Page 1060 – RTO Insider

March 26, 2019

Report: ‘Naive’ PJM Underestimated GreenHat Risks

By Christen Smith

Naive, overconfident staff and underlying market flaws allowed a small trading shop to amass the largest portfolio of financial transmission rights in PJM history without the collateral to back it up, an independent review concluded on Tuesday.

The RTO’s Board of Managers commissioned a special report on the GreenHat Energy debacle in October, just four months after the company defaulted on 890 million MWh of FTRs and racked up $100 million (and counting) in losses.

The review concluded PJM staff ignored red flags about the company’s assets and exhortations from other members about the portfolio’s financial shortcomings — a failure of protocol that CEO Andy Ott said “needs to change.”

“PJM needs to get better,” Ott told RTO Insider. “Quite frankly, we’re just not used to this type of behavior from a market participant.”

Independent Review

The board hired three consultants to focus on the RTO’s role in enabling the default, handing off the task to Robert Anderson, Neal Wolkoff and Arleigh Helfer. Anderson serves as executive director of the Committee of Chief Risk Officers, whereas Wolkoff has consulted with the U.S. Commodity Futures Trading Commission and has held leadership positions at the New York Mercantile Exchange and the American Stock Exchange. Helfer is a litigation attorney based in Philadelphia.

“It is clear what a significant outlier GreenHat was,” the report reads. “GreenHat’s trading pattern was conspicuous in that its positions were far larger and of longer tenor than those of other financial participants in the FTR market.”

The report tracked a four-year timeline of events, beginning with GreenHat’s 2014 entry into PJM despite “a questionable history,” followed by unchecked growth in FTRs that more than doubled each year between 2016 and 2018, as well as warnings from at least four other market participants who estimated the portfolio was short by as much as $40 million. It ended with the company defaulting on a $624,000 collateral payment last June.

“Long tenor of a financial position is riskier than a near-term duration because less is known about the distant future than the near future, and more events can intervene to affect the value of a position over time,” the report said. “GreenHat’s portfolio was very risky because of its size and the length of time the positions would be open and subject to market forces before settlement.”

Size and tenor of GreenHat’s portfolio versus others | *PJM*

GreenHat, which listed its address as a UPS store in Coronado, Calif., was owned by two traders who previously gained notoriety as participants in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the Doubling Down – With Other People’s Money.)

FERC Commissioner Richard Glick said in January the commission must investigate participants who willfully manipulate the market through fraud and escape any sort of punishment, thereby perpetrating their schemes on other RTOs. “That investigation should consider the full extent of our existing authority under the Federal Power Act and whether any legislative action is needed to ensure the commission has the authority to preclude these individuals from continued participation in wholesale electricity markets,” Glick said. “I hope this is an issue we can address in the months ahead.”

The consultants also determined a flaw in PJM’s methodology for calculating collateral adjustments created “counter-intuitive” and “sometimes directionally incorrect” collateral requirements. The faulty approach meant even as GreenHat’s portfolio became increasingly risky, its collateral requirements actually shrank, leaving healthier portfolios to essentially subsidize the entire FTR market, the report found.

The report’s authors noted that “best practices incorporate forward information to determine collateral requirements for market participants. In contrast, PJM’s assessment of risk was based entirely on historical, or backwards looking, information.” They recommended PJM require use of mark-to-auction values from more frequent auctions, include long-term FTRs in monthly or bimonthly auctions, and base collateral on forward-looking metrics to better capture risk.

Growth with declining collateral requirement | *PJM*

PJM Response

Ott said the RTO takes the report’s deep criticisms “very seriously,” announcing Tuesday a list of reforms it will implement immediately, starting with the hiring of a chief risk officer — someone with the knowledge and experience to prevent such calamities from befalling the market again.

“We realize we need to get better at credit risk management,” he said.

PJM will also review and revamp its credit risk assessment and monitoring procedures, as well as facilitate stronger coordination between PJM’s markets, credit/finance and legal groups, and the Independent Market Monitor.

“We expect this report will provide the momentum to move these issues forward,” Ott said in a press release Tuesday. “PJM will work with our members and federal regulators to examine changes recommended by the report designed to strengthen the regulation of our FTR market. It is our job to make sure this never happens again.”

Ott said federal regulators identified issues with PJM’s credit risk management practices in 2010, but stakeholders expressed reluctance over the potential costs of implementing a more sophisticated system.

Independent reviewers confirmed a 2007 FTR default by Tower Research Capital spawned recommendations on how to improve risk management policies and market surveillance, including increasing the frequency of auctions, limiting positions based on participant’s capital, basing collateral on forward-looking metrics and shortening the time period of settlement for outstanding charges.

After lengthy discussions, stakeholders agreed only to the latter recommendation. The review blames PJM staff for not effectively communicating the critical necessity of the other suggested changes.

“This is something where we have to look at ourselves and what we could we have done better and there’s plenty there,” Ott said on Tuesday.

Ongoing Fallout

At the Market Implementation Committee meeting on Feb. 6, PJM CFO Suzanne Daugherty told members that a FERC order to rerun the July 2018 FTR auction to liquidate GreenHat’s positions could add $250 million to $300 million to the $186 million the RTO had earlier projected the default would cost members. (See PJM: FERC Order Could Boost GreenHat Default by $300M.) On Tuesday, the commission issued a tolling order giving it more time to rule on PJM’s rehearing request on the issue (ER18-2 068 ).

“We recognize the shortcomings identified in this review,” Ott said. “PJM takes the cost of this default very seriously, and we are committed to reforms that better protect market participants in the future.”

GreenHat’s significant growth in exposure and MTA loss | *PJM*

The review faults “dismissive” attitudes from the PJM executive team and flawed legal advice regarding the RTO’s ability to revoke GreenHat’s trading rights after concerns grew over its projected losses. Daugherty acted on her own authority in 2017 when she halted the company’s ability to participate in future FTR auctions — held in June and December each year — before reversing her decision three weeks later, fearing possible Tariff violations and legal repercussions.

Daugherty, who retired as CFO last month, had declined to say whether her departure was related to the GreenHat fallout. (See PJM CFO Retiring in Wake of GreenHat Default.) Tuesday’s report better illuminated her role in the debacle, noting she and other PJM staff put too much faith in verbal and written agreements with GreenHat guaranteeing the company held $100 million in assets and would receive a $62.2 million payout from two bilateral contracts.

“If PJM knew its customer better, PJM may have recognized these instances as red flags indicating the GreenHat pledge agreement may have actually been a sham before signing,” the report said. “These red flags may have helped PJM to conclude that GreenHat did not have an asset worth $62 million to pledge and assign.”

Ott said Tuesday other organizational changes lie ahead for the RTO but declined to comment on the status of specific staff members, noting there “is certainly a need to strengthen different departments.”

March 26, 2019

Former Mass. DPU Chair Reflects on Service

By Michael Kuser

After serving a four-year term as chair of the Massachusetts Department of Public Utilities, Angela O’Connor became a free agent last month — just like some of the basketball players she knew during her decade helping to market the Boston Celtics.

That job had her wearing a headset behind sportscaster Marv Albert and Los Angeles Lakers star Earvin “Magic” Johnson while she coordinated timeouts with referees.

Asked about the Lakers’ conspiracy theories regarding their “heated” locker room in Game 5 of the 1984 NBA Finals at the Boston Garden, when temperatures in the arena neared 100 degrees Fahrenheit, O’Connor said, “Whatever you heard, it was probably true.”

O’Connor, known as Angie to her friends, is more circumspect when it comes to her time at the DPU, crediting “incredible staff expertise” with helping her to run the agency “at the busiest time in its history.”

She is most proud of the work DPU did helping Gov. Charlie Baker position the state to procure Quebec hydropower and getting ISO-NE to become the first grid operator in the country to change its market rules to accommodate state procurement of clean energy contracts through Competitive Auctions with Sponsored Policy Resources (CASPR).

The RTO in February concluded Forward Capacity Auction 13, the first run under the new CASPR rules, at the lowest clearing price in six years. (See ISO-NE Completes F C A 13 Despite Controversy.)

“That was a lot of work to try to convince folks, ‘you got to do this,'” O’Connor said. “And Massachusetts wasn’t doing it to crush a price because there’s a recognition that you can’t run the system on wind, solar, storage, fairy dust and unicorns. You need power plants to be able to back up those intermittent resources, tremendously flexible plants, and they are gas plants, largely.”

Private and Public

In all her regulatory work, O’Connor said she “wanted to make sure that whatever we did would not be a barrier to innovation. Massachusetts is a small state but a thought leader.”

Though she had no state government experience prior to her role at DPU, O’Connor was conscious of the need to work with public officials, having come to the job from being Northeast region executive director at TechNet, a trade association representing the technology industry to state and federal policymakers.

And she went to TechNet from the New England Power Generators Association, which she founded and where she served as president.

“It’s very different coming from the private sector into government,” she said. “We were the first state to regulate Uber and Lyft, known as transportation network companies or TNCs, which we started in 2015. People just didn’t associate that with DPU … but then we also oversee the [Massachusetts Bay Transportation Authority] for public safety.

“It’s all about how you handle things, and all those skills are transferrable to other industries, but I do love energy,” O’Connor said.

She refuses to speak on the record about her toughest experience at DPU, overseeing the agency’s response to the Columbia Gas pipeline explosions around Lawrence last September, in which one person was killed and about two dozen others were injured. Her reticence around the incident — the largest such disaster in U.S. history that forced the evacuation of three towns — is because it is still under investigation by the National Transportation Safety Board and the DPU.

“I would like to add how proud I am of the work the team did to support the governor and [Energy Secretary Matthew Beaton’s] work on the ground, especially Pipeline [Safety] Division Director Richard Wallace,” O’Connor said.

‘A Privilege’

“Regulation is like a black hole to some people in other industries,” O’Connor said. “They think, ‘We’re saving the planet, you don’t have to regulate us,’ which is not true. However, I came to appreciate that perspective because from the private sector, you want to get things done, but making good policy takes time.”

O’Connor once headed up energy policy at Associated Industries of Massachusetts (AIM), the commonwealth’s main statewide employer organization, a job she came to from managing operations for the Massachusetts Health and Educational Facilities Authority (MHEFA) PowerOptions program in the 1990s, which today is the largest energy-buying consortium in New England.

MHEFA was a bonding authority for colleges, universities and nonprofits, and after the move into energy aggregation, “we had under contract [more than] 500 MW of load, which was MIT, Harvard, Boston College, Northeastern, Mass. General Hospital … the Museum of Science [and] the Museum of Fine Arts,” she said.

“That was my first energy job, and I remember we also had Sister Mary Ruth and Little Sisters of the Poor,” O’Connor said. “We had a two-year contract with a one-year extension, or a five-year contract, and Little Sisters of the Poor was the same cost as Boston College or MIT. One little facility, but that was one price.”

Massachusetts went all-in on restructuring the electricity industry, she said.

“I really liked this energy thing, and [as] scary as it sounds, I liked the process of [the New England Power Pool]. I liked all the people around a table. I liked how do you figure things out, how do you bring consensus,” O’Connor said.

[NEPOOL voted in March to admit this RTO Insider correspondent as an End User member under strict rules that prevent the publication from reporting publicly on what he hears in meetings. O’Connor said she hopes FERC does the “right thing” in its ongoing proceeding over the matter and directs the organization to allow press to report on the meetings. (See RTO Insider Reporter Admitted to NEP O OL.)]

“Even though there were challenges, public service really is a privilege,” O’Connor concluded. “I remember when I was sworn in, [Baker] said that — over my four years I learned he was right — it truly is a privilege to serve the people of the Commonwealth and to give back. I have been blessed with a number of amazing jobs, and working for this administration was by far the best of all.”

March 25, 2019

Overheard at the NE Electricity Restructuring Roundtable

BOSTON — FERC Commissioner Cheryl LaFleur kicked off her farewell tour with reflections on electricity markets in New England and around the country, NERC CEO Jim Robb shared concerns about fuel security, and a panel of experts discussed the challenges confronting the industry.

Attendees heard that and more at the 161st New England Electricity Restructuring Roundtable hosted by Raab Associates on Friday. Following is some of what we learned during the event.

NERC CEO Jim Robb addresses the 161st New England Electricity Restructuring Roundtable in Boston on March 22. | © *RTO Insider*

Attributes over Volume

LaFleur, who announced in January that she will leave the commission between the end of her term June 30 and the end of the year, offered her insights into the changes on the horizon. (See LaFleur Announces Departure from FERC.)

“I am seeing lots of evidence from all over the country, in organized markets and outside organized markets, that a fundamental shift is underway in how we procure and pay for electricity,” she said.

“Back in the vertically integrated days … we took it for granted, and many times we still do, that energy is priced on volume,” LaFleur said. “Aside from a few ancillary services that were co-optimized at a lower price, everything was volumetric, and it worked as long as the cost curves were that way. Well, there’s a lot of evidence that the cost curves are not going to look that way in the future.”

With persistently low gas prices, even in New England, zero-marginal-cost renewables coming online, and distributed energy and demand-side resources changing the load curves, the industry can’t assume that resources are going to make money on volume, and that peaks are going to set the prices at which resources make money, she said.

“Across all the markets and regions, what we’re seeing is people … paying for attributes rather than volume in the energy markets, in the capacity markets and in the ancillary services markets,” LaFleur said.

“The trouble is, an attribute is a slippery thing” and can encompass anything from stockpiling coal to pricing carbon; from flexible ramping to scarcity pricing, storage or fuel security, she said.

“And it’s in the capacity markets too, where we have Pay-for-Performance; Capacity Performance; seasonal capacity,” LaFleur said. “I’m starting to think if we’re not going to pay on volume, how are we going to pay? And this is fundamental. … Most of the money is in the energy market. How we pay for energy is going to determine what we get and how we pay to keep the lights on.”

The “cut-across issue” for LaFleur is jurisdictional, where the federal government does some things and the states do others.

“We understand what’s interstate, and we have jurisdiction over the ISO rates, and then the states have their jurisdiction, but then here are resources connecting behind the meter at the distribution level that operate like wholesale resources,” she said in response to a question about DERs.

“It’s really easy to say, ‘Oh, we should have more cooperation with the states,’ but it’s really hard to figure out how to do that in this space because our system was set up as if we knew the difference between central station wholesale and distributed [resources],” LaFleur said. “So, [there is] a lot to work through, but … I think it’s way more an opportunity than a challenge. It could be, to use an overused word, transformative.”

‘A Lot to Celebrate,’ but…

New England has benefited from ISO-NE’s creativity in dealing with fuel security, said Robb, who has been at the helm of NERC for nearly a year after leaving the chief role at the Western Electricity Coordinating Council.

“There are really three hotbeds of issues in reliability around the country,” Robb said. “The first one is California … the epicenter of the issues around an integration of large-scale solar into the system. … Whoever thought we’d have too much generation on peak?”

Until the Aliso Canyon gas storage facility came in service, it was not clear what a growing balancing role the natural gas system was playing in response to the surge in solar capacity, and how that system was being stressed by fast-ramping gas-fired plants pulling gas off the network faster than it could be replaced, Robb said.

“The other area is Texas, which is really testing all of our patience on the question of capacity adequacy and reserve margin,” Robb said. “They’re operating at about a 7 to 8% reserve margin going into the summer. They put great faith in the market signals that they’re sending to the operators and to the plants online. They made it through a very hot summer last year, so there’s something in the soup that we’re starting to understand about what kind of reserve margins are really necessary.”

The third area is New England, and “from an environmental perspective there’s a lot to celebrate,” Robb said. “You have substantially repositioned your fleet to a much lower carbon footprint than it was 20 or 30 years ago to meet environmental objectives and have managed to keep the lights on.

“The shift away from on-site fuel — large coal, nuclear and petroleum — to resources that are dependent on weather and just-in-time delivery of fuel really changes the risk profile,” he said. “The issue up here is not one of capacity adequacy; it’s one of energy adequacy and, importantly, fuel adequacy to serve load.”

Robb looked at the dramatic oil consumption during last winter’s sever cold snap — when generators burned as much oil in two weeks as they normally do in a year — and asked what would have happened if the cold snap had lasted another day.

Oil supplies at plants around New England declined rapidly over the two-week cold spell as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

“You guys are a day away from a load-shedding event,” Robb said.

Getting Late

Where the NERC CEO sees the region’s glass as being half-empty, Dan Dolan, president of the New England Power Generators Association, said he “would argue that we passed the stress test [and] came through the most severe cold snap in 100 years with gas in the system at the end.”

“The open market has been extraordinarily successful at dispatch of least-cost resources,” Dolan said.

However, he pointed to the increasing trend of states procuring energy contracts and estimated that state-sponsored resources will compose more than half of the region’s energy production by 2027.

Dolan cited research by Joe Cavicchi of Compass Lexecon, commissioned by NEPGA, that says New England’s much-needed fast-ramping resources require capital investment — and that generators believe the market signals get mixed in a half free, half state-controlled market.

Jonathan Raab of Raab Associates, who conducted the roundtable, asked if the wholesale markets are at a tipping point, and if so, how New England can prepare for the world 10 years from now.

“It’s later than you think,” said Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection.

“We hear from those who have been in this market for quite some time that there’s a lot of volatility, uncertainty, marginal earnings and even from the [perspective of the] status quo, it’s not a market that a lot of people are feeling comfortable continuing to invest in,” Dykes said.

“Our failure to plan proactively [for natural gas supply constraints] … has exposed our ratepayers to the exercise of market power by those generators who do have the ability to provide fuel-secure resources,” she said. (See Exelon to Push for Laws, Rules to Boost Profitability.)

The retreat at the federal level on the need to address climate change has injected further uncertainty for those who would like to move forward with market-based approaches to valuing carbon reduction, she said.

Connecticut has long-term contracts approved or pending for 52% of the state’s energy demand, including 13% for non-nuclear resources needed to meet its renewable portfolio standard, Dykes said.

“If we’re paying a capacity payment to resources for availability for an entire year, for resources that we know don’t have access to pipeline gas to be able to run year-round, I think some further refinement on what that market is designed to procure is important,” Dykes said.

To the extent that states are seeking to meet their planning objectives for environmental policy around carbon, the more that those products can have resource adequacy and fuel security benefits will also be helpful, she said.

Inflection Point

“We are with our capacity markets nearing an inflection point where we need to figure out exactly what our resource adequacy construct needs to be going forward,” said Mark Karl, ISO-NE vice president for market development.

As he did in December, Karl said the RTO’s long-term solution for energy security has three components: multiday-ahead markets, a new ancillary service integrated into that market and a new, voluntary forward seasonal auction. (See Fuel Security the Focus at ISO-NE Consumer Liaison Meeting.)

“I should be clear it’s not just about fuel; it is about energy security,” Karl said.

The RTO’s enhanced storage participation rules go into effect April 1, with a second phase coming in the second half of this year, and staff are working on a third phase, he said. (See FERC Accepts ISO-NE Storage Tariff Revisions.)

In addition, the RTO prepared an interim proposal for compensating generators for fuel security, which it plans to file this month with FERC, with or without stakeholder endorsement. (See ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)

The Analysis Group’s Paul Hibbard, former chairman of the Massachusetts Department of Public Utilities, said the desire to reduce energy sector carbon emissions is the biggest market factor of all.

With various state policies being enacted, “how do the markets provide the resources needed to maintain reliability, particularly during winter months?” Hibbard asked. “That’s what makes this so incredibly difficult.

“There’s really very little opportunity for resources to earn sufficient revenues through energy markets when you look five or 10 years out, but we still have to maintain reliability during those winter months,” he said.

When the Pilgrim nuclear plant and the remaining oil and coal units retire, the system will become “a lot more peaky” from a gas supply perspective, he said. “What really changes here is that the consumption of natural gas power plants for electricity spikes in the winter … so it really increases our reliance, particularly for power sector reliability, on LNG over the course of the 25 or 50 coldest days of the year.”

Add electrification and “things get really scary, because now pipelines can’t even meet total demand for gas for over 100 days in the year,” Hibbard said. “It’s this combination of what the states are trying to do to meet carbon-reduction goals, and the feedback that has on the electric system, that makes the challenges so incredibly important when thinking about this transition over the next 10 years.”

– Michael Kuser

March 25, 2019

FERC Denies KEPCo Complaint Against Westar Energy

By Tom Kleckner

FERC last week denied Kansas Electric Power Cooperative’s complaint that Westar Energy had twice violated its generation formula rate (GFR) in assessing its own rates and federal income tax reduction (EL19-17).

In its Federal Power Act Section 206 complaint, KEPCo alleged that Westar failed to reflect the reduction in the federal corporate income tax rate that went into effect on Jan. 1, 2018, in the utility’s rates paid and calculated under the GFR. KEPCo also asserted that Westar improperly included about $551,000 associated with Westar’s settlement of a personal injury lawsuit in the GFR’s annual update in 2018.

The complaint filed last November included a list of informal challenges to the 2018 update. It maintained Westar should have corrected the overstated tax expense from Jan. 1 to May 31, 2018, as a mistake, charging that the company used the improper corporate tax rate for the 2018/19 contract year.

The co-op asked the commission to order Westar to recalculate the GFR, exclude the settlement’s $551,000 from the 2018 update and provide refunds with interest.

Westar responded by saying that it believed all charges in the 2018 update were appropriate. Westar asserted that KEPCo failed to demonstrate how the GFR as a whole is unjust and unreasonable.

FERC found that Wester correctly applied its historical test year methodology in the 2018 update, applying a 35% federal corporate tax rate in calculating the GFR from Jan. 1, 2018, through May 31, 2019. The commission pointed out the update was properly based on 2017 costs, including the 35% tax rate in effect in 2017.

The commission relied on precedent set in a recent decision in which Duke Energy also had a cost-based tariff that followed a historical test year methodology and applied the 35% tax rate in its 2018 annual update. FERC dismissed a wholesale transmission customer’s attempt to apply a lower income tax rate because it found the utility “correctly used the federal corporate income tax rate in effect in 2017 in preparing the 2018 annual update.”

In that proceeding, the commission said it “generally requires that formula rate inputs be calculated on a synchronized basis over the same test period … [using] the federal corporate income tax rate in effect during the historical test year period, absent a contrary statement in the filed rate.”

“No such contrary statement exists in Westar’s GFR,” the commission said.

FERC said KEPCo provided little support for its argument that the GFR’s tax component is an exception to the historical test year approach. “The lack of an explicit requirement in Westar’s GFR one way or the other on the correct federal corporate income tax rate favors use of the prior year rate, consistent with the historical test year methodology,” the commission said.

FERC made a similar decision last week in case involving a Louisiana city’s complaint against Cleco Power. (See related story, FERC Backs Cleco on Tax Rate Calculations.)

The commission did not address Westar’s inclusion of “certain expenses in the injuries and damages account,” as KEPCo withdrew its challenge.

Commission Denies Reduction of ITC Great Plains Adder

FERC last week also denied the Kansas Corporation Commission’s request that a previously awarded transmission-only company (transco) adder for ITC Great Plains be reduced, pending the KCC filing a Section 206 complaint (ER09-548).

ITC Holdings’ headquarters in Novi, Mich. | *ITC Holdings*

The KCC in December filed a motion requesting FERC direct ITC to show cause why the adder in its overall return on equity should not be reduced from 100 to 25 basis points, given the commission’s findings in a docket involving Consumers Energy.

In that proceeding, FERC found that three ITC Holdings subsidiaries in MISO (International Transmission Co., Michigan Electric Transmission Co. and ITC Midwest) were no longer fully independent and that a recent merger had reduced, but not eliminated, their level of independence as transcos. The commission said a 25-basis-point transco adder was appropriate for the subsidiaries.

However, FERC said ITC Great Plains’ transco adder was granted in a 2015 order that became final when no party appealed the order on rehearing. The commission noted that if a party believes that “changed circumstances warrant a revisiting of previously granted transmission incentives,” that party should file a Section 206 complaint.

March 25, 2019

FERC Accepts NYISO RMR Compliance Filing

By Michael Kuser

FERC on Thursday conditionally approved NYISO’s deadlines for completing final market power reviews for deactivating generators (ER16-12 0 -007).

NYISO submitted the proposal in response to a commission directive in April 2018 as part of the ISO’s larger plan to revise its reliability-must-run rules. (See FERC Orders Deadline on NYISO Market Power Reviews.)

The commission found the ISO’s two proposed timelines “appropriately work back from a generator’s proposed deactivation date, recognizing the flexibility generators have in proposing deactivation dates.” It also noted the ISO’s proposal “focuses on ensuring the accuracy of final physical withholding determinations at deactivation.”

The 2,480-MW Ravenswood Generating Station in Queens, N.Y.

FERC, however, also found that the proposal “fails to strike the appropriate balance between the needs of the deactivating generator for ‘transparency and certainty’ and NYISO’s need to ensure that the data and assumptions underlying the final physical withholding determinations are not ‘too far removed from a generator’s actual deactivation date.’”

FERC instead said the ISO’s proposed alternative in its answer to a protest by the Independent Power Producers of New York “better strikes this balance, allowing deactivating generators to timely plan their deactivations while giving NYISO adequate time to perform its physical withholding determinations and base them on ‘market conditions close to the time of deactivation.’”

As a result, NYISO must submit a further compliance filing that requires it to provide a deactivating generator final physical withholding determinations at least 60 days before the deactivation date specified in the generator’s updated notice to the ISO, which the resource owner must submit 90 days before the specified deactivation date.

Time Issues

NYISO’s Market Monitoring Unit supported the filing, saying it would leave the ISO better positioned to perform its evaluation based on market conditions that are close to the time of deactivation.

The Monitor also agreed with proposed “irrevocable action or inaction” rules, which require generators to make irrevocable deactivation-related decisions well ahead of shutdown, saying the provisions properly allow the ISO to apply reasonable judgment to consider and classify deactivation decisions as practicably irreversible even when they are not strictly irreversible.

The commission declined IPPNY’s request for clarification around those rules, saying “we believe that NYISO should have discretion to, in consultation with the Market Monitor, consider the facts and circumstances on a case-by-case basis to determine what events will have an irreversible consequence.”

FERC similarly disagreed with IPPNY’s assertion that requiring generators to deactivate no more than five days before and 10 days after their specified date is unreasonable.

The commission said NYISO’s proposal addresses its “concern that the final market power review ‘may be less effective with data and assumptions too far removed from a generator’s actual deactivation date.’ In addition, IPPNY fails to recognize that deactivating generators have the flexibility to choose their actual deactivation date when they request a final physical withholding determination.”

March 25, 2019

ACORE Speakers: Green New Deal Advancing Climate Debate

By Michael Brooks

WASHINGTON — The Green New Deal — the nonbinding resolution introduced early last month by Rep. Alexandria Ocasio-Cortez (D-N.Y.) and Sen. Ed Markey (D-Mass.) calling for the U.S. to use 100% renewable energy resources by 2030 — has sparked furious debates among policymakers, experts and the national media.

Joe Balash, the Interior Department’s assistant secretary for land and minerals management, addresses the American Council on Renewable Energy’s Renewable Energy Policy Forum at the Conrad Hotel in D.C. on March 20. | © *RTO Insider*

There is plenty to disagree about: the resolution’s merits; its feasibility; its inclusion of other goals unrelated to climate or energy, such as those regarding health care; and whether it will help, or hurt, Democrats in the 2020 elections.

But in at least one of these debates, which took place during the American Council on Renewable Energy’s Renewable Energy Policy Forum last week, everyone agreed on something: The Green New Deal has put climate change to the fore of U.S. politics like never before.

“We’ve had more conversations about climate in the last five weeks since we introduced the Green New Deal than we’ve seen in the past 10 years,” said Morgan Gray, Markey’s legislative director.

Though the conference, which attracted about 100 renewable industry executives to the Conrad Hotel on Wednesday, featured panels on topics such as state renewable portfolio standards and integrating renewables into RTO/ISO markets, federal policy on climate change was top-of-mind for many who spoke or asked questions.

‘Good Politics’

Washington Gov. Jay Inslee, one of the 14 (as of press time) major candidates to be the Democratic nominee for president, set the tone for the day with his opening keynote speech.

“I believe very strongly that defeating climate change, building clean energy [and] building renewable energy must be the number one job of the United States, because if it is not Job 1, it won’t get done,” said Inslee, who has made climate policy the centerpiece of his political career and campaign.

Though he stopped just short of endorsing it, Inslee said the Green New Deal has been helpful in moving climate change up the list of priorities for Congress. He noted, as many other speakers did, that climate was not even discussed during the 2016 presidential debates.

Absent from the resolution is a plan detailing how the U.S. would achieve the ambitious goals. This was a source of contention among Gray and his fellow panelists, who often freely sparred without interference from moderator Julia Pyper, senior editor at Greentech Media.

The Green New Deal “is good politics,” said Alex Flint, executive director of the Alliance for Market Solutions, a conservative think tank that advocates a tax on carbon emissions. “Climate change is an increasingly important thing to voters in both parties, and we’re beginning to see that. That’s why the Green New Deal has resonated.

“From a policy perspective, it’s completely bankrupt,” he continued. “There’s no actual policy: What’s going to happen with FERC, the Federal Power Act? Are we going to need a new tax policy? None of that is there.”

But, “and this is a good thing, it’s pulled Democrats so far to the left that it has a created an opening at the center of political discourse for Republicans.”

Christy Goldfuss, senior vice president of energy and environment policy for the Center for American Progress, debated with Flint about a carbon tax being the “only” solution, saying, “We are going to have to take many big steps in order to address climate change.”

But she agreed that the Green New Deal “brings people to the table to figure out solutions that have bipartisan support.” She noted that Democrats were able to take control of the House of Representatives by moderate candidates winning in purple districts. They will be looking for legislation they can compromise with Republicans on, she said. “Absent the Green New Deal, that would not be where we are.”

From left to right: Julia Pyper, Alex Flint, Christy Goldfuss, Morgan Gray and Heather Reams. | © *RTO Insider*

A Real Deal?

The resolution is too politically charged, with Republicans ridiculing it as a ban on airplanes and hamburgers, said Heather Reams, executive director of Citizens for Responsible Energy Solutions, another organization that advocates market-based solutions to climate change. But she also said she was pleased that it has sparked real debate over solutions to climate change.

“Republicans need to step up,” Reams said. “They need to start talking about what they’re for, instead of what they’re against. And they need to do that, like, ASAP.” The comment prompted murmurs of agreement from the audience.

“That’s a wholly new statement that I haven’t heard in the last 10 years,” Gray said. “I think that’s kind of the shift that we’ve seen as a result of the Green New Deal.”

All of the Democratic presidential candidates who serve in the Senate are cosponsors of Markey’s resolution and swiftly endorsed it as part of their campaigns, while more moderate and pragmatic members of the party have dismissed it as too ambitious. (See House Democrats Put Climate Change Front and Center.)

Seeking to capitalize on the division, Senate Majority Leader Mitch McConnell (R-Ky.) has planned a vote on the resolution for this week. Minority Leader Chuck Schumer (D-N.Y.) is urging his caucus to simply vote “present.”

On Friday, Politico reported that it had obtained a draft of a “Green Real Deal” being circulated by Rep. Matt Gaetz (R-Fla.) to counter the Green New Deal. The draft acknowledges climate change as a threat to national security and says the government should promote innovation to reduce greenhouse gas emissions, but it does not set any targets for future carbon cuts.

March 25, 2019

FERC OKs Trans Bay Cable Sale to NextEra

By Hudson Sangree

Despite protests from a number of cities, FERC last week approved the sale of the Trans Bay Cable, a 400-MW line that runs for 53 miles under San Francisco Bay, to NextEra Energy Transmission (EC19-36).

“Based on the record in this proceeding, we find that the proposed transaction will not have an adverse effect on rates,” FERC wrote.

The cable’s current owner is Trans Bay Cable LLC, a portfolio company of SteelRiver Infrastructure Partners of Sausalito, Calif. The Trans Bay Cable provides electric transmission between two substations owned by Pacific Gas and Electric and is under CAISO control.

The Trans Bay Cable runs for 53 miles under San Francisco Bay, providing transmission between two PG&E substations. | *SteelRiver Infrastructure Partners*

Trans Bay and NextEra asked FERC to approve the deal in December. The companies did not publicly disclose the purchase price, but news reports put it at $1 billion.

The line’s current rates are fixed under a settlement agreement that expires next year. In its comments to FERC, the Northern California Power Agency said NextEra should not be able to recover acquisition costs after that settlement rate expires.

Six cities in California — including Anaheim, Riverside and Pasadena — said NextEra’s application failed to state how the transaction could affect rates. The city of San Francisco requested FERC to require more information from the applicants regarding acquisition costs “in order to ensure that no unlawful acquisition premium will be included in rates.”

Another intervenor, the California Municipal Utilities Association, said “that applicants have chosen to withhold key financial data from parties in this proceeding and that, without that information, parties are forced to rely upon public news reporting regarding the terms of the proposed transaction,” FERC wrote. “California Municipal Utilities Association states that, given that the applicants have chosen to request confidential treatment of financial data, it is difficult to test their assertion that the proposed transaction will have no adverse effect on rates.”

The 400-MW high-voltage transmission line serves the San Francisco area. | *California State Coastal Conservancy*

NextEra said it has no intention of trying to recover acquisition costs from CAISO customers via rate increases, and FERC said that even if NextEra did so, it would face a difficult test under Section 205 of the Federal Power Act to show the “the acquisition provides specific, measurable and substantial benefits to ratepayers, consistent with commission precedent.”

With regard to the confidentiality concerns, FERC said intervenors can request copies of confidentially filed materials, but that so far, none has done so.

March 25, 2019

Glick Disputes FERC ‘Breakthrough’ on LNG Projects

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — FERC Commissioner Richard Glick on Thursday rejected Chairman Neil Chatterjee’s claim of a bipartisan “breakthrough” on the commission’s evaluation of LNG projects, joining with fellow Democrat Cheryl LaFleur to say the panel was still ignoring the projects’ impact on climate change.

On Feb. 21, a FERC news release celebrated the commission’s 3-1 approval of the Calcasieu Pass LNG export project in Louisiana, calling it a “breakthrough … agreement that may provide a path forward” for the commission’s review of 12 other proposed LNG facilities.

The release quoted Chatterjee thanking LaFleur and Republican Commissioner Bernard McNamee for joining the chairman in the majority. It made no mention of LaFleur’s six-page concurrence, in which she disagreed with Chatterjee and McNamee for failing to disclose the cumulative greenhouse gas emissions from the project (CP15-550). (See LaFleur Sides with Republicans on LNG Terminal as Glick Dissents.)

Glick, who had authored a seven-page dissent, said at Thursday’s monthly open commission meeting that the ruling was “anything but a breakthrough.”

Although the order did acknowledge the project could produce almost 4 million tons of direct GHG emissions annually, Glick said, it ignored the impact of them on climate change and “then found that the project’s environmental impacts will not be significant and that, as a result, the project is in the public’s interest.”

“I don’t want to hear that assessing significance is too hard. The commission is called upon to do it all the time in other contexts with far less information than we have in this proceeding.”

Site plan for the Calcasieu Pass LNG export project | *Venture Global LNG*

LaFleur’s Frustration

LaFleur, who has joined Glick in opposing some gas pipeline projects, wrote in her concurrence that she supported Calcasieu Pass as “not inconsistent with the public interest” based on the “governing law.”

In her comments at Thursday’s meeting, LaFleur repeated her frustration with the Republicans’ reluctance to address GHG emissions.

“We have been treating climate impacts differently than all the other environmental impacts that we look at,” she said. “We know how to quantify, mitigate [and] consider impacts to land, water and species. We make calls on whether impacts to wetlands or to a specific species of mussels are significant. But we don’t do that for climate change impacts. Instead we say we can’t figure out how to do it.”

She also complained about the split jurisdiction over LNG exports. While FERC permits the facilities and evaluates their direct environmental impacts, the Department of Energy decides whether the export of the fuel is in the public interest, including the consideration of upstream and downstream GHG emissions.

“It’s hard to do the [public interest] weighing if we’re only in charge of the impact but someone else is in charge of the benefits. I think we could be well served by looking at the lifecycle of [LNG] exports and what the aggregate climate impacts are,” she said.

“I don’t have the authority to make that happen,” she acknowledged. “In the meantime, I have to do my job, which is deal with the applications that are before us. I will continue to try to look at them case by case.”

McNamee, Chatterjee Respond

Chatterjee, who had made his opening remarks before his Democratic colleagues, did not address their comments in the open meeting.

McNamee, however, defended the commission’s order, insisting it “seriously addressed” the GHG emissions.

“I think it’s a disappointing thing that in this town, often if there’s a disagreement about how something should be done or what the conclusions are, that some will say that it wasn’t done, that they’re ignoring something,” he said.

“We have to look at each order separately. But we were able to show, at least here, that Washington can work,” he continued. “We compromised. We come together. We listen. We can get things done.”

Speaking to reporters after the meeting, Chatterjee said, “I actually thought that was a model for how constructive dialogue can take place in Washington, and I want to commend all three of my colleagues for their approach to this. I echo Commissioner McNamee’s sentiment: This is an example of how Washington can work.”

He said LaFleur was instrumental in brokering the compromise that led to the inclusion of the emissions figures and how they compare to total U.S. emissions.

“This was a big win for her,” he said. The language “was a change in a policy, a major change in policy. The commission had been approving projects in the past without the inclusion of this language. … Commissioner McNamee and myself had to get comfortable with what the legal implications of this change would be. …

“I was not completely comfortable with the change in our approach, and neither was Commissioner McNamee, but it was important that we negotiated in good faith with Commissioner LaFleur. And I for one view it as a significant accomplishment for her.”

Chatterjee also complimented Glick for his dissent.

“While he spoke very passionately, and we may disagree in our interpretation of what the Natural Gas Act allows, I commend him for his very strong and rigorous dissent because that’s the purpose of these multimember commissions. Strong dissents make the order stronger. In crafting the underlying order, we have to ensure we are dotting all our i’s and crossing all our t’s to account for all the arguments that he is making in his dissents.”

Litigation Risk?

LaFleur and Glick said the commission’s failure to consider GHG emissions creates a risk that its orders will be overturned on appeal. They cited the 2017 D.C. Circuit Court of Appeals order that remanded FERC’s approval of an environmental impact statement (EIS) for the Southeast Market Pipelines Project and a federal court ruling last week faulting the Bureau of Land Management’s EIS on oil and gas drilling in Wyoming.

Glick said LNG developers could take steps to mitigate their GHG emissions, citing the Freeport LNG terminal, which he said “substantially reduced their greenhouse gas emissions … by employing all-electric compression motor drives. A developer can also offset emissions with emissions-free power. This isn’t rocket science. So, before we pat ourselves on the back and give ourselves the good government award, we need first to do our job under the law, which in this case means not ignoring the impact a project will have on climate change.”

March 25, 2019

SPP on Track for WECC RC Certification

By Tom Kleckner

SPP Vice President of Operations Bruce Rew last week said that he “feels pretty confident” the RTO will meet its first major target in providing reliability coordination services to 12% of the Western Interconnection’s load.

During a Wednesday meeting of the Western Reliability Executive Committee (WREC) in Tucson, Ariz., Rew said SPP is “doing well” in preparing for the certification process, which begins with the Western Electricity Coordinating Council’s on-site certification visit Aug. 13.

Rew said staff are updating and creating new procedures to include the Western footprint. He told the WREC the procedures will not be shared with customers, but a summary of methodologies will be provided.

SPP is updating and validating its system model, using Peak Reliability’s as a benchmark. Peak has provided RC services in WECC since 2011 but it will wind down operations at the end of the year.

SPP and CAISO RC Wins Most of the West.)

SPP staff are also working with the RTO’s Congestion Management and Seams Task Force to identify a “consistent and agreed-upon” congestion management approach between SPP West transmission owners and balancing authorities. The approach includes a redispatch methodology for congestion within the SPP West RC.

SPP is scheduled to go live with its RC services Dec. 3. It announced in September it had signed RC contracts with more than a dozen Western entities.

SPP’s timeline for launching its RC services | *SPP*

The WREC met following a two-day meeting by the Western Reliability Working Group, which spent much of its time discussing SPP’s communications processes, coordination among reserve sharing groups and emergency operations preparedness.

SPP staff encouraged new members to sign up for NERC’s Grid Ex V on Nov. 13 and 14, in which the RTO will participate as a player. Staff said more than 200 employees, including senior officers, will participate in the biennial exercise, which tests response to and recovery from simulated cyber and physical attacks. GridEx IV, in 2017, had more than 6,500 participants from 450 organizations.

March 25, 2019

MISO Seeking Multiple Vendors for Market Platform Redesign

By Amanda Durish Cook

NEW ORLEANS — MISO will attempt to divide its ongoing market platform replacement into a series of smaller agreements with vendors rather than one large contract with an outside party — a move that could affect the project’s timeline.

The RTO says the move will avoid overreliance on any single vendor, and that it is continuously evaluating possible impacts to the timeline and scope of the platform redesign. It had planned to begin to move its system from a server-based platform to the cloud in 2020. (See New MISO Platform Headed to the Cloud.)

The MISO Board of Directors meets on March 21. | © *RTO Insider*

MISO Vice President of Market System Enhancements Todd Ramey last week said the RTO can “lean on” its legacy platform system a little longer than originally anticipated if necessary. It was planning for a complete swap-out by 2023, under some pressure from existing platform vendor General Electric, which originally said it would also end IT support for the platform around that time.

However, GE is now willing to support the existing platform through 2030 at no additional costs to MISO, Ramey said. He said MISO and GE have “proactively negotiated an annual cost to run the existing platform until 2030 in advance should it be needed.”

“So quite a bit more runway if we need to do that,” Ramey said during a Board of Directors meeting Thursday.

Director Barbara Krumsiek half-jokingly asked for assurances that it won’t take until 2030 for a complete replacement.

“We’re working hard to make sure we can make the transition much sooner,” said Ramey, adding that MISO’s goal is to stick to its original timeline. He stressed that the RTO has not yet found any reason to extend use of the legacy platform and hasn’t made any such decision.

The multi-contract move will negate MISO’s earlier plans to reveal a chosen single vendor at the beginning of 2020 after finishing an evaluation of alternatives to GE.

MISO will provide its next update on the platform redesign to the board in June. Ramey said staff are already training members on how to work on the new platform.

Noting that cybersecurity was one of the reasons MISO cited for moving to a new platform, Director Thomas Rainwater asked RTO executives to include an update on how they will bolster cybersecurity measures if they prolong the use of the legacy system.

At a March 19 meeting of the board’s Technology Committee, Director Baljit Dail asked if GE might have any expectations of a single, large contract. MISO Executive Director of Market Development Jeff Bladen said GE was in agreement about moving forward with a series of smaller agreements.