Page 1104 – RTO Insider

January 13, 2019October 31, 2023

Mass. Looks to Double Down on OSW, Clean Goals

By Michael Kuser

BOSTON — Massachusetts is seeking to broaden its already ambitious goals for procuring clean energy and reducing emissions, state officials said last week.

Topping the agenda: The state is considering to solicit an additional 1,600 MW of offshore wind energy even as it is barely halfway through a procurement process for the same volume as authorized by 2016 legislation.

“We’re launching an offshore wind study to look at … whether we can get an additional 1,600 MW,” Massachusetts Department of Energy Resources Commissioner Judith Judson said Wednesday at a meeting of the Environmental Business Council of New England.

The Environmental Business Council of New England sponsored a briefing by DOER officials at the law office of Prince Lobel in Boston on Jan. 9. | © RTO Insider

Massachusetts last May awarded Vineyard Wind an 800-MW offshore wind contract that runs 20 years and has two 400-MW tranches. The first tranche starts at $74/MWh and the second at $65/MWh, with the prices increasing by 2.5% per year. Partially redacted contract summaries from the state’s Department of Public Utilities show an average nominal price of $64.97/MWh in 2017 dollars.

Judith Judson | © RTO Insider

“We’re excited to be jump-starting the offshore wind industry,” Judson said. “Because of the way we set that up, with a long-term, revenue-fixed contract … we were able to get that at a price that no one believed was possible. I know when we opened the bids, we were like, ‘Whoa’; we were surprised. I think everyone was surprised.”

John Rogers, an energy analyst with the Union of Concerned Scientists, wrote in a September blog post that the “price wasn’t just impressive; it caught us really off-guard. I had been expecting a price about twice as high.”

“We’re still in the midst of procuring our first 1,600 MW, and we will be issuing our next solicitation for offshore wind in the near term as well,” Judson said.

The young industry came of age in December, when the eighth federal lease auction brought in $405 million for three wind energy sites offshore Massachusetts — about six times the revenue from all previous auctions combined. (See Mass. Offshore Lease Auction Nets Record $405 Million.)

Regional Benefits

Judson outlined what the DOER has done in the four years since Gov. Charlie Baker was first elected (he won a second term in November) and said the state is a national leader in energy efficiency and solar energy.

In November, the state launched the Solar Massachusetts Renewable Target (SMART) program, which provides incentives for projects on brownfields, landfills, parking lots and rooftops. The DOER is now in the final steps of developing its next three-year plan to submit to the DPU, she said.

She also pointed out the state’s utilities have contracted with the proposed New England Clean Energy Connect project designed to bring Canadian hydro energy to Massachusetts through Maine.

“One thing I’ll note about that, at about 5.9 cents[/kWh], if you look at that in total [compared] to what we pay for energy, capacity and ancillary services as well as renewable energy attributes, it’s a very cost-effective price; in fact [it’s] lowering bills,” Judson said. “But it doesn’t just lower bills in Massachusetts. When that project comes into the regional wholesale market, it provides those cost savings to every consumer in New England.”

The Maine Public Utilities Commission is holding hearings this month (Docket No. 2017-00232) on a certificate of public convenience and necessity for NECEC, a project of Avangrid subsidiary Central Maine Power and Hydro-Quebec. The project has drawn opposition from environmentalists, fossil fuel generators and renewable energy advocates who want more local solutions that don’t rely on hydro. (See Maine PUC Move Poses Hurdle for NECEC.)

Left to right: DOER division directors Michael Judge, Eric Friedman and Nick Connors. | © RTO Insider

Clean Peak and Leading by Example

DOER division directors briefed meeting participants on their activities. Michael Judge, head of renewable and alternative energy, explained the state’s new Clean Peak Minimum Standard, which was recently set to zero for 2019 while the agency works out the details of the program. (See Mass. Inaugurates Clean Peak Standard.)

Michael Judge | © RTO Insider

“This is a big piece of legislation that was passed as part of last year’s energy bill [H4857] and sets a portfolio standard for resources that can deliver clean energy during peak periods,” Judge said. “The RPS doesn’t actually focus the delivery of that renewable energy to align with peak periods when you have the highest cost and the highest emissions on the grid.”

Judge referred to the solar “duck curve,” which demonstrates how output from solar resources tends to be highest at mid-day during periods of modest demand.

“Trying to shift that generation so that it’s actually addressing the peaks to flatten the load, that’s one of the big objectives, but also addressing seasonal peak issues,” Judge said. He said DOER will develop the clean peak regulations over 2019, and that there will be a higher standard in 2020.

The state Comprehensive Energy Plan (CEP) published last month says increased electrification in the transportation and thermal sectors may increase electric load — and peak load, depending on the timing of energy use, especially the charging of energy storage and electric vehicles.

Nick Connors | © RTO Insider

DOER Director of Green Communities Nick Connors said the state has granted more than $100 million in the 10 years of the program to support towns in such things as speeding up their permitting process.

Eric Friedman | © RTO Insider

Eric Friedman, head of the Leading by Example Office, said his team had “put a lot of effort into moving away from heavy fuel oil,” with the use of about 18 million gallons avoided over the past decade and some 200 million kWh reductions in energy use. The state has 80 million square feet of building space, consumes more than 1 billion kWh and emits 1 million tons of greenhouse gases.

Even small steps add up, Friedman said. The state has moved to reduce mowing on its properties, as well as the use of gasoline-powered landscaping equipment, increasing pollinator habitat by letting the grass grow.

Storage and Energy Efficiency

Transportation’s share in emissions has been going up as the power and building sectors improve, so electric vehicles are going to be at the center of change in the next few years, said Will Lauwers, DOER director of emerging technology.

Will Lauwers | © RTO Insider

“EVs move with people, so load, consumers and EVs are in the same location, and that’s an opportunity for synergy,” Lauwers said. “Energy storage and dispatchable load such as EVs will enable continued greening of the grid.”

The state now has 380 MWh of energy storage capacity, but storage interconnection is becoming increasingly more challenging, as it is not addressed in utility tariffs, Judge said.

“In many cases what ends up happening is a utility will say, ‘Now you have 2 MW of storage here, you also have a 2-MW solar array, so you’re 4 MW; you can put 4 MW on our system,’ which is not necessarily how the system is designed to operate,” Judge said.

Maggie McCarey | © RTO Insider

Director of Energy Efficiency Maggie McCarey said her office is focusing on developing and implementing the next three-year strategic plan for 2019 to 2021.

The expiring strategic plan — in effect through this month until the DPU approves the new one — had the highest EE goals in the country, while the new one is expected to deliver approximately $8 billion in savings to consumers, McCarey said.

January 11, 2019

Judge, Gov., CPUC and Protesters Weigh in on PG&E Mess

By Hudson Sangree

The California Public Utilities Commission began the process of implementing wildfire cost recovery provisions Thursday, as protesters argued against any effort to bailout Pacific Gas and Electric for the deadly wildfires of 2017 and 2018.

Protesters chant, with some wearing masks, at Thursday’s PUC meeting in San Francisco. | *CPUC*

The day before, a federal judge proposed ordering PG&E to reinspect its entire grid before the start of the 2019 fire season and fix any problems it finds as a new condition of its probation in the San Bruno gas line explosion.

And earlier this week, California’s new governor, Gavin Newsom, said he had been talking with PG&E executives to address the utility’s dire financial situation.

The moves are the latest developments in the quickly evolving PG&E meltdown in the wake of November’s Camp Fire, which killed 86 people. The utility’s possible culpability for that blaze and other massive wildfires has raised the specter of bankruptcy, caused PG&E’s stock price to plummet and led to speculation about whether the company might sell major assets, including its gas division. (See PG&E’s Troubles Mount After Camp Fire; PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status.)

Dealing with PG&E’s safety problems is “like repairing a jetliner while it’s in flight,” CPUC President Michael Picker said in a December news release. “Crashing a plane to make it safer isn’t good for the passengers.”

In its meeting Thursday, the CPUC unanimously approved an order instituting rulemaking to begin putting in place the provisions of last year’s landmark wildfire bill, SB 901, to allow for cost recovery by electric utilities. (See California Wildfire Bill Goes to Governor.)

The new law “describes how the commission will review applications by electrical corporations that request recovery of costs and expenses from wildfires in 2017 … and requires the commission to ‘determine the maximum amount the corporation can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service,’” the commission said.

“In undertaking the adoption of criteria and a methodology to determine the maximum amount the corporation can pay, the commission is mindful of both the finite resources of ratepayers in California and the importance of maintaining financially viable utilities to provide safe and reliable service,” it said.

The order laid out a series of questions to help determine the criteria and methodology the PUC will use to evaluate applications by utilities for cost recovery, and established a schedule for the proceeding, with opening comments due Feb. 11.

Protesters with the Democratic Socialists of America were among those who argued against a bailout for PG&E on Thursday. | *CPUC*

Identify and Fix

At least a dozen protesters occupied the PUC hearing room in San Francisco on Thursday, chanting and speaking beyond the one-minute time limit Picker allowed. Some continued over the president’s repeated objections.

“Ma’am, can you finish it up?” Picker said to one public speaker as she shouted at him from the lectern. “You’re repeating yourself.”

CPUC President Michael Picker listens Thursday to speakers protesting any move to relieve PG&E of liability for deadly wildfires. | *CPUC*

The speakers, including members of the Democratic Socialists of America’s San Francisco chapter, argued that the state should not provide cost recovery to utilities responsible for wildfire deaths.

“You need to be in jail. You need to stop getting money from the public,” one speaker said regarding PG&E.

Another speaker read aloud the names of dozens of fire victims.

On Wednesday, U.S. District Judge William Alsup in San Francisco said that unless he was convinced otherwise, he would impose new probation conditions on PG&E in the 2010 San Bruno gas line explosion case, which killed eight people and resulted in the utility being convicted of six felonies for knowingly violating federal safety rules and obstructing a federal investigation.

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 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.

He gave the parties until Jan. 23 to show why he shouldn’t impose the new conditions and scheduled a hearing for Jan. 30.

January 11, 2019

ISO-NE, NEPOOL Answer Generators on FCM Test Price

By Michael Kuser

ISO-NE on Wednesday urged FERC to reject a pr o test filed by the New England Power Generators Association over the RTO’s proposed “test price” mechanism to be applied to resources seeking to retire capacity through the RTO’s substitution auction (ER19-444).

The complaint stems from the Nov. 30 joint filing by ISO-NE and the New England Power Pool proposing several Tariff changes to help implement the RTO’s Competitive Auctions with Sponsored Policy Resources (CASPR). FERC approved the RTO’s two-stage capacity auction designed to accommodate state renewable energy procurements last March. (See Split FERC Approves ISO-NE CASPR Plan.)

As part of the proposed changes, ISO-NE is seeking to introduce the concept of a test price that approximates a resource’s competitive price to acquire a capacity supply obligation.

“Without some mechanism to assure competitive bidding, stakeholders worried that a participant would have incentive to reduce its primary auction delist bid below competitive levels in order to clear the primary auction and, as a result, qualify for ‘severance’ payments in the substitution auction,” NEPOOL explained in a separate answer to NEPGA’s protest filed Jan 7.

The test price would “serve as a screen for competitive behavior in the primary auction to determine whether an existing capacity resource’s demand bid can enter the CASPR substitution auction,” according to the RTO. It is intended “to thwart uneconomic bidding behavior in the primary auction of the Forward Capacity Market that, if unchecked, could reduce the primary auction clearing price below its competitively based level.”

ISO-NE noted that its Tariff currently requires its Internal Market Monitor to make two annual filings with FERC showing various inputs for the Forward Capacity Auction slated for the following year. One of those filings, submitted each July, covers retirement delist bids from participants that intend to retire a resource.

“Since the CASPR test price is an auction input that is established as part of the IMM’s review of retirement bids (and uses largely the same formula specified in the current Tariff for calculating retirement delist bids), the CASPR-related changes contemplate the filing of the test price values as part of the July filing of the retirement bids,” the RTO explained.

While NEPGA does not oppose the filing of the test prices, it does contend that the IMM should be required to file participant-submitted test price values — not the values determined by the IMM.

NEPGA argued that prioritizing the IMM’s values would usurp a market participant’s sole right under the Federal Power Act to file a retirement delist bid as its rate for acceptance by the commission and that “the test price likewise is a rate, term or condition” of the participation in the FCA.

ISO-NE countered that NEPGA’s argument is an “abbreviated repeat” of arguments the organization made in a protest of the previous Tariff revisions related to market rules for retirement of resources.

“In that proceeding, NEPGA argued that the proposed Tariff changes denied market participants their Section 205 filing rights to seek a determination of their own rates by requiring the IMM to file, in the July retirements filing, the IMM-determined delist bid price for a retiring resource, rather than the delist bid price submitted to the IMM by the market participant,” ISO-NE said. “The commission squarely rejected NEPGA’s contention.”

The RTO said Section 205 rights are not at issue in the proceeding, “as the test price — like many other inputs into the auction — is not a rate, term or condition.”

NEPOOL contended that instead of “unnecessarily” disrupting the stakeholder process, NEPGA should have “appropriately presented an amendment to the test price mechanism” at stakeholder meetings, in which case “NEPOOL may have supported an alternative approach that could have assuaged NEPGA’s concern.”

While it participated in the stakeholder meetings, neither NEPGA nor any other stakeholder suggested this alternative proposal, NEPOOL said. Stakeholders considered and debated the entire package of CASPR-related changes over last summer before a final vote at the Participants Committee in November, it said.

Resolving the Mystery

In the same filing, the RTO also answered NEPGA’s Jan. 8 mot i on to lodge a Dec. 28 decision by the D.C. Circuit Court of Appeals (Exelon v. FERC, 17-1275) into the test price proceeding.

In the decision, the court remanded back to FERC its order accepting ISO-NE’s retirement delist bid mechanism in the FCA, 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. (See FERC OKs Lower Delist Threshold in ISO-NE.)

“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.

It remanded the case to FERC “to resolve the mystery,” saying the commission “should issue its clarification expeditiously, and in no event later than Feb. 1, 2019.”

“NEPGA agrees with commission counsel that it is the market participant’s right and obligation to make that showing, and as it explained in its limited protest in this proceeding, the law likewise applies to the test price market participants will be required to file for acceptance by the commission if the commission accepts the test price design in this proceeding,” NEPGA said.

The RTO reiterated its contention that NEPGA’s assertions are an “abbreviated” recycling of prior arguments rejected by FERC and that “NEPGA has made no attempt in its protest to explain why the same assertions do not similarly fail when aimed at the test price mechanism.”

In addition, the RTO said the D.C. Circuit’s remand “decides nothing regarding the issues in contention here regarding the test price” and that “at this stage, therefore, there is nothing of relevance to be gleaned from the D.C. Circuit’s opinion.”

January 11, 2019

EPSA Asks Supreme Court to Review ZEC Rulings

By Michael Kuser

Several power producers joined the Electric Power Supply Association on Monday in petitioning the U.S. Supreme Court to review appellate court rulings upholding the New York and Illinois zero-emission credit programs.

Last September, both the 2nd and 7th U.S. Circuit Courts of Appeals rejected claims by EPSA and others that New York’s and Illinois’ ZECs, respectively, intrude on FERC jurisdiction. (See Appeals Court Upholds NY Nuclear Subsidies and 7th Circ u it Upholds Ill. ZEC Program.)

EPSA on Jan. 7 petitioned the Supreme Court for writs of certiorari to review both decisions. The group was joined on the 2nd Circuit petition by NRG Energy, with the New York Public Service Commission and Exelon — and its three New York nuclear plants — named as defendants. Calpine joined the 7th Circuit petition in the case against the Illinois Power Agency, the Illinois Commerce Commission and Exelon.

Exelon’s Byron Generating Station’s two nuclear reactors in Illinois produce more than 2,300 MW of electricity.

Enough Percolation

The New York PSC created the ZEC program in August 2016 as part of its Clean Energy Standard, which set a goal of reducing greenhouse gas emissions by 40% by 2030.

The PSC said it designed the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)

The 2nd Circuit said that ZECs, like renewable energy credits, are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field pre-emption under the” Federal Power Act.

The court noted that the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.

But EPSA attacked ZECs from a different angle in its petitions.

“The question presented is whether the FPA pre-empts only state subsidies that explicitly require a wholesale generator to sell its output in FERC-approved auctions, or whether the FPA also pre-empts state subsidies that lack such an express requirement but that, by design, subsidize only generators that sell their entire output via such auctions, thereby achieving the same effect,” both petitions said.

“This is not a situation in which further percolation in the courts of appeals is warranted. Indeed, delay risks long-term distortion of the energy markets,” the petitioners said. “The programs already in place are causing multibillion-dollar distortions and skewing decisions about long-term investment in energy generation.”

In addition, the petition on the Illinois ruling said the 7th Circuit’s “decision also rests on an erroneous understanding of the structure and operation of the Illinois ZEC program,” and that while “these factual and procedural errors were addressed in a rehearing petition, the court took no corrective action.”

Old Wine in New Bottles

Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, said, “These arguments about the text of the FPA and the court’s 2016 Hughes decision largely repeat the generators’ briefs filed at the 2nd and 7th Circuits. In rejecting these arguments, the 2nd Circuit panel found it ‘telling that [the generators] cannot persuasively explain why FERC’s holding [disclaiming jurisdiction over RECs] does not apply equally to ZECs.’”

Peskoe pointed out that amicus briefs filed at the appellate courts explain that “a decision endorsing petitioners’ sweeping view of FERC’s authority over all payments received by generators would threaten existing renewable energy programs and deny FERC the opportunity to harmonize its market regulation with state programs.”

The 7th Circuit’s opinion cited the Hughes ruling, in which the Supreme Court said it did not intend “to foreclose [states] from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation.’”

“And that’s what Illinois has done,” the 7th Circuit said. “To receive a credit, a firm must generate power, but how it sells that power is up to it. It can sell the power in an interstate auction but need not do so. It may choose instead to sell power through bilateral contracts with users (such as industrial plants) or local distribution companies that transmit the power to residences.”

EPSA had contended that Illinois’ ZEC program infringed on FERC’s jurisdiction by indirectly regulating interstate energy markets by using average auction prices as a component in a formula that affects the cost of the ZECs. But the 7th Circuit found the value of ZECs does not depend on the generators’ auction offers.

January 10, 2019

McNamee Declines to Commit to Resilience Docket Recusal

By Michael Brooks

FERC Commissioner Bernard McNamee on Monday informed Senate Democrats that ethics advisers told him he was not required to recuse himself from the commission’s ongoing inquiry into RTO/ISO grid resilience (AD18-7).

In a letter to Sen. Catherine Cortez Masto (D-Nev.) dated Jan. 7, McNamee attached a Jan. 2 memo to him written by Charles Beamon, FERC associate general counsel. In the memo, Beamon described his Dec. 12 meeting with McNamee, saying he advised the commissioner that he did “not view your prior position and statements as demonstrative of an unalterably closed mind as to” the proceeding.

Beamon, however, cautioned that “we must exercise continued oversight to ensure that Docket No. AD18-7 does not develop in such a way as to replicate or closely resemble” the Energy Department’s Notice of Proposed Rulemaking for FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel (RM18-1).

FERC Chief of Staff Anthony Pugliese, left, and Bernard McNamee, center, head of DOE’s Office of Policy, made the case for coal and nuclear price supports at a breakfast meeting of the Consumer Energy Alliance on the sidelines of the NARUC Annual Meeting in Baltimore in November 2017. Michael Whatley, right, CEA’s executive vice president, moderated. | © *RTO Insider*

McNamee helped draft the NOPR, unanimously rejected by FERC, as the department’s deputy general counsel for energy policy. In response to Democrats at his Senate Energy and Natural Resources Committee confirmation hearing in November, McNamee said he “clearly” would have to recuse himself from the NOPR docket, which Beamon reiterated in his memo. (See Democrats Urge McNamee’s Recusal from Resilience Docket.)

But Beamon said that although the dockets are related, “I advised you that I do not view the relationship as requiring your recusal.” He said he also emphasized the dockets were different proceedings and noted that the resilience docket “is an administrative inquiry in which the commission received over 200 comments suggesting various outcomes.”

After he was confirmed 50-49 in early December, 17 Senate Democrats wrote to McNamee on Dec. 12 — coincidentally the same day he met with Beamon — requesting he update them on what guidance he received. Along with his work on the NOPR, they also questioned his impartiality based on a leaked video of a speech he gave while working for the Texas Public Policy Forum in June. (See Senate Confirms McNamee to FERC.)

In the speech, McNamee criticized environmental groups and renewable energy resources, describing the efforts of his group to change public opinion on fossil fuels as a “constant battle between liberty and tyranny.”

Beamon’s memo quoted case law saying that parties cannot challenge the presumption of an agency official’s impartiality “by merely showing that an official has ‘taken a public position, or has expressed strong views, or holds an underlying philosophy with respect to an issue in dispute.’”

As an example, Beamon cited former Commissioner Philip Moeller’s comments in 2011 on a bill in New Jersey, which he said would “crater the capacity market” in PJM. The Maryland Public Service Commission had cited these comments in its request for rehearing of FERC’s acceptance of the RTO’s revisions to its minimum offer price rule (MOPR) (ER11-2875).

The court unanimously decided that Moeller’s comments “did not show that he ‘had made up his mind regarding two as-yet-to-be filed proceedings concerning a related, but very separate matter — the specific, regionwide operation of PJM’s MOPR,’” Beamon said.

Beamon concluded his memo by saying he “advised you to seek my guidance on any matter related to your past statements, positions, work or any other concerns that you may have.”

January 10, 2019

FERC OKs PJM Tx Constraint Penalty Factor Changes

By Robert Mullin

FERC on Tuesday approved PJM Tariff changes designed to bring the RTO into compliance with Order 844 by improving market participants’ insight into the use of transmission constraint penalty factors.

“The proposed revisions will provide transparency regarding PJM’s transmission constraint penalty factor procedures and also produce more transparent and appropriate pricing and investment signals that correspond to an underlying transmission constraint,” the commission said in its ruling (ER19-323).

Transmission constraint penalty factors are the values at which security-constrained economic dispatch (SCED) will relax the flow-based limit on a transmission line in order to relieve a constraint rather than redispatch a costly resource.

Issued last April, Order 844 said that a lack of transparency prevents market participants from understanding how the factors influence LMPs. (See FERC Orders RTOs to Shine Light on Uplift Data.)

In its compliance filing, PJM explained that its current logic for relaxing constraints prevents the penalty factor from setting the marginal value of a transmission constraint, thereby understating the severity of the constraint and producing LMPs that fail to send appropriate price signals to inform generation and transmission investment decisions.

FERC approved PJM’s proposal to remove the constraint relaxation logic from its market operations and allow the penalty factor to set the marginal value for a constraint when SCED “cannot produce a solution that manages the flow on a transmission constraint within the limits of the transmission constraint.”

The commission also found PJM’s Tariff revisions adequately describe how the penalty factor will be reflected in LMPs. The RTO had clarified that the marginal value for a constraint is used as an input for determining LMPs’ congestion component.

PJM also explained it will allow the penalty factor to set the marginal value for a constraint in market-to-market transactions, although it retains the ability to use the constraint relaxation logic at the request of an adjacent RTO.

“PJM states that it expects to use constraint relaxation logic for market-to-market congestion management with Midcontinent Independent System Operator Inc. until the second quarter of 2019, when MISO will update its market clearing engine to allow transmission constraint penalty factors to set the marginal value of the transmission constraint in its markets,” the commission noted.

PJM’s default transmission constraint penalty factor will be $2,000/MWh for real-time transactions within its own boundaries and $1,000/MWh for M2M coordinated transmission constraints on its side of a seam.

FERC also approved PJM’s plan to revise penalty factor values “to reflect persistent system operational or reliability needs, changes in the costs of resources available to relieve congestion, changes to operating practices for managing market-to-market coordinated constraints, and the unique attributes of certain transmission facilities.”

The commission additionally accepted the RTO’s proposal to post adjustments to penalty factor values “as soon as practicable” rather than setting a hard deadline, “in the event that an unforeseen circumstance arises that prevents modified values from being posted within such a deadline.” In doing so, it dismissed the Independent Market Monitor’s argument in favor of a deadline.

FERC also disagreed with the Monitor’s contentions that PJM should not retain the ability to apply its constraint relaxation logic for M2M constraints, as well as its assertion that penalty factor values take into account other system constraints, include RTO-wide reserve penalty factors.

“Establishing the default transmission constraint penalty factor values based on historical evidence, as PJM proposes, ensures that the SCED application considers all physically available dispatch options and available units to resolve binding transmission constraints,” the commission said.

The Tariff revisions take effect Feb. 1.

January 10, 2019

SPP Staff Outline Seams Strategy to SSC

By Tom Kleckner

SPP’s interregional relations staff on Wednesday shared with the Seams Steering Committee their strategic vision for seams efforts through 2021.

The vision is heavy on improving transmission planning across the seams and offering reliability coordination services in the Western Interconnection. Staff referred to the seams strategy as a “living, breathing document” that will eventually be posted on the committee’s website.

The goals include implementing improvements to the SPP-MISO Coordinated System Plan by the end of the first quarter, a process that will begin with a Jan. 31 meeting between RTO staffs and stakeholders.

SPP and MISO have revised their joint operating agreement’s planning criteria in the hopes of agreeing on a first interregional project between the two. Legal staff are currently drafting language for a MISO, SPP Tweak Interregional Criteria.)

The RTOs also plan to begin a new study this year, using the new criteria.

Other strategic goals include:

Implementing agreements between the SPP RC in the West and neighboring RCs;
Developing RC coordination agreements with neighboring western RCs;
Devising a cost-allocation Tariff mechanism for seams projects not driven by FERC Order 1000; and
Defining the coordination of grid-switchable resources with ERCOT during emergency conditions.

Clint Savoy, the RTO’s senior interregional coordinator, told the SSC that staff have begun reaching out to neighbors to evaluate the potential value and benefits of sharing operating reserve responsibilities with other balancing authorities.

The committee also welcomed ITC Holdings’ David Mindham and Corn Belt Power Cooperative’s Kevin Bornhoft as new members.

November M2M Payments Flow SPP’s Way

The MISO-SPP market-to-market (M2M) process resulted in more than $148,000 in SPP’s favor in November, the fourth straight month incurred payments have failed to reach $1 million.

Permanent flowgates accounted for the financial difference, binding for 53 hours. Temporary flowgates were binding for 592 hours but resulted in a $60.11 amount due to MISO.

SPP has amassed $51.8 million in distributions since the RTOs began the M2M process in March 2015, with payments flowing in its direction 21 of the last 26 months.

January 9, 2019

PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status

By Hudson Sangree

PG&E’s beleaguered stock price sank even lower Monday and Tuesday, dropping by more than 30% over two days because of fears the company could go bankrupt or be broken up by the state after two years of catastrophic wildfires in California. (See PG&E’s Troubles Mount After Camp Fire.)

The company’s share price fell from $24.40 late Friday to a new low of $16.79 as trading started Tuesday morning. It recovered slightly during the day Tuesday and closed at $17.56.

PG&E’s stock began its latest tumble after Reuters, citing unnamed sources, reported Friday the company was exploring filing for bankruptcy.

PG&E’s stock price plummeted after November’s Camp Fire and continued plunging this week amid talk of the company declaring bankruptcy and selling off its gas division. | *PG&E*

S&P Global Ratings dropped the company’s credit rating from investment grade (BBB-) to “junk” (B) status Tuesday and said it might make further downgrades if PG&E does not take clear steps to preserve its creditworthiness, given state officials may be unwilling to help the company.

“Previously, we assumed that given California’s robust renewable portfolio standards and the increasing risks of climate change, legislators and regulators would proactively work with the utility to preserve credit quality to achieve these goals. However, based on recent developments, we no longer believe this to be true given the utility’s own missteps,” S&P said. “We expect that negative public sentiment and the increased political pressure will challenge the regulators’ willingness and ability to implement measures to protect credit quality over the near term.”

Before the wine country fires of 2017, PG&E’s stock price had reached a high of more than $70/share. Just prior to the Camp Fire in November, it had been holding relatively steady for months. On Nov. 7, the day before the Camp Fire destroyed the town of Paradise, Calif., and killed 86 residents, the utility’s stock price stood at about $49/share.

The plunges after the 2017 and 2018 fires resulted in PG&E losing roughly $16 billion in market value over 14 months.

State fire investigators blamed PG&E equipment for starting 17 of the 21 major wine country fires in 2017 but have not determined the cause of the most destructive of those fires, the Tubbs Fire, which wiped out the northern portion of the city of Santa Rosa, Calif.

In recent court filings, PG&E reiterated its argument that a private landowner, who employed an unqualified person to run distribution lines on her property, may have started the Tubbs Fire.

The cause of the Camp Fire hasn’t been determined either, but PG&E reported severe damage to a 115-KV distribution line and flames near the origin of the Camp Fire on the morning it started. (See PG&E Grapples with Line Safety After Camp Fire.)

Also on Tuesday, PG&E reported Patrick M. Hogan, head of electric operations, would be retiring Jan. 28 and Michael A. Lewis had been elected by the board of directors to succeed him as senior vice president.

“Mr. Lewis, 56, has served as Vice President, Electric Distribution Operations of the Utility since August 2018,” PG&E said in a filing with the U.S. Securities and Exchange Commission. “At his previous company [Duke Energy], Mr. Lewis helped the distribution and transmission organizations achieve industry-leading safety benchmarks,” the utility said.

PG&E recently announced a “board refreshment” process in which it would seek to recruit more directors with safety experience, following criticism from the California Public Utilities Commission and lawmakers that its safety culture was deeply flawed.

January 9, 2019

Munis Wary of PJM Rules on Non-Retail BTM Generation

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — A PJM proposal to revise the rules on non-retail behind-the-meter generation met with suspicion from municipal utilities and cooperatives at Tuesday’s Operating Committee meeting.

PJM introduced a proposed problem statement, saying current rules are inconsistent with Capacity Performance (CP) requirements and the lack of reserves for this growing class of resources could present reliability problems.

Non-retail BTM generation (NRBTMG) refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary services and administrative fee charges.

PJM’s rules on such resources resulted from a 2005 settlement agreement (EL05-127), before development of the RTO’s capacity market and CP constructs. NRBTMG resources can be called upon during the first 10 Maximum Generation Emergencies annually, while CP resources are required to perform during all Performance Assessment Intervals (PAIs). BTM operators that fail to perform face reduced netting benefits.

“The right to call upon NRBTMG during an emergency was established to address a concern that if too much generation is designated as NRBTMG and allowed to net against load, system reliability would be compromised since PJM would not be carrying reserves for a large amount of load associated with NRBTMG,” PJM said.

However, non-retail BTMG is not specifically addressed in PJM’s Emergency Procedures Manual (M-13), making it unclear whether such resources would be requested to operate during any emergency.

NRBTMG resources are expected to run at full output. “‘Full output’ was considered a reasonable expectation of performance at the time of the NRBTMG business rule development, when more traditional types of NRBTMG existed,” PJM said. “With the increased development of renewable NRBTMG in the PJM region, the expected performance level of NRBTMG should be reevaluated.”

PJM identified about 400 MW of non-retail BTMG in an outreach in 2006, before East Kentucky Power Cooperative, Duke Energy and American Transmission Systems Inc. (ATSI) joined the RTO, said PJM’s Theresa Esterly. The RTO hopes to get a current tally of such resources through current efforts to update its data on all distributed energy resources.

Closing ‘Loopholes’

Jim Benchek, FirstEnergy | © *RTO Insider*

Jim Benchek, of FirstEnergy, said his company will support the review, provided the scope of the issue is clarified, as a way to “cover up loopholes for avoiding performance requirements.”

“Calpine has been pushing to look at this issue for a while,” said Calpine’s David “Scarp” Scarpignato. While CP resources are penalized for failing to perform, the operators of underperforming NRBTMG will “lean on the rest of the system and they’re not going to face any kind of penalty,” he said.

Scarp also said the review is timely because any rule changes could affect the business models of DERs.

A Solution in Search of a Problem?

But representatives of cooperatives and municipal utilities questioned the need for new rules. “We want to be able to continue to use them the way we’ve been using them,” said Carl Johnson of the PJM Public Power Coalition.

Steve Lieberman, American Municipal Power | © *RTO Insider*

“You have a solution and you’re trying to find a problem,” said Steve Lieberman of American Municipal Power. “… It seems like you’re trying to make an equivalency between NRBTMG and capacity resources receiving capacity payments.”

Mike Cocco, of Old Dominion Electric Cooperative, agreed, saying ODEC would oppose extending CP rules to non-capacity resources. He said any PJM proposal affecting NRBTMG must be comparable to the netting rules for retail BTMG. Cocco suggested expanding the scope of the problem statement to include a review of existing netting rules for both NRBTMG and retail BTMG.

Scarp also suggested the inquiry be broadened to include retail BTMG, saying performance failures by such resources “could give you the same reliability issues.”

Lieberman said expanding the scope could make it impossible to complete the work in the 10-month time frame proposed by PJM. “I don’t want to face another letter from the Board [of Managers]” setting a deadline for action, he said, referring to the Board’s recent ultimatum on market formation changes. (See Section 206 Filing on PJM Reserve Pricing Likely.)

Operating Committee Chair Dave Souder asked stakeholders to propose any changes to the problem statement before the OC’s next meeting, when the RTO hopes to bring the inquiry to a vote.

January 9, 2019

FERC Discloses Data Behind New England ROE Order

By Michael Kuser

FERC on Monday disclosed data underlying its new formula for setting return on equity rates for New England transmission owners (NETOs) and explained how the data influenced the ROE methodology outlined in an October 2018 briefing order.

But the commission’s Jan. 7 order also noted it had not yet made any final determinations and referred complainants to the paper hearing on the issue (EL11-66-001, et al.).

The release of information came in response to a Nov. 16 motion for expedited disclosure by a coalition consisting of Connecticut’s utility regulator and New England power cooperatives. The group sought the data and analyses underlying two graphs the commission referenced in its decision to no longer rely solely on the discounted cash flow (DCF) model but give equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)

The Connecticut Public Utilities Regulatory Authority, Eastern Massachusetts Consumer Owned Systems, Massachusetts Municipal Wholesale Electric Company and New Hampshire Electric Cooperative asked the commission to “identify and, where not already in the record in these four proceedings, release the sources, data sets, and analyses underlying Figure 2 and Figure 3 in its October 16 Order.”

The commission’s new policy came in its long-awaited response to the D.C. Circuit Court of Appeals’ April 2017 ruling vacating FERC’s 2014 order on the NETOs’ ROE rates. (See Court Rejects FERC ROE Order for New England.)

Data Details

The Monday order said that Figure 2, “ROE Results from ROE Models,” shows the ROE results from the four models over the four test periods at issue in the proceeding and that in calculating the expected earnings midpoint for Period 2, it had excluded ITC Holdings and Wisconsin Energy from the proxy group “as high-end outliers because their ROEs were more than 150% of the proxy group median for the NETOs,” which was 10.225%.

FERC’s new ROE formula gives equal weight to four models. | *FERC*

ITC Holdings was similarly excluded from the proxy group for Period 3, as was CenterPoint Energy for Period 4. The commission listed all other data effects as “none,” except for its CAPM ROE midpoint, which had been rounded up in Figure 2 to 10.46% from 10.45%, as its exact midpoint is 10.455%.

The motion for disclosure said, “Figure 3, which is titled ‘Regulated Utilities PE Chart’, appears to be excerpted from a report generated by Evercore ISI, an investment banking advisory firm. This report is not in the record for these proceedings and appears from our research to be proprietary and not publicly available.”

The commission responded that Evercore ISI produced Figure 3 and that it “does not have access to the data or analyses that were used to produce that chart and therefore cannot provide that information. The Briefing Order relied on Figure 3 only for the limited purpose of showing that there had been a substantial increase in utilities’ price to earnings ratio during the period [of] October 2012 to December 2017.”

Regulated utilities price/earnings | *Evercore*

Figure 3 was part of the briefing order’s explanation of why, during that period, “utility stock prices appeared to have performed in a manner inconsistent with the underlying premise of the DCF model that an investment in common stock is worth the value of the infinite stream of dividends discounted at a market rate commensurate with the investment’s risk,” said the commission.

Moreover, the commission said it did not rely on Figure 3 for any final determination on the use of the DCF model to determine utility ROEs.