American Electric Power on Thursday reported strong fourth-quarter and year-end earnings in line with analysts’ expectations.
While results were dampened by the global trade wars and a stronger dollar, company executives said they expect the positive economic activity to continue in 2019.
AEP earned $363 million ($0.74/share) last quarter, compared to $401 million ($0.81/share) for the same period in 2017. Analysts had expected earnings of 72 cents/share, according to the Zacks Consensus Estimate.
Year-end earnings were $1.92 billion ($3.90/share), up from $1.91 billion ($3.89/share) the year before.
“Our strong earnings performance in 2018 was driven by a robust economy,” CEO Nick Akins said during a call with analysts. “2018 has clearly been a great year, but we’re even more pleased with our track record over the last eight.”
Akins said that over the past five years, the Columbus, Ohio-based company has provided a total shareholder return of more than 92%, greater than both the S&P 500 Index (50%) and the S&P 500 Electric Utilities Index (65%).
CFO Brian Tierney noted AEP’s performance would have been even better had it not been for its service territory’s higher exposure to tariffs. He said 38% of all U.S. exports originate in AEP’s 11 regulated states.
“The early-year performance carried us through the headwinds,” Tierney said, referring to the company’s benefits from tax reform.
AEP’s service territory | AEP
The company expects positive economic activity to continue in 2019, fueled by oil and gas development in its western footprint.
AEP’s stock price opened at $77.10 on Thursday and closed at $77.74. It has gained 11.5% over the past year.
CARMEL, Ind. — State regulators in MISO and SPP are making progress on the seams issues that continue to vex the RTOs, but much work remains, MISO stakeholders learned Tuesday.
The Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC) have been meeting since mid-2018 to discuss interregional coordination, which has never produced a major project, frustrating some stakeholders and causing market inefficiencies. Regulators last year initiated meetings with RTO officials to ask for solutions. (See Regulators Examine MISO, SPP Seams Issues at NARUC.)
The RTO’s market-to-market process has resulted in more than $51 million in payments from MISO to SPP since March 2015, compensation paid to manage congestion at the seam. The grid operators also face possible renegotiation next year of the 2016 settlement agreement addressing compensation for energy transfers between MISO Midwest and South above the current 1,000 MW of contract path capacity on SPP transmission.
Speaking during a Jan. 22 update at MISO’s Informational Forum, Missouri Public Service Commissioner Daniel Hall said the RTOs experience “significant inefficiencies on the seams” that are both “philosophical and structural.”
“There’s a growing awareness that these seams issues are becoming more significant due to the diminishing reserve margins,” Hall said, adding that some “personality issues” between MISO and SPP staff may have contributed to past difficulties.
Hall said regulators from both regions have outlined goals of improving seams coordination through:
Better market-based transactions and operations across the MISO-SPP seam;
Equal consideration of “beneficial regional and interregional projects in transmission planning”;
“Timely interconnection of new resources that includes consideration of the dynamics of the interconnection queue in both RTOs”; and
Improved inter-RTO relations through state-led cooperation.
“There’s nothing earth-shattering here,” Hall said of the OMS-RSC coordination effort. “We want to reduce transmission constraints to benefit ratepayers.”
“No one is right or wrong where viewpoints don’t align. We strive to understand the drivers behind our differences. It’s not personal. … The best outcome for customers is the best outcome. Customers in all portions of an RTO footprint should benefit from RTO membership,” Hall said.
While Hall said the RTOs are already working on several coordination issues such as better emergency coordination and easing interregional project criteria, some seams issues — including regional through-and-out rates and pseudo-tied generation — are being left unaddressed.
OMS and RSC representatives will meet again in D.C. on Feb. 10 in conjunction with the National Association of Regulatory Utility Commissioners winter meeting. Hall said the two groups will discuss the need for additional questions for both RTOs and explore the possibility of requesting a FERC analysis or commissioning an independent analysis on the MISO-SPP seam.
MISO Plans Seams ‘Hot Topic’ Talk
RTO seams issues will feature as MISO’s first 2019 “hot topic” in-depth stakeholder discussion in March. Staff said the goal is to get policy-level input from stakeholders on how to best approach coordination with its neighbors.
Jeremiah Doner, MISO director of seams coordination, said the RTO’s physical central position in the Eastern Interconnection “introduces a number of different regulatory and structural models that we have to work with.” He cited the 11 separate RTOs, independent utilities, cooperatives and federal agencies that border their territory and have varying seams coordination agreements with the RTO.
MISO’s neighbors | MISO
Doner said MISO is looking for stakeholders to offer views on what they would consider optimal coordination and a more consistent model for seams coordination with both RTO and non-RTO neighbors. MISO would look to improve price formation, transmission planning and cost allocation along all its seams, he said.
Customized Energy Solutions’ David Sapper asked how MISO might improve its transmission sharing with SPP so that South capacity is not trapped because of the contractual limit on SPP transmission connecting that region with Midwest.
Doner said MISO is open to discussing changes to the contract governing the Midwest-South contract path, which can be altered beginning in 2021.
In a separate monthly market operations report delivered at the meeting, MISO said it is monitoring additional generation committed for capacity that became trapped behind the contractual constraint in December. MISO Executive Director of System Operations Renuka Chatterjee said the capacity wasn’t ultimately needed because load did not materialize.
MISO load averaged 75.5 GW in December and load peaked at 94.2 GW on Dec. 11. Chatterjee said it was a mild month for the RTO, except for a few cold days at the beginning. Rising coal and natural gas costs lifted real-time prices to an average $31/MWh, she said, up 21% from a year earlier.
Calpine’s modification of PJM’s energy price formation proposal emerged Wednesday as the first choice members will consider at Thursday’s Markets and Reliability Committee meeting.
In a series of votes that capped the 23rd meeting of the Energy Price Formation Senior Task Force (EPFSTF) on Wednesday, Calpine’s proposal won 73% support, besting PJM’s own proposal, which was supported by 57%. Almost three-quarters of voters also said they preferred Calpine’s proposal to the status quo.
Almost three-quarters of voters supported Calpine’s modification of PJM’s price formation proposal over the status quo. | PJM
The rule changes would affect shortage pricing, reserve products, synchronized reserves, secondary reserves and the alignment of the day-ahead and real-time reserve markets.
PJM’s proposal would replace the current stepped operating reserve demand curve (ORDC) with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties.
The RTO would increase the price for the initial horizontal segment of the curve to $2,000/MWh and replace the second step of the curve with a downward sloping segment valued at $2,000 times the PBMRR.
Calpine supports the PJM proposal except that it would eliminate the RTO’s proposed transitional mechanism for the energy and ancillary services (E&AS) revenue offset used in the capacity market. PJM proposed the transition to reflect expected changes in revenues under the changes; as E&AS revenue increases, the net cost of new entry goes down.
Before the vote, PJM’s Adam Keech explained the RTO’s transition plan. Assuming FERC approval is received in the first quarter of 2020, PJM would implement the revised curve on June 1, 2020, with an $850/MWh penalty factor and move to a $2,000/MWh penalty factor starting June 1, 2023, for the 2023/24 delivery year.
PJM proposed adjusting the energy and ancillary services (E&AS) revenue offset used in the capacity market based on simulations of energy and reserve market outcomes. | PJM
Keech said PJM would simulate energy and reserve market outcomes based on actual operating conditions and use the results to adjust the E&AS offset. The simulations would be used to “scale” the revenues used to determine the offset, Keech said.
More than 230 task force members cast votes on the proposals.
The D.C. Office of the People’s Counsel proposed a similar ORDC to PJM but would treat the impact of the regulation requirement differently. It received only 5% support.
The Independent Market Monitor won 19% support for a proposal that would leave the ORDC unchanged and reduce the current two-step penalty factor ($850 and $300) with a single penalty factor equaling the safety net energy offer cap of $1,000/MWh. If PJM approves a cost-based offer above that price, the penalty factor could increase in $250/MWh increments to a maximum of $2,000/MWh.
No Shoo-in
Despite its seeming strength in Wednesday’s task force vote — which allowed members with multiple affiliates to cast multiple votes — Calpine’s proposal is no shoo-in. At Thursday’s MRC meeting, the voting will be subject to sector weighting, with no affiliate voting and a two-thirds threshold required for approval.
If the Calpine proposal fails to win the required supermajority, PJM’s proposal will be considered next. The Monitor and OPC proposals also could be considered if the preceding proposals fail.
The Members Committee is also expected to vote on the issue Thursday.
The Calpine and PJM proposals are likely to face opposition from at least some load interests.
Susan Bruce, attorney for the PJM Industrial Customer Coalition, said “the costs [the rule changes would impose on] energy-intensive customers are extreme.”
Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), complained that PJM had not provided enough information on the impact of the proposed changes on prices.
Keech said PJM ran two simulations and that the data has been available since September. “It would have been great if that desire [for additional data] was provided earlier,” he said.
“Since the very beginning, OPSI has been very clear that we wanted to see the cost impact of those proposals before we determine whether they are just and reasonable,” Carmean responded.
In a letter to the Board of Managers on Wednesday, OPSI asked PJM to delay action until stakeholders have time to evaluate additional data.
“PJM has detailed its concerns with current energy and operating reserve pricing mechanisms but has not justified the urgency of resolving these concerns, established the operational and cost effectiveness of its solutions, or adequately evaluated the risks and rewards of its proposed reforms,” wrote OPSI President Michael Richard, of the Maryland Public Service Commission. “It seeks to institute new market structures under an unnecessarily rushed timeline, allowing little opportunity for its staff to generate the analyses necessary for stakeholders to fully understand the potential impacts these proposals will have on market sellers and consumers, gauge the reasonableness of the proposals or develop alternatives.”
Ultimatum
The board told members last month that it will make a unilateral filing with FERC if they do not reach consensus on a package by Jan. 31.
Under current market rules, PJM says, inflexible generators such as coal, nuclear and large gas units are not permitted to set price. As a result, RTO officials say, LMPs do not accurately reflect the true cost to serve load when those units are running.
Inflexible units are those with declining average costs that are unable to economically produce power output within a certain range or have an economic minimum output that exceeds the amount of energy needed from the unit, PJM says.
The issue, which had been masked by upward pressure on prices from rising demand and the higher costs of marginal units, is now more urgent because low fuel prices and more efficient units have resulted in a generation mix that is less differentiated by cost and more by physical operational attributes, the RTO says.
It contends flexible units will benefit because the rule changes will eliminate a source of price suppression.
California Gov. Gavin Newsom named new members to the CAISO Board of Governors on Tuesday, along with a new member to the Public Utilities Commission and members of the state’s newly created commission on catastrophic wildfires.
To the CAISO board, Newsom appointed University of California Berkeley Professor Severin Borenstein and Los Angeles Business Council President Mary Leslie. He also reappointed current CAISO Chairman David Olsen to a second two-year term.
“This is an exciting time for the ISO as the industry develops approaches to reliably integrate renewable energy,” Borenstein told RTO Insider in an email. “The board will have an important role facilitating opportunities for beneficial trade with the rest of the western market and continuing to support California’s climate goals.”
The five-member CAISO board will have to grapple with major issues this year, including the ISO’s new reliability coordinator role for much of the West. Service on the CAISO board pays $40,000 per year.
Borenstein has been a professor at Berkeley’s Haas School of Business since 1996. He serves as the faculty director of the business school’s Energy Institute. Previously he was a professor at the University of California Davis.
Leslie has been president of the LABC since 2002. She was the deputy mayor of Los Angeles under Mayor Richard Riordan from 1994 to 1995 and a commissioner at the Los Angeles Department of Water and Power from 2001 to 2003.
Challenges also await the PUC as it tries to deal with the fallout from PG&E Corp.’s collapse because of massive wildfire liability.
Newsom named Genevieve Shiroma, an elected director of the Sacramento Municipal Utility District, to fill the seat on the PUC left vacant when Commissioner Carla Peterman’s term expired in December.
Shiroma was a longtime member of the state Agricultural Relations Board and its former chairwoman. She was chief of the Air Quality Branch at the California Air Resources Board from 1990 to 1999 and an air quality engineer from 1978 to 1990.
The PUC position pays $153,689. Newsom’s nominees to the PUC and CAISO require State Senate approval.
Newsom appointed Peterman to an unpaid seat on the state’s new Commission on Catastrophic Wildfire Cost and Recovery, established as part of last year’s Senate Bill 901 to examine wildfires caused by utility infrastructure and “to produce recommendations on changes to law that would ensure equitable distribution of costs among affected parties.”
The six-member panel is required to hold at least four public workshops and provide recommendations to the governor and State Legislature by July 1.
In her last meeting with the CPUC in December, Peterman emerged as a strong proponent of giving utilities leeway to de-energize transmission lines under dangerous weather conditions. De-energization “is an option we don’t want to exercise often, but we do want the option to exercise,” she said at the time. (See Calif. Regulators to Scrutinize De-energization.)
Joining Peterman on the panel is former State Assemblyman Dave Jones, the state’s insurance commissioner from 2011 until earlier this month. Jones previously served as counsel to U.S. Attorney General Janet Reno and worked from 1989 to 1995 representing low-income families and individuals for Legal Services of Northern California.
The commission will also include Crowell & Moring attorney Michael Kahn, who was CAISO chair from 2001 to 2005 and head of the California Electricity Oversight Board from 2000 to 2001. Kahn was also a member of the California State Insurance Commissioner Task Force on Environmental Liability Insurance from 1993 to 1994.
The legislature will fill the other three seats on the wildfire panel. Appointees do not require Senate approval.
SACRAMENTO, Calif. — Could PG&E’s announcement that it plans to file for bankruptcy Jan. 29 be a ploy? A lawyer representing thousands of wildfire victims said she thinks it’s quite possible.
On the steps of the California state Capitol Tuesday, former state Sen. Noreen Evans, now a plaintiffs’ attorney, said she believes PG&E won’t go through with filing for Chapter 11 reorganization at the end of the month, as it has said it would.
The utility’s move likely is an attempt to get California’s new governor, Gavin Newsom, and lawmakers to intervene, Evans said.
“I think there’s a very huge possibility they won’t file as planned,” Evans said. “It would open a can of worms.”
If PG&E, the state’s largest utility, were to enter bankruptcy, it would call into question billions of dollars in energy contracts and payments to CAISO, among other obligations. (See PG&E Meltdown Could Cost CAISO Members, Generators.)
Evans, whose former district includes areas of Santa Rosa, Calif., devastated by wildfires in 2017, is now part of a legal team representing 4,000 fire victims in the state’s catastrophic blazes during the past two years.
The ex-lawmaker joined famed PG&E foe Erin Brockovich at the Capitol to protest the utility’s alleged efforts to avoid financial liability for the Camp Fire, which killed 86 residents and destroyed the town of Paradise, Calif., in November 2018. The wildfire was by far the deadliest blaze in state history.
Brockovich urged California leaders to do more than have a seat at the table in deciding PG&E’s fate. “Be the head of the table and take control of this runaway monopoly,” she said.
Brockovich gained movie fame after she helped build a case against PG&E in the 1990s for polluting the desert town of Hinkley, Calif., with hexavalent chromium. She has remained one of the utility’s most prominent critics.
Brockovich, Evans and other victim advocates don’t want PG&E to enter bankruptcy because it would put plaintiffs and their lawyers in line for payment behind PG&E’s secured creditors. A bankruptcy judge would parcel out compensation, not jurors.
Investors, too, are arguing against PG&E’s bankruptcy plan. BlueMountain Capital, a major shareholder, sent the utility a second letter this week urging it to postpone filing for bankruptcy protection and arguing bankruptcy is unwarranted. PG&E shareholders would likely lose their investments in a Chapter 11 reorganization.
Evans and other PG&E critics, notably public interest group Consumer Watchdog, have said PG&E’s bankruptcy is a ruse to get state lawmakers to do what they wouldn’t do last year — get PG&E off the hook for billions of dollars in liability.
After the wine country fires of 2017 devastated Napa and Sonoma counties, PG&E lobbied lawmakers to overturn California’s longstanding use of inverse condemnation to hold utilities strictly liable, regardless of negligence, for damage to private property caused by their equipment.
Gov. Jerry Brown sided with PG&E last year because he was worried the giant utility would renege on the billions of dollars it plans to invest in renewable energy. In passing Senate Bill 901 last year, lawmakers didn’t alter inverse condemnation, but they provided a process by which utilities could seek long-term bond financing for wildfire debts. (See California Wildfire Bill Goes to Governor.)
The process, however, didn’t apply to 2018 fires, including the Camp Fire. Lawmakers initially showed interest in amending SB 901 to include last year’s fires but have recently backed off because of public anger against the utility.
Though state officials have yet to determine the cause of the Camp Fire, PG&E has said its transmission line sparked flames near the start of the Camp Fire on the morning it began.
PG&E announced earlier this month it would file for bankruptcy because it faces at least $30 billion in financial exposure for the Camp Fire and wine country fires. Absent state intervention, it said, bankruptcy was its only viable option.
SPP saw an increase in price spikes and overall prices during October and November thanks to above-normal scarcity pricing, according to the Market Monitoring Unit’s fall State of the Market report.
The Monitor attributed the scarcity increases to higher volatility in wind output, pointing to an increase in mid- and long-term wind forecast errors as the primary culprit. It also said a 72% increase in natural gas spot prices at the Panhandle hub ($2.13/MMBtu to $3.67/MMBtu) and unplanned generator outages or derates contributed to the uptick.
Volatility of wind output | SPP
Redispatch costs increase faster with more expensive gas until scarcity occurs, the MMU said, driving up the number of scarcity events.
“Since the scarcity caps are price-based, they are reached more frequently due to increased gas prices,” the report said.
The long-term wind forecast, used for the day-ahead reliability unit commitment’s wind output, had an average error rate of 7.8% in 2018, almost double the 2016 average of 4.3%. The mid-term load forecast, used four hours ahead of the intra-day RUC processes, had an average error rate of 4.5% last year, 28% higher than 2016’s average of 3.5%.
When large wind dips are not accurately forecasted, the market will often be short rampable capacity, the MMU said. This forces SPP operators to manually force more capacity online.
The real-time marginal energy price peaked at $1,575/MWh at 2:40 p.m. on Sept. 3. Operators responded to an unexpected sudden drop in wind output by adjusting the load offset and manually committing quick-start units. It took three intervals before prices dropped back below triple digits.
The Monitor said there is no “current answer for better forecasting” fluctuations in wind energy but noted a ramp product would “help abate these price spikes” by reducing their frequency and effects.
“By reserving ramp for unexpected conditions, such as wind drops or unit trips, the market will be better positioned when these events occur,” the MMU said.
SPP’s Market Working Group is coordinating staff’s development of a ramping product. Staff is currently testing different alternatives.
The fall report covers September, October and November. The MMU will host a webinar on Friday at 1 p.m. CT to discuss the report.
The report also indicates the following:
Energy prices have climbed slightly, with fall prices averaging around $27/MWh.
The number of intervals with negative energy prices continues to decline.
Overall congestion across the SPP footprint has declined.
Commission Welcomes Legislative Input on Energy Storage
Texas regulators last week agreed to let state lawmakers help them determine who will own energy storage devices in the ERCOT market.
DeAnn Walker, chair of the Texas Public Utility Commission, said during the commission’s Jan. 17 open meeting that she prefers to hear from legislators before developing rules, reiterating a position expressed in a recent report to the 86th Texas Legislature. (See “PUC Asks Legislators for Clarity on Battery Storage Ownership,” ERCOT Briefs: Week of Jan. 7, 2019.)
“If they don’t, we can circle back in June … because we or the legislature need to address this,” Walker said. “I’d like to give them the opportunity, because we asked them to weigh in.”
The PUC has already opened a rulemaking on energy storage ownership (Project 48023) after last year rejecting AEP Texas’ request to connect two West Texas battery storage facilities to the ERCOT grid. Transmission and distribution providers have squared off against generators over the devices’ ownership.
Walker said in the meantime she wants to start a discussion on electric vehicles and asked staff to open a project on the subject. She has suggested the PUC work with the Texas Commission on Environmental Quality in planning how the distribution system will support the charging stations’ infrastructure.
“There’s going to have to be a charging station in Marfa, Texas,” Walker said, referring to the artistic community of about 2,000 people in the West Texas desert. “No one’s going to be able to get from El Paso to [Austin] without one.”
Walker hopes to have recommendations ready for the next legislative session in 2021.
Prelim Order Sets Issues in Oncor-Sharyland-Sempra Deal
The PUC issued a preliminary order identifying issues to be addressed in proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services — but not before first chiding the parties for clouding the issue of who will own what and where (Docket 48929).
The companies in October announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)
“It would be helpful if you could file a table” listing the assets, Walker said. “Not a chart, because your charts make no sense.”
“We could have done a better job in our application setting forth exactly what we’re asking for,” said an apologetic Lino Mendiola, legal counsel for the Sharyland companies. “It’s a complicated transaction. We recognize that.”
Of specific concern to Walker is who will own the transmission assets necessary to integrate Lubbock Power & Light into ERCOT. The PUC last year approved Lubbock’s transfer of 70% of its load from SPP into ERCOT. Coincidentally, it came during the same meeting that Sempra’s acquisition of Oncor was approved. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
The transactions would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in Central, North and West Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest.
Mendiola said the geographic split between Oncor and Sharyland complicates the situation, but that the parties had worked out an 86-14 split of assets. Most of the transmission infrastructure would reside in the north with Oncor.
“Our group wants to ensure there are not things in the transmission rates that shouldn’t be in the transmission rates,” said legal counsel Phillip Oldham, representing Texas Industrial Energy Consumers, the lead intervenor in the proceeding.
A hearing on the merits is scheduled for April 10-12.
ERCOT Governance Changes Approved
The PUC approved by consent amendments to ERCOT’s Articles of Incorporation and bylaws (Docket No. 48677). The changes were approved by more than the necessary two-thirds of the grid operator’s corporate membership in September.
CARMEL, Ind. — With spring maintenance season approaching, MISO is opening the floor to encourage stakeholders to offer ideas to address the growing divide between resource availability and need.
MISO is commencing work on longer-term solutions in its multiphase resource availability and need project, focusing on possible revisions to its loss-of-load expectation study and load-modifying resource (LMR) accreditation. It is also exploring further changes to outage scheduling, new seasonal capacity modeling and a possible development of a seasonal capacity auction. Discussions on more major changes will continue through 2019.
During a Jan. 17 Market Subcommittee meeting, Chair Megan Wisersky said the discussions are now “de rigueur” at the large public MISO stakeholder meetings.
The RTO will this month also file a proposal requiring resources to provide 120 days’ notice for planned outages, with only one “limited adjustment” to the outage schedule allowed up to 60 days before it begins. Those outages would not be permitted during predefined periods with expected low margins.
MISO had planned by April 1 to implement a firm policy of considering outages scheduled during low-margin periods as forced, impacting a resource’s accreditation. However, the RTO is now pledging to grant an exemption to outages and derates starting between April 15 and July 29 if resource owners provide two weeks’ notice and “adequate margin is projected when requests are scheduled.” The revision comes after several stakeholders this month called for less stringent rules. (See Stakeholders Press MISO for Flexibility in Outage Proposal.)
MISO market design adviser Dustin Grethen said the Market Subcommittee should now shift focus to what’s needed to meaningfully improve price signals to spur more available and flexible supply. MISO may make at least two more FERC filings, one late this year focused on resource adequacy — if needed — and one in the first half of 2020 focused on new market mechanisms.
“The start of the 2016 planning year, we saw energy offers significantly drop. We used to see about 8 GW more in energy offers,” Grethen said, adding that since that time, MISO has used less traditional sources such as wind power and reserves to cover its load and supply requirements.
Grethen said the drop coincided with EPA’s rollout of the Mercury and Air Toxics Standards, which forced many coal-fired generators into retirement.
Some stakeholders debated whether MISO should extend its official calendar summer season, pointing out that the latest maximum generation event took place in mid-September, on a blisteringly hot day but still outside of what the RTO considers summer. Outside of MISO’s peak summer season, LMRs are not required to respond to emergencies.
MISO staff said the event technically occurred in what the RTO considers fall, despite the heat.
“Timing is everything,” Customized Energy Solutions’ David Sapper commented wryly.
Sapper urged MISO to incentivize more supply by staying away from solutions that include generator penalties. “I think you’ve heard from stakeholders that we want more carrots than sticks,” he said.
CES’ Ted Kuhn asked why MISO’s LOLE study doesn’t predict likely emergency frequency when the study projects other system conditions. He said the LOLE study could be redesigned to show when and where MISO will likely face tight operating conditions.
“When is the number of emergencies more than what we really plan on?” he asked.
Sapper asked if MISO might revive discarded market ideas, such as financially binding multiday commitments.
“I think a lot of that’s to be determined,” Grethen said. He added that any solution that MISO recommends will be supported by studies and simulations.
Grethen said he would return in February for a more in-depth discussion on long-term supply fixes and a formal request for solution submissions.
NEW ORLEANS — SPP staff have been tasked with providing “at least an outline” of comments next week for submittal to EPA in response to its proposed rulemaking under Clean Air Act Section 111b.
Usha Turner, OGE Energy’s director of environmental affairs and federal public policy, appeared before SPP’s Strategic Planning Committee last week to make the request, saying that the RTO’s role as a reliability manager “carries significance” on this issue.
EPA in December proposed revisions to a 2015 Clean Air Act rule stipulating that partial carbon capture and storage (CCS) technology was the best system of emission reduction (BSER) for new coal-fired plants. Turner said the changes would mainly revise CO2 emissions limits that apply to new coal plants but pointed out that the agency is also accepting comments on the need to revise the rule to allow more flexibility in operating simple cycle combustion turbines (SCCTs).
“It would be important for SPP to engage,” Turner told the SPC during its Jan. 16 meeting. “We found in talking with the EPA last year a lack of understanding of how this market works, and why the diversity and flexibility of resources and the diversity in technology is very important in your role of providing affordable and reliable electricity in your service territory.”
The comment period is open through Feb. 21. Turner said the deadline could be delayed, however, by the partial government shutdown.
Turner said SCCTs have a rolling 12-month efficiency-based generation output limit, but if a unit exceeds this limit, it must comply with combined cycle units’ CO2 limits.
“The rule establishes output-based restrictions for simple cycle units,” Turner explained. “If you operate those units above a certain capacity factor, you must meet the emissions standards of a combined cycle unit, which, by design, is unachievable.”
“This is a pretty substantial issue,” said Golden Spread Electric Cooperative’s Mike Wise, noting his company discussed the issue with EPA recently when installing its own CTs. “We’re concerned about these rules. The pool’s need for these resources shouldn’t be unduly constrained.”
“Our area is really a good laboratory,” SPP Vice President of Engineering Lanny Nickell said. “We should not be constraining these units that absolutely keep the grid’s reliability functioning properly.”
Nickell said he wasn’t sure whether the Feb. 21 deadline would provide SPP enough time to study the rule’s impact, but he said common sense told him that “new units, more efficient and economical, are being punished.”
“I believe that’s where we end up. We’ll see more emissions,” he said.
Michael Desselle, the RTO’s chief compliance and administrative officer, reminded the SPC about the organization’s agnostic view of resources.
“If there’s any advocacy we should be talking about, it’s to leave us the flexibility in the marketplace, and the RTO, for reliability purposes,” he said. “You need a diverse portfolio of resources.”
Steve Gaw, representing the Advanced Power Alliance (formerly The Wind Coalition), said he was concerned about a lack of analysis about the rule’s impact on the market. “I’m not sure SPP should be advocating for individual companies with varied interests,” he said.
Altenbaumer Continues to Exert his Influence
Larry Altenbaumer is playing a strong hand in his first year as chairman of SPP’s Board of Directors.
In the few months since replacing Jim Eckelberger last year, Altenbaumer has revamped board meetings, shortening the duration and focusing them on strategic discussions with members and the Regional State Committee. (See “Altenbaumer Tweaks New Governance Schedule,” SPP Board of Directors/Member Committee Briefs: Oct. 30, 2018.)
Pointing to stakeholder satisfaction surveys that indicate shortfalls in strategic planning, Altenbaumer said he wants to make better use of the opportunities for the board and its interaction with the Members Committee and the RSC.
Altenbaumer has also assumed chairmanship of the SPC. Long-time committee chair Wise is now vice chair.
Altenbaumer told the SPC he will also chair a task force on affordability and value, an initiative he has been pushing since last January. He hopes the group’s work will be incorporated into SPP’s 2020 operations planning and budget cycle.
“We’ll make an assessment in October this year about what further steps might need to be addressed,” Altenbaumer said.
The task force is scheduled to hold its first meeting on Jan. 30, following the board’s regular quarterly meeting. Altenbaumer said the meetings will be “quasi closed,” with each SPP member entitled to have one representative attend.
Outside groups will be invited to present best practices and their own successful experience within other organizations, Altenbaumer said. He said the group will identify ways to better communicate the task force’s efforts and will work to “keep the RSC up to speed.”
The task force will report to the board and also includes CEO Nick Brown and Directors Bruce Scherr and Julian Brix; Markets and Operations Policy Committee Chair Holly Carias, with NextEra Energy Resources; Wise; retired Director Harry Skilton; and member representatives Darrin Ives (Evergy), Jerry Peace (OGE Energy) and Jim Jacoby (American Electric Power).
SPP staff will continue to work with members as it struggles to provide a solid foundation for validating accurate network integration transmission service (NITS) data.
COO Carl Monroe reviewed staff’s 2018 efforts in surveying customers’ understanding of their responsibility to report NITS load. He said grandfathered agreements and behind-the-meter generation have hindered integrating the reported data.
Transmission customers are legally responsible for reporting their load, Monroe said, but this information may also be provided by meter agents. He said a single NITS contract can involve multiple pricing zones, with each zone comprising multiple delivery points, and that a single transmission zone can have multiple settlement locations.
Asked by Altenbaumer how close SPP is to where it should be in reporting the data on a 1-to-10 scale, Monroe said, “Eight or 9. I’m not sure it’s a 10, but that’s a Carl Monroe sense.”
While the work is not yet complete, Monroe said he is ready to facilitate a discussion with interested stakeholders to draft a revision request for mapping NITS data.
The D.C. Circuit Court of Appeals on Friday denied a petition by North Carolina to overturn several FERC decisions that kept the state from acquiring the system of dams on the Yadkin River (17-1243).
The state has been seeking the four dams collectively known as Yadkin Hydroelectric Project No. 2197 since 2009, when previous owner Alcoa announced it would close and dismantle the Badin Works aluminum smelting plant. The Yadkin Project had powered the plant, which at its peak employed about 1,000 workers, for almost half a century.
The High Rock dam, one of four that make up the Yadkin Project in North Carolina
Alcoa started curtailing production and laying off workers in 2002 amid a downturn in the aluminum market. By the time it applied for relicensing in 2006, Alcoa was only using 3 to 5 MW of the 210.5-MW project to power the plant.
In approving Alcoa’s application in 2016, FERC denied North Carolina’s proposal that the U.S. government acquire the project and transfer it to the state, saying the company had failed to maintain the jobs at Badin Works, which had been cited as a benefit in the project’s original 1958 license (P-2197).
“The state’s proposal — albeit creative — lacked any basis in the law,” D.C. Circuit Judge David B. Sentelle wrote in agreement with FERC.
The Federal Power Act allows FERC to recommend that the federal government take over, maintain and operate hydroelectric facilities after a license expires. “North Carolina does not and cannot identify a single case, statute or regulation to provide authority” for the federal government to transfer a seized project to a state government, Sentelle said. The judge noted that the state could have filed its own application for the project with FERC, negotiated a sale or initiated a condemnation proceeding of the project.
“Thriftiness and political pressure do not create a legal basis for federal recapture when its sole purpose is transferring the hydropower project to a state,” Sentelle said. “Indeed, none exists.”
North Carolina also challenged FERC’s approval of Cube Yadkin Generation’s $243 million purchase of the Yadkin Project in 2017, a challenge the commission also denied. The state alleged that Alcoa misled the state and other potential applicants for the project into thinking the company intended to continue operating Badin Works.
“Alcoa disclosed the curtailment of industrial production at Badin Works every step of the way, from its initial filing of intent to relicense, through its various correspondences with FERC, to the license application itself,” Sentelle said. “The loss of jobs from the closure of Badin Works is a dark and menacing cloud that hangs over the state of North Carolina. However, Alcoa did not conceal this impending squall and, thus, FERC did not err by denying North Carolina’s request to reopen licensing.”
The state attorney general’s office could not be reached for comment Monday because of the Martin Luther King Jr. Day holiday.
Though it is no longer the owner of the Yadkin Project, Alcoa still owns the land bordering the river, though it agreed to sell it as part of FERC’s approval of its relicense application. Local conservation group Three Rivers Land Trust is raising money to purchase an initial 2,310 acres of land by September so it will be granted an additional two years to purchase the remaining 2,390 acres.
