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February 3, 2019

NYISO Looks at Carbon Charge Credits, Tariff Changes

By Michael Kuser

RENSSELAER, N.Y. — NYISO stakeholders learned Thursday that pricing carbon into the wholesale energy market would have little effect on corporate credit rules and that any necessary changes will only be discussed after a second-quarter vote on market design and Tariff revisions.

ISO Manager of Corporate Credit Sheri Prevratil told the Market Issues Working Group (MIWG) that, based on the current market design, the only potential change might be to adjust the projected true-up exposure timing of transaction settlements to reflect the true-up timing of emission charges.

“Currently, that particular [timing] requirement is triggered off only the four-month true-up as a percentage of the initial invoice,” Prevratil said. “Depending on the timing of when those carbon true-ups come in, it may impact [that] and we might have to make a change on the trigger to the final bill closeout as it relates to the initial or formal settlement.

“But that’s the only one that right now I see might have to change as a credit rule,” Prevratil said.

If necessary, such rule changes would likely have to go through the ISO’s Billing, Credit and Accounting Working Group, and potential credit rule changes would not delay implementation plans for carbon pricing, she said.

New York’s Implementing Public Policy Task Force (IPPTF) in December turned its carbon pricing proposal over to the ISO’s stakeholder process through the MIWG, which began its work in January. (See Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off.)

There may be more than one proxy generator bus at a particular interface with a neighboring control area to enable NYISO to distinguish the bidding, treatment and pricing of products and services at the interface. | *NYISO*

Energy Credit Components

NYISO will also evaluate potential adjustments in the external transactions component to account for carbon charges on imports and carbon payments on exports.

“Currently, we do anticipate that that carbon charge or carbon payment will just be a part of the daily net gains and losses, part of those calculations, and just summed up daily as the daily bill finalizes,” Prevratil said. “Carbon pricing will net in the daily advisory bill and will therefore net against daily energy purchases or sales in the Energy and Ancillary Services credit calculation.”

At the previous MIWG meeting, market participants expressed concern about a gross carbon charge that would be netted against the residuals in net cost, and that the resulting net amount would be further netted with all the other energy and ancillary services numbers that go into that calculation, she said.

The intent of the second part of the calculation is to capture changes, Prevratil said. “For example, we’re in a polar vortex right now. … If that run rate on average exceeds what we’re already holding, then you’re going to get a collateral call and it will be due two business days later. That will continue, but that’s a rolling 10-day run rate, so once those charges go down, then it will fall back to the first part of the calculation.

“We don’t anticipate changing the methodology of this,” Prevratil said.

The energy and ancillary services credit requirement equals the higher of the following:

The highest month’s price adjusted energy purchases in the prior equivalent capability period divided by the number of days in that month, multiplied by 16 days; or

The total average daily energy purchases incurred over the last 10 days, multiplied by 16 days.

New Tariff Sections

Pricing carbon into the wholesale energy market would require new Tariff sections related to applying a carbon charge, defining the social cost of carbon (SCC) and allocating carbon residuals, Ethan D. Avallone, senior energy market design specialist, told the MIWG.

NYISO’s Market Administration and Control Area Services Tariff (MST) would also require revisions to other sections, and subsequent Tariff presentations, including redline Tariff sheets, will build on the one considered at Thursday’s meeting, Avallone said. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)

As an example, Avallone pointed out, MST sections 7.2 and 7.4 would need to address emissions data reporting; section 17 would address the carbon component of the locational-based marginal price (LBMPc); section 23.3 would cover emission rates and reference levels under a carbon charge; and section 26 would cover any potential credit rule changes. NYISO will address those details when credit discussions begin this fall after approval of the carbon pricing market design.

Stakeholders asked what would happen to the ISO’s carbon pricing scheme if New York were to implement a carbon tax.

“We will follow what’s in the budget bill, and we will evaluate how it impacts NYISO’s efforts,” said James Sweeney, a senior attorney at the ISO. “We will make efforts in the Tariff such that entities don’t pay twice for carbon. How exactly it would be done is yet to be determined.”

The ISO foresees no revisions to MST sections 4.2 and 4.5, which describe day-ahead and real-time energy settlements, respectively, nor to guarantee payments such as bid production cost guarantees (BPCG), day-ahead margin assurance payments (DAMAP) and import curtailment guarantee payments.

NYISO’s current guarantee payment practices will continue under carbon pricing, Avallone said.

He emphasized that the ISO will charge each supplier on carbon emissions resulting from actual energy flows.

For example, NYISO will charge each supplier scheduling imports or pay each supplier scheduling exports the LBMPc at the relevant proxy generator bus, but the supplier will not be subject to a carbon charge or payment if the transaction fails in the ISO’s checkout process or is curtailed at the ISO’s request.

The latest NYISO schedule on carbon pricing calls for discussing LBMPc calculation and identifying marginal units on Feb. 15; Tariff revisions on Feb. 28 and March 18; and carbon bid adjustment for opportunity cost resources on March 4.

February 3, 2019

Xcel Again Betters Year-end Guidance

By Tom Kleckner

Xcel Energy last week reported that it once again met or exceeded its earnings guidance, posting year-end profits of $1.26 billion ($2.47/share), compared to $1.15 billion ($2.25/share) in 2017.

It was the 14th straight year the Minneapolis-based company had exceeded its own guidance.

Xcel’s fourth-quarter earnings were $215 million ($0.42/share), up from $189 million ($0.37/share) a year earlier. That met Zacks Investment Research’s consensus forecast.

Xcel continues to focus its efforts on clean energy. | *Xcel Energy*

Oil and gas production and strong economies in Xcel subsidiary Southwestern Public Service’s footprint drove a 1.3% increase in energy sales. The company expects flat sales in 2019, but it reaffirmed its 2019 earnings guidance of $2.55 to $2.65/share.

CEO Ben Fowke said the company’s clean energy transition continues to be a strategic priority. He said the company’s steel-for-fuel strategy has achieved a 39% reduction in carbon emission from 2005 levels. The company has set an 80% carbon-reduction target by 2030 and a goal of 100% carbon-free energy by 2050.

“Technologies have come a long way in the last 10 years, and it gives me confidence that our 100% carbon-free bill can be met as well,” Fowke said during a Jan. 31 conference call with financial analysts.

Xcel secured approval for more than 1 GW of new wind in Texas and New Mexico and 300 MW of wind in South Dakota. It completed construction of its 600-MW Rush Creek wind farm in Colorado and also acquired 70 MW of repowered wind energy.

Investors on Wall Street applauded Xcel’s performance, driving the company’s share price up $1.22 to $52.14, a 2.4% increase. It hit an all-time closing high of $53.68/share in December.

February 3, 2019

SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019

By Tom Kleckner

Board Approves Modernized Cost-recovery Structure

NEW ORLEANS — SPP continued its effort to modernize its cost-recovery processes last week, agreeing to replace its broad single rate schedule with four targeted ones.

The Board of Directors approved the Schedule 1A Task Force’s recommended preliminary designs during its regular quarterly meeting. The group’s four rate schedules seek to better align beneficiaries with payers and include energy transactions in their design.

January’s Board of Directors/Members Committee meeting | © *RTO Insider*

The new rate design was approved by the Markets and Operations Policy Committee two weeks prior. The task force will now draft Tariff language and bring it back for approval in April or July. It has targeted implementation by June 2021. (See “1A Task Force’s Fee Schedules OK’d,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)

SPP says its current cost-recovery mechanism is based on a two-decade-old structure “that no longer aligns with actual use of our system.”

Under the new rate design, four rate schedules will replace the current one. Planning, scheduling and dispatch costs will be paid by transmission customers; financial administration costs by their users; market-clearing costs by virtual and real-time market participants; and markets facilitation by real-time market participants.

The task force agreed to use a mix of demand and energy charges, with market costs recovered through energy changes and planning costs through demand. Much of the debate centered on scheduling and dispatch costs, energy billing determinants and financial instruments, said Evergy’s John Olsen, the task force chair.

“I don’t think we made anyone perfectly happy throughout the process, but it was a great compromise,” Olsen said.

Oklahoma Gas & Electric’s Greg McAuley abstained from the Members Committee vote on the issue, saying his company wants to see independent generators paying their share of the costs.

“We don’t see Tariff language dealing specifically with that,” he said. “We thought this was a missed opportunity to address what we see as an inequity that exists now. We’ve got more generation in our [interconnection] queue than we’ve got load. This was an opportunity to take that uncommitted new generation and give it a stake in this infrastructure that accommodates them.

“We think it’s a move in the right direction. We’ll be watching and participating moving forward,” McAuley said.

David Osburn, general manager of the Oklahoma Municipal Power Authority, said he agreed in principle with the proposal, as market participants would be paying more of their share of the costs.

“Our concern was going from one charge to four. We just want to be careful not to make something more complex than it should be,” Osburn said. “As the real numbers develop, hopefully, we’ll get a better comfort level as we move forward. Being a small organization, we have difficulty covering all these activities.”

The task force was only formed last summer, but some of the work goes back several years, said Director Bruce Scherr, chair of the Finance Committee.

“We put a very significant stake in the ground here,” he said. “We can make refinements as we go through time. That’s not trivial, because it will require new filings at FERC. But it’s an important step in the right direction.”

OG&E’s Greg McAuley and Director Phyllis Bernard share a microphone. | © *RTO Insider*

Brown: SPP’s Prime Focus is RC Services in West

SPP CEO Nick Brown told the board and members that the grid operator’s primary goal this year will be to successfully implement reliability coordination services in the Western Interconnection.

The RTO recently said it remains on track to be certified in August and is scheduled to go live with its RC services on Dec. 3. It has signed RC contracts with about 12% of the load once served by Peak Reliability, which announced last year it would cease to exist by the end of this year. (See CAISO RC Wins Most of the West.)

“Entities coming and going in our footprint is not a new thing for us,” Brown said, referring to the additions of Nebraska public utilities and the Integrated System, and Entergy’s move to MISO. “It’s a new thing for entities in the West and for NERC. We’re very aware of NERC’s anxiety for taking what was performed under a single entity’s umbrella and bifurcating that under multiple entities.”

Also foremost on Brown’s mind is the Value and Affordability Task Force, which held its first “quasi-closed” session — members were allowed one representative to attend — on Jan. 30. Reporting directly to the board and led by Board Chair Larry Altenbaumer, the group is reviewing the cost recovery of transmission investments and the ongoing benefit being delivered from that investment and SPP’s operation.

“There’s significant confidential information that will have to be shared, if that group is to do its job,” Brown told members. “It makes me nervous. I compete with every one of you for personnel.”

Other SPP goals include:

Replacing the organization’s settlement system, which processes the more than $20 billion in annual revenues that flow through the markets. The project is behind schedule, but staff believe they can begin testing the system in May.
Improving generation interconnection processes.
Seeing conclusion of the work of the Schedule 1A Task Force and the Holistic Integrated Tariff Team, which are seeking to improve SPP’s transmission planning, markets and cost-allocation processes.

Members Increase Board’s Compensation

During a special Members Committee meeting, members sided with a Corporate Governance Committee recommendation and increased the board’s compensation for meeting attendance.

Directors will see their annual retainer raised from $30,000 to $50,000. Attendance at required meetings and board dinners will yield a total annual compensation increase from $81,000 to $101,500.

Brown said the CGC based its recommendation on recent research from NERC, two-year-old data from the ISO/RTO Council and a national association of board directors. On an annualized basis, he said, SPP directors’ compensation fell around the 50th percentile of the market.

Brown said SPP will work with compensation consultant Mercer this year to do a “full-blown” study.

Members also elected three representatives to three-year terms on the Members Committee: American Electric Power’s Peggy Simmons, representing the investor-owned utility sector; and Basin Electric Power Cooperative’s Tom Christensen and Tri-County Electric Cooperative’s Zac Perkins, representing the cooperative sector.

Perkins won a contest vote for his seat against Midwest Energy’s Bill Dowling, who was nominated from the floor without discussion.

GreenHat Energy Situation Unlikely in SPP, Director Says

Scherr told the board and members that an event similar to GreenHat Energy’s massive default on financial transmission rights in PJM’s market is unlikely to happen in SPP. PJM now estimates the event could cost its members more than $430 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

“There are significant differences in the SPP markets, such as the level of congestion and structure of [FTR] products, which reduce the likelihood of this magnitude,” he said.

Scherr said he is heartened by the Credit Practices Working Group and Market Monitoring Unit’s oversight of the grid operator’s FTR markets.

Board Approves $1.8B in Transmission Projects

The board passed a consent agenda that included the 2019 SPP Transmission Expansion Plan (STEP) report, previously endorsed by the Markets and Operations Policy Committee. The report anticipates that an estimated $1.8 billion of projects will be built over the next five years in 13 states.

Also approved as part of the agenda:

Revision to SPP’s bylaws to allow any member to appeal to the board with a written request any action taken or recommended by an organizational group.
A Tariff revision (TWG RR237) that removes duplicative or unnecessary language in the SPP criteria to make it consistent with NERC Standard TPL-001-4’s requirements and account for the differences between NERC’s requirements and SPP’s Tariff.
East River Electric Power Cooperative’s sponsored upgrades of a new 115-kV line and a 115/69-kV transformer near Aberdeen, S.D. The project will be a creditable upgrade eligible for incremental long-term congestion rights or cost recovery through the Tariff’s Attachment Z2.
Modification of Westar Energy’s notification to construct a 345/138-kV transformer, requiring all elements and conductor to have an emergency rating of 440 MVA. The original requirement was 492 MVA.

February 2, 2019

NERC Seeks $10M Fine for Duke Energy Security Lapses

By Rich Heidorn Jr.

NERC has recommended a $10 million fine on an unidentified utility for repeated violations of critical infrastructure protection (CIP) reliability standards over more than three years that exposed a “lack of management engagement, support and accountability.”

Energywire and The Wall Street Journal reported that the unnamed utility was Duke Energy, one of the nation’s largest, with 7.6 million retail electric customers in six states and 49,500 MW of generating capacity. The company told the Journal it does not comment on enforcement filings.

The control room at Duke Energy’s Buck combined cycle plant in Rowan County, N.C. | *Duke Energy*

In a Notice of Penalty filed Jan. 25, NERC cited 127 violations between 2015 and 2018 (52 posing “minimal” risk, 62 “moderate” and 13 “serious”). While most of the violations were self-reported, others resulted from compliance audits (NP19-4).

Although many of the details were redacted as critical energy/electric infrastructure information (CEIl), the document refers to “companies” and “regional entities” in the plural, suggesting a large, multistate utility was involved.

“The 127 violations collectively posed a serious risk to the security and reliability of the [bulk power system]. The companies’ violations of the CIP reliability standards posed a higher risk to the reliability of the BPS because many of the violations involved long durations, multiple instances of noncompliance, and repeated failures to implement physical and cybersecurity protections,” NERC said. “As an example, the companies’ failure to accurately document and track changes that deviate from existing baseline configurations increased the risk that the companies would not identify unauthorized changes, which could adversely impact BES [bulk electric system] cyber systems.”

The notice cited as contributing causes “disassociation of compliance and security that resulted in a deficient program and program documents, lack of implementation, and ineffective oversight and training.”

It also criticized “organizational silos” illustrated by a lack of communication between management levels and “a lack of awareness of the state of security and compliance.”

There were also silos across business units “that resulted in confusion regarding expectations and ownership of tasks, and poor asset and configuration management practices,” NERC said.

In a settlement, the companies agreed to pay the fine and to improve their performance by increasing senior leadership involvement and oversight; creating a centralized CIP oversight department; and restructuring roles to focus on standards, enterprise oversight, enterprise CIP tools, compliance metrics and regulatory interactions. They also agreed to conduct industry surveys and benchmark discussions to develop best practices.

Redacted excerpt from NERC’s Notice of Penalty.| *NERC*

The companies also agreed to invest in enterprise-wide tools for asset and configuration management, visitor logging, access management, configuration monitoring and vulnerability assessments; increase training; and institute annual compliance drills.

NERC said the penalty was based on the companies’ “repeat noncompliance” and “deficient” compliance program, mitigated by the lack of evidence of any attempt to conceal the violations. The settlement and fines are subject to approval by FERC.

Among the most serious violations cited were:

A failure to protect critical cyber asset (CCA) information. One-line diagrams lacked the appropriate NERC ClP classification markings and some employees were improperly granted “read-only” access to CCA information.
A failure to follow its change control and configuration management process. In three instances, software upgrades were deployed on a single CCA in the production environment without first being tested as required by the change control process.
A failure to maintain annual cybersecurity training for some employees with electronic or physical access to CCAs.
A failure to timely revoke former employees’ and contractors’ electronic access rights.
Allowing individuals improper electronic access to CIP-protected information.
Improperly configured routers that prevented monitor server logs from being sent to the security incident and event management (SIEM) device.
A failure to monitor electronic security perimeter (ESP) inbound and outbound communications and to restrict inbound electronic access to ESPs. “The companies used overly broad ESP firewall rulesets, which permitted access across ports and services that were not required for operations or for monitoring CAs within the ESPs,” NERC said. “Additionally, the companies failed to implement strong technical controls to ensure the authenticity of the accessing party for [redacted] individuals who were granted unauthorized access to the ESPs.”
Firewalls were configured to allow external remote access to sensitive systems without first going through an intermediate system, using encryption or requiring multi-factor authentication.
A failure to implement physical access controls to limit unescorted access to the physical security perimeter (PSP) and failing to document all required information in visitor logbooks.
Repeated failures to adhere to cybersecurity testing procedures, including deficient testing on software upgrades and failures to implement security patch programs.
Failing to change passwords on annual schedule and failing to change factory default passwords for remotely accessible BES cyber assets.

Duke Energy Center, Charlotte, N.C. | *Duke Energy*

NERC’s filing came days before intelligence officials told the Senate Intelligence Committee on Jan. 29 that Russian hackers have the capability to disrupt electrical service in the U.S.

“Moscow is now staging cyberattack assets to allow it to disrupt or damage U.S. civilian and military infrastructure during a crisis and poses a significant cyber influence threat,” officials said in the annual Worldwide Threat Assessment.

“Russia has the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure — such as disrupting an electrical distribution network for at least a few hours — similar to those demonstrated in Ukraine in 2015 and 2016. Moscow is mapping our critical infrastructure with the long-term goal of being able to cause substantial damage.” (See DHS: 2017 Russian Probes Hit Hundreds of Energy Cos.)

The report also warned that China also “has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks—in the United States.”

February 2, 2019

NERC Seeks $10M Fine for Duke Energy Security Lapses

By Rich Heidorn Jr.

It also criticized “organizational silos” illustrated by a lack of communication between management levels and “a lack of awareness of the state of security and compliance.”

There were also silos across business units “that resulted in confusion regarding expectations and ownership of tasks, and poor asset and configuration management practices,” NERC said.

Energywire and The Wall Street Journal reported that the unnamed utility was Duke Energy, one of the nation’s largest, with 7.6 million retail electric customers in six states and 49,500 MW of generating capacity. The company told the Journal it does not comment on enforcement filings.

Among the most serious violations cited were:

A failure to protect critical cyber asset (CCA) information. One-line diagrams lacked the appropriate NERC ClP classification markings and some employees were improperly granted “read-only” access to CCA information.
A failure to follow its change control and configuration management process. In three instances, software upgrades were deployed on a single CCA in the production environment without first being tested as required by the change control process.
A failure to maintain annual cybersecurity training for some employees with electronic or physical access to CCAs.
A failure to timely revoke former employees’ and contractors’ electronic access rights.
Allowing individuals improper electronic access to CIP-protected information.
Improperly configured routers that prevented monitor server logs from being sent to the security incident and event management (SIEM) device.
A failure to monitor electronic security perimeter (ESP) inbound and outbound communications and to restrict inbound electronic access to ESPs. “The companies used overly broad ESP firewall rulesets, which permitted access across ports and services that were not required for operations or for monitoring CAs within the ESPs,” NERC said. “Additionally, the companies failed to implement strong technical controls to ensure the authenticity of the accessing party for [redacted] individuals who were granted unauthorized access to the ESPs.”
Firewalls were configured to allow external remote access to sensitive systems without first going through an intermediate system, using encryption or requiring multi-factor authentication.
A failure to implement physical access controls to limit unescorted access to the physical security perimeter (PSP) and failing to document all required information in visitor logbooks.
Repeated failures to adhere to cybersecurity testing procedures, including deficient testing on software upgrades and failures to implement security patch programs.
Failing to change passwords on annual schedule and failing to change factory default passwords for remotely accessible BES cyber assets.

NERC’s filing came days before intelligence officials told the Senate Intelligence Committee on Jan. 29 that Russian hackers have the capability to disrupt electrical service in the U.S.

February 1, 2019

Judge Postpones Strict Probation Conditions for PG&E

By Hudson Sangree

A federal judge on Wednesday delayed his decision to impose extensive new probation conditions on Pacific Gas and Electric in its criminal case for the 2010 San Bruno gas line explosion, including a requirement that the utility inspect its entire grid for safety problems before the start of this year’s fire season.

Instead, Judge William Alsup, of the U.S. District Court for the Northern District of California, in San Francisco, said he would wait to the see the fire mitigation plan that PG&E files with the California Public Utilities Commission on Feb. 6, in compliance with last year’s SB 901. The judge also asked lawyers representing both explosion and wildfire victims to submit more information on fire safety measures they discussed at Wednesday’s hearing.

A section of the 30-foot gas pipeline owned by PG&E that exploded in 2010, killing eight people in San Bruno, Calif.

The hearing in the San Bruno case came a day after the utility and parent PG&E Corp. filed for bankruptcy, in part because they potentially face billions of dollars in liability for the fatal wine country fires of October 2017 and the Camp Fire in November 2018, which killed 86 people and destroyed the town of Paradise.

On Jan. 9, Alsup issued a tentative ruling in which he said that, unless the parties convinced him otherwise, he would impose new probation conditions on PG&E, which was convicted of six felonies for knowingly violating federal safety rules and obstructing a federal investigation after the 2010 explosion that killed eight people. (See Judge, Governor, CPUC and Protesters Weigh in on PG&E Mess.)

Those new conditions would include requiring the utility to reinspect its entire grid in the coming months and to remove any trees or branches that could contact power lines. In addition, he said PG&E would have to “identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions.”

The Camp Fire killed 86 residents and wiped out the town of Paradise on Nov 8, 2018. PG&E equipment is a suspected cause. | *NASA*

The utility “shall identify and fix damaged or weakened poles, transformers, fuses and other connectors; and shall identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires,” Alsup wrote.

“These conditions of probation are intended to reduce to zero the number of wildfires caused by PG&E in the 2019 wildfire season. This will likely mean having to interrupt service during high-wind events (and possibly at other times), but that inconvenience, irritating as it will be, will pale by comparison to the death and destruction that otherwise might result from PG&E-inflicted wildfires,” the judge wrote.

PG&E protested the proposed conditions, saying it would cost between $75 billion and $150 billion to comply with the requirements. Federal prosecutors also encouraged the judge to back down and defer to the federal monitor overseeing PG&E in the wake of the San Bruno case. (See PG&E Cleared in Fire that Burned Santa Rosa.)

February 1, 2019

Make PG&E a Public Utility, Protesters Tell PUC

By Hudson Sangree

SACRAMENTO, Calif. — Protesters at the Public Utilities Commission meeting on Thursday urged the commissioners to try to turn Pacific Gas and Electric into a publicly owned utility as part of its Chapter 11 reorganization that began when the company filed for bankruptcy protection Tuesday.

Protesters at Thursday’s CPUC meeting in Sacramento read aloud the names of those killed by wildfires. | © *RTO Insider*

“We have the opportunity to radically restructure what our energy system looks like — safe, public and one that ensures everyone the right to access,” said Morganne Blais-McPherson, a University of California, Davis student and co-chair of the university’s Young Democratic Socialists of America chapter.

Unlike recent protests at PUC meetings in San Francisco, the Sacramento gathering was relatively tame. Demonstrators didn’t disrupt the meeting or shout. They spoke only during public comment, mostly without going over the two-minute time limit set by PUC President Michael Picker.

The calm meeting capped off a tumultuous week of hearings and court filings involving PG&E and the PUC.

On Monday, the PUC called a hasty and controversial meeting to allow PG&E to obtain billions of dollars in debtor-in-possession (DIP) financing to see it through bankruptcy.

On Tuesday, just after midnight, the utility filed for bankruptcy in federal court in San Francisco. The first hearing in the bankruptcy case, which was mainly procedural, was held that afternoon. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)

Protesters displayed signs during Thursday’s CPUC meeting in Sacramento. | © *RTO Insider*

On Wednesday, a judge considered whether to impose stringent new conditions on PG&E for violating criminal probation in the 2010 San Bruno gas line explosion case, and the State Assembly held an oversight hearing of the PUC in which some lawmakers demanded that regulators do more to keep PG&E and other utilities from sparking deadly wildfires. (See related story, Lawmakers Grill CPUC President on PG&E, Fires.)

Another bankruptcy hearing started Thursday morning in San Francisco, about the same time the PUC was meeting in Sacramento. (See related story, Judge Postpones Strict Probation Conditions for PG&E.)

Seth Sanders, a member of the Democratic Socialists of America, said that as a parent and ratepayer, he was upset to see PG&E seek bankruptcy protection when it is suspected of starting November’s Camp Fire, which killed 86 people and destroyed the town of Paradise.

“I have been sick to my stomach,” Sanders told commissioners. “This is a terrible insult to the memories of the dead.”

Protesters listen to the CPUC proceedings during Thursday’s meeting in Sacramento. | © *RTO Insider*

Sanders and other protesters called for a restructuring of PG&E into municipal systems, citing the Sacramento Municipal Utility District as a model. Their statements were met with quiet finger snapping from other demonstrators, some of whom stood holding signs.

(San Francisco officials have said publicly they might be interested in taking over PG&E’s assets in the city and forming a municipal utility.)

At one point, protesters read aloud the names of about 40 fire victims, as they have done at other PUC meetings.

“Unless you do something, you’re going to get us all killed,” Robert Henderson told the commissioners during the public comment period.

Mary Kay Benson, of Butte County, Calif., said many of those who died in the Camp Fire were senior citizens, like her. | © *RTO Insider*

Mary Kay Benson said she was from Chico, the neighboring town to Paradise in largely rural Butte County. Many of the dead were senior citizens, like her, Benson said.

“Are we all just corporate collateral?” she asked the commissioners.

Pete Woiwode, of Oakland, said he was at Monday’s raucous meeting in San Francisco, when the PUC approved PG&E’s DIP financing with little public notice and over the objections of demonstrators.

“That should not have happened,” Woiwode said.

February 1, 2019

Lawmakers Grill CPUC President on PG&E, Fires

By Hudson Sangree

SACRAMENTO, Calif. — Public Utilities Commission President Michael Picker told lawmakers Wednesday the commission probably isn’t the best public entity to address the “enormity” of the state’s recent wildfire crisis.

The PUC has been trying to help prevent wildfires sparked by electric utilities, as required by last year’s SB 901. But the commission, Picker said, is more like a specialized court that sets utility rates, not a fire prevention agency such as the Department of Forestry and Fire Protection.

“They understand fires. We understand ratemaking,” Picker told the Assembly Utilities and Energy Committee during its annual oversight hearing of the PUC.

He said the commission was set up long ago to slowly gather and weigh evidence on regulated utilities, not to react quickly to urgent public safety matters.

“I don’t think this is where you’re going to get a sense of urgency,” Picker said later.

Officials of the California Public Utilities Commission listened to lawmakers critique their handling of the state’s wildfire crisis at an oversight hearing Wednesday. | © *RTO Insider*

Picker’s briefing on the PUC’s varied activities quickly turned into a sometimes tense discussion of wildfires and Pacific Gas and Electric, which filed for bankruptcy Tuesday. (See PG&E Files for Bankruptcy.) Some lawmakers were cordial with Picker, while others grilled him about what the commission was doing to prevent more devastating wildfires like the deadly ones that ravaged the Northern California in the past two years.

“We’re well over 100 deaths in these fires,” said Assemblymember Jim Wood (D), whose North Coast district was heavily scarred by the wine country wildfires of 2017. “What will you do this year to protect Californians?”

Picker said the PUC had been in the process of figuring out what to do with PG&E, including breaking up the company or replacing its board members.

Financial penalties, including a $1.6 billion fine after the San Bruno gas line explosion in 2010, had failed to change the company’s board members or safety culture, he said.

“Fines are just not enough,” Picker said.

Now those decisions likely will be made by a federal bankruptcy judge, with the PUC recommending a reorganization plan for PG&E, he said.

“We will contend with them as advocates for ratepayers in bankruptcy,” Picker said.

Earlier this month, a federal judge overseeing PG&E’s criminal probation in the San Bruno case said he might require the utility to inspect every inch of its grid before the 2019 fire season starts this summer. The judge backed off on that plan, at least temporarily, in a hearing in San Francisco earlier Wednesday. (See Judge Postpones Strict Probation Conditions for PG&E.)

Picker said the PUC had looked at what it would take for it to inspect the state’s high-risk fire areas for overhanging branches and other safety problems. He said the commission would need to hire between 15,000 and 20,000 workers to inspect 4.2 million power poles and 200,000 miles of transmission lines.

A better investment, he said, would be for utilities to adopt extensive weather monitoring, as San Diego Gas & Electric did in Southern California. The National Weather Service typically estimates wind gusts on ridgetops. Fires start near electric lines in canyons down below. SDG&E deployed an extensive network of weather stations and cameras in such locations, Picker said. (See Calif. Regulators to Scrutinize De-energization.)

“They had to develop a whole new weather system within their service area,” and PG&E could do the same in Northern California, he told committee members.

During a Legislative oversight hearing Wednesday, Assemblywoman Eloise Gomez Reyes (D), right, asked PUC President Michael Picker, left, why more wasn’t being done to prevent wildfires sparked by electric utilities. | © *RTO Insider*

Assemblyman Bill Quirk (D) suggested the PUC had been partly responsible for driving PG&E into bankruptcy. SB 901 tasked the commission with performing a stress test to determine how much a utility could pay in wildfire liability without harming ratepayers or undermining grid reliability. The rest would have to be paid by shareholders.

Creditors wanted to know the extent of PG&E’s expected liability, Quirk said. The utility must borrow $2 billion a year, and the PUC’s inability to provide creditors with more certainty had led major ratings firms to downgrade PG&E’s creditworthiness to junk status and cut off its access to credit, he said.

Picker said the PUC couldn’t supply a stress-test figure until all official fire investigations have concluded and it performs its own analysis, which could take 18 months. “We don’t know the cost in the end,” he said.

February 1, 2019

NERC Issues $10M Fine for Security Lapses

By Rich Heidorn Jr.

It also criticized “organizational silos” illustrated by a lack of communication between management levels and “a lack of awareness of the state of security and compliance.”

There were also silos across business units “that resulted in confusion regarding expectations and ownership of tasks, and poor asset and configuration management practices,” NERC said.

February 1, 2019

NYISO Management Committee Briefs: Jan. 30, 2019

By Michael Kuser

RENSSELAER, N.Y. — NYISO last month incorporated additional 115-kV transmission facilities in its energy market model, Chief Operating Officer Rick Gonzales told the Management Committee on Wednesday.

Gonzales said the facilities, mostly in western New York, were incorporated into the real-time market on Dec. 4 and the day-ahead market on Dec. 5. “Commensurate with that activity, we also deployed an enhanced Niagara model, which allows us to better address those transmission constraints,” Gonzales said in delivering the monthly operations report.

The Niagara Power Plant comprises 25 individual generating units, divided into three bulk power system injection points: Niagara 230-kV Bus (1,770 MW total); Niagara 115-kV East Bus (860 MW total); and Niagara 115-kV West Bus (645 MW total).

The ISO previously represented all 25 units as a single facility in the market models, which precluded the market model from shifting generation among these units to manage congestion and increase output from the plant. Operators can now shift output among these generators to manage congestion on both the 230-kV and 115-kV facilities.

Last month’s moves completed a project to begin scheduling and pricing more than 20 lower-voltage transmission facilities in the day-ahead and real-time markets, an effort the ISO’s Market Monitoring Unit, Potomac Economics, had recommended since 2014. (See “ISO to Begin Incorporating 100+kV Tx Facilities in Markets,” NYISO Business Issues Committee Briefs: Sept. 12, 2018.)

Howard Fromer, director of market policy for PSEG Power New York, asked whether the changes had led to a reduction in out-of-merit actions or prices.

“We’re very happy with the way that those two actions have turned out,” Gonzales said. “Securing the 115-kV with its additional constraints into our energy market has resulted in significant reductions in out-of-merit actions for Niagara or Ontario imports.”

He said the enhanced Niagara modeling should result in much more price stability in the entire New York Control Area because Niagara is a significant supplier of energy, reserves and regulation.

The ISO’s Manual 12, Transmission and Dispatch Operations Manual, says, “From time to time, generators must be operated out of economic order or at levels that are inconsistent with the calculated schedules. Any NYISO-authorized deviation from the schedule is considered out-of-merit (OOM) generation and is not subject to regulation penalties. A unit that is out-of-merit is balanced at actual output and may be eligible for a supplemental payment if its bid production cost is not met.”

Winter: So Far, So Good

Emilie Nelson, NYISO vice president of market operations, gave an update on January operations, noting the cold weather over the Martin Luther King Jr. Day weekend (Jan. 19-22) and the arctic blast that hit the state that day.

NYISO winter peak loads (MW): 2004/05 to 2017/18 | *NYISO*

Although there was substantial snowfall upstate, the storm caused no real transmission or distribution issues, Nelson said. Good coordination with transmission owners and neighboring grid operators led to some transmission being returned to service from maintenance outages in advance of the anticipated weather, she said.

“We did see in advance of the [MLK] weekend generators begin to switch to oil, with escalated gas prices and some limitations projected in advance of Monday, which was the coldest day,” Nelson said. “We of course have a weekly fuel survey process — which can occur more frequently for prolonged periods of cold weather — and we had sufficient oil inventories.”

Demand peaked at 24,728 MW on Monday, Jan. 21, exceeding the 90/10 day-ahead forecast, she said. The demand for energy reflected peak temperatures across the New York Control Area of 8.8 degrees Fahrenheit, which came in very close to the forecast. The minimums experienced were 3 F in Syracuse, 0 F in Albany and 6 F in New York City.

“This was the first time [this winter] we had the cold extend all the way into the downstate regions,” she said. On Jan. 21, the ISO saw about 700 MW of derates because of fuel-related issues and an additional 160 MW from other cold weather issues, Nelson said.

Consolidated Edison, National Grid and other natural gas pipeline operators issued operational flow orders in advance.

The storm hitting as she spoke looked to be very similar to the one in mid-January, both in terms of projected peak load and the value of low temperatures across the state, Nelson said.

Committee Approves Repricing TCC Credit Requirement

The MC approved using the market clearing price to calculate the credit requirement for fixed-price transmission congestion contracts (TCCs), in accordance with Market Services Tariff Section 26.4.2.4.1.

Sheri Prevratil, NYISO manager of corporate credit, reiterated the case she made in persuading the Business Issues Committee earlier in January, which recommended the measure to the MC. (See NYISO Business Issues Committee Briefs: Jan. 16, 2019.)

Under the changes, the ISO will use $0 as the payment obligation portion of the requirement if the price calculated for the fixed-price TCC is less than $0. Otherwise it will continue to use the greater of the payment obligation or the credit holding requirement until receiving payment for the contract. The credit holding requirement is the greater of the auction TCC holding requirement, the fixed-price TCC holding requirement or the mark-to-market calculation.

“Essentially we’re just proposing to change the fixed-price TCC credit requirement to be in line with the holding requirement for auction TCCs,” Prevratil said.

Asked whether stakeholders were adequately protected from the risk of a default like that of GreenHat Energy in PJM, Prevratil said, “Yes, in the end we will be covered more appropriately for these TCCs because the market clearing price will be used to better reflect the risk of the TCC instead of using the fixed price across the term of the TCC.” (See FERC OKs Key PJM Changes to Address GreenHat Default.)

If the change is approved by the Board of Directors in March, the ISO will file with FERC in April for deployment in June.