ISO-NE concluded Forward Capacity Auction 13 on Monday at the lowest clearing price in six years, moving ahead with the event despite Vineyard Wind’s pre-dawn, emergency motion asking FERC to stay the process.
It was the first auction run under the Competitive Auctions with Sponsored Policy Resources (CASPR) rules, which established a secondary substitution auction in which Vineyard assumed an obligation of 54 MW from an existing resource that will retire in the relevant 2022/23 commitment period, the RTO said.
The auction’s preliminary clearing price of $3.80/kW-month was well under last year’s clearing price of $4.63/kW-month.
Closing at a preliminary clearing price of $3.80/kW-month, FCA 13 continues the trend of declining prices shown in the previous three auctions. | ISO-NE
“This year’s auctions procured the resources needed for a reliable power system at a competitive price, while implementing new procedures to accommodate state-sponsored renewable resources,” Robert Ethier, ISO-NE vice president of market operations, said in a statement. “It’s our responsibility to run these auctions and our wholesale markets under the rules approved by FERC, and we fulfilled that responsibility again this year.”
Resources totaling 43,641 MW, including 34,925 MW of existing capacity and 238 new resources totaling 8,716 MW, qualified to participate in this year’s auction, while the regional capacity target for 2022/23 is 33,750 MW, the RTO said.
Border Issues
Vineyard’s emergency motion came after the commission failed to act on the wind developer’s Dec. 14 request for waiver of ISO-NE Tariff provisions requiring that the auction’s renewable technology resource (RTR) exemption be granted only to resources within the borders of a New England state (ER19-570, ER19-444). (See Vineyard Wind Files Emergency Motion to Stay ISO-NE Auction.)
FERC Commissioners Cheryl LaFleur and Richard Glick issued a joint statement Feb. 4 saying that “by failing to act, the commission has introduced significant uncertainty into this auction. All parties, including New England’s states, consumers and auction participants, deserve better.”
A joint venture by Iberdrola and Copenhagen Infrastructure Partners, Vineyard last May won a contract to supply Massachusetts with 800 MW of offshore wind energy, and in December won another lease area off Martha’s Vineyard in an auction conducted by the Bureau of Ocean Energy Management. (See Mass. Offshore Lease Auction Nets Record $405 Million.)
Killingly Energy Center natural gas combined cycle plant schematic | Killingly Energy Center
The RTO on Wednesday reported the primary auction concluded with commitments from 34,839 MW to be available in 2022/23, leaving a surplus of 1,089 MW over the capacity requirement.
“More than 2,600 MW of new resources secured obligations during the primary and substitution auctions, including the Killingly Energy Center, a 650-MW natural gas plant under development in Connecticut, new energy efficiency and demand response resources, and imports,” the RTO said.
In addition, approximately 145 MW of resources received obligations under the RTR designation, which allows a limited number of renewable resources to participate in the auction without being subject to the minimum offer price rule.
Under ISO-NE’s Tariff, only renewable resources built within a New England state were eligible for the RTR exemption in FCA 13. Offshore wind projects proposed for federal waters will be eligible for the exemption in FCA 14, scheduled for February 2020. More than 300 MW remain in the RTR exemption cap and will be carried over to next year’s auction, the RTO said.
The grid operator also reported that it had retained two units, Mystic 8 and 9, needed for fuel security in the 2022/23 capacity year, as approved by FERC. (See ISO-NE Fuel Security Measures Approved.)
The RTO said by the end of this month it will file with the commission finalized auction results, including resource-specific information.
SACRAMENTO, Calif. – The Public Utilities Commission is considering whether to fine Southern California Edison for its failure to promptly report a nearly $1 billion shortfall in revenues last year that should have triggered action under state law.
The commission on Thursday unanimouslyapproved a sizable rate increase in 2019 to cover the shortfall, adding to millions of Californians’ already-high electricity costs. The increase amounts to about 1.4 cents/kWh, adding $11.50 to an average residential customer’s electricity bill in the summer and $7.67 in winter, according to the most recent data available.
The commissioners weren’t happy about the decision.
They criticized SCE’s failure to act sooner to compensate for a $983.8 million Energy Resource Recovery Account (ERRA) under-collection as of Dec. 31, 2018.
A Southern California Edison natural gas peaker plant near Los Angeles. | SCE
Assembly Bill 57 required the PUC to establish the ERRA account in 2002 to reconcile the fuel and purchased power costs that investor-owned utilities can recover in rates but for which they do not earn a return. The resulting regulation mandates utilities alert the PUC if their costs are likely to exceed or fall short of year-ahead projections by more than 4%.
The company was aware it had a problem as early as May but assumed market forces would correct it, commissioners said.
“The trigger was not called, and so we’re looking now at the end of the year where they incorporated this shortfall into their next year’s revenue forecast,” Commissioner Martha Guzman Aceves said. “This is not the type of process that we would like to see in any future year, particularly in this year. We want to be able to adjust [for] any shortfalls as they come.”
It was “disappointing” SCE hadn’t raised the matter in June or July, she said.
Even more alarming to the commission was the reason for the shortfall. The company cited dramatic increases in natural gas prices in August and November caused by supply constraints and suppliers taking advantage of safety fixes and upgrades as reasons for hiking prices.
The capacity of the Aliso Canyon natural gas storage facility, for instance, has been limited since a massive methane leak in 2015. The damage to Aliso Canyon, once the state’s largest natural gas reservoir, poses challenges to generators and regulators alike. (See FERC OK’s Extension of Most Aliso Canyon Measures.)
The PUC and California Energy Commission held a joint workshop Jan. 11 to discuss constrained supply and high gas prices in Southern California.
“The gas market is no longer competitive,” Guzman Aceves said during Thursday’s PUC voting meeting in Sacramento. Aging infrastructure and the state’s increasing reliance on renewable sources of electricity are among the factors tightening gas supply, she said.
The PUC is weighing proposals to help alleviate the situation including reducing operational flow order (OFO) penalties and ensuring utilities “balance to the core,” meaning they better forecast supply and demand, she said.
Guzman Aceves said an SCE proposal to establish a cost-based natural gas supply procurement tariff for any CAISO-connected electric generation was “timely and innovative.” The ISO has endorsed the plan.
“We have to move beyond the notion that the market itself is going to control the gas price,” she said.
Commissioner Liane M. Randolph expressed support for the second phase of Thursday’s proceeding to determine whether to fine SCE. That will happen at a future meeting, still to be determined.
“I think it’s important to deal with the fact that the utility did not call out these increased costs in a timely manner so that we could have potentially dealt with them,” Randolph said.
Electric ratepayers will see a roughly 5% increase in 2019 to compensate for SCE’s under-collection, Commissioner Clifford Rechtschaffen said. The situation is “quite concerning,” he said, especially when many “people are grappling with the collective cost of utility services” and will have trouble coping with costs that aren’t predictable and stable.
Natural gas constraints in Southern California | California Energy Commission
Genevieve Shiroma, who was recently appointed to the PUC by Gov. Gavin Newsom, said she wanted to take action to “buffer customers” from spikes in natural gas prices.
“It’s a warning signal in terms of what happened last summer,” she said.
She, too, said she wanted to understand the reasons for Southern California Edison’s “noncompliance.”
“It’s not some sort of discretionary thing, it seems to me,” she said. “Regulations are regulations.”
Co-sponsorship memos supporting a plan to save Pennsylvania’s nuclear reactors began circulating through the state legislature this week as the window of opportunity to prevent facility closures dwindles.
The bipartisan proposal — born out of discussions within the state’s Nuclear Energy Caucus (NEC) last year — would add nuclear energy into the Alternative Energy Portfolio Standards (AEPS) Act. The 2004 law mandates electricity distributors boost usage of renewable or alternative energy sources to 18% by 2021. Nuclear generation supplied about 42% of the state’s net generation in 2017, compared with 4.5% for renewables, according to the U.S. Energy Information Administration.
State Sens. Ryan Aument (R-36) and John Yudichak (D-14) spearheaded the Senate version of the memo. Both lawmakers served as caucus co-chairs and oversaw a November 2018 report that concluded “allowing any nuclear plant in the Commonwealth to close would have significant consequences for fuel diversity, resiliency, the environment, customers, and the state’s economy.”
“Given our state’s prominence in energy production, it is important that lawmakers focus on an inclusive energy policy that promotes and respects the contribution that each resource offers. The NEC looks forward to continuing the dialogue with our colleagues in the General Assembly in the coming weeks and months,” Yudichak said last year. “But time is not on our side. Pennsylvanians — especially those whose livelihood depends on nuclear energy — are looking to us for action.”
Exelon’s Three Mile Island nuclear power plant is in Pennsylvania, where the company is working to get subsidies for nuclear generation.
Sponsoring legislators urged support from other members to thwart a projected $4.6 billion annual cost to taxpayers should the state’s five nuclear facilities deactivate — including $788 million in increased electricity rates, a $2 billion GDP loss, $1.6 billion carbon emissions-related increases and $260 million lost to managing harmful criteria air pollutants.
“Unless we address this inequity, Three Mile Island will shut down in October 2019, Beaver Valley will shut down in 2021, and the Commonwealth’s three other nuclear power plants are likely not far behind,” the memo said. “To be clear, this shutdown process is irreversible, thereby guaranteeing the permanent loss of Pennsylvania’s nuclear assets.”
A Controversial Rescue
Proponents of the measure — including Nuclear Powers PA — say nuclear energy deserves inclusion in AEPS because it provides 93% of the state’s zero-carbon electricity. Rescuing the state’s aging generators from decommissioning could likewise preserve up to 16,000 full-time jobs and $69 million in state tax revenues, they contend.
“These lawmakers are demonstrating tremendous vision and leadership by identifying an achievable legislative plan to reform AEPS and help address a fundamental flaw within the markets,” said Martin Williams, NPP co-chair and business manager of Boilermakers Local 13 in Philadelphia. “Pennsylvania is the second-largest nuclear power-producing state. We have been leaders in this industry for years, and so it’s encouraging to see our lawmakers matching that with their own leadership. Much work remains, but we are encouraged by this important step forward.”
Power generators, natural gas industry advocates and industrial electricity consumers argue nuclear generation companies, like Exelon, shouldn’t expect ratepayers to bail them out for failing to adjust to the competitive electricity market — particularly when cleaner and cheaper alternatives exist to fill the void.
“More efficient and affordable power generating resources have lowered energy costs and are providing a new lifeline to Pennsylvania’s manufacturers,” said Rod Williamson, executive director of Industrial Energy Consumers of Pennsylvania. “Now that Pennsylvania’s manufacturers are experiencing a competitive advantage based upon energy costs, we cannot afford subsidies to nuclear generation owners that will risk tens of thousands of good manufacturing jobs.”
Glen Thomas, president of GT Power Group and former chairman of the state’s Public Utility Commission, told This Week in Pennsylvania a state bailout undermines the current market infrastructure and should be avoided.
“The competitive markets have worked really well here, and when you start interfering with those markets by picking winners and losers in Harrisburg, ultimately that’s not the system we should aspire to,” he said. “We should aspire to have a system where consumers are empowered to pick where their electricity comes from.”
Tony Iannelli, NPP co-chair and president and CEO of the Greater Lehigh Valley Chamber of Commerce, said correcting a faulty electricity market, preserving jobs and boosting air quality remain a “critically important effort.” Including nuclear energy in AEPS will add resilience to the power grid and prevent 37 million tons of carbon dioxide emissions annually, according to the legislative memo.
“Two of the state’s five plants have announced plans to close prematurely beginning later this year due to an imbalanced electric marketplace,” Iannelli said. “And the sad reality is that all five Pennsylvania nuclear plants are hindered in the current market environment and projected not to meet costs if this fundamental market flaw is not addressed.”
Exelon Behind a Similar Proposal Elsewhere
Exelon manages the largest nuclear fleet in the country, with 13 facilities nationwide and three in Pennsylvania alone. The company said last year its three main goals include ensuring fair compensation for resilient resources, addressing PJM’s identified price formation flaws and expanding zero-emission credit (ZEC) programs, like those seen in New York and Illinois. (See Exelon Confident in Nuclear Support Programs.) Illinois legislators passed the Future Energy Jobs bill in 2016, providing Exelon $235 million in ratepayer-funded zero-emission credits and keeping its Clinton and Quad Cities facilities operational for another decade. (See Illinois Lawmakers Clear Nuke Subsidy.) New York’s Public Service Commission created a ZEC program that same year as part of a plan to reduce greenhouse gas emissions by 40% by 2030. (See New York Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)
Paul Adams, Exelon’s senior manager of corporate communications, said updating Pennsylvania’s AEPS to include nuclear energy among the 16 other forms of renewable and alternative energy options detailed in the law makes sense on multiple fronts.
“The climate challenge is urgent and we must consider all energy options to accelerate our transition toward a low-carbon economy,” he said. “This is an important next step toward valuing the carbon-free energy that nuclear energy provides Pennsylvania. The loss of these plants would cost the Commonwealth $4.6 billion annually in the form of increased pollution, higher electricity prices to consumers, lost jobs and reduced economic activity.”
Vineyard Wind on Monday filed an emergency motion for FERC to stay ISO-NE’s 13th Forward Capacity Auction, claiming it “will suffer irreparable injury” if it is not afforded renewable technology resource (RTR) status in the auction, which was scheduled to begin the same day the company submitted its request (ER19-570, ER19-444).
Resources obtaining RTR status are exempted from the auction’s minimum offer price rule (MOPR).
The Feb. 4 motion came after the commission failed to act on Vineyard’s Dec. 14 request for waiver of ISO-NE Tariff provisions requiring that the RTR exemption be granted only to resources within the borders of a New England state. FCA 13 covers the capacity commitment period from June 1, 2022, to May 31, 2023.
Vineyard Wind turbines | Vineyard Wind
Commissioners Cheryl LaFleur and Richard Glick issued a joint statement Feb. 4 saying, “We are disappointed that the commission failed to act on Vineyard Wind LLC’s requests for a waiver and emergency motion in advance of ISO New England’s forward capacity auction. We recognize that the commission can move forward only when it has a majority of votes for a particular action. Nevertheless, by failing to act, the commission has introduced significant uncertainty into this auction. All parties, including New England’s states, consumers and auction participants, deserve better.”
Vineyard cited “extraordinary circumstances” in requesting the stay, or in the alternative, that the commission vacate the results of the auction and permit a new auction to occur as soon as practicable after action on the company’s petition.
Bloomberg quoted RTO spokesman Matthew Kakley as saying “The auction is already underway. A delay would be unfair to the hundreds of other market participants.”
The company also requested that “the commission follow the path it used in addressing the requests for declaratory order in advance of the expected bankruptcy filing of Pacific Gas and Electric Co. and establish a one-day comment period and issue an order on the merits promptly thereafter.” (See FERC Claims Authority over PG&E Contracts in Bankruptcy.)
A joint venture by Iberdrola and Copenhagen Infrastructure Partners, Vineyard last May won a contract to supply Massachusetts with 800 MW of offshore wind energy, and in December won another lease area off Martha’s Vineyard in an auction conducted by the Bureau of Ocean Energy Management. (See Mass. Offshore Lease Auction Nets Record $405 Million.)
BOEM Mass Rhode Island leases: A chart from the Bureau of Ocean Energy Management shows wind energy lease areas offshore Massachusetts and Rhode Island. | BOEM
‘Plain Vanilla’
In a Jan. 29 order, the commission accepted the RTO’s Tariff revisions to support implementation of the Competitive Auctions with Sponsored Policy Resources (CASPR) rules, which the commission accepted in March 2018 (ER19-444). (See related story, FERC Clarifies ISO-NE Generator Delist Bid Rights.)
But in a partial dissent, Glick said the RTO adopted a “confounding interpretation of what qualifies as a state-sponsored resource” by concluding that an offshore wind facility procured in a state solicitation does not qualify as a state-sponsored resource for the purpose of the RTR exemption to the MOPR, which CASPR retained as a transition mechanism to the fully fledged substitution auction.
In comments filed Jan. 4, the RTO said it “does not oppose” Vineyard’s request for waiver, noting that it adopts the approach outlined in the filed Tariff revisions, including the request that, if the RTR cap is reached, the proration provisions will only apply to resources that, similar to Vineyard, seek RTR treatment under revised rules.
Vineyard said it filed its original waiver request “in good faith” in accordance with longstanding FERC processes.
“The timing of the petition was well within the commission’s accepted time frames,” the company said. “Market participants rely on FERC to address this type of plain vanilla filing … on the merits and in a timely fashion. Up until now, the commission has always done so. In Vineyard Wind’s understanding, this situation is unprecedented.”
The Massachusetts Department of Energy Resources on Feb. 1 filed comments supporting Vineyard’s original petition, saying that the company’s contracts with it “represent over a year’s worth of collaboration and consultation” and are “a significant milestone” in the state’s “transition to a clean, diversified energy portfolio.”
Gov. Charlie Baker also sent a letter last week asking the commission to approve Vineyard’s request for a limited Tariff waiver, reiterating the department’s point that “the total direct and indirect benefits to Massachusetts ratepayers from the long-term contracts with Vineyard Wind are expected to be approximately $1.4 billion.”
METAIRIE, La. — MISO and SPP staff told stakeholders last week that there is “more support than not” for the RTOs to conduct a joint study of interregional transmission projects in 2019, and each year after that.
The RTOs’ interregional groups spent much of 2018 revising their joint operating agreement to increase the odds of agreeing on interregional projects. By improving the joint study — or coordinated system plan (CSP) — and its efficiency and effectiveness, the RTOs hope to identify and build “cost-effective projects that provide benefits to both regions.” (See MISO, SPP Tweak Interregional Criteria.)
The staffs eliminated a $5 million cost threshold for the projects, added avoided costs and adjusted production cost benefits to project evaluation, mandated CSP studies, and removed the joint modeling requirement in favor of individual RTO regional analyses done simultaneously.
MISO Expansion Planning Engineer Ben Stearney said during a Jan. 31 Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting that staff expect the joint study to be done annually. The committee later this month will help determine whether that process begins this year.
“This will allow us to prepare a better analysis or comparison of regional projects, because they’re done simultaneously,” Stearney said.
MISO and SPP conducted CSP and regional reviews in 2014 and 2016 but were unable to reach an agreement on the few projects they targeted.
“The change allows us to get to the solution quicker,” said SPP’s Casey Cathey, manager of reliability planning and seams.
SPP Interregional Coordinator Adam Bell conducted an in-depth review of the joint study process and its continued focus on coordination between the RTOs. “The better you understand each other’s processes, the better we’ll be,” he told stakeholders.
Bell said economic models, using four futures on MISO’s side and two on SPP’s, will be used to identify regional needs. The models will be developed out of the existing MISO Transmission Expansion Plan and SPP’s Integrated Transmission Planning, respectively.
“MISO will be able to evaluate projects as they would do regionally, as will SPP,” Bell said. “While it’s not exactly an apples-to-apples comparison, it doesn’t preclude you from finding projects that are beneficial to both.
“All that’s really required of a regional need,” he said, “is that it comes out of the MTEP or ITP.”
SPP’s needs solution window closes Feb. 6, while MISO’s ends March 1.
The RTOs have also added both a study model review and project review by the Joint Planning Committee, an interregional group comprising representatives from both RTOs. The JPC will also vote on a project’s proposed interregional cost allocation.
Under the proposed CSP interregional cost allocation, SPP and MISO will each calculate project benefits using their respective regional models. The share of project costs will be based on the percentage of the total project benefit.
The respective legal departments are reviewing the revised JOA language. The RTOs expect a FERC filing to be made in March.
CSP process overview | MISO & SPP
The IPSAC will hold a conference call Feb. 26 to continue the needs discussion and determine whether to conduct a joint study this year.
Last week’s meeting was almost held at MISO’s facility in Eden, Minn., where the temperature was -8 degrees Fahrenheit. The temperature in Metairie was 62 F at the same time.
TAC Endorses Granularity to Ancillary Services Products
ERCOT stakeholders last week moved to address the Texas grid’s growing pains by tweaking the system’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010.
The Technical Advisory Committee on Jan. 30 endorsed a Nodal Protocol revision request (NPRR863) that modifies responsive reserve service (RRS) to become primarily a frequency response service, allowing resources to earn compensation for providing primary frequency response (PFR). It also creates a new ERCOT contingency reserve service (ECRS), providing the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix.
The TAC gathers for its January meeting.
Electranet Power’s Marty Downey, representing the Independent Retail Electric Providers segment, pointed out that while wind energy and other renewables increase their presence in the ERCOT market, the ancillary services’ design has remained the same.
“Our grid has changed dramatically,” he said. “Wind energy continues to put pressure on ERCOT to address lower inertia. This gives ERCOT the tools to address that.”
South Texas Electric Cooperative (STEC), which sponsored the revision request, said RRS has been a staple of ancillary service offerings since the beginning of the zonal market. Its two components — PFR and 10-minute energy deployment — reflect the thermal generation technology available when the market opened, STEC said.
The co-op noted that NERC reliability standards require ERCOT’s online resources to provide PFR unless exempted by the grid operator. The system’s generation resources end up “providing an uncompensated service … and are subject to compliance risk” regardless of whether they have an RRS responsibility at the time, it said.
STEC also said ECRS provides ERCOT with additional flexibility while also “liberating” the 10-minute component from RRS. The co-op said creating two distinct ancillary service products removes barriers to entry, creates market efficiencies and appropriately compensates resources for the services they provide.
The Advanced Power Alliance’s (formerly The Wind Coalition) Walter Reid supported the NPRR. “Our members are all developing batteries and solar,” he said, pointing to more than 2 MW of energy storage in ERCOT’s interconnection queue.
“This is going to happen. We need to do things to facilitate this happening,” Reid said, calling for the revision request’s quick implementation.
As proposed, fast frequency response will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.
Stakeholders rejected a suggestion from industrial consumers, uncomfortable with the bifurcated approach and $2.5 million to $3.5 million in costs, to move implementation back to 2021 and 2022, respectively. An amended motion failed on a roll-call vote, gaining only 36% support.
The motion to endorse NPRR863 passed by an 86-14 margin. Luminant Generation, Reliant Energy Retail Services and industrial consumers voted against the measure.
South Texas Electric Cooperative’s Clif Lange
“The market does need certainty,” said Ian Haley, director of ERCOT regulatory policy for Luminant. “We have a fleet of generation resources that need to know what to provide. Having uncertainty seems scary to someone in our position.”
“We’re going to add a lot more renewables this year and next year. Inertia is going to be low,” said Sandip Sharma, ERCOT’s manager of operations planning. He said the grid operator hit 127 MW of inertia in 2018, its lowest level ever.
“ERCOT has been waving the inertia flag for several years. We’re on the cusp of that,” STEC’s Clif Lange said. “Now’s the time. … Holding off on PFR only increases the cost to consumers.”
Members Approve Urgent Battery Request
The committee accepted an urgent revision request that will allow Luminant to operate an energy storage system in West Texas, without setting requirements for future storage facilities.
NPRR915 defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy-offer curve.
The measure, sponsored by Luminant, passed with one abstention.
Haley said as Luminant developed its 9.9-MW Upton 2 energy storage system, which became operational Dec. 31 south of the Midland-Odessa region, it became apparent the generator would have to register the battery under requirements not currently defined in the protocols. Upton 2, the largest storage project in Texas, was designed as a settlement-only resource, but it would have been required to register as a “capital G” generation resource.
Haley noted that while Luminant can update market offers from the battery, the fully charged resource will only last 4.5 hours when pushing its full capacity onto the grid, possibly leaving it “completely deployed and drained before those offers can take effect. This clarifies how we are supposed to let ERCOT know, ‘Please do not deploy the battery for the next [security-constrained economic dispatch] run.’”
Luminant’s Ian Haley
Haley described NPRR915 as a one-off until ERCOT can get a handle on how to better accommodate battery storage systems.
“This shouldn’t apply to all batteries until we have a holistic view on all of this, but we should have a way for our battery to operate,” he said.
ERCOT said it plans to hold one or two workshops addressing energy storage issues, likely following the March spring break season. TAC Chair Bob Helton, of ENGIE, said the workshops will help determine whether to create a task force or turn the work over to stakeholder groups.
“We’re going to need a couple different set of rules for how batteries are operated, rather than shoehorning them into our existing software,” Reliant Energy Retail Services’ Bill Barnes said. “We encourage ERCOT to move forward [with the workshop] and get rules in place that make sense.”
ERCOT Director of System Planning Warren Lasher committed to previewing with the TAC at its next meeting a list of issues to be discussed during the workshops.
Reid was among several stakeholders urging ERCOT to hold the workshops as soon as possible. He reminded the committee that storage facilities are currently being registered in the market.
“The toe is in the water and batteries are hitting the ground, so the iron is getting ahead of the paper,” he said.
ERCOT’s RUC Activity Up over 2017
Staff’s annual review of reliability unit commitment (RUC) activity indicated a 14.2% increase over 2017, much of it to help resolve local issues with high load in the Permian Basin.
ERCOT’s 642 instructed resource hours in 2018 resulted in 613 effective RUC resource-hours, as compared to 562 and 534, respectively, for 2017. Staff said 22% of the effective resource-hours were bought back, resulting in a total RUC make-whole amount of about $460,000.
More than half of the total resource-hours came during the first half of May in the Permian Basin, where oil and gas production continues to drive much of the load.
In a separate required report, ERCOT’s Sean Taylor said the grid operator’s forecasted system administration fee of 55.5 cents/MWh for 2020 and 2021 will be “adequate.” Taylor said staff will provide an update when the commission weighs in on how it intends to fund real-time co-optimization.
Members Re-elect Helton, Coleman to TAC Leadership
The TAC re-elected Helton as chair and the Texas Office of Public Utility Counsel’s Diana Coleman as vice chair for 2019.
TAC Chair Bob Helton and ERCOT COO Cheryl Mele
The members also confirmed the leadership of its Protocol Revision (Chair Martha Henson, Oncor, and Vice Chair Melissa Trevino, Occidental Chemical), Reliability and Operations (Chair Kevin Bunch, EDF Energy Services, and Vice Chair Tim Hall, Southern Power), and Wholesale Market (Chair David Kee, CPS Energy, and Vice Chair Resmi Surendran, Shell Energy) subcommittees.
The Retail Market Subcommittee’s leadership will be confirmed at the TAC’s next meeting.
TAC Endorses PUC’s Changes to ORDC
Responding to a January directive from the Texas Public Utility Commission, the committee endorsed an Other Binding Documents revision request (OBDRR011) that modifies ERCOT’s operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity. (See Texas PUC Responds to Shrinking Reserve Margin.)
The change shifts the ORDC’s loss of load probability (LOLP) curve by 0.25 standard deviations in 2019 and by the same measure in 2020. The use of a single blended ORDC curve is expected to lead to its more frequent use, and at higher levels.
The commercial and industrial consumer segments abstained from the vote. So did Direct Energy’s Sandy Morris, who said she continues to have concerns about consolidating the curves.
In “respectfully” abstaining, Thompson & Knight attorney Katie Coleman, representing the Texas Industrial Energy Consumers, noted her association’s longstanding opposition to the change and its potential increased costs.
“We’re still not in favor of it,” Coleman said. “In addition to not being comfortable with the magnitude of the shift, we’re also uncomfortable with combining the curves. It amplifies the pricing impacts.”
The PUC asked staff to provide to the commission a high-level implementation plan and timeline during its Feb. 7 open meeting. The grid operator is planning a March implementation.
The TAC also endorsed NPRR871, which had previously been tabled. The revision request gives ERCOT a mechanism to conduct a reliability review of customer- or resource-funded transmission projects, but without providing a recommendation.
“We don’t want the review process short-circuited by the project’s source of funds,” said STEC’s Lange, who helped supply the NPRR’s final language.
Jeff Billo, ERCOT’s senior manager of transmission planning, told stakeholders the grid operator would follow its normal study process in conducting the review, which would take 90 to 150 days. Billo said should staff identify a reliability or congestion problem, ERCOT would have the authority to recommend the project not proceed.
The TAC approved six other NPRRs, a second OBDRR and two Retail Market Guide changes (RMGRR):
NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart and how activities will be settled.
NPRR886: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
NPRR910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives an RUC instruction.
NPRR911: Reinstates previous language in the applicable protocol sections for determining online combined cycle generation resources’ (CCGRs) logical resource nodes’ real-time LMPs, following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
OBDRR010: Codifies that the high sustained limit will be included in the ORDC pricing’s online capacity for resources that have been awarded a three-part supply offer in the day-ahead market, but decide not to operate in the real-time market and subsequently receive a RUC instruction. Related to NPRR910.
RMGRR156: Moves ERCOT-specific market communication responsibilities to the Business Practice Manual while retaining retail-specific market communications and processes in the RMG.
RMGRR157: Allows transmission and/or distribution service providers to give an internet-based solution for safety-net submittals.
The Senate Environment and Public Works Committee on Tuesday voted 11-10 along party lines to advance the nomination of Andrew Wheeler to be EPA administrator to the full Senate.
Wheeler, who has been serving as acting administrator since the July resignation of Scott Pruitt, was nominated to be the official head of the agency by President Trump early last month.
Republicans on the committee praised Wheeler for his work at the agency, while Democrats expressed concern about his efforts to roll back Obama administration policies on vehicle and power plant emissions — statements that largely echoed those made at his confirmation hearing Jan. 16. (See Dems Press EPA’s Wheeler on Climate at Confirmation Hearing.)
“It brings me no joy to say that he has not done what I had hoped he would do in a number of important respects,” Sen. Tom Carper (D-Del.), ranking member of the committee, said of Wheeler’s tenure as acting administrator. “In fact, in many instances, Mr. Wheeler has gone further than his predecessor in his rejection of important measures that are supported by a broad list of environmentalists and industry.”
Carper cited EPA’s proposal to rescind its finding under the Obama administration that it is “appropriate and necessary” to regulate hazardous air pollutant emissions from power plants under Section 112 of the Clean Air Act — a finding that led to the creation of the Mercury and Air Toxics Standards.
“In this MATS rollback proposal, EPA is willfully ignoring the actual benefits of reducing air toxics that permanently damage children’s brains and cause cancer, and ignoring the fact that the compliance costs were a third of what were originally estimated,” Carper said.
Ahead of the vote, Sen. Shelley Moore Capito (R-W.Va.) had raised concerns about a Politico report that Wheeler had signed off on a plan not to regulate two toxic chemicals, PFOA and PFOS, in drinking water. She joined 19 other senators from both parties in signing a letter Feb. 1 urging Wheeler to reverse that decision.
“Mr. Wheeler and his staff came to my office and addressed those concerns by pledging to look at all available statutory authorities EPA has been granted by Congress to address this potential crisis,” Capito said. “I intend to closely track the steps that EPA and other agencies are taking to address this public health and environmental health crisis, which has had a particular impact on West Virginians living in affected communities, to ensure that the federal government is sufficiently responsive to their concerns.”
CARMEL, Ind. — MISO filed new requirements on outage coordination last week despite the fact that some stakeholders still aren’t entirely sold on the plan.
The Wednesday filing seeks to impose new generator accreditation penalties for planned outages taken during what MISO deems “low-margin, high-risk periods” (ER19-915).
Speaking at a Reliability Subcommittee meeting Thursday, Jeanna Furnish of MISO’s outage coordination team said the plan will incent the forward scheduling of planned generation outages. She said the RTO is now revising its Business Practices Manual language to match the Tariff filing should FERC accept the proposal.
“Increasing forced outage rates for generation in the MISO region, together with a significant correlation in the timing of planned generator outages and derates, have caused resource risk outside of the traditional summer peak times. This has created a new paradigm, where generator owners can no longer simply schedule their outages around peak load times to avoid operating risk,” MISO explained in its filing.
The RTO’s proposal would require generation resources to provide 120 days’ notice for planned outages, although those scheduled 14 to 119 days in advance would be exempt from accreditation penalties provided they are scheduled during predefined periods with adequate margins. Penalties would apply to planned outages and derates scheduled fewer than 14 days in advance and occurring during a declared maximum generation emergency. The proposal also provides safe harbor provisions for resources if a planned outage is adjusted at MISO’s request.
MISO has also proposed a transition period for the new rules, which would exempt outages scheduled prior to April 1 from the accreditation penalty. Requests and revisions submitted April 1 or later for outages starting April 15 through July 29 would be exempt from the penalty if the request is submitted no later than 14 days in advance and MISO foresees “adequate projected margin at the time of the request.” The full set of outage requirements will go into effect for outages scheduled to start July 30 or later.
While the rules are considerably less strict than the ones MISO had originally proposed, some stakeholders were still calling for more lenient requirements up until the time of filing. (See Stakeholders Press MISO for Flexibility in Outage Proposal.) Other stakeholders were repeating calls for the RTO to improve its own load forecasting.
In comments to MISO, Ameren Missouri said the two weeks’ notice requirement should be reduced to just one week, “more commensurate with the load and weather forecasting accuracy.” DTE Energy also called for a seven-day notice requirement in addition to a request that MISO provide daily updates to its Maintenance Margin, a nonpublic member webpage that keeps a monthly forward account of how many megawatts can be taken out of service without affecting reliability.
At least one stakeholder still had bigger problems with the outage coordination proposal.
“Reforms have been focused solely on penalizing generation owners,” Exelon’s David Bloom wrote. “Instead, MISO and its stakeholders should continue to examine ways to improve MISO load forecasting or consider new or modified requirements to use existing tools like the Maintenance Margin.”
Exelon also criticized MISO’s requirement to count a full 24 hours of a planned outage as forced when it is scheduled without the two-week notice and during a generation emergency, even when emergency conditions persist for shorter periods. The proposal is still “unduly punitive,” Exelon said. MISO’s proposal assesses a forced outage penalty against resource accreditation for a minimum of 24 hours or the overlap between an outage scheduled without the two-week notice and emergency conditions, whichever is greater.
RENSSELAER, N.Y. — NYISO stakeholders learned Thursday that pricing carbon into the wholesale energy market would have little effect on corporate credit rules and that any necessary changes will only be discussed after a second-quarter vote on market design and Tariff revisions.
ISO Manager of Corporate Credit Sheri Prevratil told the Market Issues Working Group (MIWG) that, based on the current market design, the only potential change might be to adjust the projected true-up exposure timing of transaction settlements to reflect the true-up timing of emission charges.
“Currently, that particular [timing] requirement is triggered off only the four-month true-up as a percentage of the initial invoice,” Prevratil said. “Depending on the timing of when those carbon true-ups come in, it may impact [that] and we might have to make a change on the trigger to the final bill closeout as it relates to the initial or formal settlement.
“But that’s the only one that right now I see might have to change as a credit rule,” Prevratil said.
If necessary, such rule changes would likely have to go through the ISO’s Billing, Credit and Accounting Working Group, and potential credit rule changes would not delay implementation plans for carbon pricing, she said.
There may be more than one proxy generator bus at a particular interface with a neighboring control area to enable NYISO to distinguish the bidding, treatment and pricing of products and services at the interface. | NYISO
Energy Credit Components
NYISO will also evaluate potential adjustments in the external transactions component to account for carbon charges on imports and carbon payments on exports.
“Currently, we do anticipate that that carbon charge or carbon payment will just be a part of the daily net gains and losses, part of those calculations, and just summed up daily as the daily bill finalizes,” Prevratil said. “Carbon pricing will net in the daily advisory bill and will therefore net against daily energy purchases or sales in the Energy and Ancillary Services credit calculation.”
At the previous MIWG meeting, market participants expressed concern about a gross carbon charge that would be netted against the residuals in net cost, and that the resulting net amount would be further netted with all the other energy and ancillary services numbers that go into that calculation, she said.
The intent of the second part of the calculation is to capture changes, Prevratil said. “For example, we’re in a polar vortex right now. … If that run rate on average exceeds what we’re already holding, then you’re going to get a collateral call and it will be due two business days later. That will continue, but that’s a rolling 10-day run rate, so once those charges go down, then it will fall back to the first part of the calculation.
“We don’t anticipate changing the methodology of this,” Prevratil said.
The energy and ancillary services credit requirement equals the higher of the following:
The highest month’s price adjusted energy purchases in the prior equivalent capability period divided by the number of days in that month, multiplied by 16 days; or
The total average daily energy purchases incurred over the last 10 days, multiplied by 16 days.
New Tariff Sections
Pricing carbon into the wholesale energy market would require new Tariff sections related to applying a carbon charge, defining the social cost of carbon (SCC) and allocating carbon residuals, Ethan D. Avallone, senior energy market design specialist, told the MIWG.
NYISO’s Market Administration and Control Area Services Tariff (MST) would also require revisions to other sections, and subsequent Tariff presentations, including redline Tariff sheets, will build on the one considered at Thursday’s meeting, Avallone said. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)
As an example, Avallone pointed out, MST sections 7.2 and 7.4 would need to address emissions data reporting; section 17 would address the carbon component of the locational-based marginal price (LBMPc); section 23.3 would cover emission rates and reference levels under a carbon charge; and section 26 would cover any potential credit rule changes. NYISO will address those details when credit discussions begin this fall after approval of the carbon pricing market design.
Stakeholders asked what would happen to the ISO’s carbon pricing scheme if New York were to implement a carbon tax.
“We will follow what’s in the budget bill, and we will evaluate how it impacts NYISO’s efforts,” said James Sweeney, a senior attorney at the ISO. “We will make efforts in the Tariff such that entities don’t pay twice for carbon. How exactly it would be done is yet to be determined.”
The ISO foresees no revisions to MST sections 4.2 and 4.5, which describe day-ahead and real-time energy settlements, respectively, nor to guarantee payments such as bid production cost guarantees (BPCG), day-ahead margin assurance payments (DAMAP) and import curtailment guarantee payments.
NYISO’s current guarantee payment practices will continue under carbon pricing, Avallone said.
He emphasized that the ISO will charge each supplier on carbon emissions resulting from actual energy flows.
For example, NYISO will charge each supplier scheduling imports or pay each supplier scheduling exports the LBMPc at the relevant proxy generator bus, but the supplier will not be subject to a carbon charge or payment if the transaction fails in the ISO’s checkout process or is curtailed at the ISO’s request.
The latest NYISO schedule on carbon pricing calls for discussing LBMPc calculation and identifying marginal units on Feb. 15; Tariff revisions on Feb. 28 and March 18; and carbon bid adjustment for opportunity cost resources on March 4.
Xcel Energy last week reported that it once again met or exceeded its earnings guidance, posting year-end profits of $1.26 billion ($2.47/share), compared to $1.15 billion ($2.25/share) in 2017.
It was the 14th straight year the Minneapolis-based company had exceeded its own guidance.
Xcel’s fourth-quarter earnings were $215 million ($0.42/share), up from $189 million ($0.37/share) a year earlier. That met Zacks Investment Research’s consensus forecast.
Xcel continues to focus its efforts on clean energy. | Xcel Energy
Oil and gas production and strong economies in Xcel subsidiary Southwestern Public Service’s footprint drove a 1.3% increase in energy sales. The company expects flat sales in 2019, but it reaffirmed its 2019 earnings guidance of $2.55 to $2.65/share.
CEO Ben Fowke | Xcel Energy
CEO Ben Fowke said the company’s clean energy transition continues to be a strategic priority. He said the company’s steel-for-fuel strategy has achieved a 39% reduction in carbon emission from 2005 levels. The company has set an 80% carbon-reduction target by 2030 and a goal of 100% carbon-free energy by 2050.
“Technologies have come a long way in the last 10 years, and it gives me confidence that our 100% carbon-free bill can be met as well,” Fowke said during a Jan. 31 conference call with financial analysts.
Xcel secured approval for more than 1 GW of new wind in Texas and New Mexico and 300 MW of wind in South Dakota. It completed construction of its 600-MW Rush Creek wind farm in Colorado and also acquired 70 MW of repowered wind energy.
Investors on Wall Street applauded Xcel’s performance, driving the company’s share price up $1.22 to $52.14, a 2.4% increase. It hit an all-time closing high of $53.68/share in December.
