Page 1242 – RTO Insider

December 4, 2017

NYISO Q3 Prices Fall on Lower Demand, Gas Costs

By Michael Kuser

NYISO third-quarter energy prices fell 16 to 30% compared with the same period a year ago because of mild summer conditions, lower natural gas prices and higher output from nuclear and hydropower plants, the ISO’s Market Monitoring Unit reported last week.

Reduced congestion into Long Island and increased congestion out of NYISO’s North Zone contributed to the decline, as well as to “substantially lower” ancillary service prices and uplift costs, MMU Director Pallas LeeVanSchaick, of Potomac Economics, told the ISO’s Market Issues Working Group on Nov. 29.

nyiso natural gas electricity demand — | *Potomac Economics*

While the Q3 report showed that NYISO’s market was competitive and that most prices and costs were down substantially compared with last year, the Monitor continued to identify potential improvements to market performance.

The report noted that a mild summer helped reduce loads by 1.8 GW on average, while natural gas prices in most of eastern New York and New England fell 12 to 19%. Nuclear and hydro units increased their average output by up to 640 MW.

Day-ahead congestion revenue fell 20% to $104 million partly because of the lower loads. West Zone lines accounted for the largest share of the congestion (25%) during the quarter, as imports from Ontario and hydro output met with bottlenecks while flowing east. New York City lines accounted for 20%, increasing because of higher gas prices relative to other regions and the expiration of the Con Ed-PSEG wheel. Long Island’s share was down sharply to 17% because of fewer major transmission outages.

Flows from the North Zone accounted for 21% of congestion, as transmission outages and derates and hydroelectric output increased, leading to several extreme negative pricing events.

Actions used to manage 115-kV congestion in western and northern New York led to import limitations from Ontario and Quebec, as well as congestion on the higher-voltage system in other parts of the state. The MMU said the costs and reliability effects of this congestion could be reduced by modeling the 115-kV constraints in the day-ahead and real-time markets.

Capacity Market Spot Prices Down

Third-quarter spot prices for capacity ranged from $2.21/kW-month in Rest of State (ROS) to $9.97/kW-month in New York City. Average spot prices were down 18% in the city and 41% in ROS, but up 6% in the G-J Locality and 51% on Long Island. Demand curve revisions reflecting changes to assumptions about the unit net cost of new entry were a primary driver for the increased prices.

While an increase in installed capacity (ICAP) was a dominant factor in the ROS price rise, supply was up only modestly from a year ago, reflecting higher test values for dependable maximum net capability, the revival of the Greenridge 4 coal unit and new wind capacity upstate. Cleared import capacity rose 350 MW from a year ago, primarily from PJM. Import capacity from Ontario increased by an average of 105 MW, offset by a similar reduction from New England.

Reserve margin and locational capacity requirements rose in all regions as a result of a recent study by the New York State Reliability Council. However, peak load forecasts fell across all regions, neutralizing the price impact from higher installed reserve margins and locational requirements.

Sharp Fall in Reserve Prices

The report also showed that day-ahead reserve prices fell by 28 to 44% from a year ago, consistent with lower load levels and lower locational-based marginal prices and primarily attributable to a decrease in reserve offer prices. After reserve market design changes in November 2015, the MMU observed offers above the standard competitive benchmark (i.e., estimated marginal cost), which it said is partly attributable to the difficulty in accurately estimating the marginal cost of providing operating reserves. However, day-ahead reserve offer prices have gradually fallen as suppliers gain more experience.

In the third quarter, a large number of units offering reserve capacity — particularly fast-start resources in eastern New York — further reduced their offer prices. The MMU said it continues to monitor day-ahead reserve offer patterns and consider potential rule changes, including whether to modify the existing $5/MWh “safe harbor” for reserve offers in the ISO’s market power mitigation measures.

Congestion Management and Pricing

The MMU noted that the ISO’s market-to-market phase angle regulator (PAR) coordination process expanded in May after the expiration of the 1,000-MW Con Ed-PSEG Wheel. (See NYISO Members OK End to ConEd-PSEG Wheel.) Congestion increased through Millwood and into New York City. In general, transmission lines in the A/B/C and J/K zones were operated more efficiently. However, the MMU observed that PARs in those areas were often not utilized to help manage congestion, being adjusted only one to five times per day on average.

The Monitor found that NYISO improved its transmission shortage pricing in June by modifying the second step of the graduated transmission demand curve (GTDC) from $2,350/MW to $1,175/MW, removing the feasibility screen and applying the GTDC to all constraints with a non-zero constraint reliability margin. As a result, constraint relaxation has been much less frequent, with violations occurring in 6% of interval during the third quarter, compared with 59% last year.

Average constraint shadow prices during transmission shortages fell moderately in most areas. Constraint relaxation leads to inefficient prices that are volatile and uncorrelated with the severity of congestion, the MMU said. Despite improved pricing outcomes, constraint shadow prices still did not properly reflect the importance of some transmission shortages. Accordingly, the MMU continues to recommend developing constraint-specific transmission demand curves.

December 4, 2017

MISO, PJM Pursue Pseudo-Tie Double-Charge Relief

By Amanda Durish Cook

CARMEL, Ind. — MISO and PJM expect to begin implementing a two-part remedy to their double-charging of congestion fees on pseudo-tied generation early next year.

MISO and PJM began collaborating to remove the overlapping congestion charges soon after the first complaint about the issue was filed with FERC last year. Stakeholders have lodged five complaints against the RTOs, including filings last year by Tilton Energy (EL16-108), American Municipal Power (EL17-29, EL17-37) and Northern Illinois Municipal Power Agency (EL17-31). Dynegy and Illinois Power Marketing filed jointly against MISO in March and added a motion to consolidate the previous complaints (EL17-54).

In an update to FERC on Nov. 22, the RTOs said their plan to address the complaints will ultimately treat pseudo-tie transactions like dynamically scheduled interchange transactions, in which two parties agree on a metered energy purchase and schedule it in both the day-ahead and real-time markets. The original value is first estimated then updated after delivery.

The first stage of the plan — slated to be in place by March — adds market-to-market settlement and day-ahead coordination of pseudo-tie transactions to the RTOs’ joint operating agreement. The second stage will have the RTOs alter their individual tariffs to address congestion charges, credits, rebates and hedges.

pjm miso pseudo-tie — Horger | © *RTO Insider*

“There’s been several challenges with the modeling on these ever since they’ve entered the market,” PJM Director of Energy Market Operations Tim Horger said during a Nov. 29 Joint and Common Market meeting of the two RTOs.

The RTOs last month filed Tariff revisions (ER18-136, ER18-137) that would enable them to factor pseudo-tie firm flow entitlements into the day-ahead market, with the attaining balancing authority modeling the impact on flowgate capacity. In real-time M2M settlements, MISO and PJM will account for pseudo-tie market flows in payment formulas, so that charges between RTOs exclude the impacts of pseudo-tie resources on flowgates in the attaining balancing authority’s calculations, ending the double-counting of congestion on flowgates.

Horger said the change comes down to modeling “proper limits in the day-ahead market.”

“PJM was modeling limits … that weren’t reflective of what the congestion actually was,” Horger said. MISO and PJM have been using a temporary rebate program until they’re authorized to include pseudo-ties in the day-ahead scheduling process. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.)

The RTOs hope to win FERC approval by March. “We’re expecting some answers and solutions shortly,” Horger said.

Phase 2

MISO and PJM will wait until later next year to roll out the second phase of the congestion remedy because it requires more complicated Tariff changes and complex software changes. Those revisions will require an attaining balancing authority to issue either refunds or financial transmission rights to cover the day-ahead congestions costs paid by pseudo-ties with load contracts. In the real-time market, credits and charges would be levied on pseudo-tie transactions based on deviations from their day-ahead schedules. The RTOs’ would leave open the option for the native balancing authority to accept a pair of day-ahead virtual transactions for pseudo-tie transactions that have FTR hedges.

“It does require more extensive software changes because it involves a hedging mechanism for deviations between day-ahead and real-time. And it may also involve refunds,” Horger said.

PJM is looking into developing a new product exclusively for pseudo-tie owners out of PJM that would allow them to hedge in the day-ahead market, similar to existing virtual transactions, he said. MISO, however, plans to hedge using its existing virtual transaction process because of the limited capability of its market system platform.

“If there’s an under-collection or over-collection in the MISO market, it’s going to be trued up with this market flow credit,” Horger said.

The RTOs will have separate filing and implementation dates for the second stage of the plan, Horger said, with PJM planning to go live in June, with MISO lagging by a few months because of IT-related challenges.

“We’re in the process of implementing a new settlement system, so that’s going to impede our ability to deliver phase two,” said Kevin Vannoy, MISO director of forward operations planning.

Some stakeholders asked if the disparate implementation dates were even possible.

Vannoy said the solutions boil down to Tariff changes that can be made independently. He promised more details on the second phase of the plan in early 2018.

Some MISO stakeholders are hoping the RTO will file a similar plan with SPP, where the potential for double congestion charges also exists, although the RTOs exchange far fewer pseudo-tied megawatts.

“We’re hoping that the pseudo-tie congestion changes will apply to SPP as well,” said Market Subcommittee Vice Chair Megan Wisersky, reporting on activities of MISO’s Seams Management Working Group in October.

MISO Monitor not Pleased

But MISO Independent Market Monitor David Patton said that MISO and PJM have yet to make a filing that will solve the underlying congestion and dispatch issues caused by pseudo-ties.

Patton’s firm, Potomac Economics, filed a protest against the first phase of the overlap solution, saying nothing in the filings “ameliorates the myriad of significant problems” caused by the uptick in resources pseudo-tying from MISO to PJM. The Monitor also argued that FERC could not even fairly evaluate the RTOs’ filing without also evaluating at least 10 other FERC dockets containing complaints against the their pseudo-tie process.

“We hope that FERC will respond to our complaint and bring some rationality to this process,” Patton said at an Oct. 12 Market Subcommittee meeting.

Horger said that for pseudo-ties to function, PJM and MISO must have comparable treatment for external and internal capacity, a binding pro forma agreement and a solution to the RTOs’ double counting of congestion.

“We need to make sure these pseudo-tie external resources are being modeled under the same criteria,” Horger said.

December 4, 2017

EIM Governing Body Approves ‘Consolidated’ Initiatives

By Jason Fordney

BOISE, Idaho — Decision-makers for the Western Energy Imbalance Market (EIM) last week approved a set of market initiatives that represents a narrowed-down version of a package CAISO proposed to market participants earlier this year.

The EIM Governing Body on Nov. 29 unanimously approved CAISO’s “consolidated EIM initiatives,” which will automate some manual processes, facilitate bilateral settlements and improve the market’s modeling accuracy.

CAISO Senior Adviser Don Tretheway briefed body members on the three aspects of the proposal over which they had decisional authority. In a presentation, he explained that one measure allows auto-matching of balancing changes in intertie schedules between an EIM resource and a non-EIM resource, allowing a member to use the external resource to “self-balance” an intertie change.

The initiative also automates the updating of mirror system resources at CAISO intertie scheduling points, which is done to prevent imbalances. Those resources allow the market to solve for the ISO and another EIM area at the same time.

“Currently, EIM entities are responsible for manually updating this mirror system resource,” Trethaway said, noting that the manual process is subject to error or delays.

A third aspect of the approved initiative supports imbalance settlement of EIM base transfer schedule changes. That measure will facilitate bilateral scheduling between EIM entities, allowing settlement of energy transfers at agreed-upon financial locations for bilateral schedule changes occurring after base schedules are submitted.

In September, CAISO announced it was dropping several aspects of the consolidated EIM initiatives because of negative feedback from stakeholders. (See CAISO Drops Proposed EIM Changes.) One proposal would have allowed non-EIM third-party transmission owners to provide transfer capacity in the market, while another adjusted management of bilateral schedule changes. A third measure would have ensured payments to EIM entities that currently don’t get compensation for wheeling power through their balancing areas.

Chairman Douglas Howe clarified with Tretheway that third-party transmission providers would reduce their own congestion revenue by providing the increased capacity to the EIM “and work against” their own interests.

“Is this really a feasible initiative at all?” Howe asked. Tretheway replied that it might be workable in certain cases with EIM transfers.

The disincentive was an issue raised by stakeholders during review of the proposal, leading it to be dropped from the initial package. (See CAISO Drops EIM Third-Party Transmission Plan.)

The Governing Body last week also gave advisory approval to separate rule clarifications for CAISO’s non-generator resources (NGR) market enhancement, which allows new types of resources (such as storage) to participate in the ISO’s regulation market. Powerex is using NGR to model its participation in the EIM, and the ISO said the changes provide additional clarity on market rules for NGR — including clarifying that such resources are subject to local market power mitigation and are not eligible to account for resource adequacy capacity.

“This is something that you would be doing irrespective of whether the EIM existed?” Howe asked, which Tretheway confirmed.

December 4, 2017

New England Grid Prepared for Winter Reliability

By Michael Kuser

ISO-NE forecasts sufficient resources to meet demand for electricity this winter and will implement special operating procedures to maintain reliability in the event of higher-than-projected demand, unforeseen generator outages or natural gas supply constraints that squeeze gas-fired power plants.

The RTO on Thursday issued its 2017/2018 winter outlook, which forecast peak demand under various scenarios:

21,197 MW at normal winter low temperatures of about 7 F; and
21,895 MW in extreme winter weather dropping to 2 F.

Resources with Forward Capacity Market (FCM) supply obligations total 30,999 MW; including resources without FCM obligations, capacity totals 32,521 MW.

Last winter’s peak demand of 19,647 MW occurred on Dec. 15, 2016, between 5 and 6 p.m., while New England’s all-time winter peak of 22,818 MW occurred on Jan. 15, 2004.

Gas Concerns

The report highlighted “a continuing concern” that “the region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow.”

ISO-NE said 4,000 MW of natural gas-fired generating capacity is at risk of not being able to get fuel when needed.

The RTO said the retirement of the 1,500-MW coal- and oil-fired Brayton Point power plant in Somerset, Mass., in May removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable.

ISO-NE cone cost of new entry winter reliability — The Brayton Point Power Station in Somerset, MA went offline in June 2017.

The grid operator is again running its Winter Reliability Program, which provides incentives for demand-side resources and generators that stock up on oil or contract for LNG. The program, which runs from Dec. 1, 2017, through Feb. 28, 2018, will be replaced by new capacity market performance incentive rules that go into effect June 1, 2018.

Total energy consumption and peak demand have been flat in New England in recent years because of increased energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems. Both the normal and extreme peak demand forecasts include the 1,832 MW in energy savings from EE acquired through the capacity market. While PV helps reduce energy consumption during sunny winter days, demand peaks in winter after the sun has set. By reducing demand on sunny days, PV can help preserve other fuels for use when demand is peaking.

December 4, 2017

Ruling Casts Doubt on Fate of Big Rivers Coal Plant

By Amanda Durish Cook

The prospects became bleaker for one Big Rivers Electric coal-fired generator last week after FERC declined to rehear an earlier ruling that denied a bid to extend interconnection rights for the Kentucky plant.

FERC earlier this year rejected Big Rivers’ initial request to keep its Coleman Station interconnected to FERC Refuses Interconnection Extension for Big Rivers’ Plant.)

In its rehearing request, Big Rivers did not challenge the commission’s earlier refusal to extend the rights, but instead argued that a “termination of interconnection service for the Coleman Station could potentially harm reliability and impose increased costs on Big Rivers’ members.”

FERC disagreed with that contention (EL17-15-001).

“Big Rivers cites no specific evidence in support of its claim that there are potential adverse impacts on system reliability due to termination of interconnection service to the Coleman Station,” the commission said in its Nov. 27 order. “Moreover, we note that MISO evaluated reliability concerns associated with the suspension of the Coleman Station when Big Rivers submitted its Attachment Y notice to suspend its operations.”

The commission’s ruling once again pointed out that Coleman cannot return to service until it complies with EPA’s Mercury and Air Toxics Standards. It also noted the plant does not currently have load to serve since the nearby Century Aluminum smelter — once the plant’s primary customer — completed load curtailment arrangements.

ferc big rivers electric — Employees in front of the Coleman Station in June 2017 | *Big Rivers*

“Big Rivers itself acknowledges that the decision of whether and when to return the Coleman Station to service will be a complicated one. It thus appears that the Coleman Station may not be returned to service regardless of whether its interconnection service is reinstated,” FERC said.

‘Not Unique’

In early October, Rep. Brett Guthrie (R-Ky.) wrote to Chairman Neil Chatterjee urging a “full and fair consideration” of Big Rivers’ request for rehearing.

But FERC said the challenges facing the nearly 50-year-old Coleman are commonplace: “While we appreciate the difficulties facing Big Rivers with regard to the future disposition of the Coleman Station, its circumstances are not unique. There are likely other generators that are currently uneconomic that would, if possible, reserve their interconnection service indefinitely in the hopes of future market changes.”

Big Rivers also argued that FERC was still allowing for disparate treatment of generators. While Coleman never had a generator interconnection agreement (GIA) with MISO, the RTO would be prohibited from cutting service to a generator operating under a GIA, the company contended.

FERC said the result would be the same, GIA or not, “because Big Rivers had not satisfied the requirement of taking ‘significant steps to maintain or restore operational readiness … as soon as possible.’”

Big Rivers additionally filed a motion in September asking FERC to consider the “evolving status of MISO’s policies on replacing retiring generation facilities and the interplay of MISO suspension, retirement and SSR rules.” MISO officials and stakeholders are currently considering whether SSR units facing terminations should be able to maintain service even after contract expiration in order to allow them to participate in the RTO’s annual capacity auction.

“Although styled as a motion to clarify the record, Big Rivers seeks to reopen the record and lodge the two MISO presentations for commission consideration,” FERC responded. “Evidence that MISO and its stakeholders are in the process of considering changes to the Tariff that may allow generators to retain interconnection rights following retirement do not constitute a ‘change in core circumstance’ at ‘the very heart of the case.’”

December 4, 2017

SoCalGas Pipeline Losses Spur Curtailment Warnings

By Jason Fordney

The loss of three natural gas pipelines is creating major concerns about Southern California’s gas and electricity supplies, with three state and local regulators saying that Los Angeles-area electricity generators could experience gas curtailments this winter.

The California Public Utilities Commission, California Energy Commission and Los Angeles Department of Water and Power (LADWP) last week issued a new assessment of the situation suggesting that curtailments are more likely this winter than last because of pipeline ruptures — but much will depend on the weather. Southern California Gas’ Line 235-2 ruptured on Oct. 1 and also damaged Line 4000, adding to an existing outage of Line 3000, according to the report.

SoCalGas natural gas pipeline — Southern California has three natural gas pipelines out of service

“Natural gas service is threatened to noncore customers, including electric generators, this winter,” the report said. “This threat occurs even though there is more gas in storage than at this time last year.”

The concerns arose even after SoCalGas’ Aliso Canyon gas storage facility resumed injections in July, despite objections from state agencies. (See Aliso Canyon Resumes Injections.) Operations at the facility had been halted following a massive methane release detected in October 2015 and finally plugged in February 2016. The California Division of Oil, Gas and Geothermal Resources determined it is safe for the company to resume injections at the site.

The agencies issuing last week’s report said that other actions under consideration include an emergency moratorium on new natural gas service connections in the Los Angeles County area served by Aliso Canyon.

“Another proposed measure would direct electricity generators to more frequently shift generation to facilities located outside the SoCalGas system to reduce gas use in December,” the agencies said. “This could allow SoCalGas to preserve storage inventories deeper into the winter.”

The report also said LADWP could delay electrical transmission upgrades until February in order to maintain access to power sources outside the region. The agencies are additionally considering slightly increasing the volume of gas that can be stored at Aliso Canyon.

December 4, 2017

No Unanimity in ‘Coal Country’ Hearing on CPP Repeal

Last week’s public hearings on the repeal of the Clean Power Plan provided EPA Administrator Scott Pruitt the stage he sought for coal industry supporters to blast the Obama administration’s environmental policies. But not everyone stuck to the script.

Pruitt said he chose to have the hearings in “the heart of coal country to hear from those most impacted” by the CPP. During two days of hearings at the West Virginia State Capitol in Charlestown, coal magnate Robert Murray, West Virginia Attorney General Patrick Morrisey and other CPP critics derided the regulation as two dozen miners in hard hats and overalls looked on in support.

epa clean power plan — Audience view of the Clean Power Plan hearing | *EPA*

But the hearings also attracted many supporters of the CPP, as well as business groups who argued for replacing the CPP with less stringent rules to provide regulatory certainty and protection against litigation.

Pruitt announced the repeal of the CPP in October, saying the Obama administration overstepped its authority by regulating beyond the “fence line” of individual generators. The question facing the Trump administration now is what the replacement — required by EPA’s 2009 finding that CO₂emissions endanger public health — should be. (See EPA to Announce Clean Power Plan Repeal.)

Morrisey said the CPP “would impose a top-down reordering of state energy economies … and would be disastrous for West Virginia and the country as a whole.”

Murray, CEO of Murray Energy, said EPA should repeal the power plan “in its entirety,” including overturning the endangerment finding.

But utilities and business groups urged EPA to leave the endangerment finding in place and focus on a replacement for the CPP.

The U.S. Chamber of Commerce asked for “durable and achievable standards.”

Scott Segal, director of the Electric Reliability Coordinating Council, which represents utilities including Duke Energy and Ameren, said he supports a regulation that would require efficiency improvements in fossil fuel plants.

“While ERCC believes that absent specific guidance in legislation from the U.S. Congress, market principles are the most sound basis upon which to proceed, we nevertheless support the process advanced by EPA,” Segal said. “Federal guidance of sufficient flexibility, and limited to actions within the fence line, can provide regulatory certainty, diminish frivolous litigation, and can aid in planning.”

Richard Revesz, director of the Institute for Policy Integrity at the New York University School of Law, told the Los Angeles Times that repeal without replacement “could open the floodgates for litigation,” leaving power companies vulnerable to “significant and highly uncertain liabilities.”

“The EPA is required to publicly regulate these pollutants. Therefore, repealing the [CPP] without a replacement is illegal,” Connecticut Department of Energy and Environmental Protection Commissioner Robert Klee testified. “Ignoring these facts won’t make the problem go away; it will only serve to make it worse and delay the solutions we desperately need to meet this local, regional, national and international challenge.”

future of energy conference climate change epa clean power plan — Klee | © *RTO Insider*

Klee told RTO Insider later that while the first day of the hearing was dominated by many coal miners in the audience, EPA’s strategy to hold the meetings in coal country “backfired” on the second day when dozens of ordinary West Virginians spoke out against repeal. Klee and others called for additional hearings in other regions of the U.S.

The Obama EPA held public hearings in four states before issuing the CPP. An EPA official said last week that the agency was considering whether to hold additional hearings and had not set a schedule for announcing what kind of replacement rule it will propose.

“As a West Virginian, I’m insulted at the choice of this location,” resident David Lillard said. “It doesn’t make for great TV to have coal executives and some coal barons speaking about saving a few pennies per ton of coal, but it’s great theater to have desperate coal miners carrying the message for the coal barons and the coal companies that have lied to them repeatedly. They were told their pensions were safe, and that was a lie. They were told they would always have health care; that promise was broken.”

Nick Mullins, a fifth-generation coal miner from Kentucky, said the CPP will lead to safer and better job options for his son. “I don’t want him to be a sixth-generation coal miner,” Mullins said, citing the physical toll of the work.

“As long as I can draw a breath, I’m going to keep working to fight climate change and protect the land and country I love,” said Stanley Sturgill, a Kentucky resident who said he suffers from black lung disease after more than 40 years as a coal miner.

“The coal miners I talk to seem to know coal jobs will continue to dry up, with or without a Clean Power Plan,” said Angie Rosser, executive director of the West Virginia Rivers Coalition. “We’ve been pitted against each other by being told we’ll either have coal, or we’ll have nothing. This administration seems to thrive on public anger and conflict. It’s a distraction. When people are fighting, they are not talking. … The clock is ticking to do something different than leaning on a dying industry.”

Indeed, just last week PPL said its Kentucky utilities will retire their aging coal units and replace them with natural gas and renewables — even without carbon regulations. The company said it projects CO₂ reductions of 45 to 90% by 2050.

More: Fairmont Times; Charleston Gazette-Mail; The Washington Post; Los Angeles Times; Washington Examiner; The Associated Press

— Michael Kuser and Rich Heidorn Jr.

December 4, 2017

Besieged CPUC Denies SDGE Wildfire Recovery

By Jason Fordney

Utilities are at the epicenter of public battles between the California Public Utilities Commission and its critics over wildfires, public safety and ethics that have major financial implications for companies and ratepayers.

Those controversies surfaced at a Nov. 30 CPUC meeting at which the commission denied San Diego Gas & Electric’s request to recover from ratepayers $379 million in costs related to the 2007 Southern California wildfires. SDG&E quickly vowed to vigorously fight the commission’s unanimous decision.

california puc wildfire — The CPUC denied SDG&E’s request for $379 million in ratepayer cost recovery for the 2007 California wildfires | © *RTO Insider*

Following recommendations by an administrative law judge, the CPUC said the utility “did not reasonably manage and operate its facilities prior to the 2007 Witch, Guejito and Rice Wildfires,” which killed two people and destroyed homes and property. SDG&E’s $379 million request was separate from other court proceedings, settlements, insurance payments and federal cost recovery regarding the fires.

Commissioner Liane Randolph said the SDG&E case turned on the specific question of equipment maintenance, including faults on a transmission line, a communications wire and vegetation management.

“There is no dispute that each of the fires were caused by SDG&E facilities,” she said. Randolph noted the decision is not a final statement of the doctrine of inverse condemnation, the legal tool that SDG&E leaned on in its claim. The logic is that “the costs of a public improvement benefiting the community should be spread among those benefited rather than allocated to a single member of the community.”

But Randolph said it is appropriate to put the costs on Sempra shareholders, not ratepayers, and the case has nothing to do with the utility’s current management of the system. “The decision is specific to the 2007 incident and the facts of this case,” she said.

Commissioner Clifford Rechtschaffen added that inverse condemnation “is somewhat of a theoretical issue in this matter.”

“The decision does not hold the utilities to a standard of perfection,” he said. “We can’t apply a standard that provides an incentive for a utility to act imprudently or unreasonably,” adding that would send the wrong signal to the utility.

In a written statement, SDG&E Chief Regulatory Officer Lee Schavrien said: “SDG&E strongly disagrees with today’s decision. The CPUC got it wrong. The 2007 wildfires were a natural disaster fueled by extreme conditions including the worst Santa Ana wind event this region has ever seen, combined with high heat, low humidity and hurricane-force winds as high as 92 mph.”

During its third-quarter earnings call, SDG&E parent Sempra Energy vowed to take legal action if denied the cost recovery. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.) The commission did receive praise from The Utility Reform Network and the California Office of Ratepayer Advocates for denying the cost recovery.

During the meeting, commissioners also discussed the increased risk of fires attributed to climate change in California. PUC President Michael Picker noted that areas of elevated or extreme fire hazard are growing in California, to almost 42% of the state, and more people are moving into those areas with higher wind and lightning.

“This is become an increasingly complex area for us,” Picker said, adding that the decision “may or may not” set a precedent for future cases.

As the battle over the 2007 fires continues, the CPUC is preparing to evaluate a similar situation for Pacific Gas and Electric regarding the particularly destructive fires that ravaged California’s wine country this summer, from which the death toll rose to 44 this week. The cause of the fires is still under investigation. (See Wildfires Color California PUC Utility Decisions.)

Embroiled in Controversy

The CPUC issued the ruling amid a swirl of legal battles, regulatory proceedings and public accusations that focuses heavily on the tenure of former President Michael Peevey, who resigned from the commission in January 2015 and has been under investigation by the state’s attorney general for engaging in back-channel discussions with Southern California Edison over the financial terms of the San Onofre nuclear plant’s closure.

The environment around the current CPUC has been increasingly darkened by years of public allegations of other ethics violations. State lawmakers last week renewed their call for Attorney General Xavier Becerra to file charges regarding improper communication between the PUC and PG&E concerning the 2010 explosion of the company’s gas pipeline in San Bruno. The request came soon after the discovery of old email communications between the PUC and former PG&E consultant and Commissioner Susan P. Kennedy regarding the San Bruno settlement. (See Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.)

The situation led to a confrontation at last week’s meeting between Picker and San Diego attorney Michael Aguirre, a frequent CPUC critic who is involved in the San Onofre case.

As Aguirre approached the microphone during the public comment period at the San Francisco hearing, Picker asked him if he was there to apologize for his “rude, abusive and disruptive behavior” at a recent hearing regarding the San Onofre plant. Aguirre ignored Picker and instead spoke of recent wildfire deaths, the San Bruno explosion and the natural gas leak at the Aliso Canyon storage facility near Los Angeles.

Aquirre said the victims of the Tubbs Fire in Napa and Sonoma Counties “are not here to ask why the California Public Utilities Commission did not enforce the safety rules against PG&E that could have saved our lives.” Picker told Aguirre he himself was a party to one of the proceedings and his appearance might violate commission rules.

Commission Response

The commission on Dec. 1 issued a lengthy public statement saying, “The CPUC has cooperated with the attorney general’s office through every step of the investigation as well as with federal investigators whose demands for documents preceded those of the attorney general. Throughout the process, the CPUC has produced more than 1 million documents to the attorney general.”

The CPUC said the agency had fully complied with a search warrant as of December 2016. “The case is in the hands of the attorney general’s office, and the next steps are up to the office,” the commission said.

At its Nov. 30 meeting, the commission also voted to defer consideration of a related $86 million settlement between it, PG&E and other parties over improper ex parte communications in the wake of the San Bruno blast.

December 4, 2017October 31, 2023

Mass. Prepares for EV Growth, Alternative Energy Standard

By Michael Kuser

BOSTON — Massachusetts’ $2,500 rebates are increasing electric vehicle sales, and state officials are preparing for the shift in demand now, the state’s Department of Energy Resources said Thursday.

“We do have a goal for 300,000 electric vehicles to be registered in the state by 2025,” DOER Director of Emerging Technology Will Lauwers said in a briefing to the Environmental Business Council of New England on Nov. 30. “Providing the charging infrastructure for that is crucial.”

EV registrations have grown from 782 in July 2013 to 3,770 as of March 31, 2017, according to the state Department of Environmental Protection. In the same period, the number of gas-electric hybrids has increased more than five-fold, from 1,034 to 5,701. The state launched its rebate program, which covers both EVs and hybrids, in June 2014.

Although the alternative transportation sector includes biofuels and gas-electric hybrids efforts, electric vehicles and transportation electrification dominate the state’s efforts, Lauwers said. The DEP’s program to incentivize workplace charging stations exhausted its funding this year.

“Utilities have shown interest in helping to reduce the cost of entry to deploying EV charging, so they would help to cover more of the associated costs with new meters, new pads and new connections,” Lauwers said. “Then there’s the VW funding.”

As penance for having rigged diesel emissions test results, Volkswagen is spending $2 billion to install more than 300 vehicle chargers in 15 metro areas, including Boston.

Resiliency, not Totality

Lauwers said Massachusetts is “a nation-leader” in its commitment to reducing greenhouse gases and fostering new renewable energy resources and has “made a lot of progress in the past 12 months” on energy efficiency, energy storage and demand reduction.

He cited the DOER’s June announcement of $10 million in incentives for energy storage demonstration projects, a 200-MW storage deployment target and a $40 million initiative that awards grants to cities and towns to use clean energy technologies to mitigate the risks of power outages arising from severe weather. Award announcements on the storage incentives are expected by early 2018. (See Massachusetts Underwhelms with 200-MWh Storage Target.)

Michael Judge, the DOER’s director of renewable and alternative energy, said storage is key for both grid stability and reducing emissions. Without storage “you end up keeping all these fossil fuel units going because they can’t ramp that fast,” Judge said.

In discussing resiliency studies that the department conducted on 12 state medical centers, Lauwer said resiliency doesn’t mean 100% of normal power availability, just enough to run core functions. For example, a nursing home might lose its heat in a power outage just because it needs 9 V to run the pilot light.

Infrequently used back-up generators at hospitals often fail in the first few hours of running, so energy storage can make a big difference in such situations, he said in discussing the agency’s analytical tools that help facility administrators understand what energy resiliency steps are economically viable for them. In addition, DOER will soon be clarifying how much energy storage utilities can own and how they will be compensated, Lauwers said.

Massachusetts is funding incentives to include energy storage in solar installations, as well as grants for peak demand reduction. Pairing energy storage with solar panels is meant to enhance grid resiliency by reducing the demand curves. Peak reduction grants cover a wide range of projects, from utilities improving the efficiency of substations, to municipalities working to reduce the energy consumption of big-box retail stores, to a thermal energy storage project on Nantucket that will delay the need for a new undersea transmission cable.

| Mass. DOER

The state this year launched its Solar Massachusetts Renewable Target (SMART) program to provide incentives for “long-term sustainable … cost-effective solar development.” The program provides adders based on location, and to projects that provide unique benefits, including community solar and energy storage.

Judge said the state’s new Alternative Energy Portfolio Standard is the only one of its kind in the country. The final draft regulations, expected to be promulgated on Dec. 29, include combined heat and power, flywheel storage, renewable thermal, fuel cells and waste-to-energy thermal technologies. The regulations oblige all retail electric suppliers to acquire a certain percentage of their power from eligible technologies, starting at 4.25% in 2017 and increasing by 0.25% each year.

“Heating is behind the electric sector in decarbonizing and amounts to about 30% of GHG emissions,” Judge said. “DOER incentives for renewable thermal energy and heat pumps are paying off, with nearly 500 MW of combined heat and power systems installed as of the end of October 2017.”

Energy Efficiency Peaking?

Arah Schuur, DOER director of energy efficiency, said the state will deliver $8 billion in efficiency benefits from 2016-2018 and that those savings will continue to grow.

“You put in a light bulb, you put in an efficient piece of technology and it lasts for five, seven, 11 or 20 years, and those benefits accrue as we add more to the portfolio,” Schuur said.

Lighting savings comprise 83% of residential energy efficiency gains and 23% of overall savings. Although the state has nation-leading goals for both electric and natural gas, efficiency savings seem to be peaking, she said.

“That’s because of the change in the lighting market and the change in federal lighting standards. So, screw-in light bulbs are nearing market saturation. There’s natural uptake of LED lights. This [is a] great good news story overall for energy efficiency,” Schuur said.

The limits to lighting’s contribution to efficiency savings will “require a whole new way of thinking about energy efficiency,” she said. The DOER is exploring new ways to achieve efficiency results, such as addressing demand through utility programs, looking at the residential contractor market and driving innovation.

December 4, 2017

ERCOT Stakeholders OK $246.7M in Freeport Reliability Projects

By Tom Kleckner

ERCOT stakeholders unanimously endorsed almost $250 million in transmission projects during last week’s Technical Advisory Committee meeting, sending the package to the Board of Directors for its Dec. 12 meeting.

The two projects will address “significant” industrial growth in the Freeport area, a seaport south of Houston on the Gulf of Mexico. Newly committed industrial loads are expected to push the area past 2.2 GW by 2022, surpassing the heavily populated Rio Grande Valley.

The market “thinks about big meaty load pockets like the [Dallas-Fort Worth] area, Houston, San Antonio and Austin, but we haven’t really thought about Freeport,” said Jeff Billo, ERCOT’s senior manager of transmission planning.

ERCOT staff project a 92% increase in the area’s load by 2019, from 1,028 MW to 1,979 MW. An additional 300 MW is expected by the end of 2022.

CenterPoint Energy, which services the area, submitted the “Freeport Master Plan Project” to ERCOT’s Regional Planning Group, proposing a two-phase approach to solve reliability criteria violations caused by the increased load. Staff’s independent review agreed with the projects’ needs, finding multiple reliability criteria violations in 2020 and 2022 cases.

The $32.3 million first phase, or “bridge-the-gap upgrades,” focuses on near-term reliability needs. It consists of a 345-kV loop and a series of reactors, autotransformers and capacitor banks at a key substation.

The $214.4 million second phase comprises a new 48-mile, 345-kV double-circuit line and circuit upgrades to another 345-kV line. It was one of five options considered by staff, four of which involved a new 345-kV right of way, and would meet the “long-term reliability criteria needs in the most cost-effective manner.”

The other four options had cost estimates of between $223.2 million and $281.8 million.

“We realize there is a long-term need to put in bigger infrastructure projects, but to get to that point, interim upgrades need to be done,” Billo said. “More upgrades will need to be done in order to meet the long-term needs of the system.”

Staff’s recommendation met little resistance from members, who only needed to be assured the load increase will be included in ERCOT’s next Capacity, Demand and Reserves (CDR) report. That report, to be released Dec. 18, includes a snapshot of planned resource additions during the next five years, current information about existing resources and the annually updated peak demand forecast for the next 10 years.

Billo also updated members on the South Plains Project, a proposed $247.5 million, 345-kV line in the Texas Panhandle.

Billo said Sharyland Utilities has proposed the transmission line as an economic project but that ERCOT’s analysis has yet been able to economically justify the project. He said about $210 million of the South Plains Project overlaps with work that would be done to integrate Lubbock Power & Light, which wants to shift 470 MW of load from SPP into ERCOT.

The Public Utility Commission of Texas has scheduled a hearing on LP&L’s integration Jan. 17-18 (Docket 47576). Until then, staff has paused further analysis.

“We will wait to see what happens in that hearing and the subsequent decision that comes out of the PUC,” Billo said. “That may supersede the need to analyze part of [the South Plains] project. If the commission says we’re going to go ahead with Lubbock and those lines get approved, we don’t have to do an economic justification for [the South Plains] lines anymore.”

Billo said staff would update its assumptions and Sharyland’s capital cost updates, and add plant retirements and other fresh data in a potential reassessment of the project that could be ready by mid-2018.