Public Service Enterprise Group (PSEG) is putting its solar and fossil fuel generation on the block as it seeks to transform into a primarily regulated electric and gas utility, company officials announced Friday during its second quarter earnings call.
In his presentation, PSEG CEO Ralph Izzo said the company is “exploring strategic alternatives” for its non-nuclear-generating fleet, which includes more than 6,750 MW of fossil generation in New Jersey, Connecticut, New York and Maryland, and 467 MW of solar generation in 17 states.
“Our intent is to accelerate the transformation of PSEG into a primarily regulated electric and gas utility — a plan we have been executing successfully for more than a decade,” Izzo said in a statement.
Izzo noted that separating its non-nuclear assets would reduce PSEG’s business risks and earnings volatility and that it would continue to improve its credit profile by investing in clean energy, methane reduction and zero-carbon generation. He said work is underway to market a potential transaction beginning in the fourth quarter of 2020 with closing sometime in 2021.
Izzo said a “shift in investor preference” toward owning regulated utility businesses without commodity exposure to merchant generation and related earnings volatility has been gaining momentum in the energy sector.
“We’re excited to explore the opportunities that will shape PSEG’s future,” Izzo said. “It is a future focused on advancing our business as a sustainable customer-focused provider of essential electricity and natural gas service, delivered by a regulated utility and contracted businesses.”
PSEG Generation’s Future
PSEG intends to retain ownership of its existing nuclear fleet under its PSEG Power subsidiary, Izzo said. Its nuclear fleet includes the 2,285-MW Salem and 1,173-MW Hope Creek Nuclear plants in Lower Alloways Creek Township, N.J., and part ownership in the 2,549-MW Peach Bottom Nuclear plant in York County, Pa.
Izzo said the Salem and Hope Creek nuclear plants produce more than 90% of New Jersey’s zero-carbon electricity and are a “cost efficient necessary component” of the state’s transition to 100% clean energy by 2050, which was outlined in the New Jersey Energy Master Plan finalized in January.
The New Jersey plants receive zero-emission credit (ZEC) state subsidies, he said, which added $0.02 a share in earnings in the second quarter. ZEC applications for the next three-year period are due in the fall with a decision by the New Jersey Board of Public Utilities (BPU) expected in April 2021.
“As we begin the second round of the ZEC program by filing our applications this fall, it’s important to note that the financial need for ZECs is more critical than ever,” Izzo said.
Hope Creek Nuclear Generating Station in New Jersey
PJM’s day-ahead power prices have remained in the mid-teens to low $20s per MWh most days during the second quarter, with recent temperatures in the mid-80s to mid-90s only causing prices to cross the $30/MWh threshold twice in the last 30 days in the PSEG zone.
Izzo said PJM day-ahead prices have declined from where they were just two years ago, when forward around-the-clock prices for the PSEG zone were approximately $30/MWh to just more than $25/MWh today. He said the lower prices reflect current market conditions, characterized by reduced loads, inexpensive natural gas and abundant generation.
“This market environment is the reality we face at our nuclear stations and is the driver behind ZECs,” Izzo said.
East Coast offshore wind areas and leases | New Jersey Board of Public Utilities
Besides its nuclear fleet, he said PSEG is continuing to evaluate potential investments in offshore wind, including a decision regarding the opportunity to acquire a 25% interest in Ørsted’s 1,100-MW Ocean Wind project later this year. (See Orsted Wins Record Offshore Wind Bid in NJ.)
The company is also evaluating participation in upcoming offshore wind solicitations in New Jersey and other Mid-Atlantic states. On July 21, New York opened a solicitation for up to 2,500 MW of offshore wind power generation capacity.
Earnings
Dan Cregg, PSEG’s executive vice president and CFO, announced a second-quarter profit of $451 million ($0.89/share), compared to $153 million ($0.30/share) last year.
Non-GAAP operating earnings were $404 million ($0.79/share), compared to $294 million($0.58/share) in 2019. The operating earnings beat the average estimate of five analysts surveyed by Zacks Investment Research of 59 cents per share.
PSEG expects full-year earnings in the range of $3.30 to $3.50/share.
Transmission Projects
Analysts on the earnings call asked about any transmission capital expenditures that could be on the horizon for PSEG.
Izzo said its subsidiary, Public Service Enterprise & Gas, continues to make progress on its portfolio of capital improvements, including several key transmission projects. In the second quarter, the company energized the second phase of its $739 million Metuchen-Trenton-Burlington Project and upgraded the transmission circuits between the Brunswick and Trenton stations.
The company also expects to complete work on a 6-mile upgrade of a 230-kV overhead transmission circuit running between the Aldene station and the Linden variable frequency transformer station by end of the 2020, having already completed approximately half of the project.
Most of the large transmission projects that came out of the PJM Regional Transmission Expansion Plan (RTEP) are “pretty much complete or near complete,” Izzo said. There is also the possibility of increasing transmission investment as New Jersey continues pursuing offshore wind.
“One of the things that the BPU is talking to all utilities, not just us, about is the possibility for accelerating some of the infrastructure programs that we want to do to help create some economic stimulus. And just given the age of our transmission infrastructure, and age of our gas infrastructure, that is something that could provide further opportunities for us as well,” Izzo said.
FERC and NERC have published a joint white paper sharing techniques that utilities can use to identify the manufacturers of equipment used in their computer networks, a response to concerns that systems could be vulnerable to cyberattacks by foreign intelligence services.
The paper focused on network interface controllers (NICs), components found in every computer with Internet access, that control connection to an Ethernet or wireless network. NICs in older computers are often found on expansion cards, but modern NICs may be built directly into a device’s motherboard.
FERC and NERC cited research demonstrating “numerous avenues” by which hackers can use NICs to compromise electronic systems. More important, however, was the prominence of devices made by the Chinese companies Huawei and ZTE, which together with their subsidiaries account for more than half of the global supply of NICs.
The two companies and other Chinese hardware makers are alleged to cooperate with China’s security services.
The white paper cited a report by the Defense Innovation Board that said “evidence of backdoors or security vulnerabilities have been discovered in a variety of devices globally” and that many of them “seem to be related to requirements from the Chinese intelligence community pressuring companies to exfiltrate information.” NICs are particularly worrying because they are so ubiquitous and because a buyer may not be able to tell at a glance that a piece of equipment contains hardware from a company under suspicion.
“If these obscurely labeled (or even unlabeled) components exist in an electric utility’s infrastructure, the same risks exist as if the hardware bore the logo of Huawei, ZTE or one of their well-known subsidiaries,” the report said.
Huawei, ZTE Are Longstanding Issues
The presence of hardware from Huawei and ZTE in the bulk power system is not a new topic. Sen. Angus King (I-Maine) asked NERC CEO Jim Robb last year whether he knew if any U.S. utilities had the companies’ equipment in their systems, with Robb admitting he was not sure. (See Senators Call for Urgency on Energy Cybersecurity.)
Since then the government has toughened its stance toward foreign hardware manufacturers, with President Trump earlier this year declaring a national emergency aimed at restricting the purchase of BPS equipment from suppliers suspected of connections with hostile governments. (See Trump Declares BPS Supply Chain Emergency.) NERC and the Department of Energy followed up on the emergency declaration in July: DOE filed a request forinformation asking utilities how they identify and mitigate supply chain vulnerabilities, while NERC issued a Level2 alert demanding data on transformer control and protection systems. (See NERC Issues Level 2 Supply Chain Alert.)
Huawei headquarters in Shenzhen, China. | Brücke-Osteuropa
The guidance from NERC and FERC is intended to help utilities investigate the hardware on their systems to find possible vulnerabilities, which some have complained about following NERC and DOE’s orders this year.
“It’s one thing for us to recognize and figure out who we bought from. … We probably have those records going back 10 years,” Mike Kormos, senior vice president of transmission and compliance at Exelon, said at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit in July. “But … [we] might have bought a transformer from one vendor, [and] who that vendor was using for subcomponents in that is something we don’t have, quite frankly.” (See Industry Seeks Clarity on Supply Chain Orders.)
Noninvasive Techniques Recommended
The white paper described several techniques for identifying NIC manufacturers from the equipment’s Media Access Control (MAC) address. This noninvasive technique does not require physical inspection of the hardware and therefore is less time-consuming and carries a lower risk of damaging important equipment or voiding its warranty.
The advantage of using a MAC address is that every piece of hardware in a system — including subcomponents like NICs — must have a unique MAC address, part of which is a string of characters identifying its manufacturer. Every hardware manufacturer is required to use one of a limited set of such strings. For instance, a MAC address beginning with “FC:E3:3C” always identifies a Huawei device.
Though this approach is useful, it is not foolproof: MAC addresses can be changed manually, conceivably allowing devices to obscure their manufacturers. NERC and FERC also warn that even noninvasive techniques run the risk of interfering with devices’ normal operation.
“Before implementing any approach detailed here, caution dictates complete testing in a non-production network to minimize or eliminate operational impacts,” the report said. “If a vendor of concern is identified, it does not confirm there is malicious activity in the network. Actions should be taken to determine if the device or component exhibits malicious activity.”
FERC has accepted settlements totaling $175,000 between SERC and Ameren, along with Ameren Missouri, for violations of NERC’s FAC-009-1 and FAC-008-3 reliability standards for establishing and communicating facility ratings (NP20-19).
SERC reported the settlements in a spreadsheet Notice of Penalty on June 30. The commission indicated in a notice on Thursday that it would not review the penalties, leaving the penalties ($90,000 for Ameren and $85,000 for Ameren Missouri) intact.
Both settlements arose from a 2017 compliance audit by SERC that involved facility “walk-downs” at Ameren’s Big River and Spencer Creek facilities and Ameren Missouri’s Peno Creek and Pinckneyville facilities. During the visits, SERC’s audit team found discrepancies between the facility ratings methodology (FRM) and the established element ratings at all four facilities.
In the case of the Big River and Spencer Creek facilities, the inconsistencies did not affect the facility rating, but SERC requested additional information to get a better idea of the scope of the discrepancies. In the resulting system walk-down, Ameren found that 2,816 out of 27,330 elements at 56 of 297 transmission facilities had incorrect ratings. Five of the affected facilities were found to have experienced exceedances of the correct ratings, totaling 62 over a one-year period.
Ameren Illinois linemen | Ameren
Similarly, the Peno Creek and Pinckneyville discrepancies led to a system walk-down in all of Ameren Missouri’s 63 generating facilities to check the physical components against the current system ratings. The utility found that 18 of its facilities had ratings that did not match its FRM, 10 of which had experienced exceedances in a single year — 762 exceedances in all.
SERC determined that the misratings had been in place since before June 18, 2007, when FAC-009-1 became effective. By the time the issues were discovered, the relevant standard was FAC-008-3, meaning that the discrepancies were assessed as a violation of both standards. Both Ameren and Ameren Missouri corrected their ratings, with the two companies finishing their corrections and returning to compliance in December 2018.
In both cases, the violations were determined to have posed a moderate risk and no harm was known to have occurred. Ameren and Ameren Missouri each implemented a number of mitigating measures. Ameren’s changes included the following:
Developing and implementing a change management process to capture any element and overall facility rating changes during planned and unplanned outages;
Hiring independent consulting firms to complete the transmission facility walk-downs;
Communicating the results of the walk-downs to SERC on a quarterly basis in 2018; and
Reverifying the walk-down results.
Ameren Missouri followed a more extensive mitigation that included the following steps:
Hiring consultants to perform walk-downs at 100% of its generating facilities to verify component ratings;
Revising its FAC-008 procedure to add a verification process for facility ratings by both the utility and an independent reviewer;
Establishing a weekly report of all maintenance jobs involving components that might affect FAC-008-3 compliance for review;
Establishing a point-of-reporting responsibility for all generating units, to be documented in the FAC-008 program documents;
Committing to conduct sample audits at three randomly selected energy centers every three years to ensure FAC-008-3 compliance; and
Completing an additional walk-down of all 63 generation facilities in the first quarter of 2020.
SERC awarded mitigating credit to Ameren and Ameren Missouri for their cooperation and settlement of the enforcement action and determined that there were no previous incidents of noncompliance to warrant increasing the penalty.
Dominion Energy announced Friday it is moving forward with its leadership succession plan, promoting Executive Vice President and Co-COO Robert Blue to president and CEO by Oct. 1.
The news came during Friday’s second quarter earnings call, with current Chairman, President and CEO Thomas Farrell continuing to lead the Board of Directors as executive chair. Farrell joined Dominion in 1995 and was promoted to president and CEO in 2006 and chairman in 2007.
Robert Blue | Dominion Energy
Farrell said the board believed it to be “an appropriate time to take the next step in our management transition” with the sale earlier in July of Dominion’s natural gas assets to Berkshire Hathaway for $10 billion and a path for the company to achieve net zero carbon dioxide and methane emissions from its power generation and gas infrastructure operations by 2050. Ferrell said there is no set timeframe for his new role as executive chair.
Thomas Farrell | Dominion Energy
“The primary goal of our succession planning process has been to ensure continuity of our strategy, public policy, corporate values and operational excellence,” Farrell said. “As executive chair, I will continue to represent the company, engaging with key stakeholders, industry groups and others that will be particularly focused on continuing to develop our strategic plan and Dominion’s leadership in the new clean energy economy.”
Blue joined Dominion in 2005 and has held several executive roles since his promotion to an officer in 2007, including vice president of state and federal affairs and president of Dominion Virginia Power. Prior to joining the company, Blue served as a counselor and director of policy for Virginia Gov. Mark Warner and a law clerk for the U.S. District Court in the Eastern District of Virginia.
Diane Leopold, executive vice president and co-COO, will become the company’s sole COO with responsibility for all of Dominion’s operating segments. Edward Baine was promoted to president of Dominion Energy Virginia.
Earnings
During Friday’s earnings presentation, Dominion CFO Jim Chapman announced the company reported a second-quarter loss of $1.2 billion ($1.41/share) on revenue of $3.59 billion, compared with a net gain of $54 million ($0.05/share) on $3.97 billion in revenue for the same period in 2019. He said the loss was impacted by worse-than-normal weather in its service territories and impairment-related charges associated with the cancellation of the Atlantic Coast Pipeline and Supply Header projects.
Operating earnings for the second quarter were $706 million ($0.82/share), compared with operating earnings of $619 million ($0.77/share) in 2019. The results beat Wall Street operating results expectations, with the average estimate of 81 cents per share for earnings among four analysts surveyed by Zacks Investment Research.
For the third quarter, Dominion expects its per-share earnings to range from 85 cents to $1.05 and a full-year earnings in the range of $3.37 to $3.63 per share.
Company Initiatives
After cancelling the long-disputed $8 billion Atlantic Coast Pipeline in July with its partner, Duke Energy, followed by the sale of its natural gas assets to Berkshire Hathaway, Dominion is now following its plan to grow its renewable energy capacity by more than 15% annually for the next 15 years. Farrell said the company has already achieved its 3,000-MW targets for renewable generation in service or under development in Virginia, a year and a half ahead of schedule.
He also highlighted Dominion’s growing solar portfolio, which makes it currently the third-largest owner of solar capacity among utility companies in the country. And Dominion’s pilot wind project off the coast of Virginia is scheduled to begin generating electricity in the third quarter, Farrell said, with the rest of the $8 billion, 2.6-GW full-scale offshore wind project continuing on schedule.
Energy Company Controversies
Recent bribery scandals involving two of the biggest energy companies in the country, Exelon and FirstEnergy, played into Friday’s earnings call. In the question-and-answer period, Farrell was asked about Dominion’s own contributions to 501(c)(4) nonprofit social welfare organizations and whether the company has any plans to modify its political lobbying strategies considering the federal investigations going on with Exelon and FirstEnergy.
He said Dominion has “fully disclosed” its 501(c)(4) contributions for several years. Over the last five years, the company’s contributions to 501(c)(4)s have been under $500,000, with 70% of that total going to an organization associated with American Petroleum Institute that supports pipeline projects.
“We have no intention of changing our practices because they are perfectly appropriate [and] completely compliant with every state in federal law by wide margins,” Farrell said. “We have nothing to be concerned about with respect to any of our political giving or giving to these so-called 501(c)(4)s.”
An agricultural hub of about 8,000 in the northeast corner of Iowa seems an unlikely choice for a state-of-the-art battery storage project, but the Department of Energy thinks it could become a template for other American towns.
The DOE is chipping in $250,000 on a $2.5 million, 2.5-MW battery storage pilot project in Decorah, Iowa, to increase the city’s capacity for rooftop solar. Alliant Energy will build the project; Sandia National Laboratories will provide technical support and collect data. The Iowa Economic Development Authority (IEDA) is also contributing a $200,000 grant.
Those groups, and others, will analyze the storage project’s operations, looking for a cost-effective model that can be used elsewhere on the grid.
Decorah Mayor Lorraine Borowski said the Decorah grid currently doesn’t have the capacity to accommodate future customer-owned solar projects. She said the town expects the battery will yield savings on avoided distribution system investments.
Alliant hopes to have the Enel X battery in service by the end of year, though COVID-19 has slowed development.
“This grid has become a lot more complex in the last couple of years,” DOE Director of Energy Storage Research Imre Gyuk said during a July 30 DOE webinar on the project. “We now have an appreciable amount of renewable energy … and for good reason because we need to worry about the world warming up and pollution … You can’t just put photovoltaics or other renewables on the grid without expecting disturbances.”
Gyuk said electric vehicles and on-site generation is also complicating once cut-and-dried load patterns.
Decorah’s “typical small Midwestern town” façade belies Iowa’s status as a storage trailblazer, Gyuk said. In 2006, he noted, Iowa Associated Municipal Utilities and the Iowa Stored Energy Project tried to install a 200-MW compressed air energy storage project in an aquifer before project leads discovered the sandstone terrain was unsuitable.
“It’s time for Iowa to get back in the game,” Gyuk said. But he said Iowa and other states still need appropriate regulatory frameworks to develop a grid containing high renewable penetration.
“What we look for is strong local support. You need a local champion,” Gyuk said of finding the right location in small-town Iowa. “You need people who are committed and will stick with the thing to make it work.”
Enel X battery storage | Enel X
The City of Decorah is providing leased space for the project in a public park.
Borowski said Decorah’s residents are often out-of-state imports and like-minded about a renewable-dominant future. And Decorah’s hard-rock topography of bluffs and hills makes line-building a challenge, Borowski said. She called the pilot program a “natural fit.”
Alliant Energy Solutions Engineer Sarah Martz said the Norwegian cultural hotspot famous for its eagle-hatching camera is on par to reach its distributed generation hosting capacity limit in a few years.
Rather than wait for the limit to approach, Martz said, Alliant wants to create capacity now in an innovative way.
Traditional line and substation upgrades to host the distributed energy could cost from $1 to $10 million, a wide range of uncertainty. The $2.5 million investment in the battery will have the added benefit of being able to manage voltage and real power flows on the circuit.
“Some of these hosting capacity issues cannot be solved by traditional line and substation upgrades,” Martz said, adding that voltage increases on a circuit still can’t manage backflows from distributed generation.
Martz said Alliant will also monitor the project to make a blueprint for other communities the utility serves.
“We really understand that you have to walk before you can run. We have to have these pilot programs for lessons learned,” said Brian Selinger, director of the energy office.
“Iowa really is on the cutting edge of the transformation of the grid,” Director of Iowa State University’s Electric Power Research Center Anne Kimber said. Iowa State also plans to study the project’s effectiveness. She said the real-world data gathered from the Decorah battery project and distribution system will be extremely useful.
“We can use the Decorah feeder data … to make better models to predict voltage stability under certain conditions,” Kimber said.
The university will also use the project to study battery health and performance over time.
MISO said last week it quickly regained control during its first maximum generation emergency July 7 during a lasting heatwave.
“Uncertainty in both load and supply, impacted by COVID-19, created some challenges that I think we successfully managed,” MISO Executive Director of Real-Time Operations Rob Benbow said during a July 30 Reliability Subcommittee meeting.
Since 2016, the RTO has not completed a single year without a maximum generation event, amassing 10 emergency events in four years. However, summertime emergencies are relatively rare for the grid operator, representing only two of the 10 events.
Benbow said MISO needed “abnormal and emergency procedures” from July 1 through July 20 to navigate tight conditions.
The RTO and its members operated under a hot weather alert July 1-10 and a capacity advisory and conservative system operations — where maintenance outages are asked to be put on hold — July 6-10.
MISO declared a maximum generation event July 7 as high temperatures collided with an unusually large number of unavailable generators in the RTO’s North and Central regions. The emergency lasted from about 1:00 to 5:30 p.m. Load peaked at 116 GW, below the 120-GW forecast.
MISO control room transmission map | MISO
Benbow said MISO anticipated the hot weather and communicated with its members as early as possible.
After the RTO had committed all available resources, almost all of the 600 MW in emergency resources called upon stepped up, he said. MISO also recalled some scheduled transmission outages during the day.
MISO maintained good communication with neighbors PJM, SPP, Tennessee Valley Authority and Southern Co. during the event, Benbow said. The RTO discussed temporarily raising the 2,500-MW MISO South to Midwest regional transfer limit with its southern neighbors, but it ultimately wasn’t necessary.
Following the July 7 event, the RTO again declared a hot weather alert July 16-20 for its Central region.
“Especially the North and Central regions were in the mid-90s for most of early July,” Benbow said.
He noted that MISO would return to the Reliability Subcommittee in August with more information on generation outages and emergency resource performance.
Multiple stakeholders said while the emergency declaration communications to members were clear, it was less clear when MISO terminated its conservative operations and hot weather alerts during July.
Some stakeholders asked if unavailable nuclear generation played a role in the emergency because nuclear plant operators tend to be older and more susceptible to severe COVID-19 infection. Benbow said while one nuclear plant was out during the emergency, he suspected it was “because of mechanical reasons.”
Mild June in MISO
June operations were a different story for the grid operator, with load peaking at just 107 GW on June 30.
June 2020 in the footprint registered at one degree Fahrenheit above NOAA’s 30-year average, according to MISO.
Low natural gas prices also kept prices low during the month.
“The real-time LMP was $18/MWh for the second straight month, a 25% decrease over 2019,” MISO Executive Director of System Operations Renuka Chatterjee reported during a July 21 MISO Informational Forum.
Chatterjee also said load — subdued by the pandemic since mid-March — has gradually begun to rebound. The RTO load bottomed out to about 10% below normal levels during May; the impact has since decreased to about 5%.
“June and July data suggests [that] COVID-19 impact on load and energy is diminishing due to warmer weather, recovering to more historical levels,” Benbow said.
MISO is still using its back-up control center at its Carmel, Ind., headquarters, he said. To date, no operators have tested positive for the novel coronavirus.
Benbow also said its non-core operations employees can now return to MISO offices on a voluntary basis. The RTO currently has no plans to make in-person work mandatory for non-operations staff, but it will likely reevaluate sometime in the fall if the pandemic crisis abates.
Meanwhile, MISO is still rearranging some generation outages after virus-induced barebones work crews caused some utilities to hold off on scheduled spring maintenance outages.
MISO Outage Coordinator Trevor Hines said the RTO is connecting with market participants to discuss rescheduling outages in the fall.
“If you have flexibility to adjust your outage schedule, please reach out to MISO,” he asked members.
Xcel Energy on Thursday reported improved second quarter earnings despite a drop in sales due to the COVID-19 pandemic.
Executives said the Minneapolis-based company had earnings of $287 million ($0.54/share) during the quarter, reflecting lower operations and maintenance expenses, lower income taxes and favorable weather that offset sales declines. That was an improvement from last year’s second quarter, when Xcel reported earnings of $238 million ($0.46/share).
Xcel said its operating companies’ weather-normalized sales for the quarter were down 7.1% compared to last year. Commercial and industrial sales were down 11.5%, but residential sales were up 5.4%.
While executives acknowledged they are seeing some positive economic signals, the company said in its earnings release that “there continues to be substantial uncertainty related to the impact of the COVID-19 pandemic on the remainder of the year.”
The Xcel Energy Center in Minneapolis is home to the NHL’s Minnesota Wild. | Xcel Energy Center
CEO Ben Fowke said Xcel is still on track with its financial plan and reaffirmed the 2020 earnings guidance of $2.73-2.83/share.
“We’ll continue to monitor and manage through the economic uncertainty of this pandemic,” he said.
Xcel recently proposed a $3 billion investment plan in Minnesota. The plan includes $1.8 billion of incremental capital expenditures for repowering wind turbines, a 460-MW solar facility and $1.2 billion of accelerated transmission, distribution and natural gas investment.
Fowke said the plan would create an estimated 5,000 jobs and add more wind and solar to its Northern States Power-Minnesota system.
Xcel’s stock gained 27 cents on the NASDAQ Thursday, closing at $69/share.
ERCOT’s Technical Advisory Committee continues to refine its virtual voting practices, reverting to a combined ballot to reduce the number of roll-call votes and make the best use of members’ time.
Last week, that resulted in the unanimous approval of a ballot loaded with 23 revision requests, two key topics/concepts from the Battery Energy Storage Task Force (BESTF) and seven other items.
Only two nodal protocol revision requests (NPRRs) were voted on separately during TAC’s July 29 meeting. Both were easily endorsed. NPRR984 adds a fourth standard contract term per year for emergency response service (ERS), and NPRR1020 allows energy storage resources with integrated loads that cannot be metered as designed to use internal sensors in calculating the loads.
ERCOT granted the latter change urgent status because it affects ongoing interconnections. The revision will be sent to the Board of Directors for its Aug. 11 meeting.
Staff added clarifying comments to NPRR1020 for the required annual audit of the congestion revenue rights’ (CRR) allocation methodology by the resource entity calculating its ESR’s auxiliary load value. They said their revisions “simply require the audit to confirm that the resource entity’s calculation of auxiliary load ‘does not understate the load value,’ rather than specifying a band of allowable measurement error.”
Tesla’s utility-scale storage plans in ERCOT are boosted by recent Protocol changes. | Tesla
ERCOT has estimated it will cost between $175,000 and $225,000 to make the change. Staff said resource limitations on software developers will delay work on the change until early next year. System implementation would also require revisions to the settlement metering operating guide.
NPRR1020’s sponsor, Tesla, said the urgent status will help it “achieve regulatory certainty and allow its investments to move forward.”
“I think we’ve got Tesla a level playing field with everyone else,” said Bob Wittmeyer, who represented energy-storage developer Broad Reach Power during the early stages of the revision request’s progress through the stakeholder process.
The measure passed without an opposing vote. EDF Trading North America abstained.
TAC endorsed NPRR984 28-1, with independent power marketer Morgan Stanley voting against the motion. Morgan Stanley representative Clayton Greer also indicated he would vote against tabling the change or moving it to the combination ballot, forcing the roll-call vote.
“I’ll vote no on everything with ERS,” he said.
ERCOT said changing the ERS standard contract terms would allow it to better align with typical seasonal conditions and help improve the service’s procurement.
Members, Staff Debate RR Development Budget
TAC approved two key topics/concepts (KTCs) from the BESTF, an initiative to address how to integrate ESRs into the ERCOT system.
Staff first had to allay stakeholder concerns that ERCOT is running out of time and money to incorporate the task force’s work, along with that of the Real-Time Co-optimization Task Force and other projects.
The Advanced Power Alliance’s Walter Reid called for the BESTF and distributed generation to be placed at the top of the ISO’s priority list of development projects
“The work the BEST Force has been doing to get batteries into the protocols needs to be finished,” he said. “We need to facilitate that [investment] … For DG, getting that done is critical.”
ERCOT currently allocates $4 million from its capital project budget to fund revision requests’ development. It has the flexibility to “exceed the target for priority needs,” spokesperson Leslie Sopko said in an email.
“We really do need to consider if there’s some way to relax that $4 million [limit],” Reid said.
Kenan Ögelman, the grid operator’s vice president of commercial operations, cautioned stakeholders against increasing the $4 million allocation.
“Expanding that doesn’t necessarily get [Reid] the relief he wants. The limits … are also resource limits,” Ögelman said. “You also have to look at expanding a budget in this environment of low interest rates and economic uncertainty. The only two options are to move dollars from elsewhere into the $4 million or expand the budget. I think you are at risk of moving dollars out of things ERCOT is doing behind the scene to deliver DG and BEST.”
Staff promised a prioritized list of projects on Aug. 3, with a follow-up discussion during a Protocol Revision Subcommittee meeting on Aug. 13.
The two endorsed KTCs are:
KTC 15-7: Restricts ESRs from withdrawing energy during a Level 3 energy emergency alert and addresses ancillary service responsibility compliance related to the charging suspensions.
KTC 15-8: Grandfathers NPRR989 ‘s reactive power requirements.
ERCOT Updates Price-correction Issue
Dave Maggio, ERCOT’s director of market design and analytics, told the committee staff expects to complete in two weeks a review of day-ahead and real-time market prices following the discovery of erroneous dynamic ratings for three 345/138-kV transformers.
Ratings from unrelated transformers were applied to the three transformers, possibly causing or missing congestion, on operating days between Feb. 12 and July 7, he said. Staff developed a software fix to resolve the issue on July 14.
ERCOT was able to issue a price correction for affected July 7 day-ahead prices. Should staff discover a need for price corrections during the historical period, which is outside the normal 30-day notification period, they will ask the Board of Directors to approve corrections, Maggio said.
Maggio said staff also discovered in May that a software glitch prevented the operating reserve demand curve (ORDC) from properly calculating certain resources’ capacity. Staff corrected the error with a software patch and conducted a detailed review of the ORDC calculations back to when it went live in 2014. They found no additional errors, Maggio said.
ERCOT staff is proposing a revision request to remove requirements that modify DC-tie load zones requiring board approval and a 48-month waiting period after approval. The issue stems from American Electric Power’s recent retirement of a DC tie near the Mexican border in South Texas.
“I think the majority of sensitivity around changes to typical load zone boundaries is because entities serving load to those areas potentially have long-term contracts,” said Reliant Energy Retail Services’ Bill Barnes. “There’s no load served there. It’s just used for export and import [of energy].”
TAC OKs Consent Agenda’s 23 Changes
TAC added NPRR1030 to the combination ballot after agreeing on a desktop edit provided by Greer. Or, as one member jokingly surmised, language provided by a ghostwriter.
The measure changes the CRR auction revenue distribution allocation methodology from a peak 15-minute settlement interval to load ratio share based on adjusted metered load totals for each month. It also makes parallel changes for the CRR balancing account and certain block load transfers for consistency and ease of implementation.
Greer offered language that provided market participants will not engage in DC tie export transactions “that are reasonably expected to be uneconomic in consideration of all costs and revenues associated with the transaction.” The language excludes CRR auction revenue distribution and CRR balancing account allocations.
By making clear such transactions would violate the Protocols, TAC was able to agree on accepting ERCOT’s comments, whose complexity extended to the measure’s implementation timeline from an estimated three months to 12 months. Staff corrected and clarified settlement formulas and corresponding variable definitions.
The edits will be temporarily “grey boxed” and eliminated with NPRR1030’s implementation.
The combination ballot included seven other NPRRs, a Load Profiling Guide revision (LPGRR), four changes to the Nodal Operating Guide (NOGRRs), four other binding document revisions (OBDRRs), a pair of changes to the Planning Guide (PGRRs), three revisions to the resource registration glossary (RRGRR) and one change to the verifiable cost manual (VCMRR).
It also included committee and subcommittee goals, a list of other binding documents and the 2021 meeting calendar. TAC will continue holding monthly meetings on the fourth Wednesday of the month to avoid conflicts with the Texas Public Utility Commission open meetings.
NPRR996: Aligns the Protocols’ hub bus names with the substation names within the ERCOT model.
NPRR1000: Removes the term “dynamically scheduled resource” from the Protocols.
NPRR1002: Establishes energy storage resource “single model” registration and charging restrictions during emergency conditions.
NPRR1003: Replaces all remaining references to the resource asset registration form (RARF) with more general language in anticipation of the RARF’s elimination.
NPRR1004: Creates a new process for determining the congestion revenue rights (CRR) auctions and day-ahead market clearing load-distribution factors by using load forecasting models and existing validation/error correction.
NPRR1015: Clarifies the market system’s submission and reporting changes necessary to complete NPRR863, implement changes to responsive reserve service (RRS) and add ERCOT contingency reserve service.
NPRR1016: Clarifies important reliability requirements for distribution generation resources (DGRs) seeking qualification to provide ancillary service(s) and/or participation in security-constrained economic dispatch.
LPGRR067: Streamlines the assignment of oil and gas profiles by eliminating current processes that are no longer applicable. The revision validates weather sensitivity only for non-interval data recorder electric service identifiers that request the oil and gas flat profile; removes the “TOU Schedules” and “Non-ERCOT Profile IDs” worksheets; and changes the distributed generation profile segment assignment process.
NOGRR195: Addresses the Texas Reliability Entity’s audit recommendations for ERCOT and modifies generator voltage control tolerance bands.
NOGRR208: Aligns the Nodal Operating Guide with the nodal Protocols as modified by NPRR1002. An alignment NOGRR for energy emergency alert will be filed following NPRR1002’s approval to align with the Protocols.
NOGRR209: Replaces all remaining references to the RARF with more general language to align with NPRR1003.
NOGRR212: Aligns the Guide with NPRR1016’s revisions and clarifies DGRs’ reliability requirements.
OBDRR018: Aligns the procedure for identifying resource nodes with NPRR1003’s changes by replacing all remaining references to the RARF with more general language.
OBDRR019: Aligns the requirements for aggregate load resource participation in the ERCOT markets with NPRR1003’s changes by replacing all remaining references to the RARF and updates the process’ change control process with similar other binding documents.
OBDRR021: Aligns the language in the calculation of RRS limits’ procedures for individual resources with the Protocols following NPRR863’s Phase 1 implementation. Also corrects inadvertent errors in the formulas for calculating droop performance to determine RRS limits.
OBDRR022: Incorporates minor edits to the initial other binding document previously approved in conjunction with NPRR933.
PGRR076: Changes the generation resource interconnection or change request (GINR) process to specify that the proposed commercial operations date in the initial GINR application must be at least 15 months after the date of the application; redefines the security screening study output; creates separate reports for the full interconnection study; coordinates reactive study; and clarifies when the dynamic data model should be submitted to meet the quarterly stability assessment prerequisite deadline.
PGRR079: Aligns the guide with NPRR1003’s changes by replacing all remaining references to the RARF.
RRGRR023: Establishes the guide’s provisions and requirements for ESRs identical to those already in place for generation resources and settlement-only generators.
RRGRR024: Aligns the glossary with NPRR 1003’s changes by replacing all remaining references to the RARF.
RRGRR026: Adds a new data point to support implementation of an interim solution representing DGRs and distribution ESRs in the ERCOT network operations model.
VCMRR029: Aligns the manual with NPRR1003’s changes by replacing all remaining references to the RARF.
NYISO has formed a selection subcommittee to find replacements for board members Tom Ryan and Jim Mahoney, whose terms are expiring, CEO Rich Dewey told the Management Committee on Wednesday.
“The process will be very similar to what we’ve done in the past, with the exception of the complications we have as a result of the pandemic and potential restrictions on when and how we can conduct the various interviews,” Dewey said. “If we need to push things a little bit later to accommodate a more effective in-person interview as opposed to doing it online, we will.”
Even if the process is delayed a couple months, the intent is still to have the new members on the board in April, he said.
Demand Curve Reset
The Analysis Group’s final report on the demand curve reset will be posted next week for review at upcoming meetings, along with the ISO management’s draft report, Dewey said. He encouraged people to read and offer feedback on the reports by the August 24 deadline, ahead of discussion at stakeholder meetings in October and a FERC filing in November.
Dewey also mentioned stakeholder concerns that projects coming through the pipeline were appropriately included in consumer impact analyses.
As part of its Grid in Transition initiative, the ISO in April recommended that it implement market design changes through 2024 regarding carbon pricing; comprehensive mitigation review; participation models for distributed energy and storage resources; enhancement of energy and shortage pricing; energy and ancillary services product design review; enhancement of resource adequacy models; revision of resource capacity ratings to reflect reliability contribution; and adjustment of capacity demand curves. (See “Planning the Future Grid” in NYISO Launches Fuel Security Effort.)
Dewey said the ISO had attempted to speed up project development by working on the items piecemeal, but some market participants requested a package approach instead, which the ISO will do.
He said they are committed to doing the impact analyses for the grid reliability and resilience and ancillary service shortage pricing initiatives and getting them to the market participants in the first part of September.
The last item Dewey brought up was the ISO’s project prioritization process in conjunction with the budget.
Because of a “very challenging” budget this year, Dewey said the ISO will not be able to complete implementation of its distributed energy resources software by the 2021 completion date. “So, we are going to move it to 2022,” he said.
Given the “challenging year,” the Management Committee also voted not to conduct a new cost of service study during late 2020-2021 to help determine whether to modify the 72%/28% cost allocation between withdrawal billing units and injection billing units.
Hot Weather Operations OK
The ISO has been operating satisfactorily through the heat and humidity of recent weeks, its first summer without Indian Point Two, the Somerset coal station in western New York, and the Cayuga generating facility north of Ithaca, said Vice President of Operations Wes Yeomans. “And we’re gaining operating experience with the very brand-new Cricket Valley 1,000 MW combined cycle plant … so we thought this would be an interesting summer,” he said.
A heat wave from July 4 to 11 caused record-tying high temperatures in the Syracuse, Rochester and Buffalo areas and a peak load of 29,902 MW, which was surpassed July 27 with a peak of 30,660 MW when another heat wave hit New York City. | NYISO
The state has had three heat waves in July — defined as three consecutive days of 90 degrees. “It feels like they’re all blending together at this point,” Yeomans said.
The first heat wave, between July 4 and 11, hit upstate in the Syracuse, Rochester and Buffalo areas, with cooler weather downstate. Buffalo hit 97 degrees for only the third time in 100 years. Syracuse had seven consecutive days over 90, only the fourth time that has happened in the last century, Yeomans said. The state saw a peak of 29,902 MW.
That changed later in the month with higher temperatures in southeastern New York, Long Island and New York City, he said.
A short heat wave in mid-July ended with a tropical storm across New York City, Long Island and Connecticut, which passed quickly “and was basically a non-event for the bulk power system,” Yeomans said.
The third wave in late July resulted in a peak of 30,660 MW on July 27. “At this point in time that’s the summer peak for 2020, but there’s still a lot of summer ahead of us, and we may exceed that,” he said.
The performance of the generation and transmission system infrastructure has been “fantastic,” he said, promising a more comprehensive hot weather operations presentation at the September Operating and Management committee meetings.
MISO and SPP regulators are close to asking the RTOs for improvements to transmission operations on their seam as their market monitors wind down a study on the subject.
The short list of recommendations could arrive at an opportune time, with both RTOs signaling a willingness to usher in a new era of cooperation.
The Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC) will discuss which recommendations could be most beneficial when their Seams Liaison Committee (SLC) meets on Aug. 10 and Sept. 14. Texas Public Utility Commission Chair DeAnn Walker, who leads the RSC side of the SLC, said July 27 that the committee is moving from the study phase to recommendation selection.
The MISO Independent Market Monitor and the SPP Market Monitoring Unit have recently summarized what they believe are the more effective actions the RTOs can take based on the study.
The SLC has indicated it will urge the RTOs to work together and quickly apply the easiest fixes that don’t entail major software upgrades. The improvements could include implementing a test based on the available flow relief an RTO can provide the other, an automated means to control power swings on constraints, and better testing and activation of flowgates near the seam.
The monitors said the RTOs cause large power flows on each other’s systems. Better managing them could save more than $30 million of the $150 million in annual congestion costs that the RTOs’ flowgates have accrued.
An Age of Teamwork?
SPP CEO Barbara Sugg has prioritized a better relationship with MISO since assuming her leadership position in January. That could bode well for the RTOs’ willingness to implement seams improvements, should the SLC recommend them.
During SPP’s quarterly stakeholder meeting July 27, Sugg said she’s “decided to take ownership of [seams issues] and work directly with MISO.” Sugg, joined by COO Lanny Nickell, has met several times with MISO CEO John Bear and President Clair Moeller.
“I have high hopes for the two companies working together to resolve issues on the seams and that the discussions will be very beneficial to both sides,” Sugg said.
“I commend her for working with John Bear on that relationship, which quite frankly has been lacking in the past,” Walker told SPP stakeholders. “Part of a goal of mine — and some of that has already been accomplished — has been better interaction between MISO and SPP staff, and now the boards.”
SPP Board Chairman Larry Altenbaumer concurred, saying the SLC “was a bit of a catalyst to try and foster an improved relationship at all levels with SPP and MISO.”
MISO also confirmed it was meeting with SPP senior leadership to “discuss opportunities to work more collaboratively on key seams items,” according to spokesperson Allison Bermudez. She said MISO looks forward to providing feedback on the recommendations and would possibly route some of them to stakeholder groups for solution development.
The monitors’ study also concluded that SPP should improve its modeling of MISO’s market-to-market (M2M) constraints. MISO, on the other hand, should eradicate its generator shift factor for low-voltage constraints and M2M constraints, the study said.
But the monitors didn’t find significant value in a joint dispatch model, saying the RTOs might save about $17 million per year, or 0.1% of the region’s total production costs. MISO Monitor David Patton said he believes that the benefits of joint dispatch aren’t being fully captured because MISO assumes optimized congestion management across the seams.
But Patton has said the RTOs could be close to implementing better interface pricing, if SPP will actively model MISO’s transmission constraints at the seams. Patton said MISO’s interface pricing with SPP could be better than its pricing with PJM because SPP is generally better at modeling the MISO transmission system than PJM.
“SPP has a pretty good depiction of the MISO system,” Patton said during July’s Market Subcommittee meeting.
Both monitors concluded this spring that a coordinated transaction scheduling process, like MISO uses with PJM, doesn’t stand to help much unless the RTOs rethink fees they impose on one another. (See Monitor Casts Doubts on MISO-SPP CTS Benefits.)
On the other hand, SPP’s MMU found that unreserved use charges are rare along the seams and don’t negatively impact the systems’ efficiency.
Charges that occur are usually because of outages or extreme weather events, MMU Executive Director Keith Collins said during a recent study update.
