Page 1078 – RTO Insider

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.

February 1, 2019

Utility CEOs Urge PJM Board to Act on Price Formation

By Christen Smith

Four top utility executives urged PJM’s Board of Managers to act on price formation at its Feb. 12 meeting after stakeholders deadlocked on the issue last week.

Exelon CEO Chris Crane | © *RTO Insider*

CEOs Chris Crane of Exelon, Ralph Izzo of Public Service Enterprise Group and Charles E. Jones of FirstEnergy signed a Jan. 29 letter criticizing PJM for failing to implement energy and capacity market rule changes despite a decade of stakeholder discussions. Douglas Esamann, president of Duke Energy’s Midwest and Florida regions, also signed the letter, which said PJM was lagging behind other eastern RTOs and ISOs in addressing its “woefully out of date” operating reserve demand curve.

“Specifically, PJM has not been able to adequately navigate the current stakeholder process that was initiated to address key energy market price formation issues,” they said. “As a result, critical reforms have been mired in regulatory proceedings for years.”

Crane and Izzo have long supported changes to PJM’s market price formation methodology, calling it a “no brainer” and “long overdue.” (See CEOs See Dollar Signs in ZECs, PJM Price Formation.) They and Jones have threatened to shutter their struggling nuclear plants without rule changes to increase the plants’ revenues. FirstEnergy also has sought subsidies for its coal-fired generation.

“It is imperative that the board and PJM act swiftly and decisively on important price formation reforms so that these fundamental issues can be addressed within the PJM markets,” the executives concluded. “The markets are at a critical juncture and clear leadership is necessary to ensure the markets evolve to work as efficiently as intended and meet the needs of customers and investors.”

‘Not Enough’

Aside from the RTO’s stalled price formation initiative, the executives also chastised PJM for not defining resilience attributes and reacting too slowly to fuel security concerns following the December 2018 NERC report highlighting potential risks from accelerated retirements. (See NERC Releases ‘Stress Test’ Analysis of Gen Retirements.)

“Instead of driving changes for appropriate market price signals, PJM remains a facilitator to implement changes that achieve stakeholder consensus,” they said. “This is simply not enough.”

“This letter is one of a number of communications we expect to receive on the subject of reserve price formation and the stakeholder process in advance on the next PJM Board of Managers meeting,” PJM spokeswoman Susan Buehler said. “The board will take all stakeholder comments into consideration before reaching any decisions.”

Jeff Dennis, managing director and general counsel of Advanced Energy Economy, criticized the companies’ reliance on the NERC report and PJM’s own fuel security study as the basis for pushing through regulatory changes without stakeholder consensus.

“Let’s be clear — they’re trying to shortcut the stakeholder process on those issues based on two reports that make no showing of likely reliability risks in the near or immediate term, finding long-term risks in only the most extreme scenarios,” he tweeted Thursday. “If we’re going to continue the search for the black swan, let’s at least do it in an open, technology-neutral way that actually addresses demonstrated grid needs, rather than forcing discriminatory tech-specific market rules that benefit fuel-dependent resources.”

Stakeholder Deadlock

The executives’ letter came less than a week after the Markets and Reliability Committee failed to approve any of five price formation proposals — from PJM, Calpine, the Independent Market Monitor, the D.C. Office of the People’s Counsel and Vistra Energy.

FirstEnergy CEO Charles E. Jones | *FirstEnergy*

At the Jan. 24 meeting, load interests balked at the Jan. 31 deadline set by the board for stakeholder action. Exelon’s Jason Barker expressed frustration over the load interests’ request for more time after more than a year of discussions, saying “the time is now to move forward.” (See PJM Stakeholders Deadlock on Energy Price Formation.)

More than 60% of transmission owners voted in favor PJM’s plan or Calpine’s compromise package. The Vistra plan likewise received 86% support from TOs. Electric distributors and end-use customers unanimously supported the Monitor proposal instead. None came close to the two-thirds sector-weighted vote needed for approval.

PJM CEO Andy Ott said last week the board will consider input from both the MRC and upcoming Liaison Committee meetings before submitting a FERC filing on the issue. The Members Committee agreed to hold a special conference call no later than Feb. 8 if additional discussions yield a potential compromise in the interim.

January 31, 2019

PJM: FERC Order Could Boost GreenHat Default by $300M

By Rich Heidorn Jr.

The cost of GreenHat Energy’s default could rise by $250 million to $300 million if PJM is forced to unwind settlements of the company’s financial transmission rights portfolio, PJM Chief Financial Officer Suzanne Daugherty said Thursday. That could push the total cost of the company’s collapse to at least $430 million, Daugherty said.

PJM said it will seek a stay of FERC’s Jan. 30 order rejecting a waiver of the RTO’s liquidation rules and requiring it to resettle five months of FTRs that the commission said should have been liquidated sooner (ER18-2068).

PJM Chief Financial Officer Suzanne Daugherty | *© RTO Insider*

In an email to members, Daugherty said the commission’s ruling would have a dire impact on members and consumers.

“The waiver request was based on the legal vehicles and FERC precedents in effect to stop liquidation in an auction that was dysfunctional and which certainly would have resulted in unjust and unreasonable rates,” she said.

FERC’s order requires PJM to rerun the cleared July 2018 FTR auction and liquidate a “significant portion” of the FTR positions from the GreenHat portfolio for September 2018 through May 2019, PJM said. It also requires the RTO to unwind the default allocations and related settlements made for GreenHat FTRs that went to settlement since September 2018.

PJM would be required to resettle every FTR portfolio impacted by rerunning the prior auctions, it said. (See FERC Orders PJM to Unwind GreenHat Settlements.)

The resettlements would “likely place a number of members in breach of their collateral requirements of PJM’s credit policy and require them to fulfill a collateral call within two business days based on the unanticipated changes in the positions in members’ FTR portfolios that would result from changing the cleared results of the July 2018 FTR auction,” Daugherty said.

The RTO asked FERC on July 26 for a waiver of Tariff rules requiring it to offer all of GreenHat’s FTR positions at a price designed “to maximize the likelihood of liquidation.” The RTO said a slower liquidation of the company’s large portfolio would reduce losses to members.

But FERC said PJM’s request would affect the outcome of the July FTR auction “as well as parties’ confidence in the rules governing future proceedings.”

The commission also rejected PJM’s request to retain $550,000 in collateral posted by one of GreenHat’s principals through a second company (ER18-1972).

PJM said it will ask FERC to rehear the waiver case and seek a stay on the order in the interim. Asked when the stay request would be filed, PJM spokesman Jeff Shields said, “We are still considering our legal options.”

January 31, 2019

LaFleur Announces Departure from FERC

By Michael Brooks

Looks like this will be the last Super Bowl that Commissioner Cheryl LaFleur gets to wear her New England Patriots jersey at FERC headquarters.

LaFleur at the Independent Power Producers of New York’s Spring Conference in May 2017, when she was acting chair of FERC. | © *RTO Insider*

LaFleur on Thursday announced she was “no longer seeking” a third term and would leave the commission by the end of the year.

LaFleur, who has served on the commission since July 13, 2010 — longer than all her colleagues’ tenures combined — said she would stay until at least June 30, the end of her current term, “and probably longer, depending on my future plans and the possible appointment of a successor.”

Senate leadership informed the commissioner Tuesday that President Trump would not nominate her for another term, according to Andrew Holleman, LaFleur’s communications and policy analyst. By law, she can stay on the commission past June 30 until a replacement is sworn in or until the end of the current session of Congress.

“She’s said all along it wasn’t her decision, so she figured she would make an announcement as soon as she heard,” Holleman said in an email.

“While this is not the outcome I had hoped for, I feel very lucky to have served on FERC for more than eight years (and counting),” LaFleur said in a statement. “It has been a high honor to serve at the commission, and I love working here. I have many people to thank for the opportunities I’ve had and will certainly have more to say as I get closer to actually leaving.”

LaFleur declined further comment. A FERC spokesperson declined to comment.

With the departure of Robert Powelson in July and the death of Commissioner Kevin McIntyre on Jan. 2, FERC would be left with three commissioners after LaFleur’s departure. A spokeswoman for Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, said she has not heard anything from the White House regarding its plan for replacement nominees. Holleman also said he had not heard anything.

A Constant Presence

Nominated by President Barack Obama, LaFleur’s tenure has been marked by frequent upheavals in the commission’s roster.

She came to the commission after more than two decades in the electric and natural gas industry, including a stint as executive vice president and acting CEO of National Grid USA.

LaFleur became acting chair of the commission after the resignation of Jon Wellinghoff in 2013, and she was nominated by Obama for a second term in 2014. The president also nominated Norman Bay, then director of the commission’s Office of Enforcement, as chair, but members of the ENR Committee protested, citing Bay’s lack of regulatory experience and the gender politics of his ascension over LaFleur. This led to an unusual deal between the Senate and the White House, in which LaFleur became the chair for nine months while Bay served as commissioner. (See Senate Confirms Bay, LaFleur.)

Bay took over the chair in April 2015. But he resigned shortly after Trump’s inauguration in January 2017, when the new president named LaFleur acting chair again until a Republican could be sworn in. The GOP seats were empty after Philip Moeller and Tony Clark left the commission in October 2015 and September 2016, respectively.

Bay’s resignation also left the commission without a quorum to issue orders and decisions, which would last for six months until the arrival of Republicans Chatterjee and Powelson in August 2017. After the resignation of Colette Honorable in June 2017, LaFleur was briefly the lone commissioner.

The commission has been split along party lines for nearly a year over the consideration of greenhouse gas emissions in gas infrastructure approvals. Following an August 2017 ruling by the D.C. Circuit Court of Appeals that said FERC must consider the impact of greenhouse gas emissions when licensing gas pipelines, LaFleur has sided with fellow Democrat Richard Glick in voting against certain projects. (See Dem Dissents Show FERC Divide on Carbon.)

With the departure of Powelson and the death of McIntyre after months of battling brain cancer that kept him from voting, Chairman Neil Chatterjee has pulled gas items from the consent agenda at open meetings.

LaFleur’s announcement brought accolades on Twitter.

“She epitomizes what public service is all about,” Glick said.

“Her measured, fair and knowledgeable approach at FERC will be missed,” said Theodore Paradise, senior vice president of transmission strategy for Anbaric.

“An exceptional servant and thoughtful leader who withstood what one of the most trying and yo-yoing of any FERC tenure,” said Dan Dolan, president of the New England Power Generators Association.

“She has been a tremendous role model to me and countless other women in the energy industry,” said Shannon Maher Bañaga, director of federal affairs for TECO Energy. “‘Thank you’ isn’t enough.”

January 31, 2019

NERC Issues $10M Fine for 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.”

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.

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 [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.

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.

January 31, 2019

FERC Orders PJM to Unwind GreenHat Settlements

By Rich Heidorn Jr.

PJM must unwind five months of settlements for GreenHat Energy financial transmission rights that should have been liquidated sooner, FERC ruled Wednesday (ER18-206 8).

In addition to rejecting PJM’s request for a waiver of its liquidation rules, the commission also rebuffed the RTO’s request to retain $550,000 in collateral posted by one of GreenHat’s principals through a second company (ER18-1972).

The two rulings complicate the RTO’s efforts to minimize the damage of GreenHat’s default, which left other PJM members liable for more than $100 million.

The commission also disclosed that its Office of Enforcement is conducting a nonpublic investigation into whether GreenHat engaged in market manipulation or violated other commission rules. “That investigation is ongoing. The commission will determine what further action, if any, may be appropriate after it considers the results of the staff investigation,” FERC said.

The RTO said it will ask the commission to reconsider its ruling on the liquidation waivers.

“PJM took the appropriate and immediate steps in the public interest, based on the legal vehicles and FERC precedents in effect, to stop a liquidation in an auction that was dysfunctional,” RTO spokesman Jeff Shields responded late Wednesday. “PJM is disappointed that FERC, in its order, may not have fully appreciated the magnitude of the impact to our members and to consumers. PJM intends to file a rehearing and/or clarification request, and a motion to stay the order. We will have a notification for members in the coming days.”

PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | *PJM*

On Nov. 29, the commission had approved Tariff and Operating Agreement revisions that require defaulted FTR portfolios to go to settlement rather than being liquidated through auction (ER19-19). (See FERC OKs Key PJM Changes to Address GreenHat Default.)

But the commission on Wednesday declined to make those rule changes retroactive, saying the waivers could harm other FTR market participants who had relied on the RTO’s existing rules.

As described by FERC, PJM “paused aspects of” the July FTR auction after all bids and offers had been received, saying it was alarmed by a lack of liquidity and the size of risk premiums related to the GreenHat FTRs.

PJM said it would instead sell off the positions during the long-term FTR auction in September and the monthly auctions between July and October, offering only those positions effective in the prompt month (i.e., selling August FTR positions at the July auction, September FTR positions in the August auction, etc.)

The RTO asked FERC on July 26 for a waiver of Tariff rules requiring it to offer all of GreenHat’s FTR positions at a price designed “to maximize the likelihood of liquidation,” saying a slower liquidation of the company’s large portfolio would reduce losses to members.

FERC ruled that the request was not limited in scope.

“Changing the rules governing an already-commenced auction is a significant step that affects both the outcome of that particular auction as well as parties’ confidence in the rules governing future proceedings. That is particularly so here, where the record indicates that PJM proposed the waiver in order to avoid the outcome that the already-commenced auction would have produced,” FERC said.

“In addition, we note that PJM proposes to waive four discrete elements of the Tariff in order to potentially substitute new rules that were not yet formed, much less included in the record, at the time PJM made its waiver request. Such a significant change to multiple parameters of an already-commenced auction is not a remedy that is limited in scope. The record demonstrates that participants submitted bids in the July monthly FTR auction relying on the liquidation process that existed at the time PJM conducted the auction. Disrupting those settled expectations is likely to cause harm to third parties, even if doing so might produce [an] otherwise more efficient outcome, as PJM contends the waiver request would.

“To the extent PJM anticipated that the commission would grant the waiver request … PJM is required to reconcile any such actions by reinstating the original July auction results, or taking steps that are necessary to comply with the effective Tariff language when the July 2018 auction was conducted, and by unwinding settlements made for September, October, November, December and January positions that should have been liquidated.”

‘Unreasonably Harmed’

Separately, the commission also rejected PJM’s request to withhold $550,000 in collateral posted by Orange Avenue, a second company owned by one of the GreenHat principals.

PJM asked to retain the collateral for up to one year while it decides whether to take legal action against GreenHat and apply Orange’s collateral to GreenHat’s debts.

Orange posted the collateral in February 2018, but before doing any trading, it sought on June 4 to withdraw from PJM and recover the collateral.

When PJM sought more collateral from GreenHat as its losses mounted in April 2017, the company gave the RTO the rights to collect money it said Shell Energy owed it for purchasing some of its FTR portfolio. PJM was left emptyhanded, however, when Shell said it had already paid GreenHat all it owed. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

PJM said it is reviewing whether to take legal action against GreenHat over its representations in negotiating the pledge agreement.

FERC denied PJM’s request to hold Orange’s money in the interim, saying the company “would be unreasonably harmed.”

“While PJM states that it intends to investigate potential fraud with respect to the execution of the pledge agreement by the managing member of GreenHat, PJM fails to make any claim that Orange may have participated in any fraud, pointing out only that GreenHat and Orange have the same managing director. On the evidence submitted by PJM, therefore, we find that Orange would be unreasonably harmed by granting PJM a waiver request.”

January 31, 2019

FERC Clarifies ISO-NE Generator Delist Bid Rights

By Michael Kuser

FERC on Tuesday clarified on remand that a capacity supplier’s retirement bid can enter ISO-NE’s Forward Capacity Auction if the supplier demonstrates that the bid is just and reasonable, despite contrary assertions by the RTO’s Internal Market Monitor (ER16-551-004).

The D.C. Circuit Court of Appeals on Dec. 28 remanded back to the commission its original October 2017 order accepting ISO-NE’s retirement delist bid mechanism in the FCA (Exelon v. FERC, 17-1275). The court’s action was based on the commission’s own explanation at oral argument that a market participant — and not ISO-NE or the Monitor — has the right to show that its filed rate is just and reasonable and will be entered into an auction regardless of the Monitor’s proposed offer price (ER16-551-003). FERC had until Feb. 1 to respond.

“We see no way to skirt the question Exelon tees up: Under ISO-NE’s new Tariff rules, does a supplier’s rate enter the auction so long as it convinces the commission that the rate is just and reasonable, over contrary claims of the Market Monitor?” the court said.

Ambiguous Language

FERC found that “certain aspects of the relevant Tariff language and the commission’s prior orders interpreting that language are ambiguous.” It ruled that the RTO’s filing must include “the relevant information and justification submitted by both the capacity supplier and the Internal Market Monitor.”

The commission last March approved ISO-NE’s request to reduce the dynamic delist threshold for FCA 13 to $4.30/kW-month from the $5.50/kW-month used in FCAs 10 to 12 (ER18-620). The threshold, which must be revised every three years, is a key parameter for generators considering retirement, which must submit delist bids to opt out of the capacity auction. (See FERC OKs Lower Delist Threshold in ISO-NE.)

“To the extent that the commission’s prior orders in this proceeding can be interpreted as inconsistent with our answers to the court’s remand, we reject those interpretations,” FERC said in the Jan. 29 order, which revised paragraphs 18, 19 and 25 of the Oct. 30 order.

“As the court correctly noted, in the case of a conditional retirement, a mitigated bid is entered into the auction, but the resource will only retire at its originally submitted price,” the commission said. “If the clearing price is below both the original bid and mitigated bid, the unit retires. If the clearing price is at or above both bids, the supplier takes on a capacity obligation. If the clearing price is at or above the mitigated bid but below the original bid, the unit must retire.”

Accepts CASPR Tariff Revisions

In a separate order Tuesday, the commission accepted the RTO’s Tariff revisions to support implementation of the Competitive Auctions with Sponsored Policy Resources (CASPR) rules that the commission accepted in March 2018 (ER19-444). (See Split FERC Approves ISO-NE CASPR Plan.)

“With respect to the test price mechanism, we find that it is a just and reasonable means to address the potential incentive for bid-shading created by the CASPR modifications to the Forward Capacity Market,” the commission said. “Bid-shading” refers to the practice of resources electing to offer their capacity below the RTO’s assessment of their going-forward costs.

ISO-NE filed the Tariff revisions Nov. 30 after FERC on July 2 denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity supply obligations (CSOs) expire in May 2022. The commission instead directed the RTO to revise its rules to allow such agreements in order to address fuel security. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

‘Confounding Interpretation’

In a partial dissent, Commissioner Richard Glick said the RTO seemed to be working at cross-purposes to the stated mission of CASPR’s substitution auction to provide state-sponsored resources subject to a minimum offer price rule (MOPR) a chance to purchase a CSO — and the associated revenue stream — from a resource that then retires from the market.

“ISO-NE adopted what can only be described as a confounding interpretation of what qualifies as a state-sponsored resource,” Glick said, referring to a provision requiring the resource be located within a state’s geographical boundaries.

“Specifically, the [RTO] concluded that an offshore wind facility that is procured pursuant to a state-mandated solicitation and that is electrically located in that state does not qualify as a state-sponsored resource for the purpose of the renewable technology resource exemption (RTR) to the MOPR, which CASPR retained as a transition mechanism to the fully fledged substitution auction,” he said.

Glick characterized the RTO’s interpretation as “discouraging” and as putting up “an unnecessary barrier to the type of resources that CASPR was supposed to accommodate.”

The RTO also proposed to bar from the substitution auction resources that bid-shade even if those resources clear the capacity construct and receive a CSO. Glick said the “unambiguous result” of that change “will be to again tilt the scales in favor of retaining traditional resources and against the incorporation of state-sponsored resources. As a result of this proposal, a resource that might otherwise retire through the substitution auction will instead remain in the market, holding a CSO that it could have sold to a state-sponsored resource.”

January 31, 2019

Cold Snap Halts DER Talk as MISO Calls Max Gen Event

By Amanda Durish Cook

CARMEL, Ind. — A dangerous cold snap spurred a maximum generation event and knocked out power to MISO’s offices Wednesday.

The arrival of the polar vortex cut short a two-day RTO workshop focusing on distributed energy resource participation, canceling an in-depth discussion on the technical concerns of adding significant amount of DERs to the grid.

As MISO security checked identification with flashlights in a darkened lobby about 8 a.m. and sent staff to work from home, temperatures hit -10 degrees Fahrenheit with a -40 windchill. At the same time, Minneapolis registered -30 F and a wind chill below -50.

By then, the MISO Reliability Coordinator had decla r ed conservative operations, suspending all transmission and generation maintenance, and a maximum generation event for its North and Central regions because of forced outages and higher-than-expected load. Both declarations will last through Thursday. The power outage did not extend to the control room. MISO first issued a cold weather alert on Jan. 25 covering Jan. 29 to Feb. 1. (See MISO Issues Cold Weather Alert.)

An empty Indianapolis street on Jan. 30 | © *RTO Insider*

The first day of the workshop on Jan. 29 focused only on an introduction to DERs, with speaker Bob Shively of Enerdynamics outlining the several unknowns surrounding DER adoption. The second day was to focus on topics such as DER interconnection, forecasting and reliability issues.

After relative quiet in public stakeholder groups on DER penetration for several months, MISO leadership last year said it will begin work on a possible participation model in anticipation of a FERC rule on the issue. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.) Before the inclement weather, the RTO had already planned two more two-day DER workshops in March in cooperation with the Organization of MISO States.

Staff said that although NERC has a definition of DERs, MISO has yet to establish its own independent definition.

The Unknown

Shively said there’s a great deal of uncertainty about how quickly DERs will permeate the energy landscape.

“It could happen in some states very quickly. It could happen in other states not so quickly. … We don’t know what’s going to be the adoption curve of consumers. … You can get people saying this, and people saying that. The answer is nobody really knows. You need to do your planning in mind thinking that nobody really knows,” Shively said.

He then cite d Bill Gates’ book “The Road Ahead”: “We always overestimate the change that will occur in the next two years and underestimate the change that will occur in the next 10. Don’t let yourself be lulled into inaction.”

But Shively said planners will have to anticipate what they literally cannot see today.

The bulk electric system and markets are not designed to incorporate DERs, he said, which lack visibility on the grid, leaving planners to exclude them in their models when they do not receive operational data.

“Bulk power system planners do not have access to data on distributed energy resources. … All that data rests with distribution companies and there’s really no coordination,” Shively said.

Several factors will affect the rate of DER adoption, he said, including the pace of state regulation and a possible FERC ruling. In some cases, he’s already witnessed the need to equip substations at the distribution level to allow generation from DERs to flow back to the grid. However, he noted, early compensation, new reliability rules and net metering changes can make or break widespread adoption. Different states might experience wildly different penetration rates. He also said utility distribution companies may have to create special DER monitoring systems.

Shively said distribution companies will soon need to reinvent themselves as DER communications networks.

“I had a guy from Duke tell me, ‘We’re no longer an energy company. We’re a high-tech communications data energy grid,’” Shively said.

He also pointed to New York’s Reforming the Energy Vision, a set of multiyear regulatory decisions and policy initiatives launched in 2014 with the goal of creating a distributed system platform provider, among other objectives.

“It’s probably harder to plan DER integration on distribution versus transmission. For distribution, you’re changing the whole way you model each of your distribution circuits,” Shively said.

‘Sneaky’ Devices

Shively said all internet-enabled devices today have the potential to become a DER.

“Anyone who has Alexa or Google to control the lights, you have a potential distributed energy resource in your home,” he said.

Shively cited a recent Wall Street Journal ar t icle on Google and Amazon planning for industry traction in third-party home automation and home area networks.

“More and more, things you’re buying today are sneakily internet-enabled whether you want them to be or not,” Shively said. He said soon, customers may be able to dictate rules such as adjusting the thermostat by 2 degrees when kilowatt-hours reach a certain price.

MISO’s next DER workshop will be held March 21-22 in Metairie, La.

January 30, 2019

PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy

By Robert Mullin and Hudson Sangree

PG&E Corp. and its subsidiary Pacific Gas and Electric Co. confirmed in court papers Tuesday the companies hope to rescind costly power purchase agreements and reform their obsolescent business model during a bankruptcy process that kicked off with a midnight filing for Chapter 11 reorganization. (See PG&E Files for Bankruptcy.)

In doing so, the utility giant challenged two recent rulings by FERC in which the commission said it shares authority with a bankruptcy judge in San Francisco to decide if wholesale power purchase agreements can be repealed or modified in the course of bankruptcy. (See FERC Claims Authority Over PG&E Contracts in Bankru p tcy.) The first hearing before that judge Tuesday gave some insight into how contentious the issue could become.

Philip Burton Federal Building, San Francisco | *U.S. Bankruptcy Court – Northern District of California*

PG&E said Tuesday it has 387 power purchase agreements with 350 companies worth about $42 billion. Those PPAs represent 13,668 MW of contracted capacity, the utility said.

PG&E said it invested billions of dollars to help the state of California meet its renewable power obligations. Those investments drove down the cost of wind and solar energy for its competition, PG&E said, but left the company still paying for the more expensive contracts.

“As a result, many of the utility’s agreements to procure renewable energy resources, which are typically long-term — 15- to 20-plus years in length — obligate the debtors at rates significantly higher than [those] currently available in the renewable resources market. On the contrary, other load serving entities, i.e., the debtors’ competitors, are able to procure required renewable energy resources at those lower rates.”

PG&E argued the only way for the companies to emerge from bankruptcy intact is for the court to allow the utility to abrogate overpriced contracts. It said any input from FERC over those contracts violates the court’s authority under the Bankruptcy Code.

In its filing, PG&E notes “recent changes in the energy landscape have significantly” altered its energy procurement needs for the future.

“In recent years, there has been a significant decrease in demand for [PG&E’s] electric supply service, which has resulted in [PG&E] providing less electricity to fewer customers,” the utility wrote. Chief among the causes are the growth of community choice aggregators, direct access and distributed generation, as well as the success of energy efficiency programs.

“Due to the incontrovertible economic significance of the debtors’ PPAs, as well as the continuously evolving competitive and regulatory factors affecting these agreements, the debtors’ PPA rejection and assumption decisions under section 365 of the Bankruptcy Code will play a vital role in the reorganized debtors’ post-emergence operations and financial profile,” PG&E’s lawyers wrote.

“As such, it is vital to a successful reorganization that the debtors’ determinations regarding whether to assume or reject their PPAs be assessed by this court pursuant to the business judgment standard to which any other debtor is subject.”

PG&E said it was primarily forced into bankruptcy by liability for massive wildfires in 2017 and 2018 that could top $30 billion. Wildfire victims and their advocates have argued PG&E was seeking bankruptcy protection to avoid their lawsuits, but PG&E insisted Tuesday that wasn’t the case.

Pacific Gas and Electric CFO Jason Wells | *PG&E*

“To be clear, the Chapter 11 cases are not a strategy or attempt to avoid PG&E’s responsibility for the heartbreaking and tragic loss of life, devastating damage and destruction to homes and businesses, and harm to the communities that has been incurred as a result of the 2017 and 2018 Northern California wildfires,” PG&E’s chief financial officer, Jason Wells, wrote in a court declaration.

The thousands of victims who are part of the 750 lawsuits filed against PG&E will now likely assume a status similar to unsecured creditors.

Shareholders, meanwhile, will have to take their chances. Investors often lose their stakes in bankruptcy, but PG&E shareholders emerged largely intact after the company’s 2001 bankruptcy in the wake of the state’s energy crisis. Whether that happens this time is highly uncertain and probably will remain so for much of the next two years, the time the bankruptcy is likely to play out.

One key difference: Unlike the previous bankruptcy that involved only the PG&E utility, this one covers its holding company as well.

14 Hours

The judge appointed to oversee the Chapter 11 proceeding in Northern California’s U.S. Bankruptcy Court pointed out that difference Tuesday during the first hearing in what promises to be a drawn-out process. Judge Dennis Montali would know. In 2001 he was picked to oversee PG&E’s prior reorganization.

Montali noted the sheer volume of the work already confronting his court.

“I want to repeat again something I made clear this morning … most of us have only had 14 hours to absorb what has been filed,” Montali said during the hearing, which began at 1:30 p.m. PG&E had filed for bankruptcy shortly after midnight. By the morning there were nearly 50 filings in the case.

The judge expressed regret that he wouldn’t be able to address the 17 motions already in the docket or hear statements from those with an interest in the outcome of PG&E’s bankruptcy.

“I’m trying to absorb everything quickly. I’m not going to listen to arguments [today],” he said.

Montali added he “feels very strongly” that the public should be able to weigh in on such a “high-visibility” case but that he couldn’t allow that during Tuesday’s hearings.

“I don’t mean to be [discourteous] or cut off people otherwise, but I can’t fit into the time frame anything,” he said.

Instead, Montali kept the hearing focused on the procedural issue of “what comes next” — namely the schedule going forward — and addressing the most immediate concerns of the parties before the next hearing, now slated for Thursday at 9:30 a.m.

Montali said some of the motions in the docket didn’t require immediate action, while pointing to a handful that did, including those related to maintaining current procedures around cash management, insurance policies, customer programs and employee wages. “The things that affect real people, like employees,” he said.

But Montali promised his court would review all the motions during Thursday’s hearing.

“The motions are fairly conventional, but the numbers are obviously much larger,” said Stephen Karotkin, an attorney with Weil, Gotsal and Manges, which is representing PG&E. “I think we were very careful to tailor for a smooth transition into Chapter 11.”

At Karotkin’s request, Montali issued orders temporarily granting the cash management request, as well as another motion intended to assure payments to natural gas and electricity exchange operators, such as CAISO. (CAISO issued a statement Tuesday saying the bankruptcy hadn’t caused any grid disruption.)

Another Weil attorney noted PG&E was seeking a preliminary injunction confirming the bankruptcy court’s exclusive jurisdiction over the debtors’ rights to reject PPAs and other FERC-regulated agreements. He said the company would need the court to act on that matter before FERC’s Feb. 25 deadline to respond to its Jan. 29 order on the issue.

“We don’t think we need to be there,” he said. “We need to be here.”

A Department of Justice attorney representing FERC piped up over the telephone: “The proceeding there is separate from the FERC one. FERC issued an order in its own jurisdiction. Nothing in this court could alter PG&E’s statutory obligation to respond to FERC.”

Montali urged PG&E’s attorneys to do what they needed to comply with FERC’s requirements until he ruled on the injunction.

January 30, 2019

FERC Rejects NEPOOL Press Membership Ban

By Rich Heidorn Jr.

FERC on Tuesday rejected the New England Power Pool’s attempt to bar members of the press from membership but left intact — for now, at least — rules barring reporting on proceedings (ER18-2208-001).

The commission’s unanimous ruling appears to open the way for RTO Insider reporter Michael Kuser to join NEPOOL. But without additional action by the commission, he would be bound by NEPOOL’s rules barring members “from reporting on deliberations or attributing statements to other NEPOOL members.”

The commission said it would be ruling separately on RTO Insider’s Section 206 complaint, asking FERC to terminate the group’s stakeholder role or direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

NEPOOL filed the request to bar members of the press from joining NEPOOL after Kuser, an electric ratepayer in Vermont, applied to join as an End-User Customer in March.

NEPOOL said the rule change was necessary because allowing the press to join would inhibit the group’s ability to foster candid discussions and negotiations that narrow and resolve complex issues. NEPOOL also contended FERC had no jurisdiction to reject the rule change.

Many of NEPOOL’s meetings are held at the Westborough, Mass., DoubleTree Hotel. | *Google*

Unduly Discriminatory

FERC said, however, it did have jurisdiction, and the proposed change was unduly discriminatory.

“The NEPOOL press amendments deny NEPOOL membership to members of the press who serve any role directly connected with news collection and reporting. Because some such members of the press otherwise would be eligible for NEPOOL membership as end-use participants, this prohibition unjustly denies them the ability to vote on NEPOOL matters despite their stake in the outcome,” the commission said.

“NEPOOL’s primary argument in support of excluding the press from NEPOOL membership relates to concerns with the reporting of stakeholder discussions. We find, however, that the record does not support the contention that allowing members of the press to become participating NEPOOL members will inhibit NEPOOL’s operations or undermine stakeholder deliberations. The Participants Committee Bylaws and Standard Conditions currently in place — which this order does not affect — already prohibit all NEPOOL members from reporting on deliberations or attributing statements to other NEPOOL members. NEPOOL has not demonstrated that barring members of the press from exercising the privileges unique to NEPOOL membership — i.e., attending, speaking, and voting at NEPOOL meetings — will meaningfully advance its aim for candid deliberation in light of these existent provisions. The NEPOOL press amendments do, however, as discussed above, prevent the participation of individuals otherwise eligible for membership solely based on their profession.”

[Editor’s Note: Kuser and RTO Insider told NEPOOL officials his application was intended to provide him a means to cover stakeholder meetings, and he did not intend to take policy positions or vote.]

Jurisdiction

FERC said NEPOOL’s membership rules were within the commission’s jurisdiction because they directly affect commission-jurisdictional rates, noting that the group’s votes “both signal to the commission stakeholder approval of ISO-NE proposals and have the potential to generate alternative ‘jump ball’ proposals for commission consideration.”

The order said it was acting consistent with commission precedent. “The commission has found that the stakeholder process within an RTO/ISO ‘is a practice that affects the setting of rates, terms, and conditions of jurisdictional services of the type that the Supreme Court has held falls within the commission’s jurisdiction,’” it said, quoting from a 2016 order involving PJM.

Remaining Questions

The commission’s ruling gave no indication how, or when, it will rule on RTO Insider’s complaint, which was filed two weeks after NEPOOL’s proposed rule change.

RTO Insider contended nonpublic meetings violate the public interest and the missions stated in ISO-NE’s and NEPOOL’s governing documents.

It also contested NEPOOL’s assertion that it is a private organization, saying FERC precedent “hardwires the NEPOOL stakeholder process into the regulatory process by requiring its use.”

RTO Insider said if the power pool can justify its press ban as a “private” entity desiring secrecy, “its special powers and privileges should be transferred to an open stakeholder process within ISO-NE, and the ISO-NE resources devoted to NEPOOL (currently $2.6 million annually) should be devoted to an open stakeholder process within ISO-NE.”

Reaction

“An occasion for dancing in the streets!” tweeted New Hampshire Consumer Advocate D. Maurice Kreis, who had opposed the ban.

Another opponent of the ban, Tyson Slocum, director of Public Citizen’s Energy Program, was less jubilant, calling it “a partial victory for the public and the freedom of the press.”

“It is outrageous that, despite today’s FERC order, NEPOOL is still free to ban the general public from attending meetings, and journalists cannot attend meetings unless they pay a membership fee. FERC-jurisdictional proceedings, where billions of dollars in electric rate policy are developed, must be freely open to the public and the media,” he said.

Miles Farmer, an attorney for the Natural Resources Defense Council, said the ruling is important “because NEPOOL’s deliberations affect New England customers’ energy prices as well as the mix of technology types that supply the region.”

“ISO New England is the only regional grid operator that has closed its door on press access to its stakeholder meetings — meetings where key decisions are made about the Northeast’s electricity supply,” said Mike Jacobs, senior energy analyst at the Union of Concerned Scientists (UCS), which had opposed the NEPOOL proposal. “The need for public debate and awareness of pending energy decisions is of paramount importance as a society faces a changing climate. It’s good to see FERC cast a vote against this proposal and in favor of a little more transparency and accountability in New England’s power planning process.”

NEPOOL Chair Nancy P. Chafetz, the New England director of market intelligence for Customized Energy Solutions, did not immediately respond to a request for comment.

NEPOOL Secretary David Doot responded to the order with a memo to NEPOOL members, saying “the Membership Subcommittee will meet to consider the pending application from the RTO Insider press reporter and recommend to the Participants Committee whether any additional conditions should apply to such a membership.”