Page 1206 – RTO Insider

February 25, 2018

PSEG Head Confident Nukes Will Get Support

By Peter Key and Rory D. Sweeney

Public Service Enterprise Group CEO Ralph Izzo expressed confidence Friday that his company’s five nuclear units will receive the price supports he contends they need to keep them running.

Speaking during PSEG’s fourth-quarter earnings call, Izzo said he was pleased with the progress of New Jersey legislation to support the three reactors the company operates in the Garden State (A2850, S877), but he cautioned that the bills’ fate isn’t guaranteed. (See related story, NJ Lawmakers Advance Latest Nuke Subsidy Bills.)

Izzo also said he expects PJM’s response in FERC’s resilience proceeding to include a proposal to allow large, inflexible generation like nuclear units to set LMPs rather than seek out-of-market “uplift” cost recovery (AD18-7). “There have been very public conversations and statements by PJM that they believe, in particular, [that] their inflexible unit challenges are things that need to be corrected in the market,” he said.

Fourth-Quarter Rebound

PSEG reported net income of $956 million ($1.88/share) in the fourth quarter of 2017, compared to a loss of $98 million (-$0.19/share) in the same quarter a year prior. Its non-GAAP operating earnings were $289 million ($0.57/share), which beat the Zacks Investment Research consensus estimate by a penny and were up from $279 million ($0.54/share) the year before. PSEG’s revenue in the fourth quarter of 2017 was $2.1 billion, less than the Zacks consensus estimate of $2.36 billion, but slightly more than the $2.09 billion the company posted in the fourth quarter of 2016.

“We ended 2017 on a strong note with operating earnings for the year above the midpoint of our guidance,” Izzo said in PSEG’s earnings release. “The recent action by the board of directors to increase the common dividend by 4.7% to the indicative annual rate of $1.80/share is recognition of our financial strength and commitment to growth.”

PSEG enters 2018 “from a position of financial strength aided by a strong balance sheet, continued execution of our strategic growth objectives and tax reform,” Izzo said. “This is possible, despite the challenges we continue to face in wholesale power markets, especially at our nuclear plants.”

Public Service Electric and Gas, the company’s regulated electric and gas utility, was responsible for two thirds of PSEG’s non-GAAP operating earnings. “Despite the challenges we continue to face in the wholesale markets, especially at our nuclear units, the continued successful investment in regulated programs have provided reliability and quality service to our customers,” Izzo said.

Warnings on Nuclear Plants

Izzo’s rosy words about the company’s financial state were tempered by his warnings about the state of its nuclear operations: three generation units at Hope Creek Generation Station and Salem Nuclear Generation Station in New Jersey and two units at Peach Bottom Atomic Power station in Delta, Pa. PSEG shares ownership of Peach Bottom and Salem with Exelon.

PSEG REV five-minute settlements market data confidentiality — PSEG CEO Ralph Izzo is confident his company’s nuclear plants will get support. The Salem Nuclear Generating Station is one of three nuclear power plants PSEG has stakes in.

The fleet had a capacity factor of 93.9% in 2017 and produced a record electric output of 31.8 TWh, up almost 8% from 29.6 GWh in 2016. But PSEG says its New Jersey nuclear units are profitable now only because of sales hedges that expire within two years.

The bills being considered by the New Jersey Legislature would make Salem and Hope Creek eligible for subsidies from a 0.4-cent/kWh charge to the state’s electric ratepayers if the Board of Public Utilities finds the units economically unviable.

Critics of previous versions of the bills have complained that PSEG hasn’t demonstrated that its nuclear plants are unprofitable.

Izzo insisted the legislation is needed and that the company will pull the plug on its nuclear plants if it isn’t passed.

“The loss of the approximately 32 TWh of clean electric energy produced by [PSEG’s] Power [unit’s] nuclear generation in 2017 would represent a severe setback to [New Jersey’s] ability to meet its clean-energy goals and result in crushing economic impacts due to resulting increases in electricity prices and major job losses,” Izzo said.

“But the risk of closure remains without a change in the financial condition of nuclear. To that end, Power recorded a $276 million increase in its asset retirement obligation liabilities at the end of 2017 to take into account a higher assumed probability of early retirement of its nuclear units.”

Izzo also was optimistic about other efforts that could increase the nuclear plants’ revenue.

“There’s multiple things going on at FERC that matter [to] PJM,” Izzo said in response to a question from an analyst. “There’s capacity market reform, there’s fast-start pricing, there’s price formation. So there’s multiple issues. … I think we’re all visiting with the commissioners and telling them how important it is. And I think we’re all seeing the same comments come out of PJM.”

PJM Stakeholders Debate Resilience Filing

At a special session of PJM’s Markets and Reliability Committee on Friday, stakeholders battled over what PJM’s response should be to FERC’s questions on resilience. Nuclear and coal proponents argued for rule changes on price formation and payments for “fuel diversity,” which would benefit aging coal and nuclear plants. Customers argued that fuel diversity should not be considered synonymous with resilience. PJM has until March 9 to file its comments.

FERC’s five commissioners all recently voiced their commitment to scrutinize any proposals purporting to address resilience. “It seems to me … that some RTOs are suggesting things that don’t necessarily [relate] to resilience,” Commissioner Richard Glick said at the National Association of Regulatory Utility Commissioners’ winter meetings on Feb. 13. (See Overheard at NARUC Winter Policy Meetings.)

February 25, 2018

FERC OKs Slash in Virtual Bidding Nodes for PJM

By Rich Heidorn Jr. and Rory D. Sweeney

FERC last week approved PJM’s proposal to reduce by almost 90% the number of bidding locations for increment offers (INCs), decrement bids (DECs) and up-to-congestion transactions (UTCs) (ER18-88).

Known as virtual transactions, these trades can be used to arbitrage price differences between the day-ahead and real-time markets and hedge financial exposure to physical positions. PJM contends that while the trading can mitigate supply-side and demand-side market power by allowing those without physical assets to compete with asset owners and load-serving entities, too many of the trades provide no benefit to the market and can increase market solution times and skew transmission flows.

FERC virtual transactions — PJM says more than 95% of UTCs offered into the market between 2012/13 and 2014/15 were at a price between +/- $10/MWh and more than half of the trades fell between +/- $1/MWh. The RTO said this trading pattern is “indicative of the low-risk positions that can be extremely lucrative without adding commensurate value to the market.” | *PJM*

Following a white paper published in 2015, the RTO won Members Committee approval for the changes in June. (See “Stakeholders Endorse Third Phase of PJM’s Uplift Solution Despite Opposition,” PJM MRC/MC Briefs: June 22, 2017.)

PJM’s proposal, filed last October, asked FERC to limit INCs and DECs to nodes where either generation, load or interchange transactions are settled, or at trading hubs where forward positions can be taken. The RTO said this would ensure the day-ahead market produces a resource commitment close to the set of resources required for real-time operations.

The changes reduced the number of INC/DEC trading nodes from 11,727 to 1,563, retaining all hub and interface nodes but eliminating some aggregate and generator nodes. Also retained were residual metered nodes — locations at which load settles the remaining portion of a zone that is not settled at a more granular aggregate location.

The new rules also eliminate zone, Extra High Voltage (EHV) and individual load nodes as trading points for both UTCs and INCs/DECs. Also barred from UTC trades are some interface nodes, while the number of eligible residual metered and hub nodes was increased. In total, the number of UTC trading points was reduced to 49 from 418.

Under the former rules, PJM said, some traders took very small, low-risk positions in the day-ahead market over weeks waiting for a single path to bind in real time. Others bid at locations with systematic price differences between the day-ahead and real-time markets because of a modeling difference between the two markets, according to the RTO.

“The extremely broad set of eligible nodes for virtual transactions that exist today also expose PJM market participants to increased financial exposure due to discrepancies between the day-ahead energy market and real-time energy market network models,” PJM said in its filing. “Something as simple as an inconsistent breaker status (open or closed) from the day-ahead energy market to the real-time energy market can create a systematic difference between day-ahead and real-time prices that provide a revenue opportunity for virtual transactions without the ability to provide any convergence between the day-ahead energy market and real-time energy market. Because individual nodes are more highly impacted by modeling discrepancies than aggregated locations due to averaging, they are often locations where virtual transactions can profit. Profits collected by virtual transactions in these cases lead to additional costs for PJM members without any benefits.”

day-ahead energy market virtual transactions FERC UTCs — Joe Bowring is PJM’s Independent Market Monitor | © *RTO Insider*

The changes were backed by the Independent Market Monitor and some generators and LSEs, but they were opposed by financial traders, who said it would lead to less efficient, less granular markets.

“With 80% of INC/DEC activity occurring at pricing nodes of type hub, zone and interface, according to PJM’s own empirical analysis, eliminating zone for INC and DEC virtual transactions can be disruptive to the market,” said Macquarie Energy.

Some opponents contended PJM had not made its case because it did not perform any quantitative analysis to compare the potential benefits with potential harms at individual load buses.

FERC sided with PJM, saying the RTO had provided sufficient evidence to support its proposal without such an analysis.

The commission said PJM’s proposal to remove zone nodes from INC/DEC trading will not significantly hinder market participants’ ability to manage exposure at the zones. “Given that market participants may bid at residual metered nodes and aggregate nodes where load is settled, they maintain a reasonable ability to manage their risk, including the risk of their day-ahead positions,” FERC said. “We note that market participants will continue to be able to hedge exposure at the zones on [Intercontinental Exchange] and Nodal Exchange and that PJM will continue to post LMPs at the locations where these futures contracts will settle.”

UTCs

Most of the commissioners also backed PJM’s reasoning for reducing UTC trading points. The RTO said UTCs create a divergence in either the source or sink location in 90% of occurrences. The transactions cannot reliably drive convergence in commitment, dispatch and pricing between the day-ahead and real-time markets because UTCs have no real-time equivalent, PJM said.

virtual transactions FERC day-ahead energy market — Ruta Skucas and Jared des Rosiers represent the Financial Marketers Coalition at PJM meetings | © *RTO Insider*

The Monitor said some traders had pursued a “penny bid strategy” — high volumes of low-risk, low-cost bids that can win large profits during low-probability events causing significant real-time price spreads. (See chart.)

Opponents of the changes insisted UTCs do have real-time equivalents in ISO-NE and ERCOT and noted that MISO and NYISO are considering adding UTC trading to improve price convergence.

The commission said it agreed with the Monitor that limiting UTC bidding to interfaces, zones and hubs “will minimize false arbitrage opportunities for UTCs currently being pursued through penny bids, as the effect of modeling differences between the day-ahead and real-time markets are minimized at these aggregates.”

FERC also agreed with PJM that reducing the biddable UTC locations should reduce the time to solve the day-ahead market, although it acknowledged the “reductions may be modest under most circumstances.”

“We acknowledge that the instant proposal may greatly reduce the opportunity to utilize UTCs in general, as well as the level of granularity at which UTCs can be utilized. We also acknowledge that the biddable points PJM proposes to delete may provide some value to the market,” FERC said. “We are not persuaded by protestors that forgoing some of the theoretical benefits associated with retaining the bidding points for UTCs at zone, EHV or aggregate nodes necessarily renders PJM’s proposal unjust and unreasonable.”

Commissioner Cheryl LaFleur dissented, saying PJM and the Monitor had “not demonstrated that eliminating certain types of biddable points is a targeted solution to address the problematic usage of UTC transactions.”

“UTCs can provide value by converging the congestion and losses component of LMPs and allowing market participants to hedge potential congestion,” she continued. “Given these potential benefits, I feel that moving in the direction of reduced granularity for the use of these products is a move in the wrong direction. However, I would be open to other solutions more targeted to the specific problems that PJM has identified.”

At the Markets and Reliability Committee meeting last week, PJM’s Adam Keech announced that staff had revised the list of biddable points to reflect the Feb. 20 order, but they planned to ask FERC how to address results since the order’s effective date of Jan. 16.

UTCs have seen explosive growth since 2011, in part because — unlike INCs and DECs — they were not assessed uplift costs. Last month, FERC denied PJM’s plan to allocate uplift to the transactions, another part of its three-phase solution to address uplift. The commissioners said it’s unfair to apply uplift to UTCs in the same way it’s applied to INCs and DECs (ER18-86).

PJM said last month that it believes FERC erred in its logic and might ask the commission to suspend UTCs until an approved solution can be worked out. (See “PJM Not Done on UTCs,” PJM MRC/MC Briefs: Jan. 25, 2018.)

February 25, 2018

Edison International Presses Wildfire Cost Recovery

By Jason Fordney

Edison International on Thursday joined other California utilities in protesting difficulties in recovering costs related to devastating wildfires, saying it will pursue “legal, regulatory and legislative” avenues on the issue.

During a fourth-quarter earnings call, Edison CEO Pedro Pizarro said the company faced “significant challenges in December and into January of this year due to wildfires and the related legal and regulatory framework in California.” He said the wildfires have increased in severity because of climate change, long-term drought and forest management policies that have led to a buildup of vegetation and dead trees. Eight of the state’s 20 worst wildfires having occurred in the last three years, Pizarro said.

The statements echo recent vows by Pacific Gas and Electric to fight for wildfire cost recovery. Both PG&E and Southern California Edison have asked state regulators to rehear a November decision denying cost recovery to San Diego Gas & Electric for about $380 million in damages costs above its insurance coverage from wildfires in 2007. (See PG&E Vows Fight over Wildfire Cost Recovery.)

Fires raged across California much of the fall, leading the California Public Utilities Commission to take on a larger response role and lawsuits against PG&E and SCE over the possible role of utility infrastructure in causing the fires. (See Wildfires Color California PUC Utility Decisions.)

Edison International cost recovery wildfire earnings — SCE says recovery of wildfire costs for utilities is a top priority

Edison, the parent of Southern California Edison, said the CPUC has not indicated whether it will allow recovery of premiums SCE spent on incremental wildfire insurance at the end of the year, which cost 29 cents/share. About a quarter of SCE’s 50,000-square-mile service territory is in high-fire-risk areas, Pizarro said.

California’s courts have held investor-owned utilities liable when their utility equipment was found to be a substantial cause of a wildfire.

“This is a statewide crisis that needs a statewide solution,” Pizarro said. In addition to ensuring sufficient fire suppression resources and improved vegetation management and zoning regulations, Pizarro said the state’s infrastructure must be hardened.

“We should evaluate the safety impacts, along with the reliability and cost tradeoffs, of steps like undergrounding more of the distribution network in selected areas, installing steel or composite poles instead of wood ones in specific locations, and using further preventive public safety shutoffs of power under high-risk conditions such as red flag warnings, which we have done selectively in the past,” Pizarro said. “When a catastrophic event occurs in spite of all these efforts, we need thoughtful policies around how financial risks are allocated, including fire suppression costs and damages.”

Fourth-Quarter Loss

Edison reported a net loss of $545 million ($1.67/share) in the fourth quarter, compared with net income of $329 million ($1.01/share) in fourth quarter 2016. On an adjusted basis, fourth-quarter core earnings were $357 million, up from $316 million a year earlier.

SCE’s fourth-quarter earnings decreased by $437 million ($1.34/share) from the fourth quarter of 2016, with a $44 million increase in core earnings offset by $448 million in charges from the revised settlement agreement on the retirement of the San Onofre nuclear plant. SCE reported operating revenue of $6.6 billion in 2017 and net income of $1.1 billion, compared with revenue of $6.5 billion and net income of $1.5 billion in 2016.

The utility filed a general rate case with the CPUC in September 2016 for 2018-2020. It is seeking a $5.5 billion revenue requirement for 2018, down $106 million from the 2017 requirement. It has requested increases of $431 million in 2019 and $503 million in 2020.

The requested increases would result in a 9.7% compound annual growth rate through 2020. However, the company noted that the CPUC has approved 81%, 89% and 92% of its previous three general rate requests.

Storage Filing

Edison’s future will include a focus on electric vehicle integration and energy storage.

SCE intends to file an energy storage procurement and investment plan application March 1 to meet its 166-MW share of distribution-level energy storage under Assembly Bill 2868.

wildfire cost recovery CAISO Edison International cost allocation — Summary of SCE large transmission projects | *SCE*

Last October, SCE released a white paper that estimated that California will need more than 7 million EVs, the electrification of one-third of space and water heaters and more energy-efficient buildings to meet the state’s 2030 greenhouse gas reduction target.

In January, the CPUC approved five of the six “fast track” projects, totaling $10 million, that SCE proposed as part of a $574 million transportation electrification initiative in January 2017. Pizarro said the company expects a decision in the second quarter on the long-term projects in the plan.

February 25, 2018

SPP: FERC Resiliency Effort Should Go Beyond RTOs

By Tom Kleckner

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.

SPP FERC Grid resiliency docket — Eckelberger | © *RTO Insider*

“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.”

February 25, 2018

ERCOT Board of Directors Briefs: Feb. 20, 2018

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.”

Bill Magness delivers his CEO report as Director Clifton Karnei (left) and PUC of Texas Commissioner Arthur D’Andrea listen. | © *RTO Insider*

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.

ERCOT Board of Directors CEO Bill Magness — Craven Crowell (head of the U) chairs ERCOT’s February Board of Directors Meeting. | © *RTO Insider*

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.

— Tom Kleckner

February 25, 2018

CMS Energy Plans a Zero-Coal Future by 2040

By Amanda Durish Cook

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.

CMS Energy Consumers Energy earnings — 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.

February 25, 2018

Eversource Outlook Unhampered by Northern Pass

By Michael Kuser

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

eversource energy earnings Northern Pass Transmission — 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.

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.)

February 23, 2018

Entergy Mississippi Backs Bill to Curb State AG

By Amanda Durish Cook

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.

attorney general jim hood Entergy Mississippi — Entergy Mississippi’s Attala Generating Plant | *Entergy Mississippi*

“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.

February 23, 2018

Gas Adders a Necessary Tool, CAISO Says

By Jason Fordney

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.

CAISO ERCOT gas price adders — CAISO briefed market participants at a February 20 forum in Folsom | © *RTO Insider*

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.

CAISO gas price adders — Alderete (left) and CAISO’s Amber Motley | © *RTO Insider*

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.”

February 23, 2018

ERCOT Monitor Touts Co-optimization Benefits

By Tom Kleckner

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.

ERCOT co-optimization Market Monitor — Garza | © *RTO Insider*

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.”