand for electricity will increase by about 1% in the winter months compared to last year. The increase is expected to be highest in the SERC-Florida subregion, ERCOT and the WECC-NWPP subregion, while MISO and SERC-East should see a decrease in demand. Other regions and subregions are expected to remain similar to last year’s levels.
Export Demand to Keep Gas Prices High
Seasonal change in natural gas storage inventories in the lower 48 states over the last five years | EIA
Natural gas production in the U.S. is expected to rise this winter, FERC said, with the Energy Information Administration forecasting an average dry natural gas production rate of 94 Bcfd for the winter, up from 90.8 Bcfd last year. The increase represents the market returning to the growth trajectory experienced over the last decade before the decline in production observed in 2020-2021, which FERC attributed to the COVID-19 pandemic.
Demand for natural gas is also on the rise, with EIA forecasting an average of 111 Bcfd for the winter, up 2.5% from last year. This is in spite of falling demand for gas as a generating resource. Upward pressure on prices is expected because of strong global demand: LNG exports are projected to average 11 Bcfd between November and February, up 21% from the average last winter, while pipeline gross exports will rise 15%, to 9.3 Bcfd.
East Asian countries, particularly China, Japan, South Korea and Taiwan, are the leading drivers of LNG export demand. Natural gas imports will be needed to balance the gas markets during the winter months, with LNG imports averaging 0.3 Bcfd — up 93% year over year — and gross pipeline imports falling 12% year over year to 7.4 Bcfd.
Storage inventory levels for natural gas are predicted to begin the winter withdrawal season — which runs from November to April — at 3,752 Bcf, 5% below the five-year average, because of a lower-than-average injection season between April and October and record withdrawals during February’s winter storms.
Propane is also starting with low stocks: For the first week of October, they were 72.3 million barrels, 20% below the five-year average for the same week and lower than any recorded level for the same period in the last five years.
The Connecticut Power and Energy Society focused its annual fall conference on the theme of equity and inclusion as drivers of “the future of energy.”
“This is something that we thought was very important for us to do this year,” CPES President Alex Judd said.
Here is some of what we heard at the virtual event.
Casten Looks Beyond ‘Hot FERC Summer’
When U.S. Rep. Sean Casten (D-Ill.) went the pop culture reference route to draw attention to FERC on the House floor in July, he did not think “Hot FERC Summer,” a play on the Meghan Thee Stallion hit “Hot Girl Summer,” would be a defining moment for him.
“I must say it cracks me up to realize that I’ve still got a few years left in me, but I now know what they’re going to say on my tombstone, and it’s going to be ‘Hot FERC Summer,’” Casten said with a laugh during his closing keynote. “Whatever else I’ve done in my life, that one minute on the House floor seems to be the thing I’ll be remembered for.”
Zeitgeist and the #HotFERCSummer hashtag aside, Casten now reaches a broader constituency when he talks about energy issues, primarily through an equity and environmental justice lens. According to the UN’s Intergovernmental Panel on Climate Change report released in August, Casten said, “we’re out of time.” (See Too Late to Stop Climate Change, UN Report Says.)
U.S. Rep. Sean Casten (D-Ill.) speaks at the Connecticut Power and Energy Society’s virtual fall conference on Thursday. | Connecticut Power and Energy Society
“We don’t have time to move slowly, and the single worst thing we can do for equity is to ignore the fires and ignore the floods because this summer is not the new normal,” Casten said. “It is the rate of acceleration. That’s our new normal.”
Economy-wide decarbonization and electrification need to happen quickly, as does the doubling of energy efficiency. And likely without the billions of dollars in funds from the Build Back Better Act that House Democrats fear will look different when the Senate potentially trims back the bill.
“It’s a grand parlor game in Washington speculating what might emerge from the Senate,” Casten said.
Billions invested in clean energy and the transmission infrastructure to interconnect it, which “without any hyperbole” would be “the single greatest wealth transfer from energy producers to energy consumers that our species has ever seen,” Casten said.
“Every technology we deploy is cheaper to operate than the ones that it displaces, and it cuts the cost of energy, to the point that creates real problems for our grid regulators,” Casten said.
Part of the reason Casten talked about a “Hot FERC Summer” was the critical role he thought the agency would need to play in building a reliable power system.
He also added that the clean energy transition is an enormous economic growth opportunity, but there is a need to ensure that it does not widen wealth inequality.
“We need to talk about this more honestly in the energy community,” Casten said. “This is going to lead to a massive increase in labor productivity. That’s one way of putting it, but the other way is it doesn’t take as many people to run a solar panel.”
Helping communities previously built around and dependent upon fossil fuel extraction and production is something that Casten understands because Illinois “used to be a coal state.” He has “a certain sympathy” for Sen. Joe Manchin, the West Virginia Democrat who is opposed to some of the more robust climate change measures touted as vital by the Biden Administration and many Democrats in Congress like Casten.
“Geographically, West Virginia is a beautiful state. It’s also a really hard state [in which] to build electricity wires and to build highways and infrastructure … so there’s a lot of logic for a West Virginian economy that’s based on the natural resources in the ground,” Casten said. “But as we’ve moved away from coal, those jobs have gone away. It’s hard to see them coming back.”
Casten thinks “it’s unfortunate” that people in West Virginia do not have leaders who describe what they have seen “on the other side of the mountaintop” when it comes to clean energy.
“Instead, [it’s] leadership that’s telling them that they agree that this mountain is too high, why don’t we just all lie down here in the forest and cry,” Casten said.
Congress needs more experts in climate change and energy issues, Casten added. He is a former clean energy company CEO and has undergraduate and graduate degrees in engineering. Climate change is Casten’s top priority.
“I would ask you to bring your expertise with an uncomfortable level of ambition because if your message to Washington is, ‘I really like the status quo,’ that’s not particularly helpful,” Casten said.
Equity in the Regulatory Process
To decarbonize the transportation sector, states like Connecticut and Massachusetts need more electric vehicles on the road. During their panel, Matthew Nelson, chair of the Massachusetts Department of Public Utilities, and Marissa Gillett, chair of Connecticut’s Public Utilities Regulatory Authority, said that people in low- to moderate-income communities need ease and access to charging infrastructure.
“Electric vehicle charging isn’t like gas stations. You’re not just replacing the gas station. They have different use patterns,” Nelson said.
He added that while getting people into single-passenger EVs is laudable, the real goal is heavy-duty equipment and vehicles.
“I recently went to an onsite demonstration of an electric backhoe, and the two things that really jumped out to me is it functioned just as well as the regular gas-powered, and it was incredibly quiet. The societal benefit of having something that is not pumping out emissions that is quiet, other than the actual digging — it’s absolutely staggering the difference. There’s a lot of non-energy benefits that come from electrifying transportation fleets.”
Gillett said she is proud of the work PURA did on its nine-year electric vehicle charging program — part of the Equitable Modern Grid initiative — that set targets for the number of charging stations deployed in low- to moderate-income areas or underserved communities. However, she added there needs to be consideration of urban mobility options such as e-scooters and e-bikes. In addition, Uber and Lyft do a lot of “deadheading,” often polluting the air in environmental justice communities.
“There’s room for creative thinking here that I’m hoping is inspired on this day,” Gillett said. “We have a lot of folks that are advancing the electrification conversation. I’m hoping that some of our stakeholders pick up on that thread and start building on top of the work that’s already been done.”
In the year since FERC issued Order 2222 to usher distributed energy resources into the wholesale energy markets, RTOs/ISOs have been creating market rules to comply with the order.
Advanced Energy Economy on Tuesday hosted a panel of industry experts and regulators who evaluated the progress and potential of the grid operators’ various paths to compliance.
To enable frequently dispatched DERs to participate in the markets, it’s important to have a continuous participation model that gives the resources credit for their full capacity value, said Greg Geller, senior director of regulatory affairs at Enel X North America.
“We can just count what those resources can do to reduce their on-site consumption, but a lot of them are going to be able to inject into the grid as well, and … we need to make sure that they can get credit for that injection,” Geller said. While grid operators such as ISO-NE and NYISO allow that now, “PJM does not have that today, and we’re hoping that as part of 2222 they will have that that single continuous model.”
In January 2020, FERC approved NYISO’s DER model, “which actually has a solution to this that we think works pretty well and we’d like to see other ISOs replicate,” Geller said. (See NYISO DER Participation Model Gets FERC OK.) The commission said that NYISO’s approach enables “heterogenous groups of technologies to aggregate and be compensated for services that they are collectively capable of providing.”
Regional Rundown
Both CAISO and NYISO are expecting FERC to fully approve their DER participation models and any subsequent Order 2222 tariff changes by the end of 2022, said Peter Dotson-Westphalen, senior director of market development at CPower Energy Management. But the commission early this month asked both ISOs to clarify details about the treatment of DER aggregations described in their filings (ER21-2455, ER21-2460). (See FERC Asks Details from CAISO, NYISO on Order 2222 Compliance.)
“We’re looking at markets that may not have significant system market model changes, whether leveraging existing market models to some degree, and whether or not the changes would actually require any significant software development or require other subsequent system changes already planned or in progress by each of the ISOs/RTOs,” Dotson-Westphalen said.
In the case of ISO-NE, stakeholders are currently discussing how the energy and ancillary services market changes would probably not go into effect until 2026, whereas the capacity market changes would be implemented in time for the Forward Capacity Auction 18, which covers the delivery year beginning in June 2027, he said.
In SPP and in PJM , DER aggregations could begin participating as early as 2023, although that could slip to 2024. Both RTOs are currently restricting multi-node aggregations in their proposals, while single-node aggregation may require system changes that could delay implementation, Dotson-Westphalen said.
Clockwise from top left: Allison Wannop, Voltus; Peter Dotson-Westphalen, CPower Energy Management; Prusha Hasan, Advanced Energy Economy; Greg Geller, Enel X North America; and Tricia Debleeckere, Minnesota PUC | AEE
MISO is currently working on a market system enhancement project, he said.
“This is all information that hasn’t really been put down in writing, but has come up in stakeholder discussions, and at this point it’s probably at least going to be 2023 before the market system enhancements project is completed and we would expect to see the participation model resulting from order 2222 to be able to be enacted. But depending on the timeline of that project and other factors, that could also slip further on down the line,” Dotson-Westphalen said.
The go-live date for the MISO region is likely 2025, said Tricia DeBleeckere, assistant executive secretary for the Minnesota Public Utility Commission.
“What that does is set a deadline for the states, essentially for our distribution utilities, to ensure that we have the systems in place to operate a reliable grid when this market product goes live,” DeBleeckere said. “There is value that we can unlock in all the different ranges of DER that are coming onto our system, and whether we utilize that through retail programs or through the wholesale program, as regulators we want options and choices to make sure that we’re picking the most cost-effective resources to participate.”
Location and Size
Two specific issues working their way out in the Order 2222 compliance process — and critical to enabling watershed change —are locational requirements and size settings, said Allison Wannop, director of legal and regulatory affairs at DER aggregator Voltus.
“Order 2222 says that each RTO/ISO must establish locational requirements that are as geographically broad as is technically feasible, but what does that mean?” Wannop said. “In California you can aggregate with energy or ancillary services within a [sub-load aggregation point] and a sublap is very large. There are 24 sublaps in California and each of those is about a gigawatt.”
California’s daily peak load of around 30 to 40 GW provides a very large area over which to aggregate, allowing for a large range of resources that can be brought into those sublap footprints, she said.
“Just to give some real-world context, San Francisco is one sublap, and the East Bay is another one,” Wannop said. “New England is pretty similar … in the size of the aggregations where you can aggregate across a metering domain, which is generally the electric distribution company territory, but then you start to see them get smaller. You have aggregations being limited to a single node and I think that is a really critical point, what a barrier a small geographic footprint for aggregation is.”
PJM limits energy aggregations to a single pricing node of only 5 to 8 MW compared with a gigawatt for aggregation in California, she said.
“We know that a DER aggregation has a minimum size but … the core point is, if you’re limiting aggregation to a single node or an interconnection point, is it really aggregation or simply a path to market for larger resources on the distribution system?” Wannop said.
On the positive side, PJM has a sampling methodology for demand response, which Voltus would like to see applied to other DERs where a subset within a group of homogeneous resources can be metered individually — for example, 100 out of 1,000 devices, and performance is determined based on the performance of that representative sample, she said.
“That puts us on a glide path at least for full DER participation,” Wannop said. “We want to look not just at what does day one implementation look like, but what does it look like in three years, and ideally, we can write rules that allow participation as technology catches up — this idea of skating to where the puck will be rather than writing rules that lag behind the technology and are stuck to the pace of a stakeholder process.”
FERC on Thursday ordered the former operator of a New York hydro project to explain why it should not pay a $600,000 civil penalty for failing to complete safety repairs over six years before losing its lease rights to the facility (P-9685-034).
Ampersand Cranberry Lake Hydro has 30 days to respond to FERC regarding the 595-kW Cranberry Lake project on the Oswegatchie River in St. Lawrence County, N.Y. The project, which is owned by the Oswegatchie River-Cranberry Reservoir Regulating District Corp. (OR-CRRDC), a state municipal corporation, includes a dam that is 195 feet long and 19 feet high and a 57,400-acre-foot reservoir.
The dam has a “high hazard potential” rating, FERC said, “which means that a failure of the project works would result in a probable loss of human life.”
FERC awarded Ampersand Cranberry a license for the project in 2015 after the company promised to complete safety work involving the facility’s fuse plug spillway in the dam’s embankment and to raise the earthen embankment crest. The fuse plug is designed to fail during very high flows to provide a controlled release and avoid a full breach and uncontrolled release.
Although the company promised to complete the work by mid-2017, “it has failed to do so,” FERC said. “Instead, Ampersand Cranberry Lake has submitted a lengthy series of extension requests covering nearly the entire time that it has held the license for the project.”
Ampersand Cranberry notified FERC in July that it had agreed to terminate its lease and give up access rights to the project site to settle litigation with OR-CRRDC, which sued the company in early 2019 over its failure to make rent payments.
The commission said the settlement came despite its repeated warnings that terminating the lease would violate the company’s license and would not relieve it of its responsibility to complete the outstanding dam safety work.
The commission criticized the company for “delaying for many years the work … that it committed to complete when it applied for transfer of the license.”
“Based on the reports that it submitted, it appears that Ampersand Cranberry Lake made few efforts to take remedial action regarding its loss of property rights, notwithstanding repeated letters from commission staff directing it to ensure that it did not lose possession of the project,” the commission continued. “In fact, seeing the potential loss of possession, Ampersand Cranberry Lake sought to absolve itself of its dam safety obligations (and the economic cost of complying with such obligations), claiming that OR-CRRDC would be responsible for completing the work on the fuse plug and embankment that it had committed to do.”
As a carrot, the commission said it would consider offsetting the repairs against the civil penalty if Ampersand Cranberry is able to negotiate access to the project and complete the fuse plug and embankment work.
But it also included a stick, warning that it “will consider naming Ampersand Cranberry Lake’s corporate parent(s) as alter-ego defendant(s) in any federal court enforcement action if Ampersand Cranberry Lake fails to make timely payment of any civil penalty that is assessed.”
FERC Commissioner Mark Christie on Thursday blasted Chair Richard Glick and Commissioner Allison Clements for opposing the Southeast Energy Exchange Market (SEEM), accusing them of wanting to force utilities in the Southeastern U.S. to form an RTO and contending that their arguments against the proposed market were made in bad faith (ER21-1111, et al.).
The SEEM proposal — which created an energy imbalance market among utilities including Southern Co., Dominion Energy, Louisville Gas & Electric, the Tennessee Valley Authority and Duke Energy — went into effect Oct. 12 by operation of law because FERC had failed to act on it by a 60-day deadline. Christie was joined by fellow Republican Commissioner James Danly in supporting the proposal. (See SEEM to Move Ahead, Minus FERC Approval.)
In a separate order, Glick and Clements also called for TVA to open its transmission system to competition, although Glick said it would require action by Congress. Christie suggested Congress require TVA to increase its use of competitive bidding for generation (EL21-40, TX21-1). (See FERC Rejects Bid to Open TVA to Competition.)
In a statement published Wednesday, Glick explained that he was prepared to vote to approve SEEM, despite his personal belief that an RTO would serve Southeastern consumers better than the proposed market, because proposals filed under Federal Power Act Section 205 require the commission to evaluate them on their own merits. But he said SEEM’s use of the Mobile-Sierra doctrine, which presumes that any freely negotiated wholesale energy contract is just and reasonable, will inhibit FERC’s ability to monitor for abuses of market power.
“I believe that the commission’s monitoring capabilities, enforcement authority and ability to institute an FPA Section 206 action provide adequate protections should any Southeast EEM members or participants engage in any conduct that may transgress the FPA or commission regulations,” Glick wrote. “That is true, however, only if the commission’s Section 206 authority is not hamstrung, for instance, by the improper application of the Mobile-Sierra presumption.”
Clements was more harsh in her criticism of the market, writing that it “fails to abide by the bedrock principles of open access and non-discrimination that were crystallized in the commission’s landmark Order No. 888, and fails to ensure “just and reasonable rates.”
“The filing parties proposed the Southeast EEM with neither any quantitative analysis demonstrating an inability by participants to exercise market power or manipulate the market, nor adequate safeguards to protect against these abuses on a going-forward basis,” Clements wrote. “It is insufficient to rely on participants’ existing market-based rate authorities given the new market structure and new market footprint of the Southeast EEM.”
During FERC’s monthly open meeting Thursday, Christie dismissed these arguments. He noted that Glick and Clements had supported PJM’s focused minimum offer price rule (MOPR) proposal, on which the commission also deadlocked and which also automatically went into effect. Pointing to the PJM Independent Market Monitor’s argument that the new MOPR would open the door for market power abuse, Christie said during the meeting that he “can’t really take seriously [Glick’s and Clements’] concerns about market power” in SEEM. (See related story, ‘Good Riddance’ to Old PJM MOPR, Glick Says.)
“What was going on here, and let’s not kid ourselves … the opposition [to SEEM] was about one thing and one thing only,” Christie said. “And that was a well-organized campaign by numerous special interest groups to force all states into federally regulated RTOs, both the Southeastern states and the Western states.”
He said both Glick and Clements “have both been very vocal about supporting this effort to push states into RTOs. Now if you want to have an open and serious debate whether consumers do better in RTO states versus non-RTO states … then bring it on. I’ll be happy to have that debate. There’s no doubt that there’s a lot of special interests who think they’re going to do a lot better and make a lot more money in an RTO construct, but consumers don’t necessarily do better. …
“It’s the choice of the states’ elected legislators whether their utilities should join an RTO; it’s not for FERC to force them or pressure them into them. … The market power issue is a dodge.” He also noted that none of the states in the SEEM footprint opposed the proposal.
Speaking at his post-meeting press conference, Glick said that “Commissioner Christie kind of lumped me in with opponents of the proposal, and I wasn’t an opponent of the proposal; I was going to vote for it. But unfortunately, my two colleagues attempted to change the commission’s precedent with regards to the Mobile-Sierra standard. … On that point I think Commissioner Christie misunderstood what I was saying.”
Clements said during the meeting that the member-controlled SEEM Operating Committee’s veto power over who could become a member of the market violates Order 888’s open-access principles.
“Since the issuance of Order 888 [in 1996], the commission has time and time again reiterated its commitment to open access as the cornerstone of the Federal Power Act’s consumer-protection directive,” she said. “The commission’s response to the SEEM filing should have affirmed yet again the noncontroversial proposition that any type of market development and transmission service must follow a just and reasonable path and avoid undue discrimination.”
Clements also called Christie’s arguments in his statement “a strawman.”
“To be crystal clear, my opposition to accepting the filing is not because I would prefer a different market structure,” she said. “My concerns are grounded in Order 888, the commission’s duty is ensure nondiscriminatory access and our obligation to ensure rates are just and reasonable.”
Danly made a similar argument in his statement about why Glick and Clements opposed the proposal, though he was not as accusatory as Christie.
“While some may have preferred that the utilities in the Southeast create [an RTO], that is not the filing the parties submitted,” he wrote. “My colleagues detail a litany of objections to the Southeast EEM proposal that, I presume, stem from just such a preference, since the establishment of an ISO or RTO would bring with it open access throughout the Southeast in accordance with Order Nos. 888, 719 or 2000. But that decision is not ours to make. That choice is reserved wholly to the states and their utilities.”
Clements responded during the meeting: “This rather head-scratching interpretation of my position would suggest a belief that Order 888 has not already required open access across the country for over two decades.”
FERC on Thursday declined a request to open the Tennessee Valley Authority’s monopoly to competition, suggesting it was up to Congress to change the rules for the nation’s largest public power system.
The commission voted 3-1 to deny a petition by three municipal and cooperative utilities to order TVA to provide them unbundled transmission service so they could purchase cheaper power from outside the TVA “fence.” Commissioner Allison Clements dissented.
Athens Utilities Board, Gibson Electric Membership Corp. and Volunteer Energy Cooperative filed their petition in January seeking relief from what they called TVA’s excessive rates and anticompetitive practices. They contended TVA does not offer transmission service to “local power companies” (LPCs) such as themselves at rates or terms that are comparable to those TVA charges itself. (See TVA Munis, Co-ops Appeal for Unbundled Tx Service.)
But the commission voted against exercising its discretion to act under Federal Power Act (FPA) Section 211A, saying “there are no established requirements under Section 211A that an unregulated transmitting utility must meet, so there can be no ‘violation’ of Section 211A by an unregulated transmitting utility.” The commission also dismissed the petitioners request for interconnection service under FPA Section 210 as moot (EL21-40, TX21-1).
At a press conference after Thursday’s open meeting, FERC Chair Richard Glick said his hands were tied by the FPA and called on Congress to eliminate restrictions on TVA customers purchasing power from outside the TVA “fence.”
“It wasn’t appropriate to use 211a to achieve what the TVA customers were trying to achieve here,” he said calling the restriction an “anachronism.”
“Not only is it unfair to TVA’s customers to not allow them to shop for cheaper power or power that has other attributes,” such as cleaner resources, but it also “gives TVA carte blanche. They know that they can run up costs if they want to. And no one’s there to make sure that they don’t gold-plate everything,” he said.
TVA’s Monopoly
TVA, which serves 10 million people in seven states, owns 36.9 GW of generating capacity and 16,000 miles of transmission. It reported annual revenues of $10.2 billion in 2020.
Athens Utilities Board, owned by the city of Athens, Tenn., provides power to 13,000 commercial and residential customers. Gibson EMC serves 39,000 commercial and residential customers in western Tennessee and Kentucky. Volunteer serves more than 120,000 commercial and residential customers in eastern Tennessee.
The petitioners say TVA owns all the transmission capable of serving their loads. “Short of taking the very expensive and duplicative step of constructing its own transmission lines, no LPC can feasibly reach an external supplier without service across TVA lines,” they said. “…TVA has taken advantage of this arrangement to charge unreasonably high bundled rates, with no incentive to efficiently manage the costs it imposes on its captive wholesale customers.”
The petitioners said they “wish only to avail themselves of the right to unbundled transmission that is readily available to virtually all of the country’s load-serving entities, and to better serve their members/customers at competitive prices.”
The petitioners said they have been receiving bundled power and transmission service from TVA for decades under 20-year contracts that require five-years’ notice before cancellation.
An analysis by a consultant for four TVA customers found they could save a combined $310 million to $750 million (2025$) over 10 years by gaining access to cheaper power. One of the four, Joe Wheeler EMC, dropped its participation in the challenge. | EnerVision
They sought relief from FERC after refusing to sign new power supply contracts from TVA that allow termination only after 20 years’ notice. All but 11 of the 153 LPCs in TVA’s footprint have signed the new contracts, according to TVA.
(Joe Wheeler EMC, the fourth largest member-owned electric cooperative in Alabama with more than 43,000 members, also joined in the petition but withdrew its participation on Aug. 30, saying it has reached an agreement on a new power supply arrangement with TVA.)
TVA said its policy is consistent with FPA Section 212(j), enacted by Congress in 1992 to prevent outside power suppliers from “cherry-picking” TVA’s customers by using FERC’s open access rules to wheel power across TVA’s transmission facilities to LPC load. Congress added the section to balance the Tennessee Valley Act’s prohibition on TVA selling power outside the “fence.”
It contended FERC lacked the authority to provide the petitioners’ requested relief, saying “the decision about whether to provide the service the petitioners request lies with the TVA Board,” a nine-member panel nominated by the president and confirmed by the Senate.
TVA also challenged the petitioners’ claim that they and their potential suppliers are “similarly situated” to TVA transmission customers that serve load off the TVA system.
Because TVA is barred from selling power to customers outside the fence, it is unable to recoup lost revenues that would result from allowing use of TVA’s system to deliver alternative supplies to customers inside the fence. “In contrast, this cost-shift problem does not arise when the TVA transmission system is used to deliver third-party power to customers outside the fence,” it said.
Undermining the Mission
TVA also said FERC action would undermine TVA’s ability to fulfill its mission by causing cost shifts to customers left behind. “It is not hyperbole to say that the petition threatens to destroy the TVA model that has been in place for nearly nine decades,” it said.
FERC “is responsible for the just and reasonable regulation of wholesale sales and transmission of electricity in interstate commerce by public utilities, along with more limited jurisdiction over government-owned utilities. TVA is responsible for supplying power to customers in the Tennessee Valley, but it also is responsible for promoting the prosperity of an entire region and of the people who live there,” it said. “Last year, for example, TVA took a number of pandemic-related measures, including providing financial assistance, reflecting its mission to promote the general welfare of those who live in the Tennessee Valley in the broadest of ways.”
“The TVA board is statutorily required to balance these and other considerations to fulfill Congress’ directive to improve the lives of the people living in the Tennessee Valley region. And the TVA board already has balanced all of these considerations.”
It cited an affidavit from economist John Reed, who said if the four original petitioners were to obtain wheeling and switch suppliers, it would shift more than $3.3 billion in costs to the remaining LPCs and their retail customers through 2040. “And if those LPCs obtained the requested wheeling service, it is likely that others would follow suit. If all eleven of the LPCs that have not yet signed new amendments were to shift suppliers [representing 15% of TVA load], that would impose over $14.9 billion in cost shifts and rate increases on remaining LPCs,” TVA said. “Without such rate increases, TVA would not be able to maintain its outstanding debt balance under the statutory $30 billion cap.”
High Prices
The petitioners said the concern over “cherry picking” of TVA customer is an “implicit … recognition that TVA is charging the LPCs for power supply and transmission at rates that would not stand up to outside competition or commission scrutiny.
“TVA’s policy is formal acknowledgement that TVA’s current rates grossly exceed those the LPCs would pay to outside suppliers and that LPCs would seek alternative suppliers if given the choice,” they said.
They cited Energy Information Administration data that TVA’s sales for resale rate increased by almost 10% between 2010 and 2019.
They cited an analysis conducted for them by consultant EnerVision that access to cheaper power would save Athens $25 million to $45 million (2025$); Gibson EMC $65 million to $115 million; Joe Wheeler EMC $75 million to $110 million and Volunteer Energy Cooperative $145 million to $480 million over 10 years.
TVA challenged the petitioners’ contention as “unsupported,” citing a 2021 assessment by Lazard, which it said concluded that TVA’s cost-of-service rates “fall within the second-best quartile both among the top 100 U.S. utilities based on sales and among its regional peers.”
It said TVA retail rates declined by 2.3% between November 2019 and November 2020, and that wholesale rates are expected to decline by 7.2% between 2019 and 2021.
Repealing the Fence
In the late 1990s, Congress heard testimony on legislation to give FERC more authority over TVA’s transmission by repealing both the prohibition against selling TVA power outside the fence and the prohibition against wheeling alternative power supplies to TVA customers inside the fence.
But the proposals failed to win support. Instead, Congress in the Energy Policy Act of 2005 gave FERC limited discretionary authority to order “unregulated transmission utilities” to satisfy “comparability” and nondiscrimination principles in the rates, terms and conditions for transmission service.
In a concurrence, Glick said he believed Congress did not intend to give FERC the authority to ignore the fence, but he said changes since it was erected call for a new look.
“In my view, the fence is a vestige of a bygone era and the region, and particularly its ratepayers, would be far better served by having access to alternative power supplies on a competitive and non-discriminatory basis. The benefits of competition and consumer choice far outweigh whatever benefits the region once derived from the current model. Accordingly, I urge Congress to consider enacting legislation to eliminate the fence and enable utilities in the region to access alternative sources of supply and likewise to allow TVA to make wholesale sales to new customers.”
In his concurrence, Commissioner Mark Christie suggested Congress could amend the law to ensure that power costs to TVA’s consumers are as “low as feasible” and require it to increase the amount of power supply it procures on a least-cost basis.
“Competitive procurements of power supply — versus allowing some customers, often the largest, simply to leave load and shop elsewhere — avoid the potential of cost-shifting to remaining customers, most of whom are small businesses and residential customers who do not have the bargaining power of very large customers,” he wrote. “Every [load-serving entity] has fixed costs, and when large customers leave load, those fixed costs must still be paid.”
Clements dissented, saying FERC has the authority to grant the petitioners’ request and that doing so would have been in the public interest.
She cited the commission’s 2011 order requiring Bonneville Power Administration to revise its dispatch policy consistent with Section 211A while also meeting its responsibilities under its governing statutes (137 FERC ¶ 61,185).
“The TVA board must adopt policies that follow its mandate to uphold the broad goals of the TVA Act in a manner that complies with any orders the commission may issue under section 211A, which may include requirements that it provide comparable transmission service,” she wrote.
TVA spokesman Jim Hopson declined to comment directly when asked if TVA would support a repeal of the fence.
“TVA’s mission is clearly established by Congress in the TVA Act and, among other priorities, ensures that we support the public power model within a defined service area,” he said. “… Arbitrary changes to this public power model, which has successfully operated for more than 88 years, could unfairly shift costs from some customers to others and negatively impact TVA’s mission established by Congress.”
Retaliation Claim
On Oct. 15, the three remaining petitioners filed a motion alleging that TVA has made statements that it is refusing to perform needed reliability upgrades due to petitioners’ challenge. In an Oct. 19 filing in response, TVA denied any retaliation and accused the petitioners of attempting to “distort the record.”
FERC said it “takes seriously allegations concerning retaliatory conduct” but that the allegations were beyond the scope of the proceeding. Glick said Thursday he has directed the Office of Enforcement to investigate the allegations.
Asked to comment on the allegation, Hopson said “it’s important to note that, over the past five years, TVA has invested more than $2 billion in improving our transmission system, which benefits all 153 local power companies we serve, who currently have received power at 99.999% reliability for 21 consecutive years. That includes the ongoing construction of a new $300 million System Operations Center located within the service area of one of the three petitioners.”
The NERC Standards Committee on Wednesday voted to delay approving the draft standards authorization request (SAR) developed in response to a preliminary joint report with FERC on the catastrophic winter storm events in Texas last February until after the final report is published.
Despite a plea for urgency and an offer to delay publishing the SAR for comment until the report’s publication from Howard Gugel, NERC vice president of engineering and standards, committee members were reluctant to authorize a SAR without more technical information that they said would be in the final report.
The report — which listed nine key recommendations for preventing another near complete collapse like the one experienced by ERCOT — was first presented at FERC’s open meeting last month. And those recommendations were included in the draft SAR that was issued by NERC staff Oct. 6. (See FERC, NERC Share Findings on February Winter Storm.) The final report is expected to be published next month, NERC staff said, but exactly when is unknown.
Gugel, however, told the committee that NERC did not expect any of the recommendations to change and that the final report would only contain more details. He noted that the SAR would have allowed for a 45-day comment period, instead of the usual 30 days, to allow the SAR drafting team to factor in the final report as it also examines comments. It would also allow them to work on their comments before the holiday season. If it had been approved Wednesday, comments would have been due Dec. 4.
“This is a matter of urgency that FERC is concerned about, we’re concerned about, our board is concerned about,” Gugel said. “We know that based on the findings that we have [that] we need to make some changes very quickly. If we don’t act somewhat soon on this, it will be very difficult to get these changes in place within the next two or three winters.
“So we think that it’s important to at least get the SAR out for comment at this point. … If we wait, we’re probably not going to be in a situation where we can address this is any expedient manner.”
But most committee members were unpersuaded by these arguments.
“I think we all know the significance of [the SAR] and the importance of it,” said Terri Pyle, director of utility operational compliance for OGE Energy. “And I also think that’s important to make sure that the SAR is right; that industry has had the opportunity to review the final report and the technical justification prior to accepting the SAR for posting for comment.”
Many other committee members echoed Pyle’s sentiments.
“I have had members reach out to me as well with concerns that we will be basing this SAR on a preliminary report,” said Sarah Snow, manager of reliability compliance at Mississippi-based Cooperative Energy.
Gugel offered to delay posting the SAR, thus delaying the start of the comment period, until the final report was published, though he cautioned the period would need to be shortened to 30 days. But he still urged for the committee not to delay action, as it next meets Nov. 17.
Kiel Lyons — NERC senior manager of grid planning and operations assurance, who is part of the team working on the report — also said that the ERO had published the preliminary report to get the ball rolling on the standards development process. “I don’t want anyone to take away [that] the findings and the recommendations that were presented at the [FERC] open meeting were in any way [premature]. … Those were the fully formed findings and recommendations of the team after the review of all the data. … That’s why we’re comfortable submitting the SAR as is.”
“Waiting until the next meeting may not really provide anything different or bring anything different to that meeting that would help this group make the decision,” said Tony Purgar, senior consultant for ReliabilityFirst. Gugel’s proposed compromise, however, “makes more sense,” he said.
Charles Yeung, executive director of interregional affairs at SPP, also found the compromise fair. “There is value for the members of this committee getting more details about the report.” But “we don’t know how much more technical information might be included in that report, and what technical information people are needing to be comfortable with the SAR.”
But committee members were still unsatisfied. Pyle moved to table the SAR until the committee’s next meeting, but another member pointed out that the report still may not be finished by then. The motion was then changed to say until after the final report’s publication.
The committee approved this by a 16-3 vote. Yeung voted against it, along with consultant Philip Winston and Steven Rueckert, director of standards at WECC.
Other Committee Action
The committee also voted to approve a draft SAR submitted by Tri-State Generation and Transmission Association that proposes to revise FAC-008-5 to enhance the accuracy of facility capability ratings to modify and provide clarification to the term “jointly owned” in the standard.
It also approved the final SAR for Project 2019-04 and the conversion of the SAR drafting team to a standards drafting team, which will commence drafting revisions to PRC-005-6. The project, proposed by the North American Generator Forum, seeks to clarify the applicability of the standard to the protective functions within an automatic voltage regulator.
