New England Power Pool stakeholders are this week discussing potential changes to ISO–NE wholesale energy markets that would include interim generator compensation to improve winter fuel security and the introduction of a multi-day-ahead market (M-DAM).
ISO-NE Principal Analyst Andrew Gillespie will on Wednesday present the NEPOOL Markets Committee conceptual details as well as a timeline for a fuel security FERC filing by Nov. 15, in line with the RTO’s January request for a four-month extension to file a plan, currently pending before the commission (EL18-182).
In the motion for an extension, ISO-NE said, “New England’s winter energy issues are fundamentally an energy supply problem, not a generation capacity shortfall problem,” but the presentation to the MC acknowledges the RTO has “heard a number of questions and concerns about the length of the market horizon, primarily how this may not align with participants’ hedging strategies … “
ISO-NE filed the rule revisions after the commission last July denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022.
Interim Compensation
Several NEPOOL stakeholders have proposed alternatives to the RTO’s market mechanisms regarding interim compensation treatment to improve fuel security.
David Cavanaugh, vice president of regulatory and market affairs for energy services firm Energy New England (ENE), was slated Tuesday to present an amendment to the RTO’s proposed Tariff language. The outcome of the planned discussion and vote, the first of a two-day MC, will not be revealed until NEPOOL posts the meeting minutes.
ENE argues the RTO’s proposal “far exceeds” its stated goal of retaining resources for fuel security reliability and preventing uneconomic retirement bids and its “resource eligibility is too broad and extends beyond target resources.”
The company instead recommends modifying ISO-NE’s proposal to limit compensation to oil, natural gas, demand response and electric storage resources.
“Compensation should be limited to resources capable of improving winter energy security by providing incremental reliability benefits,” ENE said. The RTO estimates costs for the interim program will exceed those of the last winter reliability program by $100 million, a figure ENE says drops to around $51 million under its amendment.
Winter reliability program costs were capped in advance and ranged from $30 million to $70 million annually. The RTO replaced that program last June with the Pay-for-Performance program, which is designed to fund performance bonuses mostly through penalties on nonperforming resources and not directly by customers. (See NEPOOL Debates Fuel Security, Cost Allocation.)
ISO-NE CEO Gordon van Welie last month said energy security risks “could become a year-round concern” as the grid transitions to distributed and renewable generation and “eventually nearly all resources in the fleet will have some energy limitations.” (See ISO-NE Chief Sees ‘Year-round’ Energy Risks Coming.)
The Pilgrim Nuclear Power Station on Cape Cod is scheduled to close down permanently later this spring, increasing New England’s fuel security risks. | Entergy
Abigail Krich, president of Boreas Renewables, was to present on behalf of the Union of Concerned Scientists a proposal guaranteeing that energy actually provided would receive the same compensation as inventoried energy.
Forward Capacity Auction 13 last month awarded payments to new renewable energy resources and also made ISO-NE the first grid operator to implement a market-based mechanism to accommodate state-sponsored resources. State-sponsored Vineyard Wind won a 54-MW capacity obligation from a retiring resource in the substitution auction. (See ISO-NE Completes FCA 13 Despite Controversy.)
Count the Days
The Massachusetts attorney general’s office commissioned London Economics International (LEI) to prepare an alternative to the RTO’s M-DAM proposal, which LEI found “conceptually and operationally complex” and would “require substantial administrative costs.”
Complete revamping of the day-ahead market (DAM) into M-DAM is an unproven mechanism and may not meet all of the RTO’s goals, LEI concluded, proposing instead a Forward Stored Energy Reserve ancillary service with updated technical methods to provide parameter values for the forward capacity market.
The advisory firm contends that while the RTO’s proposal might increase revenues for some power plants and prevent inefficient retirement, the resulting higher energy prices may lower net cost of new entry, which would suppress capacity market prices and potentially accelerate retirement.
FSER Timeframe: Forward stored energy reserve timeframe should balance ISO-NE’s ability to forecast its need for reserves versus the time it takes to arrange fuel or other necessary inputs to stored energy. | London Economics
LEI said its proposal meets the ISO-NE’s needs and Massachusetts’ goals of incorporating market signals, supporting operational visibility and helping prevent inefficient retirement, while its blend of old and new components creates a “solid foundation for winter energy reliability.”
Calpine is scheduled to present again its case for a Forward Enhanced Reserves Market (FERM), with Senior Analyst for Government and Regulatory Affairs Rebecca Hunter arguing all problems that fall within a planning horizon time frame are left unsolved without a forward price signal. (See “Market Reaction,” New England Talks Energy Security, Public Policy.)
FERM would have no offer cap, but awards to resources with capacity supply obligations would be incremental to the clearing price. In addition, FERM resources would have daily day-ahead must-offer obligations in winter months only, and the construct would allow participation from resources without a supply obligation, such as energy-only resources that only plan to be available for peak days in the winter.
AUSTIN, Texas — Infocast’s annual ERCOT Market Summit last week attracted more than 150 policymakers with utility, solar, wind and other energy executives to explore potential solutions and opportunities in Texas.
Attendees participated in discussions on an expected surge of solar capacity, living with ERCOT’s shrinking reserve margin, the benefits of energy storage and the market’s transmission needs.
Resmi Surendran, Shell Energy North America’s senior director of regulatory policy, keynoted the three-day event by saying the rising forward curves reflect the increased risk ERCOT faces this summer. The grid operator’s reserve margin has dropped to 7.4%, reflecting a lack of new baseload generation additions and the recent loss of yet another aging coal plant. (See ERCOT Says Emergency Conditions this Summer ‘Likely’.)
Noting the 2019 forwards are $50/MWh below 2018, Surendran said, “It may be skepticism, because so much wind is coming, or the possibility of a lot of demand response or because of the ORDC [operating reserve demand curve] changes, or just waiting for the [March 5 seasonal resource assessment] to come out and see how tight the summer will be.
“The only thing we can really say is the capacity will be really tight, and any small change can swing it one way or the other,” she said.
Speaking on a panel taking a long-term view of ERCOT’s wholesale market, Thompson & Knight’s Katie Coleman, who represents industrial customers, disputed the notion that the market “got lucky” last summer. Operating with an 11% reserve margin, ERCOT met 14 demand peaks above the previous record without resorting to emergency measures.
“My clients don’t think we got lucky. We think the market performed the way it was supposed to perform,” she said. “You have a market with a ton of risk, people will show up. When you have the type of financial risk we had last summer, it really motivates people. I think you will also see that this summer, and people should start adjusting their expectations.”
Coleman said “empirical evidence” revealed customers “were doing things they hadn’t done before” last summer to reduce their loads and help the market meet demand. “It’s a misconception that a low planning reserve margin corresponds to higher real-time prices,” she said. “Barring contingencies, you’re going to see good performance again this summer, and you may or may not see high prices in real time.”
“You’re just going to get more continued price volatility around wind because of the renewables buildout,” said Hugh Byrd, Citibank managing director for ERCOT/West power trading. “We’ll get to the point where we almost need renewable generation to meet peak demand, which will increase price volatility.”
“Wind penetration has created impacts on pricing, where it’s hard for baseload generation to stay active in this market,” said the Lower Colorado River Authority’s John Dumas, vice president of market operations.
Dumas said changes to the ORDC’s calculation prescribed by the Public Utility Commission of Texas will increase scarcity pricing sooner, but he was doubtful those modifications will have a “dramatic impact” on unit commitment decisions this summer. (See Texas PUC Responds to Shrinking Reserve Margin.)
“[They’re] not going to be enough to drive a combined cycle [plant]. They plan to be online for the peak anyway,” Dumas said. “Potentially, you might commit some gas turbines sooner.”
“We’re moving away from a world where you can count every megawatt out there,” Coleman said. “You have to trust the market.”
Panel Debates ERCOT’s Competitive Market
Bill Barnes, NRG Energy’s director of regulatory affairs, also urged attendees to place their faith in the ERCOT market. Saying he didn’t want to reflect on the market’s shrinking reserve margin, he trained his focus on what he called a “success story.”
“The ERCOT market is really the envy of the rest of the country and the world,” Barnes said. “It should not be a surprise that we have low reserve margins. We’ve had six to seven years of low pricing; pricing drives waves of exit and investment. We’ve seen some investment funded by subsidies [the Competitive Renewable Energy Zones], and exit driven by these same subsidies and some by low natural gas prices. When you have low prices for such a long period of time, you will have financial discipline.
“It’s time for the market … to support that next wave of investment in our energy supply, and it should not be tempted to intervene with out-of-market actions or subsidies. [Low reserve margins] should not be a surprise. We’ve known for years … an energy-only construct without a capacity construct always results in lower reserve margins.”
Calpine Director of External Affairs Brandon Whittle countered by pointing out that competitive electric markets “are not the perfect competitive markets we studied in ECON 101, where everything made sense.”
“One of the traits of a perfect competitive market is low barriers to entry and exit,” Whittle said. In ERCOT’s case, he said, that would be the units’ start-up costs, which become sunk costs once the unit is online.
“We’re going to need dispatchable generation to come online. To do that, they have to overcome the barrier to entry,” Whittle said. “The reserve margin will remain uncomfortably low over the next few years, depending on new entrants into this market. There are significant costs to build new generators, so significant that it takes decades to recover those costs.”
In the meantime, Barnes said the probability of an emergency event this summer is “pretty high … probably 90 percent-ish,” and that the market should be prepared.
“That’s how an energy-only market is intended to function. That’s how you increase revenues to incentivize the next wave of investment,” he said. “These events can be well-managed and organized and have very little disruption to consumers. We’re going to get a good sense of what our appetite for the real risk of reliability is. We lived it a little in 2011, but that was a weather event. This is more a lack of supply.”
ERCOT COO Cheryl Mele, sitting alongside Barnes, said, “We would expect to operate effectively.”
One audience member pointed out the only drawback with Barnes’ premise will be the political blowback from rotating outages, driven by constituent complaints.
“Hopefully, ERCOT will help manage any emergency event and explain that voluntary load reduction is not necessarily a bad thing,” Barnes told RTO Insider in response, referring to the grid operator’s emergency response service.
A trio of wind energy developers agreed there was a time and a place for production tax credits, which expire in 2020. With the Dec. 31 deadline to begin construction fast approaching, they debated what to expect in a post-PTC world.
“We’ve had a love-hate relationship with PTCs,” said Tri Global Energy’s Tom Carbone, who expects to see 25 GW of wind energy come online in Texas through 2020. “Today, even without the PTC, [wind] is a very competitive solution. It’s also created somewhat of a perverse market, where you have runs with negative pricing. I’m probably one of the few guys in the room who looks forward to when the PTC is gone.”
“At least two of us are getting our feet wet in national markets. We see how they structure deals in a way they should post-PTC,” Pattern Energy’s Ward Marshall said. “[PTCs] were a necessity. It kind of leveled the playing field. It’s a great story from that standpoint, but I do believe theirs is a valiant death. I think it’s a dip, as we work on structuring on the other side.”
Originally enacted in 1992, the PTC is an inflation-adjusted tax credit of 1.9 cents/kWh for electricity generated by qualified facilities. The credit has been reduced 60% for those facilities that begin construction this year.
“We’re not afraid of a post-PTC world,” Macquarie Capital’s Thomas Houle said. “They served their purpose, and quite well, but we have a cheaper pool of long-term debt available now. It’s amazing how quickly the market adapts to these changes. We’re expecting a nine- to 12-month dip, but we’ll see what happens.”
“If you want to go to a market where they don’t need additional capacity, SPP is the market for you,” said Steubing, the company’s director of origination and structuring, pointing to the RTO’s 30% reserve margin. “ERCOT has a low reserve margin. SPP is the opposite end of the spectrum. … If you’re trying to sell in Texas, you’re selling to people who don’t have a car. In SPP, you’re talking to people with three 2001 Honda Accords. Maybe they will talk to you when one of those breaks down. You’re not going to find super motivated buyers in SPP.”
As Steubing spoke, Enel Green Power North America was announcing a 497-MWsolar project in West Texas, the state’s largest. The day before, food distribution heavyweight Sysco said three solar garden sites in Houston and Dallas were operational. They are part of a 25-MW, 10-year renewable energy agreement with an NRG subsidiary.
ERCOT has more than 43 GW of solar projects in its interconnection queue, but only 5 GW have interconnection agreements. SPP has 26 GW of solar in its queue, according to one count.
“The natural resource, the sun, is fantastic in Texas. We have to start there,” said Brian Whitlatch, AEP Energy Partners’ managing director of energy marketing. “The ERCOT market is one of the best-run RTOs, so it’s a very efficient market and it’s deregulated, so there are lots of buyers on the retail and wholesale side.”
Marc-Alain Behar, ENGIE Solar’s managing director for North America, said the Texas market’s liquidity and its “sophisticated wholesale environment … allows for financial innovation around commercial structures.”
“The first utility-scale solar project with a hedge is going to happen in Texas,” Behar said. “What’s new is the corporate demand for virtual [power purchase agreements], which started three to four years ago and which were mostly taken on by wind, from a price standpoint. Last year, we saw solar taking its share of that market. Here in Texas, we are seeing that the price point of solar being offered to those customers for a 12-year, 15-year PPA is competitive with wind. I see a lot of this continuing, because that demand from corporate customers is still there.”
“We’ve been watching Texas for some time. We thought there would be a tipping point, and I think we saw that last year,” Steubing said. “There were lots of transactions happening, and that’s carried forth in 2019, in Victoria, outside Houston and the greater Dallas area. It’s really exciting to see how solar has been able to avoid the pitfalls of wind and get built outside of the West.”
Is There a Place for Storage in ERCOT?
If solar and wind energy are going to increase their share of the fuel mix, energy storage could play a key role.
John Hall, the Environmental Defense Fund’s associated vice president for clean energy, is working on a comprehensive plan to increase the use of wind, solar, energy efficiency and DR in Texas. He believes the competitive market will play a primary role in driving the state’s clean-energy results.
“ERCOT projects that within the next 10 years, Texas could be on track to achieve 40 to 50% wind and solar capacity on the grid,” Hall said. “Storage is what would make that level of non-emitting capacity not just possible, but practicable. Its ability to address intermittency issues and ensure grid reliability is key to unlocking the potential of these energy resources.”
There are also market realities, Steubing and Behar said.
Steubing said Recurrent has executed on a solar/storage product in California for a 180-MW battery. But, he pointed out, California has a storage mandate, and neighboring states have capacity markets that lend themselves to solar and storage.
“I’m not saying there’s no value to storage, but not when we’ve seen customers motivated in states where they’re obligated to capacity and energy requirements,” he said.
“Between the solar and the wind, there’s a good complementarity which makes the storage proposition more difficult. You can buy cheap wind and cheap solar when you need it,” Behar said. “ERCOT is not the place we see [energy storage] happening.”
FERC last week approved CAISO Tariff changes designed to incorporate generator contingencies and remedial action schemes into its market optimization and congestion pricing methodology (ER19-354).
“The commission accepts CAISO’s filing because we agree with CAISO that its proposal will more closely align market dispatch and prices with actual operations,” FERC wrote. “This will allow prices received by generators to more accurately reflect their contribution to congestion under a dispatch that is secure against generator contingencies. We also agree with CAISO that its proposal will be beneficial by reducing reliance on exceptional dispatch.”
FERC approved CAISO tariff revisions related to generator contingencies and remedial action schemes.
The ISO filed the Tariff revisions in November. It proposed language to clarify its rules on modifying and operating the grid to expressly include generator contingencies and remedial action schemes to deal with the loss of generators. It also proposed adding new components to its marginal cost of congestion formula.
“CAISO states that making several clarifications to existing terminology will improve transparency,” FERC wrote. “In particular, CAISO proposes to add a sentence to the definition of a ‘contingency’ to expressly include ‘potential outages due to remedial action schemes.’”
The ISO proposed similar clarifications to section 27 of its Tariff, which addresses its market and processes.
“CAISO states that these clarifications consist of parentheticals to clarify that remedial action schemes are included in CAISO’s modeling of transmission contingencies,” FERC said.
The ISO also proposed adding a new component to its formula for calculating congestion prices that accounts for generator outages. Currently, the grid operator calculates the marginal cost of congestion based on the “economic effect of additional power at a specific point flowing across a given transmission constraint,” the commission said.
To do so, CAISO multiplies the transmission constraint coefficient by the power transfer distribution factor and its shadow price, FERC noted.
“The power transfer distribution factor is the percentage of a power transfer that flows on a transmission facility as a result of the injection of power at the relevant bus and the withdrawal of power at the reference bus,” the commission said. “CAISO notes that the shadow price is the marginal value of relieving the constraint.”
Under the revised formula, CAISO will calculate the cost of congestion, then subtract the product of the power transfer distribution factor for the relevant generator contingencies and its shadow price, FERC said.
“CAISO contends that its proposal will ensure that its preventative modeling and market prices reflect grid realities. CAISO argues that the proposed revisions will also decrease out-of-market actions and the need for operators to manually monitor remedial action schemes and generator contingencies,” the commission said. “In addition, CAISO asserts that its proposal will appropriately price each generator’s contribution to congestion in the markets.”
The Sacramento Municipal Utility District (SMUD) said Friday it is canceling a 500-kV transmission line project it was developing in conjunction with the Western Area Power Administration because the project had proven too expensive and was no longer needed.
The Colusa-Sutter Transmission Line Project (CoSu) was intended to increase SMUD’s ability to import hydroelectric power from the Pacific Northwest and export from the Sacramento area. (See WAPA, SMUD Extend Scoping Period for Colusa-Sutter Project.) It would have created a new link between the California-Oregon Transmission Project (COTP) and SMUD and WAPA facilities on the east side of the Sacramento Valley.
“A recent California Energy Commission study makes the case for projects like this that enhance transmission capability to import valuable out-of-state renewable resources for California to meet its 50% renewable energy goals by 2030,” WAPA and SMUD said in a statement in 2017. That study pointed out that a shortage of available transfer capacity on the California-Oregon Intertie would inhibit California’s ability to import additional carbon-free energy from the Northwest.
The proposed Colusa-Sutter transmission project was intended to improve SMUD’s access to Pacific Northwest renewable resources via the California-Oregon Transmission Project. | WAPA
In a news release Friday, however, SMUD said “it was determined that the project is too costly.”
As planning for the project commenced, federal power marketing agency WAPA said its existing transmission facilities did not have enough capacity to meet SMUD’s increasing need for energy.
SMUD said that the project’s initial phase, meant to evaluate environmental impacts and conduct preliminary engineering, had shown the estimated $245 million price tag had increased by more than $100 million and could end up costing much more.
The utility said its decision to join CAISO’s Western Energy Imbalance Market starting in April “will provide lower-cost access to a broader regional market,” reducing the need for transfers to and from the Pacific Northwest.
SMUD and WAPA have been working on the CoSu project since the utility’s board of directors approved a development agreement in December 2014. The new line would have connected the COTP system in Colusa County with the Central Valley Project system in Sutter County, improving access to renewable energy generated in the Northwest.
SMUD, headquartered in Sacramento, canceled a 500-kV transmission line project it was planning in conjunction with WAPA.
Since the project’s inception, the need for it has diminished, SMUD said.
“Since SMUD started planning the project, the development of SMUD’s long-term integrated resource plan has greatly reduced the value and need of the proposed line,” it said. “The IRP analysis indicates SMUD would better focus its resources on the suite of local, regional and in-state renewable and reliability projects, as well as incremental transmission infrastructure.
“Canceling CoSu also reduces pressure on SMUD rates during the early critical phase of IRP implementation,” SMUD added.
FERC last week reversed a waiver it had previously issued to SPP on Attachment Z2 of its Tariff and directed the RTO to provide refunds of credit payment obligations, with interest (ER16-1341).
The commission ordered SPP to refund credit payment obligation amounts dating back to 2008, except for the one-year billing adjustment limit allowed in the Tariff.
SPP was seeking a retroactive waiver of its Tariff so that it could invoice transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period prior to its April 2016 request. In its reversal Thursday, FERC found “the relief sought by SPP … is prohibited by the filed rate doctrine and the rule against retroactive ratemaking.”
SPP’s headquarters in Little Rock, Ark. | WER Architects
The commission approved the waiver request in a July 2016 order that set aside the one-year time limit. In November 2017, FERC denied a rehearing request by several stakeholders. (See “Z2 Waiver Upheld,” FERC Rejects SPP Change on Network Resource Upgrades.)
But FERC issued a voluntary remand of the waiver orders after Xcel Energy appealed to the D.C. Circuit Court of Appeals in January 2018. The commission’s reversal was prompted by the court’s June decision to uphold FERC’s order rejecting Old Dominion Electric Cooperative’s request for a waiver of Duke, ODEC Rebuffed on Polar Vortex Gas Refunds.)
FERC noted the D.C. Circuit has recognized the commission’s “‘broad remedial’ authority to remedy unjust outcomes.” But it said that exercising its authority under the Federal Power Act in this instance “would be inappropriate,” noting that the court in ODEC “highlighted that the commission cannot disregard for good cause or any other equitable grounds either the filed rate doctrine or the rule against retroactive ratemaking.”
Attachment Z2 details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP said that delays in implementing computer software kept it from listing certain creditable upgrades in aggregate facilities study reports, calculating and assessing costs, and distributing credits to transmission customers before August 2016.
An SPP spokesman said the company is reviewing the order and its options. It estimates the credit payment obligations for the historical period to be approximately $200 million.
Last week’s order requires SPP to file a report within 120 days detailing how it plans to make the required refunds and allows third parties to comment on the RTO’s proposal. “SPP shall not provide any refunds prior to the issuance of a further commission order directing refunds,” FERC said.
Xcel Energy upgrade project | em>Burns & McDonnell
Commissioners Cheryl LaFleur and Richard Glick, who reluctantly concurred with the decision, issued separate statements attached to the order.
“The financial impacts of today’s order will rightly be frustrating to those parties that would otherwise receive credits for the historic period, and the order provides an unfair windfall to those who benefited from those upgrades during the historic period but are not required to pay for them,” LaFleur wrote.
“This is a result that could have been avoided, and we should, where possible, take steps to prevent similar issues in the future. As today’s order notes, the New York Independent System Operator Inc. Tariff authorizes the commission to order changes to otherwise ‘finalized’ data and invoices. I join Commissioner Glick in encouraging SPP and other RTOs/ISOs to consider comparable revisions to their tariffs to avoid similarly inequitable outcomes in the future.”
Saying they want to move forward quickly with real-time co-optimization (RTC), Texas regulators approved a list of issues to be discussed during a summer workshop on the potential market change (Project 48540).
ERCOT staff have said it will take four to five years and about $40 million to implement RTC, under which energy and ancillary services are procured simultaneously every five minutes in the real-time market to find the most cost-effective solutions for both.
“I want real-time co-optimization moving forward, the sooner the better,” Public Utility Commission Chair DeAnn Walker said during the commission’s open meeting Thursday. “We are hearing in my office that the more ERCOT’s operations staff learns about real-time co-optimization, the more excited they’re getting about the tools and benefits, as far as efficiencies not only in the market, but system efficiencies as well.”
The commission is asking stakeholders to file written comments on what value to set as the systemwide offer cap, what value to set for lost load and which ancillary services should be used in developing ancillary service demand curves, among other issues.
The PUC is scheduling the workshop in early June.
PUC Amends Preliminary Sempra-Sharyland Order
The commission adopted an amended preliminary order on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services (Docket 48929).
The order sets aside the prudence of investments in any assets for future rate cases and clears up inconsistencies involving allocation factors.
The applicants are seeking the PUC’s approval for the $1.37 billion worth of transactions, which were announced in October. The deals would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in Central, North and West Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest. (See Sempra, Oncor Deals Target Texas Transmission.)
A hearing on the merits is scheduled for April 10-12.
The PUC also:
approved $369.2 million in AEP Texas system restoration costs stemming from Hurricane Harvey in 2017 (Docket 48577); and
levied a $68,000 administrative penalty against Southwestern Public Service for exceeding its system average interruption duration index value (Docket 48826).
PUC, Gas Regulator Call for Coordination
The PUC and the Texas Railroad Commission (TRC) issued a joint statement last week describing their efforts to prepare for the summer months by guiding coordination among natural gas pipelines, gas-fueled power plants, and utilities that service the pipelines, plants and other customers. The TRC has jurisdiction over natural gas utilities.
The agencies urged companies to finalize their coordinated preparations for the summer, maintain clear lines of communication as the summer progresses and participate in ERCOT’s Gas-Electric Working Group. Natural gas fuels about half the generation in ERCOT.
“Texas has more than enough natural gas to fuel power generation,” TRC Chair Christi Craddick said. “We must make sure it can get where it’s needed, when it is needed, and that requires coordination between gas pipelines companies, electric generation facilities and electric utilities.”
PUC spokesman Andy Barlow said the agencies’ goal is to “guide maintenance scheduling to reduce situations in which pipeline maintenance might interrupt the flow of gas to Texas gas-fired plants and/or electricity flow to pipeline facilities.”
Texas Senate Confirms Commissioners
The Texas Senate on Wednesday unanimously confirmed all three commissioners, who were appointed by Gov. Greg Abbott between legislative sessions. The commissioners have been serving between eight and 17 months.
Commissioner Shelly Botkin’s term expires on Sept. 1, with Walker’s expiring in 2021 and Commissioner Arthur D’Andrea’s in 2023.
CARMEL, Ind. — In the wake of its January grid emergency, MISO has pledged to further study generation cutoffs in extreme temperatures and how it can best account for voluntary load curtailments in load forecasting.
MISO said its Jan. 30-31 emergency was in part triggered by a greater-than-expected drop in wind generation, with emergency demand difficult to predict as schools and businesses closed for the day and millions of energy consumers lowered their thermostats during the event in response to utility requests. (See MISO Details ‘Uncertainty’ Behind Winter Max Gen Event.)
MISO said temperatures in its North region were more than 6 degrees Fahrenheit below those during the 2014 polar vortex. Forced outages surpassed 20 GW, while total outages and derates took more than 35 GW of generation offline. Although the RTO didn’t call on its neighbors for imports, its higher emergency prices attracted more than 5 GW of imports. Over the two days, the RTO exceeded $18 million in uplift charges, on par with other severe cold snaps. Load-modifying resource (LMR) use peaked at almost 3.9 GW on Jan. 30.
“Basically, it was unprecedently cold in MISO,” Director of Central Region Operations Ron Arness said during a Reliability Subcommittee meeting Wednesday. “Temperatures were colder than any since the existence of MISO, and we suspect that’s why wind generation was cutting off. … Even though the temperatures are abnormal, we should have this cutoff information so we can make good assessments about what generation is forecasted for the next day.”
IPL crews restoring power Jan. 31 | Indianapolis Power and Light
Arness said MISO will gather operating parameters to determine what generating resources must switch off in response to temperature thresholds and establish a load forecast variable that includes known voluntary load curtailment.
He added that quantifying voluntary curtailment is “a difficult thing to do, but one that MISO will look at nevertheless.”
Grid Strategies’ Michael Goggin, representing the American Wind Energy Association, said that while there were cold-weather wind cutoffs, large amounts of imported wind from PJM into MISO helped alleviate the emergency. He also said wind generation in Michigan helped to cover Consumers Energy’s gas supply issues following a fire at a compressor station.
Goggin also said it “makes perfect sense” for MISO to keep an account of the operating cutoffs across all classes of generation.
“I think once they do that, they won’t have an issue,” Goggin said in a telephone interview with RTO Insider.
He added that significant outages across all MISO resource types on Jan. 30 were a “much larger factor” than the missed wind forecast.
“There’s just a lot of equipment failures across all resources when you have temperatures this extreme,” he said.
As with past emergencies, some LMRs did not respond or verify availability in MISO’s communication system, Arness said. The RTO will hold training for LMR owners on how to navigate its system April 23-24 and again May 21-22 in anticipation of its summer peak.
As expected, MISO’s January operations report reflected the extreme cold and emergency declaration on the last two days of the month. The RTO’s peak load of 101 GW occurred on Jan. 30.
MISO also hit a new record wind output peak of 16.3 GW on Jan. 8, besting the previous record of 15.6 GW from March 31, 2018.
MISO to Work Through 2-Hour LMR Notification
MISO plans to work with stakeholders to determine how it will provide two-hour notice to LMRs called up to respond to emergency conditions.
Customized Energy Solutions’ Ted Kuhn asked how long LMRs are on the hook under the two-hour warning should MISO need to shift the emergency declaration to a later time.
“You just need to make sure it’s clear how long they have to be available. It’s not an indefinite; it needs to be [a fixed time period],” Kuhn said.
MISO staff said it was extremely unlikely that the RTO would continuously delay an emergency declaration over several hours, but it may need a little flexibility as it monitors possible maximum generation events.
“The timing of the peak is not a fixed thing. It could come earlier; it could come later,” said Dustin Grethen, MISO market design adviser.
“The two-hour notification is just that: making sure if they have someone drive out to flip the switch, they’re driving at the right time,” MISO Director of Resource Adequacy Coordination Laura Rauch said.
The RTO will discuss the filing amendment with stakeholders during this month’s Resource Adequacy Subcommittee meeting.
RENSSELAER, N.Y. — NYISO on Thursday said it has commissioned Analysis Group to model the social cost of carbon in order to finalize a carbon pricing scheme for its wholesale electricity markets.
“In the last week we decided to have Analysis Group and Sue Tierney and Paul Hibbard do a fresh analysis,” Executive Vice President Rich Dewey told the Installed Capacity/Market Issues Working Group, referring to a senior adviser and principal, respectively, at the consulting firm.
“The scope of work for the Analysis Group is to build on the analysis previously done by [The] Brattle [Group] and (a) validate the findings, (b) extend the assessment based on the newly announced more aggressive policy goals and (c) identify any complementary benefits that might have been overlooked in the scope of the Brattle study,” Dewey said.
Dewey’s surprise announcement came near the end of a meeting devoted to new Tariff rules on carbon emissions and pricing. Stakeholders had begun to push ISO staffers to explain the timeline ahead of an anticipated vote on carbon pricing in the second quarter and describe exactly how the grid operator is learning whether the state supports their efforts.
“We all recognized when we started that this was new ground, uncharted territory,” Dewey said, indicating that the ISO would not present a carbon pricing package to FERC without state support. “We’re not going to take a vote and put forth a [Federal Power Act Section] 205 filing without state support. … We’re not going to ram through a vote by June without all on board.”
NYISO has commissioned Analysis Group to model the social cost of carbon in order to finalize a carbon pricing scheme for its wholesale electricity markets. The above graph is from an U.S. Interagency Working Group study in 2013. | U.S. Government Interagency Working Group on Social Cost of Greenhouse Gases
Howard Fromer, director of market policy for PSEG Power New York, said timing is critical.
“While we are figuring out how to price carbon, the state is moving forward with significant implementation of its policies,” Fromer said. “Renewables, a host of storage solicitations and draft air emission regulations were just issued for comment that impact over 3,000 MW of peakers in the New York City-Long Island area, all affecting how the market responds and thinks about what’s happening. We can’t wait too long to decide on how to act.”
Mark Reeder, representing the Alliance for Clean Energy New York, said, “The only thing we can affect is whether or not to have a carbon price, not whether or not the state’s environmental goals are admirable.”
Filling the Gaps
A task force created in October 2017 by NYISO and the New York Public Service Commission worked for more than a year developing a proposal to price carbon into wholesale markets. In December, it turned the proposal and final details over to the ISO’s stakeholder process. (See IPPTF Hands off Carbon Pricing Proposal to NYISO.)
“What we worked on in our stakeholder process is to get to a package that people are comfortable with, and at the end of March we’ll know what are the gaps,” Dewey said.
He added that the contract with Analysis Group is not meant to undermine the initial analysis done by Brattle, but “to look at unmonetized benefits,” whether in public health or other areas. The ISO will post details of the study as soon as possible, he said.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said he had no issues with the decision to conduct another study on the impacts of carbon pricing, but he was critical of the ISO’s decision to commission the study without even consulting stakeholders on the decision and, in particular, on the scope of the study.
Before Dewey’s announcement, Mager said, “It might be helpful to get a list of what the ISO considers to be open issues. Right now we have no clarity, and we want to understand the [carbon pricing] proposal on a comprehensive basis and go back to our clients.”
“We want more than silence from the state; we need a positive statement of support, at least when we go to FERC,” said Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers.
Rochester Energy Storage Hub | NY-BEST
Breidenbaugh said his clients already have uncertainties regarding subsidies, questioning how the state would structure thousands of megawatts of renewable energy contracts and whether the contracts will reflect carbon pricing effects or be layered atop them. He said they are “profoundly skeptical” about carbon pricing, especially in the context of a potential carbon tax being imposed by the state.
NYISO will discuss Tariff revisions and price calculation — specifically identifying marginal units — on March 18, and Tariff revisions again on March 28.
There will likely be at least one more meeting after that, said Nicole Bouchez, NYISO’s principal economist.
Tariff Terms, Penalties
NYISO on Thursday also proposed new Tariff sections to describe carbon charges, payments and residual allocation.
The ISO requires new Tariff definitions of carbon emissions and the cost of such emissions to effectuate carbon pricing, said Ethan D. Avallone, an ISO senior energy market design specialist. He also reviewed the work done so far on carbon residuals. (See NYISO Ponders Response to Carbon Charge Shortfalls.)
New sections of Rate Schedule 18 will include carbon charges and payments for import and export transactions, as well as for wheel-throughs and the carbon residual allocation, Avallone said. New sections of Rate Schedule 9 will include carbon charges for suppliers.
The Tariff language defines emissions as “point-of-production carbon dioxide emissions that result from energy injected, or start-up to inject energy, in connection with participation in the wholesale market.”
The ISO proposed a price on carbon emissions equal to the SCC — presumably as determined by the PSC — minus the value of any other state, multistate or federal charges for carbon emissions that a supplier must pay, including but not limited to emission allowance costs.
Penalties for failing to report or underreporting carbon emissions ramp up according to the severity of the lapse, from 0.5 times the applicable charge for failure to report emissions data by day 60, to 1.5 times the applicable invoice charge for failure to report by day 170, to double the charge for underreporting.
One stakeholder questioned the procedures for levying such penalties but was reassured that generators have a significant window in which to correct emissions data before being subject to penalties for underreporting or failing to report.
The Organization of MISO States and SPP’s Regional State Committee’s Liaison Committee has asked MISO’s Independent Market Monitor Potomac Economics and SPP’s Market Monitoring Unit to conduct a seams analysis and identify “specific seams issues from their perspective.”
Potomac’s Michael Wander and the MMU’s Keith Collins will provide a list of issues to Missouri Public Service Commissioner and OMS President Daniel Hall and Kansas Corporation Commissioner Shari Feist Albrecht, the committee’s chair and vice chair, respectively. Committee members are scheduled to hold a March 15 conference call to narrow the list for the monitors’ analysis.
“Hopefully, they will pick issues that can be monetized for ratepayers,” Hall said during a March 1 conference call.
Hall said he prefers a single report from the monitors but agreed two reports might be appropriate should their perspectives differ.
The MISO-SPP seam | ACES
The Liaison Committee has been meeting since mid-2018 to help improve the grid operators’ interregional coordination, which has never produced a major project. That has frustrated some stakeholders and caused market inefficiencies.
Members met most recently in a closed session during the February National Association of Regulatory Utility Commissioners meeting. (See “OMS-RSC Talks Continue,” OMS Taps State Attorney for Leadership Role.)
Future meetings will be open to the public, Hall said then.
FERC has rejected a trade group’s complaint that MISO is improperly accounting for the deliverability of some capacity resources, saying it could find no Tariff language to support a violation.
The commission on Thursday said MISO isn’t in violation of its resource adequacy construct over capacity deliverability as the Coalition of Midwest Power Producers (COMPP) alleged late last year (EL19-28).
Rather than finding any Tariff provisions that evidenced violation, FERC said that MISO is “responsible for determining whether … capacity resources are deliverable to load.”
“Although power producers contend that ‘deliverable to load’ should be read to mean that capacity resources must have firm transmission service up to their full installed capacity levels, power producers fail to identify any Tariff provisions that support this assertion,” FERC said.
The commission also said COMPP didn’t demonstrate that MISO’s current practice jeopardizes reliability.
| MISO
COMPP’s complaint alleged that MISO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the RTO allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. The group said MISO’s megawatt count from deliverable resources comes up short annually and drives down payments to capacity resources demonstrably positioned to deliver on their obligations. COMPP asked FERC to direct MISO to develop a solution to comply with its Tariff before the 2019/20 capacity auction. (See Trade Group Lodges Complaint over MISO Capacity Rules.)
MISO’s Tariff requires capacity resources to demonstrate deliverability either by having network resource interconnection service (NRIS), which stipulates that the entire ICAP of the resources must be deliverable, or by having energy resource interconnection service (ERIS) and procuring firm transmission service up its UCAP level.
No Discriminatory Treatment
In response to the complaint, MISO said it doesn’t hold capacity resources to different standards because it doesn’t require NRIS resources to perform to ICAP levels, instead requiring both to demonstrate deliverability up to their UCAP levels for the purposes of the capacity auction.
FERC agreed. “As described in its resource adequacy Business Practices Manual, MISO calculates the [UCAP] level of a resource by first determining its [ICAP] level. Once the [ICAP] value is determined, MISO applies the resource’s forced outage rate, thereby converting the [ICAP] level to a lower [UCAP] level. Next, MISO validates that the resource is deliverable by having the resource demonstrate deliverability up to its [UCAP] level,” FERC said.
The commission also said UCAP values are a vital part of MISO’s resource adequacy construct, with even the reserve margin formed as an “unforced capacity requirement.”
“Given the consistent use of unforced capacity values for purposes of resource adequacy in … its Tariff, we find that MISO reasonably implemented [its Tariff] by requiring capacity resources with ERIS to demonstrate deliverability up to their unforced capacity levels,” FERC said.
MISO said COMPP mischaracterized its Tariff “process improvements” discussions with the Independent Market Monitor as “admissions of Tariff violations.” The RTO has promised to have stakeholder discussions about resource deliverability and LOLE implications, with any potential fixes aimed at the 2020/21 capacity auction. (See “Capacity Auction Recommendations,” MISO Concurs with Monitor Ideas, Pledges More Study.) It said there was no evidence it violated Tariff provisions establishing a planning margin, the LOLE study methodology to create the planning margin or its duty to ensure the deliverability of capacity resources. MISO also said working on a rule change less than a month before the April capacity auction would seriously disrupt the auction.
At any rate, transmission deliverability is outside the scope of its LOLE analysis because the study assumes no internal transmission constraints, the RTO added.
However, the Monitor had asked FERC to side with COMPP, agreeing that “the terms of the Tariff result in a mismatch for some ERIS resources between the capacity assumed to be available in the LOLE studies and the capacity those suppliers can actually deliver.” But the Organization of MISO States urged FERC to hold off on ordering relief so the RTO could continue to address the issue through ongoing stakeholder discussions.
‘False Sense of Urgency’
MISO said the complaint created a “false sense of urgency” by implying that its recent emergency events had anything to do with capacity deliverability. To the contrary, the RTO said the events “have been driven largely by correlated planned outages and the use of emergency-only resources outside of the summer season.”
The RTO also argued that the power producers represented by COMPP are not prevented from auction participation nor are they suffering harm from MISO’s existing rules. It also said COMPP should have first sought dispute resolution with MISO. Finally, MISO alleged the complaint only sought to “disqualify 1,400 MW of generation owned by other auction participants to gain a competitive advantage.” The Monitor last year said as much as 1,400 MW worth of capacity resources needed to meet reserve requirements may not have been deliverable in the 2018/19 planning year.
