SPP’s Strategic Planning Committee and other stakeholders on Friday reviewed a draft of a staff-written response to FERC’s grid resiliency docket (AD18-7), agreeing that the commission should consider “the roles and relationships of all participants in the electric industry, not just RTOs and ISOs.”
In a conference call, staff invited comment on the draft and said they are considering raising other issues that affect resiliency but aren’t addressed in FERC’s questions.
Among the issues SPP said it intends to raise is whether FERC should involve others in the proceeding. The commission opened the docket in January, after terminating the Department of Energy’s proposed rulemaking that called for cost-of-service payments to coal and nuclear generators to strengthen grid resilience. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Staff’s draft response thanks FERC for being able to share its practices and perspective on resilience, but it also urges the commission to widen industry involvement.
“If [grid resilience] is so important to the nation, why are RTOs the only ones looking at it?” SPP General Counsel Paul Suskie asked.
SPP Chairman Jim Eckelberger agreed, suggesting FERC should be looking at the broader picture of how RTOs and ISOs interact with each other.
“If I were FERC, it wouldn’t be just the reliability of each RTO, but how can neighbors help neighbors?” he said. “If the point is efficiency in the national system, it ought to be highlighted.”
SPP is also suggesting that FERC consider cost-allocation and jurisdictional issues and determine who would pay for supplies necessary to protect resilience. SPP is asking for stakeholder feedback by March 2 so it can meet its March 9 filing deadline.
American Electric Power is among those that have already responded with input. AEP’s Jim Jacoby reminded those on the call that the resilience issue began with DOE’s call to protect coal and nuclear plants.
“All of this needs to be based on engineering studies and judgment,” Jacoby said. “We’re not for across-the-board subsidies by fuel type. We think solid fuel, or stored fuel, provides a lot of benefits, but you need to look at where that plant is needed and when it’s needed.”
SPP drafted its initial response using five teams of staff members, each addressing one topic: planning, operations, cybersecurity, compliance/NERC standards and legal/regulatory. The teams focused their work on how RTOs and ISOs should assess threats to resilience, and how SPP mitigates those threats. The teams held a conference call on Feb. 14 with FERC staff to discuss the issues.
“Clearly, we could build a grid where the lights would absolutely not go out,” Suskie said. “But I don’t think the public would want to pay for that.”
AUSTIN, Texas — ERCOT CEO Bill Magness found himself playing catch up during his Feb. 20 report to the ISO’s Board of Directors, revising a slide on the fly with the latest record for wind production.
“As is often true with wind records in ERCOT,” Magness said, pointing to Jan. 11’s 17,376 MW of wind generation, “that record has already been broken.”
At 10:05 p.m. the night before, the ERCOT system set its latest record by generating 17,541 MW of wind energy.
Looking ahead, Magness said tightening reserve margins following the retirement of more than 4.3 GW of generation make the upcoming summer “all about performance.” Including delayed projects and more than 3.8 GW of new resources, the ISO has seen its reserve margin shrink from 18.9% to 9.3%, leaving it with 77.2 GW of capacity on hand to meet a projected summer peak of almost 73 GW.
“We at ERCOT are doing everything we can think of with people and processes to prepare for what’s coming,” he said. “But I think everybody in the market is doing that as well. We all understand it’s about good performance.”
Additional resources, much of it solar and other renewables, are on the way. ERCOT received 196 interconnection requests last year, more than any year going back to 2007. Utility-scale solar projects accounted for 56% of those requests.
Magness reported a preliminary $10.8 million favorable variance in net revenues, driven by colder weather and under-budget project and hardware expenses.
He also shared what he called a “more tasteful” Super Bowl-related factoid than water usage during the game: the frequency increase in all three interconnections following a 20-second NBC Sports equipment failure that caused television screens to go black late in the first half. Magness said data from the Texas Synchrophasor Network showed that the loss of load was roughly the same as a large generator tripping, but with frequency up rather than down.
ERCOT staff also reported that it is addressing a delayed $2.4 million congestion revenue rights system upgrade with additional vendor resources and increased defect resolution.
“There is an urgency behind this,” said Mandy Bauld, director of ERCOT’s project management office. “We need the system to function because we need certainty around the auctions.”
Directors Grant ‘Critical’ Status to West Texas Project
The board accepted staff’s recommendation that it designate part of a West Texas transmission project as being “critical” to system reliability. The designation means a 345-kV line’s certificate of convenience and necessity application at the Public Utility Commission of Texas will be expedited — and its construction likely completed sooner.
Jeff Billo, ERCOT’s senior manager of transmission planning, told directors that load projections in the Permian Basin’s Delaware Basin — “The hot spot of hot spots,” he said — have grown from a peak of 22 MW in 2010 to a projected 964 MW in 2021. The project’s original study last year had a committed load of 533 MW in 2021.
“To say that this is load growth that we have never really experienced before is an understatement,” Billo said.
The board approved the transmission line as part of the Far West Texas Project last year. The $336 million project consists of two 345-kV lines necessary to support continued oil and gas development southwest of Odessa. (See ERCOT Board Approves West Texas Transmission Project.)
Oncor, one of three companies involved in the project, has submitted two additional projects to ERCOT’s Regional Planning Group, and is also pondering load-shed schemes to maintain reliability before the two upgrades are in place. Billo said Oncor was confident it could have the 345-kV line in service by 2020, if it was designated as “critical” to reliability.
The board also approved a resettlement of the Greens Bayou Unit 5 reliability-must-run agreement with NRG Texas Power, resulting in a $25,949.96 refund to ERCOT. The RMR contract was terminated in May 2017, but costs to NRG were allocated over 31 days that month, instead of the 29 days during which the agreement was in place. (See ERCOT Ending Greens Bayou RMR May 29.)
Board Re-elects Chairs, Confirms TAC Chairs
The board wasted no time in re-electing Craven Crowell and former PUC Commissioner Judy Walsh as its chair and vice chair, respectively. Crowell, an industry veteran and eight-year chairman of the Tennessee Valley Authority, and Walsh have served in their positions since January 2012.
The complete board then re-elected Magness as ERCOT’s CEO and ratified the ISO’s officers. The directors also confirmed the elections of Dynegy’s Bob Helton and the Texas Office of Public Utility Counsel’s Diana Coleman as the Technical Advisory Committee’s chair and vice chair, respectively.
Seven NPRRs Gain Unanimous Approval
Representing the Consumer Market segment, Director Nick Fehrenbach with the city of Dallas pulled a nodal protocol revision request (NPRR841) from the consent agenda over concerns it might result in unintended consequences for bid strategies in the day-ahead market.
The NPRR would correct an oversight in a previous change request (NPRR782) by revising the calculations used to determine the make-whole payment for incorporating the ancillary services infeasibility charge. Those charges are clawed back from generators that are unable to provide ancillary services because of a transmission constraint or through some fault not their own.
Fehrenbach said he wanted to avoid changes in market bid strategies “when there’s no longer the threat of that infeasibility charge” and requested staff monitor participants’ behavior.
“I want to make sure we don’t have a big upswing [in make-whole payments], and if there is, see if it has an impact on behavior or strategy,” he said.
Fehrenbach ended up making the motion to pass NPRR841, which carried unanimously.
The board approved six other NPRRs, including one designed to maintain ERCOT’s independence from FERC oversight, and a system change request (SCR) on its consent agenda:
NPRR819: Removes language referencing “data errors” for resettlement of the day-ahead and real-time markets; gives the ERCOT board authority to direct a day-ahead resettlement parallel to its authority to direct a real-time resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone.
NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
NPRR852: Creates a more efficient approval process when updating the CRR activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the Wholesale Market Subcommittee.
NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
NPRR861: Clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and its market participants with respect to FERC. Possible actions include but are not limited to ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.
SCR794: Updates how the security-constrained economic dispatch limit is calculated by ERCOT’s Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.
PUC Chair DeAnn Walker thanked the board for passing NPRR861, saying it was very important to her.
“Chairman Walker, as long as you’re happy, we’re happy,” Crowell said.
CMS Energy last week pledged it would phase out all coal generation by 2040, days after releasing 2017 earnings that were hampered by one-time adjustments relating to recent federal tax cuts.
Michigan-based CMS, which owns Consumers Energy, said the move will cut its emissions by 80%. The company also said it plans to generate 40% of its electricity from renewables and storage by 2040. By then, the utility will also heavily rely on natural gas, hydropower and improved efficiency to meet demand.
Consumers currently relies on an energy mix of 34% natural gas, 24% coal, 11% pumped storage, 10% oil, 10% renewable sources, 8% nuclear and 3% market purchases.
The utility began moving away from coal in 2016 by closing seven of its 12 coal-fired generating plants, eliminating 38% of its carbon emissions when compared to the company’s 2008 levels. (See CMS Touts Generation Reliability, Palisades PPA Replacement.)
The utility currently operates five coal plants, including three units at the 1,450-MW J.H. Campbell generating station in Ottawa County and two units at the 511-MW Karn generating station near Bay City, Mich.
Consumers Energy’s Karn/Weadock generating facility near Bay City. The Weadock plant (R) was retired in 2016. | Consumers Energy
Consumers said it will release a detailed timeline on its plans to phase out the remaining coal units and reach renewable goals in June when it files its integrated resource plan with the Michigan Public Service Commission. The commission requires regulated utilities to file an IRP once every five years, detailing how they will meet customer demand.
“Consumers Energy is embracing a cleaner, leaner vision focused primarily on reducing energy usage and adding additional renewable energy sources, such as wind and solar,” the company said in Feb. 19 statement announcing its plan.
CMS CEO Patti Poppe told the Associated Press that the company believes that climate change is real and it wants to be on the right side of history.
The company also announced new five-year environmental goals for its Michigan locations, including saving 1 billion gallons of water, reducing waste sent to landfills by 35% and restoring or protecting 5,000 acres of Michigan land.
“We’re proud and uniquely qualified to provide the strong leadership needed to protect our planet and our home state for decades to come,” Poppe said.
Consumers supplies power to 6.7 million Michigan residents, two-thirds of the state’s population.
2017 Earnings
CMS earlier this month announced 2017 net income of $460 million ($1.64/share), reflecting a charge associated with federal tax reform, compared to the $551 million ($1.98/share) reported for 2016. Last year’s figure reflected a one-time charge related to the federal tax cut passed in December. Without that charge, CMS would have earned $610 million ($2.17/share), at the high end of the company’s prediction.
Poppe said the tax cut will overall have a long-term positive impact on CMS’ business model, lowering customer rates and providing “headroom for necessary capital investments.” She also noted that CMS managed a 7% annual growth rate last year despite “atypical weather and [a] record level of storms.” The company predicts it will see a 6 to 8% annual growth rate throughout 2018.
Eversource Energy last week said it has the levers to keep earnings growing — with or without its troubled Northern Pass transmission project in New Hampshire.
The company on Feb. 22 reported full-year 2017 earnings of $988 million, up 4.8% from the previous year on a strong rate base and good results from its transmission business, which earned $391.9 million. The electric distribution and generation segment earned $497.4 million for the year.
Fourth-quarter earnings rang in at $237.4 million, up 3.6% from $229.2 million in the same period a year ago.
Humble Pie
Northern Pass route map | Eversource
During a Feb. 23 earnings call, CEO Jim Judge told analysts the company was surprised and “humbled” by the New Hampshire Site Evaluation Committee’s (SEC) Feb. 1 rejection of its Northern Pass transmission line, just one week after Massachusetts awarded the project its solicitation for 9.45 TWh/year of hydro and Class I (wind, solar or energy storage) renewables. (See New Hampshire Rejects Permit for Northern Pass.)
Eversource partnered with Hydro-Quebec on the 1,090-MW line to bring up to 9.4 TWh of Canadian hydropower to New England each year for 20 years, starting in December 2020.
Massachusetts this month selected a transmission project proposed by Avangrid subsidiary Central Maine Power as an alternative if New Hampshire regulators fail to approve Northern Pass by March 27. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
Lee Olivier, Eversource executive vice president for business development, said the company is confident that it can make a good case for Northern Pass if the SEC grants a rehearing.
CFO Phil Lembo said the company can sustain earnings growth of 5 to 7% a year with or without Northern Pass, and that the project was not dependent on any request for proposals.
Olivier said that Eversource partnered with Orsted to form Bay State Wind for the offshore wind solicitation in Massachusetts but was not yet disclosing the specific amount of investment involved. In December, the joint venture proposed a 400-MW or 800-MW wind farm 25 miles off New Bedford to be paired with a 55-MW battery storage facility. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Regulatory and Operational Highlights
Lembo said Eversource in January closed a $258 million sale for 1,200 MW of the remaining generation assets belonging to its Public Service Company of New Hampshire subsidiary.
The company in December merged its Western Massachusetts Electric Co. and NSTAR Electric subsidiaries and will no longer report the former as a separate unit, Lembo said. Massachusetts regulators also approved spending on grid modernization and energy storage, and a performance-based rate design effective Feb. 1, 2018. Eversource so far has invested $100 million in solar projects in the state.
Subsidiary Connecticut Light & Power last month filed a settlement with state regulators on a rate plan that proposes $154.5 million in increases over the next three years and a 9.25% return on equity, with the final figures to reflect a decline in the federal income tax rate to 21%. The company expects a decision on April 18.
FERC and ROE
The federal regulatory situation “remains unclear” as Eversource and “the other New England transmission owners continue to litigate the fourth transmission ROE complaint before FERC,” Lembo said.
| Eversource
Hearings were held in December and an administrative law judge decision is due next month, he said.
“Meanwhile, we’re awaiting a ruling from the commission on how they will address the court-ordered remand of their decision in the first complaint, as well as initial rulings in the second and third complaints,” Lembo said, adding that the earnings results reflect the current 10.57% base ROE the commission approved four years ago.
FERC last October rejected a bid by New England transmission owners, including Eversource, to increase their ROE to the levels in place before being reduced by a 2014 commission order that was vacated by an appellate court early last year. The commission said it would address the actual rate in a later remand order, but has yet to do so (ER15-414, EL11-66.)
The D.C. Circuit Court of Appeals ruled last April that FERC had “failed to provide any reasoned basis” for setting the base ROE at 10.57%, adding that the commission failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable. (See FERC Rejects New England Tx Owners on ROE.)
After fighting a decade-long battle against a billion-dollar lawsuit over retail rates, Entergy Mississippi is supporting a bill that would restrict the ability of the state’s attorney general to sue utilities.
Attorney General Jim Hood | Mississippi Attorney General
Attorney General Jim Hood is urging Mississippi residents to call legislators to vote against the bill, saying its defeat would ensure families remain protected against “greedy corporations.”
State legislators are considering a total three bills to limit instances in which the attorney general’s office can sue corporations on behalf of the state.
A bill introduced in the Senate would reauthorize funding for the Mississippi Public Service Commission, which faces a June 30 shutdown without reauthorization. However, Hood says new provisions in the bill attempt to impede his 2008 antitrust lawsuit over Entergy Mississippi’s rates by requiring him to first seek permission from the PSC before proceeding with legal action.
SB 2295 would give the PSC “exclusive original jurisdiction over the intrastate business and property of public utilities,” including “the establishment of retail rates; challenges, including customer complaints, to the amount of a retail rate or customer bill or whether such rate is just and reasonable; and challenges to the validity or accuracy of rates charged by a public utility, or to the accuracy or reliability of information submitted to the Public Service Commission by a public utility or other person in support of or in opposition to a proposed or approved rate, regardless of the legal theory upon which any such challenge is made.”
The Mississippi House of Representatives is considering two other bills that would also weaken the attorney general’s authority. HB 1238 would allow regulated entities to claim they do not have to abide by the Mississippi Consumer Protection Act because of other state and federal regulations, while HB 1177 seeks to bar the attorney general from filing suit and collect damages owed to the state, instead vesting that authority with state agencies and private citizens.
“These bills directly impact every Mississippian, and if they are signed into law, it would be devastating to everyone,” Hood tweeted on Feb. 21. Explaining why the attorney general is tasked with representing the state, Hood said state agencies “do not generally have resources needed to investigate and prosecute and could use different theories.”
But Entergy Mississippi is “strongly” backing SB 2295 and maintains the bill will provided needed clarity over which agency can regulate utilities, said utility spokesperson Mara Hartmann. Entergy Mississippi says it only supports SB 2295, not the other House bills.
The bill “includes language that reinforces and clarifies the 1956 law establishing the Mississippi Public Service Commission and making it the original jurisdiction for matters involving utilities,” spelling out that the PSC is the “proper forum” for state claims such as the attorney general’s “improper lawsuit” against the utility, Hartmann said.
“Now is the appropriate time to make the statute absolutely clear that the PSC is the body to regulate utilities,” she said. She also noted that the attorney general is allowed to participate in any PSC proceedings.
The Lawsuit
It’s not yet clear if the bills would affect Hood’s ongoing antitrust lawsuit against Entergy Mississippi. Hood filed the lawsuit in 2008, alleging the utility engaged in deceptive trade practices when it forced customers to buy the most expensive electricity the company generated while selling the lowest-cost power to outside companies from 1998 to 2009, prior to the utility’s MISO membership.
Hood claims Entergy owes $1.1 billion in refunds to customers and additional penalties, though he’s fighting in federal court to obtain documents from the utility to strengthen his claims. Entergy Mississippi so far has resisted efforts to turn over documentation related to its fuel-procurement practices. The private lawyers now handling the case for Hood won $106 million in class-action damages a decade ago for Louisiana customers of two Entergy subsidiaries in Louisiana using similar arguments of overcharging. That case was settled by Louisiana utility regulators.
Hartmann says it’s ultimately up to the court to determine how SB 2295 would affect the lawsuit should the bill pass.
Hood takes a different view, predicting that Entergy would try to use the new provisions to get the lawsuit thrown out.
“This isn’t kids’ games and should not be dismissed as just partisan politics,” Hood said in a Feb. 21 press release. “This is a billion dollars of the people’s money. The legislators driving these bills are attempting to give taxpayer money to corporations. We don’t want to believe it, but you can see corporations writing our laws. This should shock the conscience of Republicans and Democrats alike. With a billion dollars on the line, no reasonable prosecutor would dismiss the possibility of bribes, kickbacks and campaign contributions being offered.”
The U.S. District Court for the Southern District of Mississippi last year said the “only thing exceptional about this case is how long it has lingered in the federal courts prior to the commencement of discovery. And the cure to that problem … is to proceed as expeditiously as possible to trial.” The court later denied Entergy’s motions to dismiss the suit. Hood hopes to bring the case to trial later this year.
Entergy Mississippi contends that Hood “improperly bypassed” the PSC when filing the lawsuit and that his allegations remain unsubstantiated. Hartmann also noted that the PSC and the Mississippi Public Utilities Staff audit energy purchases that Entergy Mississippi makes for its customers.
“Entergy’s customers already pay for annual audits of the company’s power purchases. The attorney general’s improper lawsuit has exposed them to the potential of paying legal costs on the same issue,” Hartmann said.
FOLSOM, Calif. — CAISO on Tuesday defended its deployment of gas price adders that have been activated frequently since last year in the face of cold weather, wildfires and concerns about pipeline outages.
The ISO implemented use of the adders — or scalars — in Southern California in July 2016 to address potential gas shortages stemming from the closure of the Aliso Canyon storage facility.
The scalars are intended to both aid regional generators in their recovery of their start-up costs and shift generation to areas in Northern California not affected by gas shortages. When activated in the real-time market, they boost the commitment proxy gas cost calculation to 175% of the day-ahead gas reference price, while gas prices in the default energy bid calculation are set to 125% of the day-ahead price.
The scalars “may not be the perfect tool, may not be the most sophisticated tool, but it’s the tool we have,” Guillermo Bautista Alderete, the ISO’s director of market analysis and forecasting, said during a Feb. 20 Market Performance and Planning Forum.
Since the scalars were implemented in July 2016, the price level of same-day gas prices in Southern California with the adders exceeded all but a very small portion of natural gas transactions, according to a CAISO staff presentation.
The scalars were deployed July 6-31, Aug. 4-7, Oct. 23-24 and from Dec. 7, 2017 to Jan. 31, 2018 — and again on Tuesday, when SoCal Citygate prices spiked to a four-year high of $25/MWh on cold weather, according to Natural Gas Intelligence.
Staff’s presentation showed that on Dec. 7, the 175% scalar shifted 2,000 MW from Southern California Edison to Pacific Gas and Electric to position the system to rely less on gas demand in Southern California. The ISO had lowered the scalars to zero on Aug. 1, 2017, after the initial summer increase, but in a Feb. 20 market notice it said it “will re-evaluate on an event-by-event basis the need for the gas price scalars adjustments.”
CAISO’s Department of Market Monitoring has recommended the ISO reduce or eliminate the adders, which it says last year caused $5 million in excess bid cost recovery payments to those resources, about $1 million of which came during Southern California wildfires, even though only a small number of market participants are using the scalars.
CAISO’s average 15-minute prices were higher than day-ahead prices in October | CAISO Department of Market Monitoring
There were high next-day gas prices and significant same-day price volatility at the SoCal Citygate delivery point on some days in the fourth quarter, but real-time gas scalars are ineffective at reflecting same-day price volatility, nor do they significantly change the order of unit commitment, the DMM said.
Bautista Alderete said the ISO is undertaking an initiative “to have a more comprehensive policy and permanent solution of how to handle these conditions on the system.”
AUSTIN, Texas — ERCOT stakeholders are once again raising the subject of real-time co-optimization (RTC) after a simulation of a recent market event showed that the ISO might have saved almost $60 million using the process.
Beth Garza, director of ERCOT’s Independent Market Monitor, shared her organization’s analysis of the scarcity event with the ISO’s Board of Directors on Tuesday. The grid operator would have saved $58.5 million over eight five-minute intervals had it been using RTC, she said.
RTC is the process of procuring energy and ancillary services simultaneously in the real-time market, with the intent of finding the most cost-effective solution for both requirements every five minutes.
“This was $58 million over 40 minutes, but every hour, there are hundreds of pennies and nickels and dollars that can be picked up,” Garza said.
On Jan. 23, real-time prices hit the energy offer cap of $9,000/MWh during two five-minute intervals. ERCOT blamed the spike on ramping issues because of cold weather and higher-than-expected load during early morning hours, but it also said resource adequacy was not a problem. (See “TAC Asks WMS to Investigate 2 Market Events,” ERCOT Technical Advisory Committee Briefs: Jan. 25, 2018.)
Using its own software and a simulation based on the security-constrained economic dispatch (SCED) 60-day report, the Monitor determined RTC would have capped prices at $7,500 during the event.
“Software is the heart of real-time co-optimization,” Garza said. “The magic was we got to move reserves. As we moved those reserves around, we moved away from fast-ramping units to slower-ramping units. By actively making decisions every five minutes, we were able to move reserves over to slightly less rampable capacity, freeing up lots of ramping capacity for five-minute energy.”
Garza made no secret of the Monitor’s advocacy for RTC, saying, “We had reserves. We had a shortage of energy. [With RTC], we could have made better choices about which units were carrying reserves and lowered energy prices.”
“This is an efficiency issue,” said Director Peter Cramton, a University of Maryland economics professor. “What you get with co-optimization is improved pricing and quantities of the resources … making the best use of existing resources in real time. That’s primary to our mission, and I think we should take it seriously.”
ERCOT staff pointed out that the Public Utility Commission of Texas has an open proceeding (Project No. 47199) investigating the use of RTC to address intermittent renewables and improve incentives for generators. The PUC has held two market reform workshops and gathered input on a wide range of potential improvements. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
PUC Chair DeAnn Walker made it clear that the commission is not ignoring the issue, pointing out that regulators requested a cost-benefit study in October.
“We’re doing this in a thoughtful way,” Walker said. “This is the cost, this is the benefit … we’re asking for true data. We’re asking for these studies to be done, in a thoughtful manner.”
ERCOT has already told the PUC it will cost about $40 million and as many as five years to implement RTC because of the project’s complexity and scope. Staff has said an RTC upgrade would touch as many as 13 ISO systems.
Year in Review
In reviewing 2017 market data with the board, Garza said load-weighted average real-time prices were up almost $4/MWh from 2016’s historic low, to $28.25/MWh. Those are the market’s highest prices since 2014, when the average was $40.64.
“We’re on the low end of prices,” she said, alluding to an average fuel index price of $2.98/MMBtu.
While energy prices have dropped since the ISO’s nodal market went live in 2010, spreads continue to exist among ERCOT’s various zones. Real-time energy prices in the Houston zone averaged around $32/MWh in 2017 but hovered around $25 in the west, with its plentiful and cheap wind energy.
ERCOT’s costliest constraint lies in the Panhandle, accumulating $140 million in congestion costs and preventing further West Texas wind from flowing into the system.
Garza said much of the congestion is related to construction, likening it to fixing the weakest link, and then the next weakest link. She used another analogy that Austinites in the audience know all too well when she compared congestion to highway construction.
“As lanes are added, congestion increases during construction,” Garza said. “It’s not uncommon for capacity to be reduced before you see a big expansion.”
The Panhandle constraint is being addressed by several projects completed or nearing completion: a synchronous condenser that went into service earlier in the week, another condenser due to go online in April and a 345-kV circuit addition expected to be energized by March 1.
At the same time, the $590 million Houston Import Project is scheduled to be completed later this spring to allow more power to be imported from the north. ERCOT staff are also closely watching the Lower Rio Grande Valley, where two dynamic reactive devices are expected to be in service later this year, addressing that region’s continued growth.
Garza said load-weighted costs for ancillary services have dropped from $1.23/MWh in 2015 to 87 cents/MWh last year, because “we’re buying the right amount of services at the right time.”
CAISO’s fourth quarter was beset by 15-minute market energy shortages and a significant shortfall in congestion revenue rights auction revenues, the ISO’s Market Monitor said Wednesday.
During a conference call to discuss its fourth-quarter market performance report, the Department of Market Monitoring said energy shortages or power balance constraints last quarter consistently pushed 15-minute market prices above day-ahead levels.
“That is not something that we typically see,” DMM Senior Analyst Gabe Murtaugh said. “These are really some interesting results.”
Average 15-minute system prices increased to almost $47/MWh in October — exceeding $750/MWh in almost 1% of intervals — but then fell in November and December. October’s 15-minute price averages were higher than day-ahead and five-minute market prices by about $4/MWh and $9/MWh, respectively.
Day-ahead and real-time prices in the fourth quarter closely tracked the “net load curve,” which represents load minus wind and solar output. High 15-minute prices during October occurred most often between hours ending 18 and 20, when net load was highest.
“Many of these high prices occurred in intervals when the supply of ramping capability bid into the market was fully utilized and the power balance constraint was relaxed,” CAISO said in the report. “Even when the load bias limiter was triggered, prices were often set by bids greater than $900/MWh.”
Load bias describes the last-minute adjustments an operator makes to the load forecast ahead of a market run to account for potential inaccuracies and inconsistencies in the forecast. Constraints in the 15-minute market drove up the ISO’s usage of the practice, a topic of continuing interest for market participants. During the call, the DMM declined to answer a question about whether the load bias usage was appropriate, saying it has raised the issue before and that the ISO is looking into it. (See ‘Load Bias,’ Prices Rise in CAISO Q3.)
CAISO’s Monitor said ISO’s Q4 congestion revenue rights payouts far exceed what it took in from the CRR auction. | CAISO Department of Market Monitoring
The department also said the ISO experienced $61 million in CRR auction “payment deficiencies” in the fourth quarter and $101 million for 2017. But not all market participants agree with the DMM’s take on the CRR auction, which is the topic of a highly scrutinized reform program by CAISO. (See CAISO Overhauling CRR Auctions.)
In the fourth-quarter report, the department said there was heavy north-to-south congestion in the day-ahead market, primarily because of planned outages in Southern California. The congestion pushed up day-ahead prices in Southern California by about $2/MWh and decreased prices in Northern California by about the same amount, the Monitor said.
FERC on Tuesday approved an uncontested settlement to raise ISO-NE’s peak energy rent (PER) adjustment, resolving the issues the commission set for hearing in a 2017 order finding that the mechanism had become unjust and unreasonable because of the interaction between it and higher reserve constraint penalty factors (EL16-120, ER17-2153).
Under the settlement, ISO-NE will increase the PER strike price for each hour “by the amounts that actual five-minute reserve shadow prices exceed the pre-December 2014 reserve constraint penalty factors (RCPF) values for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively).”
The change will be applied from Sept. 30, 2016 — the date of the initiating complaint by the New England Power Generators Association (NEPGA) — through May 31, 2018, the last day of the capacity commitment period for Forward Capacity Auction 8.
| ISO-NE
The commission’s Feb. 20 order directed ISO-NE to make a compliance filing reflecting the settlement.
NEPGA had asked the commission to apply the revised PER and any resulting refunds to capacity suppliers to an Aug. 11, 2016, scarcity event, but the commission rejected the request in November 2017, saying it would impose “an unforeseen and significant increase in costs” to load. (See Generators’ Rehearing Bid on ISO-NE Scarcity Rules Denied.)
The Feb. 20 order noted the settling parties did not agree on the application of the revised strike price methodology to FCA 9, the capacity commitment period from June 1, 2018, through May 31, 2019.
| ISO-NE
The New England States Committee on Electricity (NESCOE) contended that the new methodology should not apply because FCA 9 was held in February 2015 — after the RCPFs were increased, which allowed resources to reflect the change in their supply offers.
NEPGA countered that NESCOE’s position “would deny capacity suppliers the full extent of the relief granted by the commission.”
The commission chose not to resolve the dispute, saying it was “beyond the scope of this proceeding.”
FERC previously agreed to eliminate the PER adjustment effective with the capacity commitment period beginning June 1, 2019 (ER17-2153, EL16-120). ISO-NE said its Pay-for-Performance program and changes to the day-ahead energy market made the adjustment unnecessary beyond that date.
ISO-NE spokesman Matthew Kakley said the PER calculations will revert to the old method for FCA 9. “The existing Tariff language (not the revised settlement language) will apply,” he said.
NEPGA president Dan Dolan said on Thursday, “PER and the appropriate strike price level has been a persistent issue in the New England markets for years. The settlement and this order help provide some certainty and stability as the market transitions to the elimination of the PER concept beginning on June 1, 2019.”
FirstEnergy CEO Charles Jones said Wednesday the company’s floundering FirstEnergy Solutions (FES) merchant generating arm is now under a death watch and that, in his “simple view of the future,” coal and nuclear generation will become extinct without market changes.
Jones told analysts on the company’s earnings call that “unless something is done to change the construct of these administrated markets, which have been administrated in a way to disadvantage coal and nuclear plants” and “unless the states step in to provide support, there will be no coal or nuclear plants left in these markets.”
During the call, Jones revealed the extent to which the company has cut ties with FES and that he expects the subsidiary will not survive the winter. He said FES has been operating independently since early last year and will no longer have access to its parent’s internal bank by the end of March, “and that will be the last tie that we have with that business.” (See FirstEnergy Selling Merchant Fleet Despite NOPR.)
“While I can’t speak for FES, I will be shocked if they go beyond March without some type of a [bankruptcy] filing,” he said.
‘Personally Disappointed’
Jones said it would be up to the subsidiaries that own generation — FES, Allegheny Energy Supply and Monongahela Power — to determine whether they will bid into PJM’s Base Residual Auction in May. He also touched on the U.S. Department of Energy’s Notice of Proposed Rulemaking and other efforts that could provide support for the company’s ailing nuclear and coal-fired resources.
“I’m personally disappointed that the endeavors haven’t resulted in a meaningful legislative or regulatory support, given the importance of these plants to grid resiliency, reliable and affordable power and the region’s economy,” he said.
The company is also “not planning to make another attempt at Pleasants,” he said, referring to FirstEnergy’s recently abandoned plan to transfer ownership of its 1,300-MW coal-fired plant from Allegheny to Mon Power, where the plant would have received a defined return based on regulatory review. He said Mon Power would meet any supply needs through PJM’s markets while the company determines how to address a capacity shortfall in its most recent integrated resource plan. Another IRP is due in two years, Jones said. (See FirstEnergy Shutting down Unsold Coal Plant.)
FirstEnergy reported a fourth-quarter GAAP loss of $5.62/share based on asset impairments and plant exit costs of $2.4 billion (3.38/share), which included reducing the carrying value of Pleasants, fully impairing nuclear assets and increasing nuclear asset retirement obligations, said Jim Pearson, the company’s new executive vice president of finance. The company also took a non-cash charge of $1.2 billion ($2.68/share) related to the Tax Cuts and Jobs Act.
K. Jon Taylor, the new president of FirstEnergy’s Ohio operations, said the tax law’s elimination of bonus depreciation would add about $400 million to the rate base, but that depreciation was already scaling down to 40% in 2018 and 30% in 2019.
Adjusted earnings were 71 cents/share for the quarter, driven by a 23 cents/share year-over-year increase from the company’s distribution segments. Jones said operating earnings for the company’s transmission and distribution segments increased 14% in 2017, or 25% if the distribution modernization rider (DMR) in Ohio is included. The company is looking for the Public Utility Commission of Ohio to approve a $450 million distribution platform modernization plan to better gird against blackouts and to prepare for “smart grid technologies.”
Wired Future
To pump up its transition to becoming a fully regulated “wires” company, FirstEnergy plans to invest $10 billion in its distribution and transmission infrastructure by 2022, starting with 2018 operating earnings guidance of $2.25 to $2.55 per diluted share, with a long-term growth-rate projection of 6 to 8% through 2021, Jones said. He said that each year between $1 billion to $1.2 billion of that investment will be targeted to transmission. That excludes the DMR in Ohio and is offset by the corporate segment.
Jones was quick to squelch any thoughts that the company is profiteering in its regulated business.
“There should be absolutely no concern in the market about us overearning in Pennsylvania. And if there is any hysteria out there, you all are smart enough to know that there are people that trade off with the hysteria,” he said in response to a question on several rate cases in the state.
The company last month announced the sale of $2.5 billion in equity to investment companies, which included the formation of a “restructuring working group” to advise on any potential restructuring at FES. The group includes three FirstEnergy executives — Pearson, Leila Vespoli and Gary Benz — along with John Wilder of Bluescape Energy Partners and Tony Horton of Energy Future Holdings. The group serves FirstEnergy’s interests, while FES is overseen by its own board of directors. Pearson is also in charge of an internal company redesign known as FE Tomorrow.
Jones also bristled at suggestions that the cash won’t be enough.
“No additional equity through 2021,” he said. “I can’t believe it’s only one month after doing $2.5 billion that we’re already getting that question again, but there will be none.”
Changes at the Top
FirstEnergy also announced several changes to its board of directors and executive suite before the call on Wednesday. Donald Misheff, who has been on the board since 2012, was elected chairman effective May 15 to replace George M. Smart, while Sandra Pianalto became a director. Smart and William T. Cottle, both 72, are retiring in May in accordance with the company’s mandatory retirement-age policy.
From left: William T. Cottle, Donald T. Misheff, Sandra Pianalto, George Smart. Cottle and Smart are retiring from the board in May. Misheff is replacing Smart as chairman of FirstEnergy’s Board of Directors and Pianalto is joining the board. They will be tasked with leading the company through its major restructuring into a fully regulated transmission and distribution company. | FirstEnergy
Within the company:
Kevin T. Warvell became vice president, chief financial officer, treasurer and corporate secretary for FES. Previously, he was FES’ vice president of commercial operations, structuring and pricing and corporate secretary.
Christine L. Walker became vice president of human resources for FirstEnergy Service subsidiary. Previously, she was the executive director of FirstEnergy’s talent management.
Jason J. Lisowski became vice president, controller and chief accounting officer of FirstEnergy. Previously, he was the controller and treasurer for FES.
Donald A. Moul became president of FES Generation and chief nuclear officer. Previously, he was president of FirstEnergy Generation.
Charles D. Lasky became senior vice president of human resources and chief human resources officer for FirstEnergy Service. Previously, he was the senior vice president of human resources.
Steven E. Strah became senior vice president and chief financial officer. Previously, he was a senior vice president and president of FirstEnergy Utilities.
Sam Belcher became a senior vice president and president of FirstEnergy Utilities. Previously, he was president and chief nuclear officer for FirstEnergy Nuclear Operating Co.
Pearson was the company’s executive vice president and chief financial officer. Taylor was a vice president, controller and chief accounting officer.
