Officials remain optimistic about MISO’s interregional transmission planning process with SPP despite its failure to produce a single project even after producing two coordinated studies since 2014.
MISO recently declined to approve a South Dakota transmission project that would have traversed both RTOs, the only potential feasible project to come out of the latest coordinated study that wrapped up this year.
Staff last month told MISO’s Planning Advisory Committee in mid-August that it no longer recommended the $5.2 million, 115-kV Split Rock-Lawrence circuit project in South Dakota, which would have been the RTOs’ first-ever interregional project. Staff instead recommended following an updated operating guide from line owner Xcel Energy and operating the Lawrence–Sioux Falls line in an open circuit to shift some congestion to the nearby Sioux Falls–Split Rock 230-kV line. (See SPP Glum as MISO Axes Last Interregional Project.)
During MISO Board Week in September, Vice President of System Planning Jennifer Curran said she thought the RTOs’ interregional process worked as intended because MISO’s regional review identified a “cheaper option” than a costly interregional project.
MISO has vowed to continue interregional communication and planning with SPP.
“MISO continues to work aggressively to try to identify cost-effective interregional projects to help ensure a robust transmission network that can mutually benefit our members,” MISO Manager of Interregional Planning Eric Thoms told RTO Insider. “In this recent case, the interregional process was successful in finding an appropriate solution to meet the need. In this case, a superior regional solution was identified after additional analysis.”
Communication Breakdown?
MISO shared its decision with SPP “in advance of the Aug. 16 Planning Advisory Committee,” Thoms said, adding that planning staff from both RTOs participated in a joint conference call in early August to discuss the information.
“We are committed to communicating study results with our partners as soon as appropriate,” Thoms said.
SPP COO Carl Monroe last month told RTO Insider that his RTO only discovered MISO’s decision through posted meeting materials and news coverage. Monroe has since walked back the comments.
“I regret misstating that SPP was unaware of MISO’s intent not to recommend the project for construction and have spoken with Mr. Thoms directly to acknowledge the error,” Monroe said. “We’re pleased with MISO’s expressed commitment to improving coordination between our organizations, and SPP likewise will do everything in our power to support interregional coordination in the interest of greater reliability and affordability across our industry.”
Thoms said the RTOs’ latest coordinated study was not conducted in vain, as MISO discovered “differences in operations and transmission service treatment that [may] arise as a potential barrier to future interregional projects.” He said MISO and SPP plan to work to better align the unnamed differences and added that they ultimately did not affect the chances of the South Dakota project proposal.
According to Thoms, MISO reached out to SPP during the coordinated study process more frequently than is required by their joint operating agreement, which outlines the procedures for interregional coordination. The JOA stipulates that the Joint Planning Committee, comprising staff of both RTOs, must meet no less than twice per year.
In addition, MISO and SPP corresponded “numerous” times during the year to discuss interregional stakeholder meetings and study data, modeling and results, Thoms said. He added that the coordinated system plan itself requires supplementary meetings to update and finalize the study.
‘Work in Progress’
MISO may still have ideas about how to improve communication with SPP regarding interregional planning, although Thoms is holding those cards close to his chest. In 2016, rather than embark on another coordinated system study, MISO suggested that the RTOs spend the year improving the study process, advice that it eventually abandoned.
“MISO and SPP continue discussions around a long-term coordination effort. At this time, those details are still being developed,” Thoms said.
He added that MISO staff are committed to “working with SPP and other stakeholders to foster effective communication and mutual understanding around these projects.”
MISO’s seams | MISO
Missouri Public Service Commission economist Adam McKinnie hails from a seams-heavy state and is often a vocal critic of the RTOs’ inability to produce interregional projects. While he declined to comment on how communication procedures between MISO and SPP could be improved, he did say there is benefit to the RTOs working together and identifying interregional projects.
“We’ve been trying to do this for years,” MISO Board of Directors Chairman Michael Curran said of interregional projects at a Sept. 21 meeting. “It has been a long struggle, and you can only do so much when your neighbor isn’t willing to coordinate, but that coordination is starting.
“Only good things can happen from here,” he told MISO stakeholders. “We’re on our way to an intermarket system, but don’t get too excited just yet — it’s a work in progress.”
BALTIMORE — PJM’s Craig Glazer wrapped up last week’s Grid 20/20 conference by joking that the National Council of Teachers of English had tweeted an objection to the forum using “resilience” and “resiliency” interchangeably.
“They didn’t tell me what the right answer was,” he said, but that Dave Anders, who leads PJM’s stakeholder engagement process, promised a sector-weighted vote on which term stakeholders preferred.
The quip provided some insight into the challenges of addressing grid resilience. If getting the term right is hard, agreeing on a definition is harder. Harder still is determining what actions should be taken, who will take them and how all the disparate responsibilities and demands are integrated into an improved system.
Many of the gray areas and friction points were on display at the conference. Government representatives promised they could be trusted with sensitive corporate information while company representatives hesitated to offer too much. Gas-fired generators cited the importance of fuel security, while gas pipelines said generators have declined to sign the firm contracts that would guarantee fuel delivery. Everyone seemed to agree that more redundancy should be built into the system, but that it can’t be too complex or too costly.
“The fact is we’re not going to be able to be 100% secure, so we’re going to have to make choices,” said Stefanie Brand, director of New Jersey’s Division of the Rate Counsel. “I think those questions need to be answered at the beginning or else we’ll be throwing solutions at a problem that hasn’t been defined.”
Transparency
Several panelists representing government interests urged companies to share information and procedures to see if there are ways to help each other.
State governments “are all very eager to hear from the private sector in their various states about what they’re doing and how they can work together,” said Tim Blute, director of the National Governors Association’s Homeland Security & Public Safety Division.
Bill Lawrence, who runs NERC’s Electricity Information Sharing and Analysis Center, assured attendees that his group maintains separation from the corporation’s compliance monitoring enforcement program to ensure that any information volunteered by companies “will not get them audited.”
“At the end of the day, this is all going to come down to trust,” said Col. Victor Macias of the National Guard Bureau. He said the nation’s 3,300 National Guard facilities are prepared to help but need to know ahead of time what they’ll be expected to do.
Part of that may be led through the Department of Energy, which was given “far-reaching authority” through the 2015 Fixing America’s Surface Transportation (FAST) Act to issue emergency orders “to do whatever [the secretary of energy] thinks is necessary to restore the reliability of the bulk power system,” said Paul Stockton, managing director at consulting firm Sonecon and a former assistant secretary of defense.
“A cyberattack will attract much more direct U.S. government attention” than any prior blackout, he said.
The industry needs to help DOE figure out what those emergency orders should be “so they’re actually helpful to you in protecting and restoring grid reliability instead of being in the way or worse,” he said.
Companies expressed reservations that too much transparency can be a hindrance.
“Once you identify a cascading risk, how in an open stakeholder process do we get this risk mitigated without giving an adversary a blueprint of how to take down the network?” asked David Roop, director of electric transmission operations and reliability for Dominion Energy.
“There are so many things now that we’re at risk with that many of us don’t understand. It’s hard because too much transparency can create more vulnerability for us, more risk,” Southern Co. Vice President of Transmission Katherine Prewitt said. “I think we just have to talk about it and decide. We’re going to get it wrong sometimes, but we’re going to get it right sometimes too.”
“As far as anything that is public, we work very closely on what are the appropriate questions to ask, what we’re willing to put out publicly,” said Laura Ritter, lead security policy adviser for Exelon. “It’s not that utilities don’t want to share, but there is a limit at the point of you’re just giving information now to the adversary.”
Gas-Electric Coordination
With PJM’s generation fleet quickly transitioning to flexible, more responsive gas-fired units, fuel security has been a persistent issue. Gas is plentiful and relatively cheap, but it must be transported through pipelines that can’t always deliver enough fuel for generators when heating demand is high.
“When we’re in a heavy winter-weather event, and we have a lot of operational flow orders on the gas system, that’s a critical time. Should we be operating differently? Should we look at conservative operations in certain circumstances?” PJM CEO Andy Ott asked in his opening remarks.
“We need to look at … what happens when a compressor station goes out on a pipeline, what happens [when] a pipeline itself goes out, how quickly do we lose the fuel source, how quickly do we lose a generator from an operational perspective,” he said. “Do we look at operating reserves? Do we need to deploy spinning reserves differently to make up for those types of events?”
Richard Kruse, vice president of gas pipeline company Enbridge, said the issue is more basic than that.
“Currently, electricity to a significant degree is using capacity that is released from primary customers and, as such, until it’s scheduled, it’s interruptible,” he said, adding that generation units can account for up to a third of Enbridge’s pipeline capacity during nonpeak periods.
“What keeps me up at night is those days when it gets cold and our traditional firm customers are using their capacity as they’re entitled to and [generating units are] forced off. That can happen … from weather conditions very quickly,” he said. “In terms of giving PJM any assurance that tomorrow — before the [capacity-use] nominations come in — we can guarantee that this power generation will be able to run is beyond our knowledge base. It will depend on how that generator contracts. It will depend on where he’s sourcing his gas. And it will depend into how he fits into a queue that’s deemed very complicated.”
Fixing the issue “will require infrastructure, and that’s a big challenge,” he said, because the industry requires firm contracts to build new pipelines. He noted the difficulties his company faced in its efforts to build in New England.
“We have been unable to navigate the state policies about who can and who cannot contract for pipeline capacity,” he said. “If you have [firm] customers, we have proven with time you can navigate those waters. Without customers, you don’t get to first base.”
The inability to expand New England’s pipelines has left the region in a “precarious situation,” ISO-NE Director of Operations John Norden acknowledged.
“In the winter, it’s very difficult for generators to rely on gas that they don’t hold firm capacity rights to on the pipeline infrastructure, so New England is highly dependent upon liquified natural gas that comes from the Middle East — [which is] not exactly the best place to be relying upon for fuel supply — and from South America.”
Cost-Effective Construction
Transmission planners have long had to balance the desire to enhance reliability while limiting the impact of additional infrastructure on the public.
Utilities all have unique situations and demands to address, so “one of the things we got to make sure we don’t do is over-engineer our solutions,” Prewitt said. “If we over-engineer our solutions, we won’t get the result that we’re hoping that we’ll get in the end.”
Rob Manning with the Electric Power Research Institute touted the value of technology to solve problems.
“There are ways to increase our throughput. There are ways to reduce our footprint. There are options that we have for how we build and where we build and if we build that are technological solutions that we’ve got to explore,” he said.
Ott and Stockton called for “making critical facilities less critical” by building redundancies such as alternative transmission paths, but transmission representatives noted the tension that creates with the public.
“I don’t know that the general public always understands what it is that they’re getting” when a line is built in a new location, Prewitt said. “When we utilize a right of way that’s already there, we increase our risk. We have one circuit today, and we put two in tomorrow. A tornado comes through, and that creates a challenge.”
Ralph LaRossa, who heads Public Service Enterprise Group’s merchant generation arm, said the crews Public Service Electric and Gas sent to Florida to help with Hurricane Irma recovery have reported that concrete transmission poles were a “big winner.” He praised Florida Power & Light’s response but acknowledged “a lot of money was spent” because much of FPL’s transmission system is underground.
“How do you do that in a cost-effective manner and not burden the customer with all of that?” he asked.
Overlap Exists, but Implementation Key
Despite the concerns, most panelists acknowledged the value of the regional perspective provided by RTOs and ISOs.
“As we’ve been in PJM, it’s been very important to us because it’s given us more surety of supply in extreme events at a lower cost by being in a broader footprint,” Dominion’s Roop said. “As a vertically integrated utility that didn’t have to deal with it, you could just do your thing a whole lot easier, so [RTO membership] does have some constraints. But I think those constraints are minimal compared to the benefits you get out.”
LaRossa said the issue is knowing where to draw the line.
“There are some things that are naturally market-driven and there are other things that are naturally regulated. I think as we have matured as an industry, we’ve mixed that a little bit. And we just need to figure out where the right balance is for everybody,” he said.
“Although the methodology is different from organization to organization or government to private sector, I think there’s a lot more overlap in how we approach these things than there are differences. The hard part is trying to identify where those overlaps are and how they could be extrapolated and used on a wider scale,” said Jonathon Monken, PJM’s senior director of system resiliency and strategic coordination.
Mountain West Transmission Group said Friday it has completed initial discussions about RTO membership with SPP’s management team and will begin public negotiations through its stakeholder process.
The conversations began shortly after Mountain West, a coalition of 10 utilities primarily serving Colorado, Wyoming and Nebraska, announced its intentions in January to join SPP. In a press release, Mountain West said it had determined that membership in the RTO could reduce customer costs and make more efficient use of its members’ transmission and generation assets.
Negotiations have reached the point where “[we] believe it is now appropriate to take our potential membership proposal to all SPP stakeholders,” Steve Beuning, Xcel Energy’s director of market operations, said in a statement on behalf of Mountain West.
SPP COO Carl Monroe said he was pleased Mountain West’s members had decided to proceed into the RTO’s stakeholder process. The next steps will include stakeholder, board and regulatory approvals, and revisions to SPP’s governing documents and processes, he said.
This will “ensure the people, technology and procedures are in place to ensure a smooth transition to [SPP] and our wholesale electricity market,” Monroe said. “We look forward to continuing our work with [Mountain West] … and providing them and their customers the value our members in the east have received for many years.”
A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. The utilities’ desire to eliminate pancaked transmission and participate in a modern market design started the group’s dialogue about RTO membership.
Representatives from the two organizations will review their work and next steps with SPP’s 95 members. They expect a months-long process for stakeholders to approve changes necessary to add new members. SPP took the same steps when it added the Integrated System in 2015 and Nebraska utilities in 2009.
The meetings will be held Oct. 13 in Denver and Oct. 16 in Little Rock, Ark. Registration will be available on SPP’s website by Sept. 29.
Mountain West has said it hopes to present a recommendation to SPP’s Board of Directors in January. The organizations could file with FERC in mid-2018, with full integration as soon as late 2019.
The Colorado Public Utilities Commission, which has regulatory jurisdiction over some Mountain West participants, has held two public information sessions on the proposal. (See SPP, Peak Reliability Pitch RC Services for Mountain West.) A third meeting scheduled for Oct. 20 in Denver will focus on governance, transmission planning, cost allocation and regulatory filings.
Mountain West’s 10 utilities — Basin Electric Power Cooperative, based in Bismarck, N.D.; Black Hills Energy’s utilities in Colorado, South Dakota and Wyoming; Colorado Springs Utilities; Platte River Power Authority in Fort Collins, Colo.; Public Service Company of Colorado, an Xcel operating company based in Denver; Tri-State Generation and Transmission Association, in Westminster, Colo.; and the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage (CRSP) Project — serve about 6.4 million customers and own 16,000 miles of transmission.
“While Mountain West remains optimistic that an RTO would benefit its entire membership, each Mountain West participant will ultimately need to individually evaluate whether potential membership benefits its customers,” the group said. “Each will pursue regulatory or governing body approval, as applicable.”
FERC last week approved CAISO’s request to be relieved of its requirement to develop a conceptual statewide plan as part of its regional transmission planning process. The commission at its meeting also ruled on two disputes regarding the Western Energy Crisis of 2000/01.
The commission approved CAISO’s request, made in June, to eliminate the need for the statewide conceptual plan, which the ISO says is obsolete because of federal planning processes. (See CAISO Seeks to Drop Outdated Planning Role.) CAISO has developed the plan each year since 2010 as part of its lead role in the California Transmission Planning Group (CTPG). But the implementation of FERC Order 1000 superseded the CTPG, which is no longer operating.
“We agree with CAISO that the implementation of Order No. 1000’s regional transmission planning and interregional transmission coordination requirements have supplanted the benefits of developing a conceptual statewide plan, and that the tariff provisions to develop a conceptual statewide plan are now redundant and therefore unnecessary,” FERC said in its order.
The commission last week also approved an uncontested settlement filed last December between certain California parties and MPS Merchant Services, the successor to Aquila Merchant Services and Aquila Power. “The settlement resolves claims arising from events and transactions in the Western energy markets during the period of Jan. 1, 2000, through June 20, 2001, as they relate to MPS,” FERC said in the order.
Separately, FERC approved another energy crisis settlement between San Diego Gas & Electric and sellers of energy and ancillary services in CAISO and the now-defunct California Power Exchange.
AUSTIN, Texas — Vistra Energy’s acknowledgement last month that it may retire some of its coal fleet sparked a lively debate among speakers at Infocast’s Texas Renewable Energy Summit last week.
Like other coal and nuclear units in ERCOT, the plants operated by Luminant, Vistra’s generating division, are often priced out of a market in which cheap gas has sent energy prices to record lows.
Luminant’s three 1970s-era coal-fired plants — Big Brown, Martin Lake and Monticello, which total almost 5.3 GW of capacity — have capacity factors ranging from 44 to 59%, leading to speculation that some or all the plants may be retired. During the company’s second-quarter call in early August, CEO Curt Morgan told analysts, “Any decisions related to optimization of Luminant’s generation fleet will likely be made in the fourth quarter.”
Neel Mitra, director of utilities and power research for Tudor, Pickering, Holt & Co., a Houston-based investment and merchant bank focused on the energy industry, told the conference Monday he expects Vistra will retire two of the three plants.
Others weren’t as bearish on ERCOT’s coal fleet.
“We’ve been hearing rumors about coal plant retirements for several years now,” said Morgan Stanley Capital’s Clayton Greer, who sits on ERCOT’s Technical Advisory Committee.
Tim Wang, a director with Filsinger Energy Partners, said the outlook has changed for fossil plants with the Clean Power Plan’s future in doubt.
“Prior to the 2016 elections, I thought it was definite we would see retirements fairly soon, but that’s gone away,” Wang said. “Really now, it’s just about economics. If you look at [Vistra’s] portfolio, you say, ‘If they retire those plants, what will they be left with?’
“If I were them, and a rational player, I’d say, ‘We need to acquire gas plants. We need to acquire gas before their valuations go up.’ Otherwise, you’re helping your competitors.”
Indeed. In recent months, Vistra has completed the purchase of a 1,054-MW combined cycle combustion turbine in Odessa and acquired two other combined cycle plants representing another 3 GW of capacity. Luminant now has almost as much gas capacity (7.5 GW) as it does coal (8 GW). All told, Luminant has about 18 GW of capacity.
Healthy Reserve Margins
Mitra’s comments came while he discussed ERCOT’s healthy reserve margins. The ISO currently has an 18.9% reserve margin, which it expects to drop to 16.8% in 2022, based on new builds and potential retirements. In its most recent Seasonal Assessment of Resource Adequacy, the ISO said it has nearly 86 GW of capacity available this winter, more than enough to meet a predicted peak demand of just more than 56 GW. (See “Seasonal Forecasts: Sufficient Generation for Fall, Winter,” ERCOT Briefs.)
ERCOT has more than 68.7 GW of thermal capacity, but wind energy now accounts for almost 20 GW of capacity and solar for another 944 MW. The continued influx of renewable resources has helped push inefficient fossil plants into seasonal or mothball status, as they are unable to compete with zero-marginal-cost wind during off-peak hours.
Only two coal plants in the ERCOT market are covering their fixed costs on an around-the-clock open-price basis, Mitra said, pointing to Luminant’s Sandow 5 unit east of Austin and its twin 800-MW units at Oak Grove, north of Houston. The units came online in 2009 and 2010.
Beth Garza of Potomac Economics, ERCOT’s Independent Market Monitor, said there is a lot of existing generation that is not recovering its costs.
“We’re in a sweet spot right now with lots of reserve and very low prices,” she said. “At some point, that has to change. We will see retirements and mothballs. The fear is, we’ll see lots of that happening at once and upsetting that balance.”
Mitra said he believes Vistra has been discussing an “orderly retirement plan” with ERCOT. However, an ISO spokesperson would only say the retirement process “officially begins” when a generation owner sends a notice of suspension of operations to ERCOT. Luminant declined to comment beyond Morgan’s statement.
Reliability Impact
“The regulators will have to start worrying about [retirements] relatively soon,” Mitra warned. He suggested improvements could be made to ERCOT’s operating reserve demand curve, which creates a real-time price adder reflecting the value of available reserves.
“In concept, it works pretty great. But in reality, you want to have increases to scarcity pricing in the summer, and we haven’t had that yet,” Mitra said. “[The ORDC] has to be a little bit more aggressive to incent new generation or coal plants to stay online. There has to be some sort of a reliability scare, but we haven’t really had one since 2011.”
Even if all three Vistra plants are retired, Mitra noted, it will only drop ERCOT’s reserve margin to 9.5%. He expects the market to tighten soon, given his belief that Vistra will retire coal generation, but only for on-peak hours. Wind generation will “continue to flood the ERCOT market during off-peak hours,” Mitra said.
Vistra emerged from Energy Future Holdings’ Chapter 11 bankruptcy in November as a tax-free spinoff. Long known as Texas Utilities and then TXU, the company was acquired in 2007 by EFH and its consortium of private-equity investors through a leveraged buyout. The deal went sour when energy prices collapsed, and EFH filed for bankruptcy in April 2014.
FERC on Wednesday accepted SPP’s proposed Tariff revisions related to shortage pricing, rebuffing the protest of one key stakeholder.
Submitted in response to FERC Order 825, SPP’s changes removed ramp-sharing obligations and other Tariff provisions that prevent shortages caused by insufficient ramp capability from triggering shortage pricing. The RTO also removed certain constraints and their associated violation relaxation limits (ER17-772).
But the commission also rejected SPP’s proposed provisions creating a demand curve designed to set scarcity prices for energy shortages, ruling that the changes fell outside the scope of Order 825. FERC said the order did not require SPP to change its shortage pricing levels, only that it initiate procedures when a shortage is indicated.
The commission provided SPP 30 days to submit a compliance filing that either removes the demand curve provisions or explains how they comply with Order 825. It also directed removal of SPP’s suggested definition of “scarcity pricing,” allowing the RTO to propose a change or modify shortage-pricing levels in a separate Section 205 filing.
Order 825 requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. SPP was one of several RTOs that already settles those transactions in five-minute intervals. (See FERC Issues 1st RTO Price Formation Reforms.)
Golden Spread Electric Cooperative protested SPP’s changes, contending that the filing did not fully comply with Order 825 because it did not address the RTO’s practice of committing additional capacity through the reliability unit commitment (RUC) process or through manual operations that can prevent potential scarcity pricing events. The co-op said this practice is not transparent, creating uplift charges and a disincentive to make efficient operations and investment decisions.
Golden Spread argued that SPP should procure fewer resources through the RUC and manual processes, and instead rely on the submission of competitive offer curves in the day-ahead and real-time markets. It asked FERC to require that SPP eliminate RUC and manual commitment practices that mask scarcity pricing conditions and address any commitment outside of the normal markets.
The commission disagreed, dismissing Golden Spread’s concerns as being outside the proceeding’s scope. FERC noted Order 825 did not require the co-op’s suggested modifications to RUC or manual commitment processes, but it agreed Golden Spread “has raised an important issue that SPP should consider exploring through its stakeholder process.”
Zero Uplift Charges for Resources Dispatched to Zero
The commission also approved SPP’s proposal to exempt generating resources dispatched to zero from paying uplift charges, ruling the plan is consistent with the RTO’s existing provisions that ensure de-committed resources are not charged for uplift (ER17-520).
FERC found that resources dispatched to zero at SPP’s instruction make identical energy contributions to the real-time market as de-committed resources. “Thus, it is reasonable that both be treated the same with regard to uplift charges,” the commission said.
SPP member Golden Spread supported the Tariff revisions but asked the commission to require further changes to allow quick-start resources to voluntarily de-commit and buy back their day-ahead position from the real-time market without being assessed uplift charges, or adapt the security constrained economic dispatch software to accommodate those resources’ unique nature.
FERC rejected that request, saying it was beyond the scope of the Section 205 proceeding.
ST. PAUL, Minn. — Three days shy of summer’s end, MISO’s staff and Independent Market Monitor convened to commend RTO operations personnel for a successful season.
Monitor David Patton said MISO’s real-time operations did a fine job of navigating summer’s Hurricane Harvey, Tropical Storm Cindy, the Aug. 21 solar eclipse and short bursts of high temperatures.
“We haven’t had any meteorites, but almost everything else under the sun,” Director Paul Bonavia joked during the summer operations presentation at the Sept. 19 meeting of the Markets Committee of the Board of Directors.
Vice President of System Operations Todd Ramey said MISO used its new hurricane action plan for the first time, maintaining communication and receiving updates from local operators near the storm. MISO held realistic hurricane simulations with MISO South operators during May and June, a first for the RTO, which ordinarily holds less-detailed hurricane drills.
“Hurricane Harvey proved to be mostly a rain and major flooding event. It did have some impact on transmission in the Eastern Texas area … but we maintained reliability throughout,” Ramey said.
Patton said despite occasional weather outbursts, the summer was “a little bit less eventful than past summers.” He called the 120.6-GW summer peak load on July 20 “very manageable” and “well below” the 125-GW forecast. A 6% rise in natural gas prices from last summer was offset by a 5% decrease in real-time energy prices due to mild temperatures and lower-than-expected average load.
The Monitor commended MISO’s ability to not declare any maximum generation events during the summer despite multiple operating reserve shortages from contingencies. He also praised MISO for producing more accurate day-ahead forecasts and more complete resource commitments when compared to last year. He told the board that while severe weather during June led to islanding in MISO, the RTO “was able to model the units in the islands and send appropriate prices during the events.”
Patton also said MISO managed real-time congestion costs effectively during the summer, as they fell from $463.5 million last summer to $334.5 million this summer, in part because of moderate load.
Divergence on ELMP
But the Monitor differed with MISO on the efficacy of the RTO’s extended locational marginal price (ELMP) program, which this spring was expanded to include resources with one-hour start-up times. The program was previously available only to 10-minute fast-start resources.
The ELMP effort is not fulfilling its potential, resulting in only a 29-cents/MWh price increase in the real-time energy market since its expansion in spring, Patton said. The Monitor has long called on the RTO to expand ELMP to allow all generators with two-hour minimum run times to set prices.
MISO said the Monitor’s price-setting expansion would not be worth the expensive software change, but Patton said his change would have increased LMPs by $7/MWh, reflecting the true cost of using peaking units.
CEO John Bear said MISO only expected modest price impacts using ELMP, and the program has already exceeded the RTO’s expectations.
Ramey pointed out that MISO’s ELMP was judged a success in the recent U.S. Energy Department electricity markets report.
“I think FERC and others will be very interested in expanding this,” said Patton, who called ISO-NE’s price formation efforts “a Ferrari” in comparison.
FOLSOM, Calif. — CAISO has launched what will be a years-long initiative to develop a program to pay storage resources to absorb excess renewable generation from the grid and make the energy available later, creating a new profit stream strongly desired by energy storage companies.
Storage companies such as Tesla have been urging CAISO to develop the new product as way to incentivize clean energy and reduce solar curtailments. During certain times of day, large solar surpluses on the ISO’s system can sometimes produce negative wholesale electricity prices and require curtailing output that could be stored and used at other times.
The load-shifting product will be the focus of the third phase of the ISO’s Energy Storage and Distributed Energy Resources (ESDER) program. CAISO changed the focus of the initiative to a behind-the-meter load-shifting product rather than the excess load-consumption product that had previously been discussed.
CAISO Manager of Infrastructure and Regulatory Policy John Goodin warned about a potential inherent flaw in developing an excess load consumption product.
“You can set up an incentive to where it is profitable just to waste energy,” Goodin said during a briefing of the ISO’s Board of Governors.
A load-consumption product could incentivize buyers to waste energy when a wholesale negative payment is higher than the retail payment. The purpose of the load-shifting product, however, is to incentivize productive use of excess renewable generation, Goodin said.
“That is good for the economy, it is good for the environment and seems like sound public policy,” he said, adding that the storage community supports the load-shifting concept. Load-shifting resources — such as a battery — could consume load when prices are negative, and the stored energy could be released behind the meter for demand management or sent to the ISO system, among other possibilities, he said.
The board last month approved a set of market rule changes that comprised phase two of the ESDER initiative, developed during a year-long process. (See New CAISO Rules Spell Increased DER Role.) That package will be sent to FERC for approval.
During the ESDER 2 initiative, Tesla and other storage companies urged CAISO to develop a new distributed energy resource product that would pay storage for absorbing excess solar generation, but the ISO declined at the time, saying more information was needed. (See Storage Advocates Urge CAISO on DR Product.)
Tesla and other energy storage companies are helping CAISO to develop a load-shifting product | Tesla
To consider the specifics of the new product, the ISO has held four meetings with storage stakeholders, including the California Energy Storage Alliance (CESA), Stem, Tesla and Green Charge. Stakeholders are finalizing the desired features of the product, and the ISO will establish working groups to fill in the details. CAISO is identifying gaps in its Tariff and current resource modeling capabilities to aid in the effort. Implementation is targeted for 2019.
CESA Director of Policy and Regulatory Affairs Alex Morris told the board that CAISO staff have over the past month worked diligently with the storage community on the proposal. “From our point of view, this is going to provide very helpful service to the CAISO, while also beneficially shifting loads,” Morris said, adding that he is hoping for rapid implementation.
“There really should be a special urgency to this product because there currently isn’t a market participation pathway for that type of behind-the-meter resource,” Morris said.
The board asked a few questions about the new product, such as how pricing would work, but did not take any votes as the proposal is in its early stages. The initiative would also require a round of comment and approval by FERC after an extensive stakeholder process that will include participation by the California Public Utilities Commission.
ST. PAUL, Minn. — MISO plans to recommend that its Board of Directors approve 343 new projects estimated at $2.6 billion as part of the RTO’s annual transmission plan.
This year’s draft project round-up comes in 40 projects short of MTEP 16 but costs about the same, directors and stakeholders learned at a Sept. 19 meeting of the board’s System Planning Committee.
MISO Vice President of System Planning Jennifer Curran said the top 10 priciest projects in MTEP 17, ranging from $26 million to $149 million, are spread “fairly evenly” across the footprint, with three in Michigan, two each in Louisiana and Wisconsin, and one each in Iowa, Arkansas and eastern Texas.
While the RTO included only half of those projects for baseline reliability reasons, the Iowa and Wisconsin projects both originated from generator interconnection requests, showing that interconnections are increasingly becoming major transmission projects themselves, Curran said. MTEP 17’s most expensive project, a new $149 million 500-kV line from Hot Springs to Happy Valley in Arkansas, is meant to relieve reoccurring thermal overloads.
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Curran said just one MTEP 17 contender may qualify as a market efficiency project. The $129.7 million project involves construction of a new substation in eastern Texas equipped with a 500/230-kV transformer. The facility would accommodate a new 500-kV line running from Hartburg, Texas, as well as a reconfiguration of the existing Sabine-McFadden and Sabine-Nederland 230-kV lines to fully relieve area congestion and reduce the amount of voltage and local reliability make-whole payments needed in the West of the Atchafalaya Basin load pocket. Some MISO stakeholders this month complained about what they perceived as late-stage modeling changes to the project. (See Late Changes to Texas Project Frustrate MISO Participants.)
Curran said the project will undergo additional stakeholder review before coming back for board approval in early December.
No Tx Coming for North-South Constraint
MISO’s collection of MTEP 17 studies this year included a footprint diversity study, an extra analysis specifically designed to identify viable transmission projects to connect the RTO’s Midwest region with MISO South. However, Curran said not one of the study’s 35 potential projects could pass the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits.
“The physical congestion, while it exists, isn’t enough to justify a fairly expensive transmission project. I think there are other benefits that aren’t being considered, but that’s the nature of this process,” Curran said.
Curran said that over the course of the study, MISO “learned a lot about the nature of the flows” near the North-South transfer constraint.
FERC on Wednesday approved negotiated rate authority for a proposed 515-mile transmission project intended to carry renewable output from Arizona and New Mexico to “key interconnections” capable of serving markets farther west.
In its decision, the commission reissued and revised the rate authority it had initially granted the SunZia transmission project in 2011 (ER17-522).
As proposed, the SunZia project consists of up to two 500-kV lines in Arizona and New Mexico, running more than 500 miles to high-voltage interconnections within those states. The first phase would include an AC line with 1,500 MW of capacity, and a second phase consisting of another AC circuit with the same rating or a 3,000-MW DC line. The project’s current owners are SouthWestern Power Group, ECP SunZia, Shell WindEnergy and Tuscon Electric.
After originally obtaining rate authority in 2011, SunZia Transmission entered talks to sign on First Wind Energy as an anchor customer for up to 1,500 MW of capacity on the line. First Wind was subsequently acquired by SunEdison, which last year declared bankruptcy.
That prompted SunZia to apply for revised negotiated rate authority as transmission provider on behalf of its merchant owners. The company also sought permission to enter into an agreement with an anchor customer for up to 100% of the project’s merchant capacity. Half of the capacity of the line was to be allocated to one or more anchor customers, and the remainder made available through open season auctions. Anticipated development costs up to the beginning of construction are estimated to be as high as $75 million.
SunZia had to demonstrate that service on the project would not show preference to any particular bidder. The company held an open solicitation for the first phase of the project, selecting wind developer Pattern Energy Group as the preferred customer. SunZia said it expects Pattern will become a co-owner of the line, and majority merchant owners would become co-owners of the Pattern project.
“We find here that SunZia Transmission’s selection process was transparent and not preferential neither toward Pattern Development nor unduly discriminatory against other potential customers,” FERC said. “Notably, SunZia Transmission has demonstrated that all interested parties were treated comparably, provided with the same information and given opportunities to discuss the Project with SunZia Transmission.”
FERC in 2013 changed its approach to evaluating applications for rate authority, retaining its current “four factor” analysis, but said that anchor customers could be allocated 100% of the capacity and could be an affiliate of the transmission developer.
SunZia said the line is “likely to serve renewable resources predominantly. At all times, the merchant capacity and interconnections have been available without preference for any particular kind of resource.”
The company is targeting the first quarter of 2018 to commence construction on the first line, which is expected to go into service in 2020. The U.S. Bureau of Land Management last year granted a right of way for the project.
