VALLEY FORGE, Pa. — PJM’s Operating Committee breezed through a light agenda during its March meeting on Tuesday.
Frequency Response Performance Underwhelms
The number of generators providing primary frequency response (PFR) in 2018 fell short of PJM’s expectations, according to the RTO’s most-recently analyzed data.
Danielle Croop, PJM senior engineer of operations and analysis, told the Operating Committee PFR-capable generators didn’t respond as anticipated during five low-frequency events selected for evaluation throughout the year, at times providing less than half the megawatts PJM expected.
“These five events are the only ones that met the [PJM] criteria for 2018,” Croop said. “There’s usually about 25 or 30 events that meet [NERC’s] BAL-003, so you can see how narrow the evaluation selection is.”
At last October’s OC meeting, PJM shared frequency response data from 13 BAL-003 events between December 2017 and April 2018 that showed similar results. (See “The Right Metric on Frequency Response” in PJM Operating Committee Briefs: Jan. 8, 2019.)
PJM assesses generator performance during events in which the system frequency goes outside a +/-40-mHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz. (See “Utilities Question Primary Frequency Response Calculation” in PJM Operating Committee Briefs: Feb. 5, 2019.) The five events fitting into the narrower criteria occurred on Jan. 27, April 7, June 30, Sept. 13 and Sept. 20.
Count of units that provided PFR by % of response compared to expected response. Only units expected to respond are in evaluation. | PJM
While generators provided 130 MW of the anticipated 165 MW during the January event, available energy dipped to 50% or less of what PJM expected during the April 7, June 30 and Sept. 13 events.
Brock Ondayko, of AEP Energy, refuted PJM’s expectation for more output, calling it “incorrect.” He said PJM’s existing dispatch software often oversimplifies a resource’s anticipated PFR capability because it doesn’t account for physical operational hold points.
“Until PJM modifies [its] dispatch software to take into account how resources actually operate and then subsequently begins to preposition capable units to respond, ‘expected’ numbers really need to be taken with a grain of salt,” he said in an email Tuesday. “While I sympathize with PJM’s dispatch issues and understand the limitations of [its] current estimates, my continuing to bring up the topic/issues for what has seemed like years has never stopped PJM from continually sharing what must be considered suspect data, without disclaimers.”
Croop defended the numbers during the meeting Tuesday, noting more accurate data will come from analysis of individual generators — to which Ondayko agreed.
“This is not absolute … but it’s a good line in the sand to see if we are getting the PFR we are expecting or not,” Croop said. “I think more intricate details will work through at the generator evaluation level.”
Ondayko requested PJM consider accounting for future PFR sources and those scheduled for retirement, referencing FERC Order 842 requirements.
“It would give us a better sense of how successful the FERC order is going to be or not going to be,” he said.
2018 Primary Frequency Event Response by Megawatts. | PJM
Stakeholders Ponder Meeting Changes
As the schedule for upcoming Operating Committee meetings fills up with obligations from new and continuing task forces, stakeholders pondered getting an earlier start.
OC Chair Dave Souder suggested starting April’s meeting at 8:30 a.m. to account for agenda items related to non-retail behind-the-meter generation business rules. Stakeholders approved a problem statement and issue charge revising the existing manual language during Tuesday’s meeting. (See “PJM Continues Review of Non-retail BTM Generation Business Rules” in PJM Operating Committee Briefs: Feb. 5, 2019.)
“I think the 8:30 start time is a little early,” said Sharon Midgley, of Exelon. “And the beginning of the meeting is sometimes important, particularly if there are any controversial endorsement items.”
Jim Benchek, of FirstEnergy, agreed an earlier start time would prove difficult for stakeholders commuting and instead suggested staying an hour later.
Souder proposed implementing a working lunch for future OC meetings, to which no stakeholders voiced any objections. He said PJM’s Dave Anders also suggested moving meetings to Thursday mornings beginning in 2020 so staff could have more time to provide accurate and updated reference materials. Planning Committee meetings would occur Tuesday mornings, instead.
FERC on Tuesday authorized NextEra Energy Transmission (NEET) Midwest to recover all “prudently incurred” costs related to the company’s investment in the Hartburg-Sabine Junction 500-kV project in East Texas, MISO’s second-ever competitively bid transmission project (ER19-775).
The commission’s granting of the abandoned plant incentive ensures NextEra will be covered for 100% of its investment if the project is canceled for reasons outside the company’s control.
Hartburg Sabine map | MISO
The Hartburg-Sabine project will consist of a new 23-mile 500-kV transmission line, four short 230-kV lines and a new Stonewood substation that will connect the longer line with the existing Hartburg substation. The project is designed to relieve congestion issues and import limitations along the Texas-Louisiana border.
MISO awarded the project to NextEra last November following a competitive bidding process in which the company’s proposal scored 97 out of a possible 100 points, beating out 11 other competitors. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.) NextEra’s proposal capped total project costs at $114.8 million, less than MISO’s $122 million estimate, and demonstrated a 2.2-1 benefit-to-cost ratio.
Under its FERC-approved formula rate, NextEra is already entitled to a 50-basis-point adder for RTO participation and a mechanism for later recovery of pre-commercial and formation costs along with a carrying charge. In its request for the abandoned plant incentive, NextEra noted the Hartburg-Sabine project is still subject to multiple layers of review, including those by the U.S. Fish and Wildlife Service, Federal Aviation Administration and EPA, as well as those by several Texas state and county agencies.
NextEra pointed to other nonregulatory risks confronting the project.
“In this regard, NEET Midwest states the project was included in the 2017 [MISO Transmission Expansion Plan] primarily because of the economic benefits to be derived from the project,” the commission wrote. “However, NEET Midwest points out that under the MISO Tariff, significant changes in those anticipated benefits could result in MISO reconsidering and potentially canceling the project.”
The company said it has no rate base or other revenue stream that could potentially offset any costs sunk into the project.
In approving the incentive, the commission noted it has previously found reliability and congestion-relieving projects selected through a regional transmission planning process are entitled to the rebuttable presumption established under Order 679, which requires an applicant to show “there is a nexus between the incentive sought and the investment being made.”
“We find the total package of incentives, including the previously granted incentives, as modified as part of the selected proposal, is reasonable because it addresses the risks and challenges associated with the development of the project,” the commission said.
ERCOT is forecasting record peak demand with increased potential emergency alerts this summer, given its historically low planning reserve margin of 7.4%.
The grid operator said Tuesday it expects a summer peak of 74.9 GW, which would break the mark of 73.3 GW set just last summer. ERCOT has 78.2 GW of capacity on hand to meet that demand, according to its preliminary summer seasonal assessment of resource adequacy (SARA).
March Seasonal Assessment of Resource Adequacy | ERCOT
David Bellman, head of power for Houston-based Skylar Capital Management, told RTO Insider the “surprising thing to note” is this year’s projected peak is almost 3% higher than last year’s predicted high of 72.8 GW, as well as being 1.6 GW higher than 2018’s actual peak.
Bellman said the forward markets lost about $2/MWh Tuesday and were trading at $138/MWh.
“The increase in peak demand and drop in resource adequacy means we expect emergency alerts to be issued this summer,” Resource Adequacy Manager Pete Warnken said during a media call.
Declaring an energy alert during scarcity situations would free up the ISO to tap into a variety of additional resources to meet demand. Those resources include demand response products, resources normally set aside to provide operating reserves, additional generation or imports from neighboring RTOs, and calls for voluntary conservation measures.
David Bellman | RTO Insider
Dan Woodfin, ERCOT’s director of system operations, said the grid operator has 900 MW of emergency response service available and another 1,300-1,800 MW of capacity from load-management programs.
The grid operator’s reserve margin dropped from 8.1% to 7.4% with the December retirement of the Gibbons Creek coal plant. Warnken said 500 MW of summer capacity, much of it from wind and solar projects, has been delayed until late spring and early summer.
The final summer SARA report will be released in May and will reflect the expected summer weather conditions.
ERCOT also released its final SARA for the spring months (March-May), saying it has sufficient capacity (81.3 GW) to meet a forecasted spring peak of 61.6 GW. The system has added 577 MW of planned gas, wind and solar resources for the spring, with another 50 MW of wind and solar capacity expected to be available for the season’s start.
The hearing the Senate Energy and Natural Resources Committee held Tuesday was perhaps less noteworthy for what was said than the fact it even happened.
Chaired by Sen. Lisa Murkowski (R-Alaska), committee members and panelists discussed the electricity industry’s role in mitigating climate change. According to ranking member Joe Manchin (D-W.Va.), it was the first hearing the committee had held on climate change since 2012.
Compared to the House of Representatives, now in Democratic hands and holding almost weekly hearings on climate change, the GOP-controlled Senate has been nearly silent on the phenomenon. (See House Democrats Put Climate Change Front and Center.) That will change as Senate Democrats up their rhetoric and make it a central platform of their 2020 re-election campaigns, as The New York Times reported Monday.
Sen. Lisa Murkowski (R-Alaska) opened the hearing displaying this graphic, which shows the rapid decrease in Bering Sea ice, as a demonstration of the impacts of climate change. | Rick Thoman, Alaska Center for Climate Assessment and Policy
Tuesday’s hearing, however, lacked partisan rancor. Instead, the few senators who attended and the panelists focused on increased investment in research and development of new technologies to make generating resources cleaner and more efficient.
This was in part because of the committee’s jurisdiction: It does not oversee EPA nor does it have direct oversight of U.S. greenhouse gas emissions. Those are under the charge of the Environment and Public Works Committee.
“I think it’s important to point out, we know here on the committee we have jurisdiction in certain areas,” Murkowski said. “We do not have complete jurisdiction over climate change — we recognize that — but we do have a role to play in developing reasonable policies that can draw bipartisan support that I think will be a pragmatic contribution to the overall discussion.”
But the homes of the committee’s leaders also played a large role in what was discussed. Murkowski, who opened the hearing with a list of adverse effects being felt by Alaska — including rapidly decreasing Bering Sea ice and a more challenging Iditarod Trail Sled Dog Race — has broken away from her party in even discussing the issue. Manchin, who frequently sides with Republicans on the committee, criticized regulations as a solution, saying they disproportionately hurt rural residents and coal miners, like those in West Virginia.
“Therefore, the path to a climate solution must offer West Virginians opportunity — not additional economic burdens,” Manchin said. “Chairman Murkowski and I share a deep concern for our rural communities and seek to use this committee as a means of identifying and legislating pathways to ensure our constituents have a role in the clean energy future.”
Manchin said the use of fossil fuels to generate electricity is “not going away anytime soon” and noted China and India are increasing the use of coal. Kenneth Medlock, senior director at Rice University’s Center for Energy Studies, put an exclamation mark on Manchin’s point by noting China has 254 GW of coal-fired capacity under construction — more than the entire U.S. coal fleet.
“So … when we think about CO2 being a problem of the global commons, it really means we need to lead by example,” Medlock said.
Manchin jumped in, asserting that the U.S. has led by example, mandating technologies such as scrubbers and low-NOx boilers. “They’re not implementing any of those,” he said.
Medlock replied his point was that the U.S. needs to lead in innovation, such as developing scalable carbon capture and sequestration (CCS), a technology seen as key to reducing emissions and even potentially reversing climate change. He noted federal R&D spending has been declining for the last 30 years “and that doesn’t make any sense.”
Susan Tierney, senior adviser at Analysis Group, said, “China is actually an unsung story on a lot of innovations,” building advanced reactors and wind turbines.
“The U.S. needs to continue to advance technology leadership … so we don’t lose to them on these competitive technologies,” she said.
Notably absent from the hearing was EPW Committee Chair John Barrasso (R-Wyo.), who last month reintroduced the Utilizing Significant Emissions with Innovative Technologies (USE IT) Act. The bill, which enjoys bipartisan support, would fund CCS R&D and create a board of experts to oversee projects under development.
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.
