LaFleur, Stakeholders Anxious over NERC Retirement Study
By Rich Heidorn Jr.
ATLANTA — FERC Commissioner Cheryl LaFleur and several stakeholders expressed concern Tuesday that “fuel war” partisans could weaponize NERC’s coming analysis on the impact of a dramatic increase in coal and nuclear plant retirements.
But based on the comments at Tuesday’s meeting, the analysis’ release may be delayed as stakeholders debate ways to prevent its findings from being taken out of context.
NERC Board Chair Roy Thilly said the assessment is “the most sensitive” NERC has performed in his seven-plus years on the board and promised the board won’t release it “until we’re comfortable” with it. We have to be “very, very, carful about enabling quotes out of context,” he said.
‘Scare Tactic-ish’
But LaFleur said the scenarios — based on an Energy Information Administration identification of units facing financial stress — were “scare tactic-ish.”
“The primary thing that makes generation retire is new generation … that’s what’s pushing this to happen,” she said.
“If there’s a specific issue, like frequency response or inverter issues or lack of black start or something else, let’s jump right on it, but I want to be sure that we don’t make an issue by the way we model it.”
The study is “so macro and worst-case it almost overwhelms the specific solutions.”
John Hughes, CEO of the Electric Consumers Resource Council, which represents industrial customers, was even more blunt, calling the scenarios “fiction.”
“Should NERC be issuing fiction, especially at this time, with the conspiracy within the industry to try to do a second round of stranded costs recovery of generation that should have been retired years ago?” he asked. “ … So, this is the battle that NERC is falling into. Any caveat or nuance it puts in the study will be missed by politicians and newspapers. They will take this study and run with it and make a fool out of this organization.”
Thilly lamented that S&P Global Market Intelligence published a story Sept. 5 based on a leaked “very early” draft of the analysis, saying the disclosure “really undercuts our process.”
The story was headlined “Power outages possible if coal, nuclear plants close rapidly.”
NERC officials said the draft included even more extreme scenarios — increasing coal retirements to 60% and nuclear to 75% — that have since been eliminated because they did not materially impact the results.
Two Challenges
Moura agreed that the results should not be sensationalized.
“I can certainly … understand the difficulties of telling this stress test scenario story without getting the general public and industry and policy makers thinking that the sky is falling. It’s certainly not. There’s a lot of processes and backstops available both at the state level, at the market level and even at the federal level to ensure reliability.”
He said the analysis identified two challenges, including ensuring new transmission where needed to address voltage stability and thermal violations resulting from shifts in generation locations.
The second challenge is managing the “end state” after the transition — the ability to respond to extreme conditions such as the polar vortex and fuel disruptions. The latter could mandate new gas pipelines, he said.
He noted that Texas got through last summer without reliability problems despite losing 4,000 MW of coal-fired generation in spring with only a few months’ notice.
Moura defended the use of the EIA expanded retirement scenarios, saying such rapid shutdowns could result from new federal environmental policies or plant owner bankruptcies. “It helps us understand the worst-case scenario,” he said.
“We certainly don’t see this as the future,” he Moura added. “It’s an engineering study to understand … what the bookends are.”
Steve Naumann, vice president of transmission and NERC policy for Exelon, the nation’s largest nuclear generator, said NERC should not take any action to block dissemination of the analysis. “Why wouldn’t you want that information?” he asked.
“The core recommendation here is ‘manage it,’” said NERC CEO Jim Robb, adding the industry needs to ensure that ] capacity markets and reliability-must run generation are performing as intended to ensure reliability. NERC’s role should be the “conscience of the industry” and avoid the politics, he added at Wednesday’s quarterly Board of Trustees meeting.
“While it is possible for coal and nuclear retirements to exceed the current announcements and long-term industry outlooks, any such acceleration would also have feedback effects on power and natural gas prices that would tend to slow down any further retirements,” Brattle Group analyst Metin Celebi said in an email Wednesday. “With additional retirements, wholesale energy prices would increase due to lower expected reserve margins and more expensive resources setting the power prices, and natural gas prices would also increase due to an increase in the dispatch of natural gas plants. … The increase in power and gas prices would improve the economic viability of the remaining coal and nuclear plants at risk for retirement, hence acting as a brake on further retirements.”
FERC on Monday granted Ameren a rehearing on an incentive rate treatment for one portion of the company’s Grand Rivers transmission project while rejecting a simultaneous request for another segment.
The 500-mile project, which is currently under development, will span Illinois and extend into Missouri, creating a continuous 345-kV path from Iowa to Indiana.
The commission denied a rehearing for the Illinois Rivers component of the project, affirming part of its February ruling that found Ameren had failed to demonstrate why the “remaining risks and challenges” associated with both the Illinois Rivers and Mark Twain segments warranted a 100-basis-point incentive adder given the late stage of project construction. (See Ameren Rate Incentive Rejected by FERC.)
In its Nov. 5 order, the commission dismissed Ameren’s contention that its February ruling failed to recognize its own precedent in Pepco Holdings, Inc., which distinguished between incentives requested after a project is already completed and those requested when a project is nearly complete (ER18-463).
The commission said its February order made clear that projects being nearly completed does not necessarily preclude them from receiving incentive adders, but that such projects also face fewer challenges, a condition the commission found applied to Grand Rivers.
“Pepco does not stand for the proposition that all incomplete projects will receive [a return on equity] incentive based on the risks and challenges of a project, as Ameren Transmission appears to suggest. Rather, Pepco stands for the proposition that an applicant may not seek incentives for a project that is already complete; a project that is not yet complete is eligible for incentives,” the commission wrote.
The commission acknowledged that Pepco granted incentives to a project that was nearly complete, but that it no long believes that it is “appropriate” to provide incentives to such projects.
“Thus, while a project being under construction does not preclude it from incentives, the commission will consider how close the project is to completion when evaluating the risks and challenges of the project — with less risk typically attendant to projects that are further along in the construction process. We note that consideration of construction progress as part of the nexus test is consistent with commission precedent,” FERC said.
In this case, the commission found the Illinois Rivers component “failed to meet the nexus test,” given that it was 90% complete at the time of its December 2017 application for the adders, with four of its nine line segments already energized and all 10 of its substations in service.
But in granting a rehearing for the Twain component of the project, FERC agreed with Ameren’s argument that it should be evaluated on its own merits — separately from Illinois Rivers — as the project had not yet broken ground by the time of last December’s application.
The commission also determined the Twain segment qualifies for the risk-reducing incentives spelled out in FERC’s 2012 policy statement on promoting transmission investment in that it will unlock constrained wind generation and relieve chronic and severe congestion, resulting in $2 billion in production cost savings across MISO.
“We also note that the Mark Twain component was reviewed and approved as part of the MISO Transmission Expansion Plan 2011 portfolio of [multi-value projects], such that alternatives to the project have been considered in a relevant transmission planning process,” the commission noted.
Monday’s order reduced Twain’s potential ROE adder to 50 basis points, citing FERC precedent in its 2015 NYISO ruling on the Edic-to-Pleasant Valley line and its 2018 ruling on NextEra Energy’s Empire line in New York, both of which are 345-kV projects similar to Twain.
“We find that the Mark Twain component unlocks location-constrained generation and provides congestion relief in a range comparable to that of the projects awarded a 50-basis-point ROE incentive in NYISO and NextEra,” the commission said.
PG&E Corp. described its wildfire prevention efforts Monday in a third-quarter earnings call that outlined strategies to power down equipment in extreme weather conditions, install thousands of cameras and weather stations along power lines, and harden its grid across large areas of Northern California.
“This is a long-term approach to frankly de-risking our assets in these high fire-prone areas,” CEO Geisha Williams told analysts on the call.
The fire-prevention plans also are part of PG&E’s efforts to reassure nervous financial markets. The company has watched its stock price plummet in the past year as investors worried about its potential multibillion-dollar liability for a series of devastating fires in 2017.
In August 2017, PG&E’s stock hit a high of more than $70/share but had sunk to about $41 by February amid talk of potential bankruptcy. The price had climbed back to nearly $49 as of Tuesday.
On Monday, the company reported Q3 net income of $564 million ($1.09/share), compared with net income of $550 million ($1.07/share) for the third quarter of 2017.
Williams began the earnings call by acknowledging the one-year anniversary of the October 2017 fires that tore through California’s wine country in Napa and Sonoma counties and leveled a portion of the city of Santa Rosa. State fire officials have blamed the company’s equipment for some of those fires, while others are still under investigation.
Some estimates have suggested PG&E’s eventual liability could be up to $15 billion under California’s unique method of holding utilities strictly liable for damage caused by electrical lines and equipment under a legal doctrine called “inverse condemnation.”
That doctrine was the subject of debate this year as the state’s elected officials tried to deal with the threat of PG&E’s financial collapse in the wake of the fires. Gov. Jerry Brown proposed elimination of inverse condemnation as part of SB 901, a landmark wildfire prevention act he signed into law in September. (See Does California need a Catastrophic Fire Fund?)
‘Important Work Remains’
The bill eventually established a procedure by which utilities could issue bonds to pay off wildfire debts, but it did not get rid of inverse condemnation, as Williams noted in the call. She said efforts to reverse the legal doctrine would continue.
PG&E outlined its efforts to deal with wildfire threats in an earnings call Monday. | PG&E
“While we believe [SB 901] represents a constructive initial step, more important work remains,” Williams said. “This law provides for improved financial stability for the investor-owned utilities in the state. However, it does not address inverse condemnation, and it remains our firm view that this must be resolved through legislative reforms or legal challenges.”
Meanwhile, PG&E plans to file a wildfire mitigation plan with state regulators in February, as required by SB 901, she said.
Actions already underway include increased vegetation management and daily aerial patrols.
Over the next four years PG&E plans to install 600 high-definition cameras and 1,300 weather stations in fire-prone areas, Williams said on the call. And, she said, “in the next 10 years, we intend to upgrade our system across a targeted roughly 7,000 miles of our highest risk areas with stronger and more weather-resistant poles and insulated tree wire.”
“These plans will be further detailed in the 2020 general rate case that will be filed later this year,” Williams said.
PG&E also is using another, more controversial tactic in its fight against wildfires and wildfire liability.
For the first time, in mid-October, it proactively shut down power lines during what the company said were high-risk weather conditions in the northern San Francisco Bay Area and the Sierra Nevada foothills near Sacramento. (See PG&E Shuts Down Power to Prevent Fires.)
“When the weather improved, our crews conducted patrols across the entire 3,400 impacted miles of our power lines by helicopter, vehicle and on foot, identifying multiple lines that had sustained damage,” Williams said. “Service was restored to nearly all customers within about two days.”
Since then, the company has received numerous complaints from residential customers and businesses that sustained losses, including claims of spoiled food, according to The Sacramento Bee and other news outlets. PG&E filed a compliance report with the California Public Utilities Commission on Oct. 31 defending its decision, the news reports said.
Jamie Court, head of the advocacy group Consumer Watch, has called PG&E’s decision to shut off power to tens of thousands of customers “blackout blackmail.” Immediately after the shutdown in mid-October, he said it was unnecessary and was PG&E’s way of sending a political message. (See Fire Season Becomes Blackout Time in California.)
“They didn’t get inverse condemnation [changed]. They want to get out of liability forever for everything, and this is the way they send a signal,” Court told RTO Insider at the time. “The biggest power a utility has is the ability to turn off power.”
CHICAGO — Following the 2011 Fukushima nuclear disaster, German leaders ordered an immediate shutdown of the country’s oldest nuclear reactors and devised a plan to meet 80% of its power needs through renewables by 2050. Such a transition is unlikely in the U.S., attendees found out at a conclave last week of PJM stakeholders and their German counterparts.
The two-day Energy Trends Forum immediately followed the annual meeting of the Organization of PJM States Inc. (OPSI) and was sponsored by OPSI and Germany’s Federal Ministry for Economic Affairs and Energy.
“The biggest question will be: Will politics stay out of the game?” said Frank Peter, the deputy executive director of Agora Energiewende, a German think tank supporting the country’s planned transition to low-carbon energy production.
“What we’ve kind of found in the U.S. is that’s an unrealistic expectation,” said former FERC Commissioner Tony Clark, a senior adviser with D.C. law firm Wilkinson Barker Knauer.
Differences
Annegret Groebel, who heads international coordination for Germany’s Federal Network Agency, said the country’s transition has been aided by a generation surplus. It has less transmission congestion and less granular pricing because it uses a zonal system, while PJM’s LMP is based on a nodal framework.
Germany has also unbundled the industry so that owners of transmission, distribution and generation assets are separate. In PJM, a holding company such as Exelon can own all asset classes through subsidiaries.
Germans are also willing to spend whatever it takes to interconnect renewables and maintain extremely high reliability, German representatives said.
In PJM, state interests can inhibit development of transmission from renewable resources to load centers. “If Pennsylvania doesn’t want energy from Iowa, then those lines serve no purpose,” PJM’s Steve Herling said.
Germany has experienced one grid-related outage since 1990, and consumers have resisted suggestions to reduce costs that might increase that risk.
Changes
PJM’s cost sensitivity might shift, if staff have anything to say about it. Vince Duane, PJM’s senior vice president for law, compliance and external affairs, said the RTO needs “an honest discussion” about maintaining reliability at least cost to reflect consumers’ actual interests.
“I hope what will evolve is a dialogue in the very near term that will examine that,” he said. Last week, PJM released the summary of a study that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements. Officials said the findings support the need to compensate generators based on their “fuel security.” (See related story, PJM Begins Campaign for ‘Fuel Security’ Payments.)
The transition might not be easy. Duane noted that one German representative said the “broader value proposition of decarbonization” is a “cleaner, quieter, more elegant world.”
“Those are three terms that have never been used to describe Americans, so we have our work cut out for us,” he said.
More to Come
While Germany has made major strides in its transition, there is still a ways to go, panelists said.
Both American and German panelists noted that surcharges on customer bills for things like system upgrades and resource subsidies are politically expedient but dull market signals that might help consumers reduce demand.
“There’s nothing greener than the electron you don’t produce,” Duane said. “At the end of the day, getting consumers to see prices and respond to prices … has to be a critical policy objective. … At least in this country, we still have a tremendous amount of dumb, discretionary load that could be curtailed, but … people don’t see a reason economically to do that, and they won’t see that reason if a lot of the electricity bill is basically tax.”
Thorsten Herdan, director-general for energy policy, heating and efficiency in the Ministry for Economic Affairs and Energy, noted in his opening remarks that the country’s energy transition focused on electricity — ignoring 80% of the country’s energy use.
“The building stock has not been addressed that much that we can meet our targets for the building sector,” he said. “We have just forgotten the transport sector. That was one of our biggest mistakes. … What are we going to do with what’s left? Are we going to electrify it? I have my doubts.”
CHICAGO — PJM CEO Andy Ott opened his remarks at last week’s annual meeting of the Organization of PJM States Inc. (OPSI) with a sports metaphor to describe the wide array of discussions that were to follow.
While there are many teams trying to achieve many goals on that field, Ott expressed willingness during the two-day meeting to consider rule changes that could redefine how they interact.
He also said there are “many ways to skin the cat” in addition to the capacity market to ensure long-term resource availability. PJM and its stakeholders have been working on a market overhaul for the past two years and smaller reforms for many years prior to that.
PJM staff have proposed adding a second phase to the annual Base Residual Auction to mitigate the impacts of subsidies on resources along with a “resource-specific carve-out” that would allow states to remove from the auction qualifying resources and procurement obligations for a corresponding amount of load. Ott’s comments suggested a willingness to reconsider American Municipal Power’s desire to emphasize bilateral contracting over procurement in the BRA. In August 2016, AMP led a coalition with other municipal utilities and cooperatives calling for a “holistic assessment” of the Reliability Pricing Model. (See Co-ops, Munis Call for Reset of PJM Capacity Model.)
A capacity market is “the most efficient way,” Ott said, but he added “frankly, if we need to evolve that … that’s doable.”
State Objectives
Ott’s openness to change was a recognition of state regulators’ frustration with the RTO. In the meeting’s first panel discussion, several regulators reiterated their intent to continue pursuing generation subsidies and other preferential policies despite opposition from pure-market advocates.
“I think I can say without question that our citizens do benefit greatly from PJM and the wholesale markets,” Maryland Public Service Commissioner Michael Richard said. “However, if we can’t find ways to adequately and fairly accommodate state policies, I’m concerned that [FERC] Commissioner [Cheryl] LaFleur may be right, and states will feel the necessity to effectively reregulate in defense of these state policies. We hope that that’s not the case and the direction that we go in.”
LaFleur expressed her concern in June, when she dissented in FERC’s 3-2 ruling requiring PJM to revamp its minimum offer price rule (MOPR) to address capacity price suppression from rising state subsidies for renewable and nuclear power. The commission initiated a “paper hearing” on the issue (EL18-178). (See FERC Orders PJM Capacity Market Revamp.)
Joe Fiordaliso, president of the New Jersey Board of Public Utilities, said his state is on a “clean-energy crusade” and working toward the largest statewide offshore wind solicitation in the country. “We must never forget the economic impact of clean energy,” he said.
Illinois Commerce Commissioner John Rosales forcefully defended his state’s zero-emission credit subsidy for several in-state nuclear plants, arguing that Illinoisans deserve capacity credit for the program because they pay for it.
“That has to be recognized, and when it’s not, I get a little angry. … That has to be accommodated by PJM,” he said.
The rhetoric got even more heated after Direct Energy’s Marji Philips criticized the vying state policies as “kids in a sandbox” kicking sand at each other.
“Are you ready to go back and tell your consumers you’re pulling out of PJM? … Because that’s what you’re doing. You’re destroying the … integrity of the market if you all do the things you want to do,” she said.
“We will kick sand in your face. I’m just being honest. We’re paying for it,” Rosales responded.
He said he felt the capacity revamp discussions at PJM were a “punitive” response to Illinois’ ZEC rule and designed so that Illinois is “going to take the hit” as an example for other states to deter them from “doing the same thing.”
He noted the state is “in a better position to negotiate in good faith” following the decision in September of the 7th U.S. Circuit Court of Appeals to uphold Illinois’ law. (See 7th Circuit Upholds Ill. ZEC Program.)
The other regulators on the panel attempted to strike a conciliatory tone.
“I’m not trying to destroy anything. I’m trying to build a better foundation,” Fiordaliso said.
“I don’t think it’s mutually exclusive,” said Richard, who became OPSI’s president for the next year. “We’re willing to pay for the [renewable energy credits]. We’re willing to pay additionally. There’s a strong interest [among Maryland residents] in helping the environment.”
Ohio Public Utilities Commissioner Beth Trombold touted the state’s utilization of its natural gas supplies and made it clear that the state was no longer seeking to protect its coal-fired generation. FERC ruled in April 2016 that it would scrutinize power purchase agreements between affiliates like ones requested in Ohio by American Electric Power and FirstEnergy under the Edgar affiliate abuse test. The companies subsequently scaled back their PPA requests to the commission.
“We’ve faced that ourselves, and we’ve moved in a different direction. We’re a big fan of competitive markets and we want to see that preserved,” Trombold said, noting her commission’s recent PowerForward initiative to give utilities “a sense of the framework we’re interested in seeing” them follow in making filings.
Pennsylvania Public Utility Commission Vice Chair Andrew Place noted that the Keystone State ranks 23rd in renewable generation.
“That speaks to my realization that we are not where we should be,” he said. Place also criticized PJM’s rules on how demand response is handled.
“It is vital that these programs be incorporated into PJM’s forecasts,” he said. “More recently, PJM’s accommodation of cost-effective, summer-DR, supply-side markets has come up, in my consideration, short of the mark.”
His comments were in reference to PJM stakeholders’ approval at the October Markets and Reliability Committee meeting to “better value” summer-only DR by allowing the resources’ value to impact the load forecast as an alternative to participating as a supply-side resource in capacity auctions. To avoid double counting, resources that take the peak-shaving alternative wouldn’t be eligible to participate as either a DR resource or price-responsive demand in the same year. (See “Summer-only Demand Response,” PJM MRC/MC Briefs: Oct. 25, 2018.)
Environmental or Economic Interests?
Direct Energy’s Philips asked regulators whether their states’ policies were driven solely by environmental concerns or were also influenced by economic interests.
“Would a carbon price make you happy, or would you still want that [renewable] development in your state?” she asked.
Fiordaliso noted New Jersey is re-entering the Regional Greenhouse Gas Initiative (RGGI) and that “carbon pricing is certainly a part of the portfolio.” Maryland is also a RGGI member, Richard said, “and yes, Maryland would like to develop as many of those resources in state as possible.”
“Keeping these policies with policymakers and with the states; I think that’s the appropriate place,” he added. “I get a little nervous with a discussion that somehow PJM might adopt and create its own carbon-pricing regime.”
Trombold deflected the question, saying Ohio’s legislature sets its energy policies. Michigan Public Service Commissioner Rachael Eubanks noted that carbon is not mentioned at all in her state’s legislation on advancing “renewable energy technologies and the corresponding benefits that come out of that, including economic benefits.”
“I would think that it would have to be a national discussion,” Rosales said. It would be “unfair” to have a carbon price implemented inconsistently across the RTOs, he said.
“The overarching goal is the environment,” said Place, who said earlier it’s his commission’s “social obligation” to either join RGGI or “see that [carbon pricing] comes about.” However, he also noted a Pennsylvania law passed in 2017 that supported in-state solar production.
“I’m not always a fan of being parochial, but at the same time, Pennsylvania was leaving a lot of tax benefit [and] federal financial support on the table, and other states were gobbling that pie. Probably sound policy, but one that in some ways does strike me as discordant,” he said.
In a subsequent panel, PJM stakeholders hashed out concerns about the current state of the capacity market revamp. The Sierra Club’s Casey Roberts said the RTO’s proposal is among those that “on their face” appear to accommodate state preferences but actually do not.
“It increases the costs to states to pursue their policies by making them pay twice,” she said, calling payments made to units whose bids are pushed out of clearing by state-supported resources “the consolation prize” and “icing on the already fattening cake that consumers probably don’t want to consume.”
Craig Glazer, PJM’s vice president of federal government policy, expressed concern over the impact of state policies on an interconnected grid.
“What if this had been a subsidy for coal from West Virginia? Would Exelon and Sierra Club be arguing states’ rights?” he asked. “If you start having one state’s policy choice … affecting every other state, your legislature may not have agreed to that policy, but you are in fact subsidizing that policy. … It’s really at the end of the day an interstate commerce challenge.”
Andrew Novotny, Calpine’s executive vice president of commercial operations, said PJM’s proposal is intended to ensure that states pay in total what they already pay today.
“That’s why we support it. States won’t be paying twice under that. They’ll just be basically paying what they are today with the sliver of side payments [for subsidies]. And if it’s not working out like that in the math, I’m sure the generator community is more than open to some sort of compromise to make sure it does work like that.”
Other Hot Topics
The meeting also covered several other hot topics, including how the evolving definition of “grid resilience” might impact wholesale markets, whether PJM’s energy market needs to be revamped and the state of the RTO’s governance.
Panelists debated how people will respond in emergencies to either share resources or horde them. Daniel Rogier, AEP’s vice president of transmission asset strategy and policy, explained his company’s “no regrets” focus for making system upgrades that have little or no downside, such as replacing wooden poles with steel ones.
Virginia State Corporation Commissioner Mark Christie noted the difficulty with making state desires known at FERC, which has switched chairs four times in less than two years.
“You express it to the chair, and the next week there’s another chair,” he said.
On energy market changes, PJM’s Stu Bresler assured attendees the RTO is “not trying to go energy-only” and therefore doesn’t need spot prices “as high as ERCOT does.” His fellow panelists urged that any changes need to come with additional transparency and granularity that allow the market mechanisms to work without administrative involvement.
Panelists on PJM governance agreed that any changes on committee structure or sector membership and vote weighting will be difficult to implement.
But Gabel Associates’ Mike Borgatti, who chairs PJM’s Members Committee, acknowledged states’ concerns about their ability to get involved.
“It’s unequivocal that what we’re doing now is not capturing enough of your input,” he said. “Figuring out how to balance that dichotomy is a two-way street.”
If you’re as old as me you may remember the movie “Body Heat” from 1981. That last scene with Kathleen Turner on an exotic island beach somewhere.[1] Yeah, you know what I’m talking about.[2]
That brings us to the GreenHat Energy debacle, with the stakeholder tab running around $185 million.[3]
Folks seem to think the GreenHat principals lost everything as their PJM financial transmission rights portfolio deteriorated in value. Bloomberg’s headline: “Ex-JPMorgan Traders Lost Millions on Bad Bets in Power Market.”[4]
I don’t think so. I suspect the GreenHat principals, Andrew Kittell, John Bartholomew and Kevin Ziegenhorn, are sipping blender drinks on island beaches just like Kathleen Turner.[5]
Kathleen Turner in the movie “Body Heat”
The Stage
But first let’s set the stage. Two of the GreenHat principals, Kittell and Bartholomew,[6] are fresh off the JPMorgan market manipulation in California from 2010 to 2012 for which JPMorgan “agrees to pay a civil penalty of $285,000,000 [and] agrees to disgorge alleged unjust profits of $125,000,000.”[7] Kittell and Bartholomew themselves paid nothing.
As recounted in a detailed RTO Insider story, they set up shop in 2014 as GreenHat Energy.[8]
“Green hat” in Chinese basically means someone is getting screwed. So at least they had a sense of humor.
Over several years, they accumulate the largest FTR portfolio in PJM history — 890 million MWh — backed by only $600,000 in collateral.
It isn’t clear that PJM connected the dots of Kittell and Bartholomew to the JPMorgan market manipulation, though the connection was hiding in plain sight in FERC’s eLibrary via a word search on “Andrew Kittell” or “John Bartholomew.”
How the Scheme Works
The scheme here relied on the minimal collateral requirement to hold hundreds of millions of dollars in FTR positions. All that has to happen for GreenHat to make money is for positions to change in value over time — as of course they will — and for GreenHat to sell “in the money” positions to third parties. GreenHat would prefer that the overall value of its portfolio increase over time, but that isn’t necessary for GreenHat to make money because GreenHat can sell positions with value, and default on the rest. Indeed, GreenHat would want to buy every possible FTR with zero incremental collateral requirement, regardless of whether it expected those FTRs to make money.
Let me give you an example that is so simple even I can understand it. Let’s say PurpleHat Energy joins PJM and puts up $600,000 credit. PurpleHat buys long-term FTRs with no additional credit requirement: let’s say FTR 1 from source A to sink B for $10, and say FTR 2 from source C to sink D for $6.
As time goes on, FTR 1 decreases in value from $10 to $7, and FTR 2 increases in value from $6 to $8. PurpleHat bundles up FTR 2 and thousands of other FTRs that have increased in value (i.e., “in the money”) and goes looking for a buyer of these “winners.” Now the buyer looks at FTR 2, for example, and is thinking that if the current $8 value is maintained to settlement, PJM will pay me $8. Of course the buyer has to discount that $8 for the time value of money, risk of value change (could be up, down), etc. So the buyer agrees to pay PurpleHat, say, $7. Notice that PurpleHat has made $1 on FTR 2 ($7 revenue minus $6 cost). Multiply that by thousands of other FTRs and their megawatt-hour quantities and you get to real money real fast.
Now remember PurpleHat is selling winners for cash to third parties and will default on the losers. So PurpleHat can make wads of money even if its overall portfolio of winners and losers goes down in value. Got it?
The Collateral That Wasn’t
Beyond this big picture, here’s a remarkable part of the story: As the GreenHat portfolio deteriorated in value, and some FTR participants raised red flags with PJM,[9] PJM asked GreenHat for more collateral.
GreenHat purported to provide that, in June 2017, in the form of pledging $62 million in future revenue from FTR sales agreements that GreenHat had with a third party, which we now know is Shell Energy North America[10] (“Pledge Agreement”). Here is how PJM described it: “Mr. Kittell worked with PJM to establish a dedicated depository account and represented that GreenHat would request the third party to deposit the revenues from the bilateral contracts into a bank account that PJM had access to and from which PJM would execute automated clearing house withdrawals to cover net losses that accumulated in GreenHat’s PJM account.”[11]
Now, one might think, wouldn’t PJM verify with Shell that Shell hadn’t already given GreenHat some or all of that $62 million (assuming that $62 million is a real number)? Well, PJM did ask GreenHat for permission to check with Shell about that $62 million, and GreenHat said … no.[12]
Now, one might think, that’s that: PJM would tell GreenHat to come up with something better than a Nigerian prince story for $62 million. Instead, PJM went ahead with the Pledge Agreement,[13] saying it had no choice,[14] and GreenHat went on to more than double the size of its FTR position.[15]
And, as fate would have it, GreenHat had already pocketed whatever was owed by Shell (not $62 million, but perhaps $7 million — more on that next).[16] Uh oh.
The $62 Million That Wasn’t
There’s one more part of the story to tell here. You’ve probably assumed, like I did, that there had to be something to the $62 million claim that GreenHat made to PJM. But maybe that ain’t so. Maybe there never was any $62 million — not at the time of the FTR sale to Shell, or ever.
Analysis of the GreenHat positions suggests they were purchased at a cost of approximately $19 million when GreenHat acquired them (with minimal collateral) and valued in the range of $25 million when GreenHat sold them to Shell. It seems what GreenHat entered into the PJM eFTR system was just made up.[17]
Per Queen in “Bohemian Rhapsody”: “Is this just fantasy?” And here the answer seems “yes.”
What Now?
What’s to be done now? FERC Enforcement should be all over this if it isn’t already. The penalties for market manipulation can be substantial as the JPMorgan order shows.[18] And PJM should vigorously pursue civil action, such as the one initiated in Texas.
Lesson for the Future
Lesson for the future: All RTOs should carefully review all their credit requirements for everything — with experts in credit — just in case Kittell and Bartholomew, or others like them, are coming their way.
P.S.: The GreenHat experience is not an indictment of energy markets in general, or FTRs in particular. It is a cautionary tale of faulty credit policy and oversight.
As early as April 2016, at least one FTR market participant was warning PJM about a 100 million MWh FTR position with minimal collateral, what DC Energy called the “Illustrative Portfolio” (yes, GreenHat’s). https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=1493734. ↑
“PJM Interconnection, L.L.C. … Verified Rule 202 Petition,” District Court of Harris County, Texas, Cause No. 201869829-7, filed Oct. 1, 2018. ↑
“PJM asked Mr. Kittell for permission to contact the counterparty to the bilateral trades regarding the contractual arrangement with GreenHat, and Mr. Kittell denied PJM’s request and specifically asked PJM not to contact the counterparty.” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (page 4). ↑
The email trail we have in the FERC filings has PJM asking for more support from GreenHat and ultimately sending an email on April 19, 2017, requesting a log of every payment GreenHat had received from Shell. But from there the paper trail goes cold: PJM doesn’t provide any response from GreenHat. https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (Appendix B, second page).Nor does it appear PJM questioned why Shell would pay GreenHat $62 million for positions actually worth a fraction of that amount (as discussed later). ↑
“To avoid a claim of interference with GreenHat’s contractual counterparty and to allow GreenHat the ability to sell down its portfolio, PJM had no choice but to comply with this request [that PJM not contact Shell].” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (page 4).This is puzzling. PJM had at least colorable Tariff authority to require meaningful collateral or other protection (if not as a condition to maintain existing positions, surely as a condition to expand those positions): “PJMSettlement may select participants for review on a random basis and/or based on identified risk factors such as, but not limited to, the PJM markets in which the participant is transacting, the magnitude of the participant’s transactions in the PJM markets or the volume of the participant’s open positions in the PJM markets. Those participants notified by PJMSettlement that they have been selected for review shall, upon 14 calendar days’ notice, provide a copy of their current governing risk control policies, procedures and controls applicable to their PJM market activities and shall also provide such further information or documentation pertaining to the participants’ activities in the PJM markets as PJMSettlement may reasonably request. … Each selected participant’s continued eligibility to participate in the PJM markets is conditioned upon PJMSettlement notifying the participant of successful completion of PJMSettlement’s verification of the participant’s risk management policies, practices and procedures, as discussed herein.” PJM Tariff Attachment Q, Section I.B (emphasis added).PJM seemed to rely on Attachment Q, Section II.D.2 (PJM has the right to “require additional collateral as may be deemed reasonably necessary to support current market activity.”), but this section appears applicable only to an “unsecured credit allowance,” which is not what GreenHat apparently had. ↑
GreenHat had a portfolio position of about 375 million MWh in mid-June 2017. The Pledge Agreement was entered into late June 2017. GreenHat went on to increase its position to 890 million MWh. https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=14937343 (Figure 1, page 9).It is not clear how this more than doubling of the GreenHat position comports with PJM’s statement, quoted in the preceding footnote, that PJM was motivated to go forward with the Pledge Agreement to “allow GreenHat the ability to sell down its portfolio” (emphasis added). ↑
“PJM specifically asked Mr. Kittell if the counterparty had paid GreenHat any of the money due to GreenHat under their bilateral trade agreements. GreenHat never informed PJM that the counterparty had paid any money on that contract. Instead, Mr. Kittell forwarded PJM documents indicating money that it claimed the counterparty owed to GreenHat under their contract that would flow to PJM under the Pledge Agreement. It wasn’t until June 2018 that PJM learned from Mr. Kittell that GreenHat sent two invoices with a “Final Purchase Price” due from the counterparty to GreenHat under two separate FTR bilateral agreements between the two parties — well before GreenHat commenced discussions with PJM regarding the Pledge Agreement, and that the counterparty paid GreenHat all of the money the counterparty believes was due to GreenHat under those bilateral agreements.” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (pages 4-5, emphasis added). ↑
How is such a thing possible? GreenHat could have used the PJM eFTR system so as to make it appear as if Shell owed GreenHat an amount that far exceeded the actual value of the positions. There is a field in the eFTR system, which PJM does not use in settlement, that purports to offer market participants the ability to enter bilateral contract transaction prices. The GreenHat/Shell transacted FTRs had entered prices in this field that did in fact add up to at least $62 million, which GreenHat apparently offered to PJM as proof that it had receivables to pledge to PJM. But use of this field is not customary for bilateral transactions in the eFTR system (most market participants leave this field blank or enter 0). In other words, GreenHat could have entered 62 cents or $620 trillion with no economic significance (which may explain why Shell would not have cared what GreenHat entered). The actual transaction prices between GreenHat and Shell would be governed by the contracts entered into by the parties, not by what was entered into eFTR. The GreenHat invoices in 2016-2017 for “Final Purchase Prices” of $5.2 million and $1.5 million appear to reflect the economic substance of the FTR sales. ↑
PJM is trying to keep $550,000 in collateral of a GreenHat affiliate in PJM Interconnection, L.L.C., Docket No. ER18-1972-000. $550,000 is peanuts. PJM’s efforts should be on civil action and on FERC Enforcement. ↑
BOSTON — Energy made up $130 billion of the $750 billion that changed hands last year between Canada and the U.S., the largest bilateral trading relationship in the world. Industry participants on both sides of the border question why the Trump administration would risk that relationship with protectionist tariffs.
“We believe in building bridges, not walls,” said Canadian Electricity Association head Sergio Marchi, speaking at the New England-Canada Business Council’s (NECBC) 26th annual energy conference Thursday, where attendees also discussed the changing resource mix, investment prospects and siting challenges.
Canadians were disappointed that the energy chapter in the original North American Free Trade Agreement was not preserved in the proposed United States-Mexico-Canada Agreement, and surprised the updated energy provisions were bilateral, not trilateral, Marchi said.
“The provisions of energy in the new NAFTA are scattered across a multiplicity of different sections, and so we’re puzzled as to why you would not want to consolidate all of these provisions in one coherent place,” he said.
David Alward, consul general of Canada to New England and a former premier of New Brunswick, said Canada did not believe the premise of the original NAFTA was unfavorable to the U.S. and noted that negotiations over the new agreement led to a pessimistic cloud of uncertainty.
“But we achieved a good agreement and brought a certain level of predictability to the relationship,” Alward said.
The Analysis Group’s Paul Hibbard, former chairman of the Massachusetts Department of Public Utilities, said, “It’s difficult to overstate the importance of Canada in meeting energy needs and renewables. … Looking forward, the potential growth in cross-border energy trade is staggering.”
Renewable, with Gas and a Little Oil
Massachusetts Energy and Environmental Affairs Secretary Matthew Beaton said his state is “continuing to make sure that we take a combo platter approach” to include all technologies in achieving a renewable energy future.
“The existing markets are becoming more aligned on natural gas, which will continue to play a very important role in the market price of energy here in New England,” Beaton said.
Carol Grant, commissioner of the Rhode Island Office of Energy Resources, said she is optimistic that people want to contribute to a cleaner world, “but I don’t think New England or anyone is saying at any price.”
ISO-NE Vice President of Market Operations Robert Ethier said the two most important issues for the RTO are winter fuel security and “addressing the states’ desire to bring in more carbon-free resources.”
Integrating those new resources is not now a problem for the RTO and likely won’t be for the next decade, Ethier said. It’s a two-fold economic challenge involving the energy and capacity markets.
“One is, bring in these zero-marginal-cost resources and insert them into our real-time supply stack, and it lowers energy prices for everyone,” Ethier said.
Second, “when the states contract for these resources, they don’t just affect the energy market, they also affect our capacity market,” Ethier said. So the RTO developed Competitive Auctions with Sponsored Policy Resources “to insulate the capacity market outcomes from having these resources, which are by most estimates uneconomic to enter into our capacity market, but enter anyway because they have long-term state contracts.”
Having new state-sponsored resources buy out old resources in the market will help manage and ration the entry of these resources into the market and prevent price suppression, he said.
“If we want to have long-term competitive markets in New England, and we want to have the prospect of merchant investment five, 10 or 15 years from now … they need to have confidence that there are going to be market opportunities for them into the future that make it worth their while to invest their money,” Ethier said.
Dan Dolan, president of the New England Power Generators Association, said 60% of the region’s electricity will soon come from state-sponsored resources not dependent on the wholesale market, “but the market is not structured to protect the 40% of generators who will remain dependent on the market.”
On fuel security, Ethier said the market needs to incent gas-burning generators to fully utilize LNG facilities and also ensure the region continues to maintain its existing fleet of oil-burning resources, at least in the near term.
“Those resources have remarkably low capacity factors for resources that were built as baseload … in the 1 to 2% range, so they hardly ever run,” Ethier said. “The thing is, when they do run, we really need them.”
Dena Wiggins, president of the Natural Gas Supply Association, said that ample and diverse natural gas supplies balance the current weak U.S. gas storage picture of about 3 Tcf, so that a disruption to production in one place no longer spikes prices.
“It’s a little bit different here in New England, but those are spot prices,” Wiggins said in reference to potential spikes. “Our consultant tells us that during the winter peaks, only about 1% of the gas traded at those high prices.”
Attorney John Gulliver of Pierce Atwood compared 2000 with 2017, with New England nuclear remaining steady over that period, producing 31% of power, while oil moved from 22% to 0.7%, coal declined from 18% to 2% and natural gas grew from 15% to 48% — “with the balance made up by healthy growth in hydro and renewables.”
Attorney Seth Jaffe of Foley Hoag said policymakers may be willing to pay the price for pursuing their political goals of a carbon-free economy, but both gas pipelines and hydropower transmission from Canada have had problems getting sited, even when hydro nominally supplants the need to burn natural gas. “You have to wonder, how are we going to get these projects done?”
Avangrid CEO James P. Torgerson said the difficulty in siting onshore wind in New York and New England is just one reason why offshore is more appealing.
“You still have to deal with the intermittency, but the good thing about offshore wind [is] the capacity factors we’re seeing for that should be in the 50% range,” compared with 33% for existing onshore wind and 40% for new onshore projects, Torgerson said.
Speaking about Avangrid’s New England Clean Energy Connect (NECEC), a project of subsidiary Central Maine Power to bring 1,200 MW of Canadian hydropower to Massachusetts, Torgerson said, “We expect to get all the approvals in 2019,” despite Maine regulators in October having suspended hearings on the project. (See Maine PUC Move Poses Hurdle for NECEC.)
The Maine Public Utilities Commission on Nov. 2 scheduled several technical conferences in the case (Docket No. 2017-00232) ahead of resuming hearings January.
“Some communities are not as supportive as they initially were … but things evolve,” Torgerson said.
NECEC faces some of the same issues as Northern Pass did in New Hampshire, so when Maine environmentalists protested plans to string high-voltage lines across the Kennebec Gorge, for example, Avangrid agreed to tunnel under the river, he said.
The project to deliver Quebec’s hydropower will reduce electricity prices in Maine by about $40 million a year, provide communities $18 million a year in tax benefits and add more than $500 million to Maine’s GDP, Torgerson said.
Algonquin Power & Utilities CEO Ian Robertson noted how the intermittency of renewables is declining and the potential for storage to assist the trend.
“We’re all trying to understand how battery storage fits into that equation. Part of what we’re doing is working with regulators to put 500 of the Tesla Powerwalls in,” Robertson said. “But I’m not sure anybody in a utility really understands how storage can be most effectively introduced into an electric grid to create value for customers.”
FERC on Thursday approved the designated entity agreement (DEA) for Transource Energy’s Independence Energy Connection, PJM’s largest-ever congestion-reducing transmission project, with one condition: that Transource stick to its original commitment for how long it can use an increased amount of equity in its rates (ER17-349).
The commission ordered that PJM submit a compliance filing within 30 days on the project that aligns the return on equity allowed for Transource in the DEA with the amount agreed to in a settlement agreement in the case. The current DEA limits Transource’s formula rates to 50% equity “once permanent financing is in place” and as long as capital market conditions “remain normal.”
Transource Energy’s Independence Energy Connection will be PJM’s largest-ever congestion-reducing transmission project. | Transource
The settlement requires Transource to reduce its equity mix from 60% to 50% by June 1, 2020. The reduction would be triggered earlier if the project goes into service or permanent financing is obtained.
The compliance filing is the third in the project’s approval path. The DEA was conditionally accepted on Jan. 12, 2017, and PJM submitted its compliance filing on March 2. That filing is now accepted with the required changes.
Transource’s Independence Energy Connection project consists of two separate lines that run north-south across the Pennsylvania-Maryland border. | Transource
The DEA approval was also conditional on the outcome of the project’s formula rate proceeding. The formula rate was conditionally approved on Jan. 31, 2017, and PJM submitted its compliance filing on March 2, 2017.
Transource requested rehearing of the formula rate but joined PJM in submitting a settlement offer on Oct. 2, 2017. FERC conditionally accepted the settlement on Jan. 18, 2018. PJM submitted its compliance filing on Feb. 16, which the commission approved on Sept. 21. The rehearing request was denied on July 6.
LITTLE ROCK, Ark. — SPP directors, members, staff and other stakeholders took time out last week from the normal board week activities to honor two directors who predate the organization’s RTO status.
The RTO treated Jim Eckelberger, who stepped down in April after 14 years as the Board of Directors’ chairman, and Harry Skilton, vice chair for 14 years, to a catered farm-to-table dinner the night before the Oct. 30 board meeting.
Staff shared a video of family, friends and stakeholders sharing their favorite anecdotes about the two men. Both were presented with plaques topped by — what else? — replicas of transmission towers.
Eckelberger and Skilton are the last remaining members of SPP’s original board, which was created in 2000. FERC didn’t recognize SPP as an RTO until 2004.
Since then, SPP has expanded its footprint with the addition of Nebraska utilities and the Integrated System, and by offering reliability coordination (RC) services to Western Interconnection entities. The RTO has also become one of the lowest-cost grid operators by creating day-ahead and financial transmission rights markets and investing billions in transmission infrastructure.
Eckelberger, who takes great pride in SPP’s cost of service, pointed to an LMP contour map of the footprint, dominated by the cool blue denoting prices in the $20 to 30/MWh range, as an example of the RTO’s effectiveness.
“SPP greatly appreciates the 18 years Jim and Harry dedicated to SPP,” CEO Nick Brown said. “They have made extraordinary contributions to our company and were instrumental in transforming SPP into the regional transmission organization we are today.”
“Both should be proud of the legacy they have created here for SPP,” said Larry Altenbaumer, who replaced Eckelberger as chairman in April.
“I’m very fortunate to have 18 years at SPP be the capstone of my career,” Skilton said.
Both men are transitioning into emeritus status, effective Jan. 1.
“We’re fortunate they’ll be staying on in this emeritus role, because they have a wealth of experience,” said the Members Committee’s Tom Kent, COO for Nebraska Public Power District.
The Members Committee replaced Eckelberger and Skilton on the board by electing newcomers Susan Certoma and Darcy Ortiz during its annual meeting. The appointments are effective Jan. 1.
Bruce Scherr, who joined the board in January 2016, was also re-elected.
Certoma is president of Enterprise Engineering, which provides software and consulting to financial firms. She previously held technology-related positions at Wachovia Bank, Goldman Sachs, Merrill Lynch and Lehman Brothers during 30 years in the finance field. Certoma holds a bachelor’s degree in management and economics and an MBA from St. John’s University.
Ortiz is Intel’s vice president and general manager of corporate services. She previously led the global team responsible for Intel’s IT operations and services and served in several CIO positions. She has a bachelor’s degree in business administration from the University of New Mexico and an MBA from the University of California, Berkeley.
Brown said the new members’ technology backgrounds will be invaluable to SPP.
“Much of our continued success now hinges on effective management of data and technology infrastructure and our approach to cybersecurity,” he said in a statement.
The committee also elected seven representatives to three-year terms on the committee, with “the narrowest of unanimous margins,” Altenbaumer joked.
The representatives are Kent for State Power Agencies; Blake Mertens (Empire District) and Kevin Noblet (Evergy) for Investor-Owned Utilities; Jason Atwood (Northeast Texas Electric Cooperative) and Mike Wise (Golden Spread Electric Cooperative) for Cooperatives; Kevin Smith (Tenaska Power Services) for Independent Power Producers/Marketers; and Jody Sundsted (Western Area Power Administration – Upper Great Plains) for Federal Power Marketing Agencies.
Mertens is the only newcomer; everyone else was re-elected.
Altenbaumer Tweaks New Governance Schedule
Altenbaumer continues to tinker with the board’s meeting schedule as he enters his first full year as chairman, saying he wants to “elevate the work of the board and members to focus on those things that are strategically important.” (See SPP Strategic Planning Committee Briefs: Oct. 18, 2018.)
Following feedback from members and the Regional State Committee, Altenbaumer has scheduled a joint session between the board and RSC on the day the state regulators normally meet (the day before the board’s quarterly meeting). That time will be used for joint informational and background presentations to the directors, members and RSC.
“It’s an opportunity to become more efficient,” Altenbaumer said. “Many presentations given to the RSC turn out to be warmups for the same presentations to the board the next day.”
Altenbaumer has left slots in the RSC and board meetings for executive sessions, but he promised “anything that relates to decisions will be addressed during the typical [open] board meeting.”
Addressing stakeholder concerns that the changes could reduce transparency, Altenbaumer said keeping discussions from public view is “by far the last thing intended from this.”
“If any of you ever feel these things are trending in the wrong direction, as far as engagement and transparency, bring it to my attention,” he said.
Given a chance to respond publicly to Altenbaumer’s comments, no one did.
As proof of how governance will be handled in the future, Altenbaumer noted the board’s only approval item was the consent agenda.
“That speaks to the collaborative process,” he said. “This is a desire to try and improve the overall governance.”
Two days later, SPP moved its December board meeting, which has traditionally been used to approve the budget, from Little Rock to the more accessible Dallas/Fort Worth International Airport. The meeting has also been shortened by two hours; next year, it will likely become a conference call.
Keith Collins, executive director of SPP’s Market Monitoring Unit, clarified comments he made during recent governance meetings that raised stakeholder concerns about the MMU’s involvement in generator retirement decisions. (See Stakeholders Push Back Against SPP Retirement Changes.)
At October’s Markets and Operations Policy Committee and Strategic Planning Committee meetings, some stakeholders pushed back against the possibility of the MMU intervening in regulatory proceedings. Collins said the MMU would only raise concerns in instances of physical withholding or other market power issues.
“The SPP Tariff is very clear,” he said. “Physical withholding and market power are under the MMU’s purview.”
“The MMU has an obligation to investigate and review those issues,” said Director Joshua W. Martin III, who chairs the Oversight Committee. The MMU reports to Martin’s committee.
Collins said the MMU has always used available data when it reviews generator retirement requests, and that the MOPC discussion was an attempt to collect data from market participants to improve its analysis.
He noted the Tariff is unclear as what the MMU should do if it identifies physical withholding or market power.
“Our responsibility rests with FERC,” Collins said. “To the extent we identify market power of physical withholding, we would have to raise that issue with FERC, unless the protocols or the Tariff [are] clarified as to what steps should be taken.”
“The Oversight Committee has reviewed this issue, and we’re comfortable with where it is right now,” Martin said.
SPP staff have said they will provide the MOPC and the board draft Tariff revisions for generator retirement procedures in January.
SPP-MISO Operating Procedures not yet Documented
Brown said during his president’s report that it is “untenable” that SPP and MISO “end up in situations where our operators are confused,” as happened in January’s “Big Chill” event.
The two RTOs have increased their coordination across their seam since the Jan. 17 event, when severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. MISO made emergency energy purchases from Southern Co. before operations returned to normal.
Brown recalled that shortly after the event, he had told the board that one of his top priorities for the year was to reach an agreement with MISO on “exact operating procedures.”
“I was hoping to report we have signed documents for this meeting, but we don’t,” Brown said.
He was able to share with directors and members a pamphlet that says SPP members receive $1.7 billion in annual benefits, an 11-1 benefit-cost ratio. The document notes the Integrated Marketplace has produced more than $2 billion in savings since going online in 2014 and references a study that indicates every dollar SPP spends on transmission investment returns $3.50 in benefits.
“I would have no problem standing before any regulatory committee and defending these numbers,” Brown said.
Western RC Services to Net $3.4M
Operations Vice President Bruce Rew said SPP’s RC contracts with Western Interconnection entities will result in $3.4 million in net income through 2024. (See CAISO RC Wins Most of the West.)
SPP expects to earn $28.4 million in revenue over the life of the five-year contracts, which are effective in January 2020. However, adding up to 20 staffers in Little Rock to handle the new responsibilities will eat into much of that revenue.
Under the contract’s terms, the Western entities will pay an initial 5.5 cents/MWh. Annual extensions will begin in 2025, and mutual withdrawal provisions are included.
Smaller entities may yet participate in SPP’s RC services, Rew said. Later entities would be evaluated on a case-by-case basis.
Consent Agenda’s Approval Adds, Deletes Members
The board’s consent agenda included changes to the membership agreement that would clear the way for Mor-Gran-Sou Electric Cooperative to become the newest SPP member.
The Corporate Governance Committee approved membership agreement amendments for the North Dakota co-op similar to changes that facilitated the membership of Basin Electric Power Cooperative and its members as part of the Integrated System’s integration. Mor-Gran-Sou, which is embedded within the Integrated System, intends to join SPP as a transmission owner.
The CGC also recommended Cielo Wind Power’s membership be terminated immediately for failing to keep up with its membership dues and repayment agreements. SPP said Cielo in January stopped responding to the RTO’s outreach efforts and ignored a March demand letter.
The Austin, Texas-based company’s delinquency dates back to 2016. It owes $18,000 and interest.
The consent agenda also included staff’s recommendation to revise the SPP-MISO Coordinated System Plan. (See “MOPC Approves Changes to Joint Model with MISO,” SPP MOPC Briefs: Oct. 16-17, 2018). Also on the agenda were the Finance Committee’s 2019 operating plan, updates to the 2019 Integrated Transmission Planning assessment’s scope, the Market Working Group’s annual violation relaxation limits analysis, and nine revision requests:
MWG RR266: Substitutes “interest” for “ownership” in language modeling joint-owned units as single resources, recognizing that “ownership” doesn’t capture stakeholder intent that power purchase agreements and other non-ownership interests be included.
MWG RR288: Allows non-dispatchable variable energy resources converting to dispatchable status to use control statuses not originally available to them. SPP’s control statuses are: offline (the resource is not operating); non-regulating (online and capable of following a dispatch instruction or contingency reserve deployment but not eligible to clear regulation service); regulating (online and capable of following dispatch or contingency reserve instruction, and regulation deployment); and manual (online but not able to follow dispatch; e.g., start-up, shutdown, testing, etc.).
MWG RR316: Updates the multi-configuration (combined cycle) resource market design by adding two additional commitment parameters: group minimum down time and plant minimum down time. Also removes sync-to-min and min-to-off times from the submitted minimum down time or group minimum down time when the resource transitions between operational configurations. The current design only allows individual registered configurations to submit a minimum down time.
MWG RR323: Defines batteries as electric storage resources (ESRs), capable of being dispatched and participating in price formation. Excluded as ESRs are those resources that are either contractually barred or physically incapable of injecting energy back onto the grid because of their design or configuration. Also creates a new registration type, “market storage resource,” to be used only by ESRs.
MWG RR332: Corrects protocol calculations from designs implemented in RR200 (design change for bilateral settlement schedules (BSS) and over-collected losses (OCL) distribution) and RR235 (correction to RR200) necessary to accurately distribute OCLs and ensure BSS are receiving their correct OCL. The change ensures corrected resettlements back to the original May 1, 2018, release date.
ORWG RR318: Changes the contingency reserve requirement calculation to allow the use of the “most severe single contingency” as the basis of the minimum contingency reserve requirement on an hourly basis. SPP said the revision allows it to more accurately and reliably set the reserve requirement.
RTWG RR305: Updates Tariff language following modifications to the aggregate facilities study process by removing the requirement to file a service agreement before modeling new transmission service in the ITP models. Also removes the requirement that SPP issue notifications to construct (NTC) and notifications to construct with conditions (NTC-C) before filing a service agreement. Adds a financial commitment date of four years to the issuance of an NTC or NTC-C.
RTWG RR322: Changes the Tariff and other documents to reflect that the RTO is no longer using U.S. Energy Information Administration data in monthly load forecasts. SPP said the data in the EIA report are not granular enough because they are at the balancing authority level, rather than the local balancing authority level required. In January, the RTO began using forecast data that are available through the NERC system data exchange (SDX) and historical data where forecasts are not available.
RTWG RR325: Revises SPP’s pro forma language for large generator interconnection procedures and large generator interconnection agreements to comply with FERC Order 845.
BALTIMORE — The drafters of the 1935 Federal Power Act could not have imagined modern distributed energy resources, let alone a small network of them that can operate independently of the grid.
FERC Commissioner Cheryl LaFleur addresses the Microgrid 2.0 conference in Baltimore. | International District Energy Association
“The phenomenon that I think FERC confronts and other agencies in Washington confront is that there’s been a lot more technological change than there’s been legislative change for a whole bunch of reasons that are above my pay grade to diagnose,” Commissioner Cheryl LaFleur told attendees of Microgrid 2.0 at the Hyatt Regency Baltimore Inner Harbor last week.
FERC Commissioner Cheryl LaFleur | International District Energy Association
“We’re trying to solve 21st century problems using … a 1930s law.”
How microgrids should be regulated was a central topic at the third annual conference held by the International District Energy Association (IDEA), which advocates for distributed generation, district heating and cooling, and combined heat and power.
Christopher Berendt, Drinker Biddle & Reath | International District Energy Association
“The reason we’re here talking about this today, probably more than anything else, is that consumer demand is driving us, and that we’re seeing more and more people say, ‘We want to see mixed-use, multi-customer microgrids because we want the variety of benefits that can come out of them,’” Christopher Berendt, counsel to IDEA’s Microgrid Resources Coalition, said during a panel on market design and policies.
Regulatory risk, he said, “acts kind of like repellant to private capital.”
“There is more capital waiting to flow into microgrid investment right now [that] you would not believe,” said Berendt, a partner with Drinker Biddle & Reath. “There is more capital chasing fewer good projects, and what is really needed to unlock those loads of capital and get more good steel in the ground is not the desire to deploy it, but the regulatory frameworks that support project financing.”
Without any direction from Congress, however, regulators must work with what they have. During her luncheon keynote speech, LaFleur pointed to the complications of DER aggregation, which the commission has been working on for nearly two years. (See FERC Rule Would Boost Energy Storage, DER.)
“It seems quite clear that distributed resources can be aggregated and bid into the market and contribute great value. But since they’re, in many cases, behind the meter, what do the states figure out? Who gets the first bite of the value?” LaFleur asked. “How are we going to figure out who pays what to whom in a sensible way? I think our staff has made a lot of progress in thinking about it. I think it can be worked through, but it’s a little more complicated than some of the … issues we usually deal with because of the number of different uses, and because although it acts wholesale when we see it in the markets, it’s actually at the distribution level.”
Dan Dobbs, Anbaric Development Partners | International District Energy Association
The industry also faces challenges at the state and local levels over siting rights of way and whether microgrids are defined as public utilities. “One thing all jurisdictions in this country have in common is that they’re not set up for microgrids,” Berendt said
Dan Dobbs, vice president of distributed energy for Anbaric Development Partners, pointed to New York’s Value of Distributed Energy Resources tariff as “a start.” (See NYPSC Takes Subway into Value Stack.)
“It’s not perfect, but it’s a good attempt at getting that value,” he said. But “you really need to be able to value power that comes in and goes out equally. That’s at the retail level, and you need to be able to do that similarly at the wholesale level when you are aggregating resources.”
