WASHINGTON — FERC Chairman Kevin McIntyre, the luncheon speaker on the second day of the Energy Bar Association annual meeting last week, said he’s often asked about his priorities as head of the commission. “I love this [question] because it suggests I get to pick,” he said to laughter.
“We get to select some of the topics we work on but … I arrived in December and at that time, there was a faint ticking sound … on the 11th floor of the FERC — something awaiting prompt attention,” he continued. The ticking sound was the Dec. 11 deadline for responding to Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to provide price supports for coal and nuclear generation.
“And I thought, in the [tradition of the] Hippocratic Oath: First do no harm. So, my first official and brave act as FERC chairman on Dec. 7 was to humbly request more time,” McIntyre said. “I’m happy to say that such time was granted and that we beat our extended deadline by a couple of days. And we managed a five-to-nothing order taking action on the Notice of Proposed Rulemaking that was proffered to us by the secretary, deciding as a commission that we could not adopt it in the form it was presented to us.” The commission instead opened a new docket on resilience — a proceeding that prompted more than 100 comments last week. (See related story, Don’t Rush on Resilience, Commenters Urge.)
McIntyre also discussed the commission’s challenges in determining whether state subsidies for generators based on their fuel source is unduly discriminatory. “Isn’t that an unfair market advantage? These are valid questions, not crazy questions. And we have before us the work of trying to figure out answers to them, and every bit as difficult as that, trying to figure out how to implement sensible policy steps based on those answers. This plays out in a number of different ways, and I wish I had all the answers. … As lawyers we like challenges … and boy is this one. It’s a real toughie.”
Former FERC General Counsel Max Minzner said the “defensive regimes” that have shielded energy companies from antitrust liability — the state action doctrine, federal pre-emption and filed rate doctrine — are being eroded.
One source of the erosion is litigation, he said, referencing the Supreme Court’s 2015 ONEOKdecision, which found that federal pre-emption under the Natural Gas Act does not prevent state antitrust suits over pipelines’ price manipulation.
Minzner, now a partner with Jenner & Block, also cited technology that can overcome natural monopolies and regulatory changes such as the development of federally regulated gas and power markets. “And finally, one of the areas that I find most fascinating, is erosion from legislative change. The rise of the market manipulation authority within the Energy Policy Act of 2005 has an overlay on the filed rate doctrine.”
Minzner was the moderator of a panel on antitrust trends, where panelist R. Scott Mahoney, general counsel and chief compliance officer for Avangrid, sparked a discussion on the risks of making intemperate statements in emails, text messages and internal presentations that can be obtained in discovery.
Mahoney said he urges Avangrid employees “to think about doing that in a … more precise way so that you don’t create the one email that then gets waved around” as evidence of anticompetitive behavior.
Richard M. Lorenzo, chair of Loeb & Loeb’s antitrust practice, recalled the damage done to Microsoft’s antitrust defense in 1999 after testimony that company Vice President Paul Maritz had threatened to cut off rival Netscape’s “air supply.”
He cited a 1982 phone call from American Airlines President Bob Crandall to Braniff Airways President Howard Putnam — which Putnam recorded — in which Crandall said, “Raise your goddamn fares 20%. I’ll raise mine the next morning.”
“So, what you write in memos matters. [We’re] trying to emphasize to employees at all levels of the company — especially at the management level — to tone it down. Write factually as opposed to emotionally with lots and lots of adjectives. It’s very important because this stuff comes back to bite you when there is discovery.”
“People want to make a splash. People want to be remembered, and so therefore they’re always pushing the envelope with respect to PowerPoints and other ideas [using] colorful language,” added Michael O’Connor, chief legal executive for law and human resources for the Salt River Project. “And once you have one of these cases and you put it in that light and it’s thrown up in a federal district court or all over the papers, people remember that.
WASHINGTON — The Energy Bar Association closed its annual meeting last week with a panel discussion with five former FERC chairs whose terms collectively spanned two decades. The former chairs offered entertaining anecdotes about the past while expressing pride over the growth of competitive markets — and frustration over forces they said threaten them.
James Hoecker (1997-2001) jokingly referred to his tenure as the “Cretaceous period of FERC regulation,” a time when he said there was less state-federal conflict but also no FERC authority to impose meaningful penalties on market manipulators. He started at FERC as a staff attorney in 1979 and left for a time before returning in 1993 as a commissioner. He cited Order 637, which revised gas pipeline rules to encourage competition, and Order 2000, which set the requirements for RTOs, among the biggest accomplishments of his tenure.
“FERC had not gotten to be so visible in the media because of its work in energy infrastructure as it’s become recently,” said Hoecker, now counsel to the trade group WIRES. “I guess I’m thankful for that.”
Pat Wood III (2001-2005) expressed regrets over not returning a phone call to Southern Co. CEO H. Allen Franklin in 2002 after announcing Standard Market Design, “which was going to solve all the problems that happened in California” during the 2000-2001 Western energy crisis.
“Maybe I’m overselling my persuasive skills and it was never meant to be, but [I wish] I could have talked them out of being so intransigent against Standard Market Design,” said Wood, now chairman of Dynegy.
He also wished he had been “more willing to accept imperfections” in the RTO applications filed by Southern and other companies in the Southeast and West.
“Accepting that could have avoided what I call the carnage that’s happened [in the Southeast] with noncompetitive generation. … But I was pretty rigid on making sure they met the criteria of Order 2000 and neither of those [regions] had” sufficient independence.
Joseph T. Kelliher (2005-2009) said his pre-commission career as a congressional aide helped him in negotiations to eliminate “hostile” anti-FERC provisions from the Energy Policy Act of 2005 shortly after becoming chair. The law gave the commission the authority to issue enhanced penalties for market manipulation and mandatory reliability rules, and deputize NERC as the Electric Reliability Organization.
“At the time, I had a lot of doubts about NERC’s capacity to discharge their responsibilities under the act,” said Kelliher, now NextEra Energy’s executive vice president for federal regulatory affairs. “And I thought it was necessary for FERC to adopt a larger role until NERC expanded its capacity, almost like a big brother throws his arm around his little brother until he gets some more muscle. … I think NERC is a much more capable institution than it was in 2005.”
Jon Wellinghoff (2009-2013) said his background as Nevada’s first consumer advocate informed his chairmanship, during which he “tried to ensure that the markets were open and fair” for technologies such as renewables and demand response.
Wellinghoff expressed special pride in Order 745, which required that RTOs pay DR resources LMPs, and Order 755, which required RTOs to compensate fast-regulation resources for speed and accuracy. He also cited Order 719, requiring RTOs to treat DR offers like generation, and Order 764, which aided the integration of variable energy resources.
“I think they’re all important to ensuring that all resources can efficiently and effectively compete in these markets. And then … in Order 1000, the transmission planning order, we tried to ensure that there was some level of competition in the planning and selection of transmission.”
Wellinghoff, who has continued to advocate for distributed energy resources as CEO of consulting firm GridPolicy, added he is “very encouraged” by actions the current commission has taken to open markets to energy storage and DERs.
“You’re seeing the distributed resource technologies just explode. You’re seeing the enabling technologies underneath them — which are really the communication and control technologies — get less and less expensive … and more available to consumers. My son is truly a computer geek. … He was cataloging our house the other day: We have 52 addressable devices in the house.”
Wellinghoff said he’d like to see more done to open competition in transmission. Without competition, he said, the industry is “going to stamp down innovation. There are many innovative technologies coming into the transmission space … that are substitutes for transmission that need to have the opportunity to compete … against the incumbents.”
Norman Bay (2015-2017) talked of the obligation he felt to live up to the legacy of his predecessors. “As I listened to their comments today, I’m struck by … the nonpartisan nature of the work that we’ve been doing. The ability of Republicans and Democrats alike to come together to get things done to further the public interest,” said Bay, now head of Willkie Farr & Gallagher’s energy regulatory and enforcement group in D.C. “I would bet that if anyone were to listen to the comments of anyone on this stage and didn’t know what political party they belonged to, they would have no idea if that person was a Republican or a Democrat. And how great is that?”
‘Crony Capitalism’
Wood and Bay debated the impact of zero-emission credits — enacted in Illinois and New York and under consideration in New Jersey — to subsidize nuclear generation.
“Are they a good idea? No. They’re crony capitalism by just a new name,” Wood said. “I do think that FERC has got to take … an informational role to let these state legislatures know … what damage these kinds of things do the operation of the competitive markets that we worked for a quarter century to set up. That’s exactly what they are. The resilience thing looks like a continuation of the same crony game,” referring to calls for subsidies for coal and nuclear plants with onsite fuel. “I just think it’s poisonous to markets.”
Bay, however, said ZECs are states’ response to the markets’ failure to price carbon emissions. “I think everyone on this panel would agree that the first best solution if you care about carbon emissions is to put a price on carbon and then harness the power of markets. That clearly has not happened.
“The second-best solution — and I would say second by a long ways — is to provide financial incentives to resources that do not produce the negative externality. And that’s essentially what states are trying to do. Running the market now without taking into account the negative externality results in an inefficient market outcome.”
“And that would be fine, I think, if all zero-emitting resources now and in the future could qualify for that,” Wood responded. “As opposed to the New York case, which is very egregious, that named plants [eligible for ZECs] and one [Indian Point] was excluded.”
Future of Capacity Markets
Wood and Wellinghoff responded to a question about the future of capacity markets.
“As one who comes from the energy-only market of Texas, it works,” said Wood, acknowledging that the market will be stressed this summer because of the reduction in ERCOT’s reserve margin. “It will be a real big test. So, ask me this question at the end of September.” (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Wellinghoff said he has grown increasingly skeptical of capacity markets.
“Don’t tell him this, but Bill Hogan may be right,” said Wellinghoff, referring to the Harvard University professor, a prominent proponent of energy-only markets. “Ultimately, I think capacity markets are very difficult to design correctly and functionally. I’m currently working in Alberta. The ISO and the government there have committed to put a capacity market in with a balancing energy-only market. I’m working with a client there trying to help them to help the ISO come up with a design that will work for everybody. And we’re close to pulling our hair out!”
Confessions
At the end of the session, moderator and FERC Administrative Law Judge Lawrence Brenner elicited confessions from some of the panelists over “impulsive” actions they took as chair.
Bay recalled being up until 2 a.m. the night before the FERC Christmas party because he insisted on hand squeezing the 20 pounds of limes needed to make proper margaritas. “You can probably divide the world into two camps: the people who believe that a margarita can be made from a mix, and the people who realize, no, you really need to use fresh squeezed lime juice,” he said.
Kelliher recalled when vineyards near California’s Russian River petitioned him to authorize the release of water from hydro projects during a drought.
“Of course my first thought was, ‘I really like Russian River red wine.’ But my question to the staff was, ‘What legal authority do I have to do that?’ And the response was, ‘Highly questionable’ — FERC-staff speak for nonexistent.
“And I thought about it for about 10 seconds and I said, ‘Release the water!’” he said to laughter. “It felt very Christ-like. I knew it was the closest I would get to being holy. … I wasn’t turning water into wine but authorizing water. … And I thought if I go down [get overturned], I’ll get a Wine Spectator cover or something.”
SPP’s winter real-time prices increased 4.6% from the previous year, according to the Market Monitoring Unit’s latest quarterly State of the Market report.
The report said real-time prices averaged $25.69/MWh, compared with $24.57 the previous winter, when prices jumped 37.9%. Day-ahead prices this winter averaged $24.07/MWh, 7 cents shy of the 2017 average.
SPP’s Low Winter Prices | SPP MMU
The MMU reviewed the report, which covered December 2017 to February 2018, with market participants during a webinar Friday.
Also last week, the MMU released its annual State of the Market report, saying SPP’s market showed increasing flexibility and improving efficiency during 2017. The MMU had shared a draft with the RTO’s Board of Directors in April. (See “MMU Shares Draft of State of the Market Report,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)
The quarterly report noted average gas and electricity prices — which have historically been highly correlated — diverged slightly this year, with gas dropping from $3.08/MMBtu in 2017 to $2.64/MMBtu in 2018. Panhandle Eastern hub prices ranged from $2.50 to $2.80/MMBtu from February 2017 until January, when they spiked to $3.23/MMBtu during a cold snap.
SPP set three new winter peaks Jan. 16-17, topping out at nearly 43 GW. Oil-fired units set prices during the period that “routinely exceeded” $400/MWh in western Arkansas, eastern Texas and southern Missouri.
Winter Prices by LSE | SPP MMU
SPP and MISO were forced to use market-to-market redispatch Jan. 16-18, resulting in SPP collecting $2.66 million during that time. The Neosho-Riverton flowgate was responsible for most of the costs, as it has been since the two RTOs began the M2M process in March 2015. Congestion on the flowgate has resulted in $26.5 million in payments to SPP, more than half of the $51.4 million M2M charges MISO has incurred.
The MMU said the flowgate also caused Empire District Electric and the Missouri cities of Carthage and Springfield to see the highest winter prices in SPP’s footprint, with Carthage seeing average real-time prices of slightly more than $50/MWh.
Other highlights from the report include:
An increase in the occurrence of negative price intervals, with winter 2018 levels higher than previous years.
A nearly 7% increase in the hourly average load for winter 2018 from winter 2017. December 2017 was at a similar level to the prior year, but January and February 2018 average loads were nearly 11% higher, driven primarily by lower-than-normal temperatures.
A 7% increase in average monthly real-time generation from winter 2017 to winter 2018. Coal-fired generation its downward trend, accounting for only 46% of energy produced during the winter. Wind resources accounted for 26% of total generation.
A 36% day-ahead wind capacity factor, which increased to 46% in the real-time market. The disparity between day-ahead and real-time capacity factors contributed to the increase in negative price intervals.
CAISO is taking comment on the latest revisions to its ongoing policy initiative to better facilitate the participation of energy storage and distributed energy resources (ESDER) in its markets.
ESDER 3 is organized under the broad themes of demand response; “multiple-use applications” that allow storage to provide services and receive revenue from more than one entity at a time; and non-generator resources (NGRs).
The latest document updates the previous iteration that was published on Feb. 15, using feedback from stakeholders and a late March workshop that tackled highly technical problems related to integration of the resources. (See CAISO Storage, DER Plans Progressing.)
Major changes include a reorganization of each proposal into three categories:
“Pre-market,” which describes changes needed before a resource can participate in the CAISO market;
“Market,” which identifies potential modeling and bidding rule changes to allow participation; and
“Post-market,” which examines implications for settlement, including measures of performance such as customer load baselines.
PDR Bid Changes Afoot
Among the new updates for DR is a proposal to allow proxy demand resources (PDRs) — one or more DR resources allowed to bid as a single resource — to bid on hourly and 15-minute bases, with an ability to change the bid within an hour. The proposal would redefine issues around infeasible real-time dispatches of demand response to conform with separate changes CAISO is making to its day-ahead market. (See CAISO Says Changes Will Better Match Forecasting, Demand.)
“Stakeholders such as the Joint DR Parties are in support of the proposal but do not believe the expanded bid options fully resolve the issue of infeasible dispatches,” CAISO said in the revised straw proposal. The Joint DR parties include CPower Energy Markets, EnerNOC and Energy Hub.
Also proposed in ESDER 3 is the removal of a requirement that DR be aggregated under a single load-serving entity, which CAISO said is supported by a majority of stakeholders. The ISO said changes being proposed in the day-ahead market proposal — including combining the integrated forward market and residual unit commitment processes while introducing an integrated resource plan procurement — eliminate concerns that had been raised about some default energy bids being rejected.
CAISO is also looking at the design of the proxy demand resource-load shifting resource (PDR-LSP), which is a DR resource that provides load curtailment and also gets paid for dispatchable load consumption to shift load. The ISO said such resources will register as two separate resources with load consumption compensated via the “metered energy consumption” methodology.
DER company Olivine recommended the creation of a more refined load-shifting product, not just a consumption product, but CAISO said the separation of the resources does not create a “consumption-only” product. A requirement that PDR-LSPs have directly metered energy storage will guarantee that the energy being discharged and charged will result in a load shift, the ISO said.
Electric Vehicle Supply Equipment Examined
As another component of ESDER 3, CAISO is working to recognize the load curtailment capability of electric vehicle supply equipment (EVSE), which is seen as a way to absorb excess output from renewables. Currently, a DR resource that includes EVSE is measured without considering the equipment’s effect on load dynamics, and the ISO is working to meter the data to measure the performance of EV infrastructure. The ISO has established a distinction between EVSE located in residential versus nonresidential areas.
EVSE can already participate in markets using the “metered generation output” (MGO) performance measurement (approved by FERC as part of ESDER 1), which recognizes a sub-metered storage device’s contribution to a facility’s overall load curtailment during a CAISO dispatch event. But the ISO cannot currently accommodate a sub-metered resource with a different performance profile than its host facility load. The ISO proposes to enable EVSE sub-metering and extend the MGO performance method for EVSE independent of, or in combination with, its host customer.
CAISO’s proposal to sub-meter electric vehicle supply equipment (EVSE) | CAISO
“Sub-metering resolves the lack of 15-minute interval metering at the host facility for measurement of curtailment in five-minute intervals, enables direct measurement of the actual EV load curtailment achieved and creates a more tailored market participation model for EVSEs,” CAISO said.
Under the initiative to facilitate market participation for NGRs, CAISO dropped a proposal to identify commitment costs for NGRs in its separate Commitment Cost and Default Energy Bid Enhancements proposal, leaving those resources to be modeled as not having start-up, minimum load and transition costs.
CAISO is taking comment through May 21 on the ESDER 3 proposal and said it will continue to hold working groups, including focused working groups to examine more complex issues or those that have cross-jurisdictional concerns. Other participants in ESDER 3 are EV charging station company eMotorWerks and the California Energy Storage Alliance.
The California Public Utilities Commission on Thursday voted unanimously to allow Southern California Gas to temporarily increase gas injections into Aliso Canyon, but it denied a request to increase the storage facility’s allowable capacity.
The commission said it approved the decision “recognizing the urgent nature of ensuring reliable gas delivery during peak summer periods and with the summer season quickly approaching, as well as various pipeline outages and curtailments constraining gas flows into the SoCalGas system.”
There is a movement among residents of the nearby Porter Ranch neighborhood in Los Angeles to shut down Aliso Canyon, with many complaining of health impacts even after the massive gas leak at the facility was contained in February 2016, after being discovered the previous October.
While the CPUC’s current protocol is to allow for withdrawals only as a last resort when needed for reliability and other alternatives are exhausted, the facility is proving to be critical to electricity reliability in the region. Its potential loss has been a topic of increasing concern for the commission. When questioning CPUC President Michael Picker during a March hearing after the commission authorized gas withdrawals, State Sen. Henry Stern expressed alarm that it had “secretly granted” SoCalGas’ request to increase usage of the facility. (See Picker Seeks Guidance on IOUs, Aliso Canyon.) But Picker said the commission’s hand is being forced because of gas supply concerns.
‘Even More Urgent’
The CPUC said its measure Thursday will improve system reliability this summer and next winter. It approved several measures within SoCalGas’ second injection enhancement plan, which the company said is needed to meet customer demand and prepare the facility for winter. The plan allows the company to implement temporary modifications to its operations to increase injections and temporarily increase storage injection capacity.
But the commission denied a request to increase the allowable inventory at the facility to enable more systemwide injections and denied a request for more flexible use of the facility through a temporary deviation from certain rules.
Location of the Aliso Canyon gas storage facility
Aliso Canyon is the largest of the company’s storage facilities and had a capacity of 86.2 Bcf before the leak. Injections into the facility were forbidden through a proclamation of Gov. Jerry Brown in May 2016 until a safety review could be conducted. The state Division of Oil, Gas and Geothermal Resources last July certified a SoCalGas safety plan, allowing injections to resume and the facility to operate at pressure of up to 2,926 pounds/square inch, which translates into a gas inventory of 68.6 Bcf, or about 80% of its capacity.
The CPUC approved a similar resolution for SoCalGas’ first proposed injection plan in June 2017 to support summer reliability last year. That decision also approved an agreement between CAISO and SoCalGas for summer reliability services through Sept. 30, 2017.
The commission said several pipeline disruptions have occurred since then. On Oct. 1, the day after the ISO’s reliability agreement expired, there was a rupture on SoCalGas Line 235-2, which is still not in service. Line 4000 also went under maintenance and is now operating at significantly reduced capacity. A right of way through the land of the Morongo Band of Mission Indians also expired, reducing the capacity of Line 2000. (See SoCalGas Pipeline Losses Spur Curtailment Warnings.)
“All of these outages have placed additional stress on the system, making storage injection even more urgent than it was in spring 2017,” the commission said.
In July, the CAISO Board of Governors approved a package of market rule changes specifically developed to deal with the reduced output of Aliso Canyon. The rules allow the grid operator to constrain the operations of gas-fired plants across the state and the Western Energy Imbalance Market in the face of tight gas supplies. (See CAISO Board Approves Aliso Canyon Rules Package.)
SoCalGas wrote to the CPUC on March 2 asking for the permission to immediately begin using Aliso Canyon to manage gas inventory and preserve withdrawal capability at other storage fields. The company was predicting colder weather and said that storage at other fields was critically low. “Noncore” gas customers such as gas plants saw curtailments, and lower storage levels made it more difficult to withdraw gas.
The commission authorized withdrawals on March 3, provided that SoCalGas coordinate with CAISO and the Los Angeles Department of Water and Power to reduce overall gas demand, and the withdrawals were only authorized through March 13. SoCalGas was to increase inventories at all facilities once demand hit normal levels. The commission directed SoCalGas to file the injection plan with the goal of rapidly achieving more storage capability at fields other than Aliso Canyon and to establish minimum month-end storage targets for the rest of 2018.
Still a Key Asset
The CPUC said that because of pipeline outages, capacity reductions and other limitations, SoCalGas’ technical assessment showed that under a worst-case scenario, there is not enough capacity for this summer to meet both customer demand and to inject additional gas into storage at the rates necessary to meet the winter season storage withdrawal rates as directed by the CPUC, even with the use of Aliso Canyon. Without the facility, the SoCalGas system would not be able to meet summer peak day demand, the commission said.
Under the plan approved by the commission Thursday, SoCalGas cannot guarantee gas storage inventory targets can be reached, even with Aliso Canyon available. The company requested that the allowable inventory at Aliso Canyon be increased to 30 Bcf from the current 24.6-Bcf limit. The commission said that request required additional examination and technical assessment.
SoCalGas estimates that it will reach the current allowable inventory next month and said not having additional injection capacity available will reduce the amount of gas available to the system on any given day.
In assessing Aliso Canyon, the CPUC is faced with the challenge of maintaining reliability while dealing with public opposition to a facility that has become a symbol of the hazards of dependence on natural gas. As unpopular as it is, the facility at present appears to be indispensable for keeping the lights on in Southern California.
WASHINGTON — It’s been 10 years since FERC revised its enforcement policy guidelines, and former commission attorneys David A. Applebaum and Todd Mullins think it might be time for a check-up.
“In many cases, penalties are just too high,” said Applebaum, a former director of the Division of Investigations in FERC’s Office of Enforcement, during a panel discussion at the Energy Bar Association’s annual meeting last week.
He said that while companies face treble damages for federal antitrust violations, some FERC penalties are five to 10 times the amount of the unjust profits.
Mullins, chair of McGuireWoods’ energy enforcement practice and a former branch chief in the Division of Investigations, agreed a review of the guidelines “might be timely.”
NAV Policy
Mullins was more emphatic about the commission’s policy on issuing staff Notice of Alleged Violations (NAVs). “There’s a pretty broad consensus that the NAV is not providing benefits,” he said. “I just think it’s time to get rid of it.”
Introduced in 2009, the policy allows FERC’s Enforcement director to make a public disclosure of its enforcement investigations — including the identities of investigation subjects — once the subject has had the opportunity to respond to staff’s preliminary findings. The NAV comes before staff finalizes its conclusions and the commission issues an order.
Previously, investigations were secret until the commission issued an order approving a settlement or began an enforcement action with an Order to Show Cause. The commission acknowledged that public notices could harm the reputations of subjects but said the change was justified because it would allow third-party market participants to bring relevant information to FERC’s attention and educate them about the nature of the alleged violations.
Applebaum, now a partner at Akin Gump, coauthored a 2017 article in the George Washington University Journal of Energy & Environmental Law calling on FERC to rescind the NAV policy.
Identifying Individuals
The article contended the policy has not produced the benefits that the commission anticipated and that the commission’s enforcement efforts are increasingly targeting individuals in addition to their companies.
Martin Ramirez, compliance counsel for Freepoint Commodities and another former FERC Enforcement attorney, said the policy does have a deterrent effect.
“There’s nothing that wakes up people in the middle of a [compliance] training than going over some of the individuals who have been affected by that policy,” he said. “Nobody wants to be the guy whose perp walked out of their place of business.”
Mullins said the disclosures can be devastating.
“When the NAV comes out — which is a one-line [summary] — and names the individual and says, ‘The staff has preliminarily determined,’ if that person works for a public company, they’re toast,” he said.
Having won court approval for pursuing individuals, the commission is unlikely to reverse the policy, Mullins said. But he said it could formalize the process and explain which individuals will be named. “There’s obviously a lot of human beings surrounding the activity. Where do you draw the line between someone who was just really peripheral and you’re not including them versus someone who you are including?” he asked. “Or are you including people just because of management responsibilities?”
Mullins noted former Commissioner Tony Clark’s dissent from the commission’s 2015 order that fined Maxim Power $5 million and employee Kyle Mitton $50,000 for overcharging ISO-NE in a fuel-switching scheme. Clark said Enforcement did not prove the case to his satisfaction and that he had doubts about Mitton’s culpability. “Even in the event that I had found that Enforcement staff had met its overall burden in the case, I could not support holding only the front-line employee culpable when management itself embraces and takes ownership of the actions,” he wrote. (See FERC Fines Maxim Power $5M in Switching Scheme.)
De Novo Reviews
The panel, which was moderated by Skadden Arps attorney Donna M. Byrne, also discussed six recent federal court rulings that said defendants in civil penalty cases are entitled to a de novo trial rather than a more limited appellate-style review of FERC’s evidence. (See FERC Loses Again on ‘De Novo’ Review.)
Applebaum questioned whether FERC will want to continue its current practice of issuing orders assessing penalties.
“If the courts are essentially saying that the order assessing penalties is really of no moment — what really matters is just the complaint that’s going to be filed — does the commission want to spend all of that time working on an order that may not be necessary?
“And so, the commission may well find itself in the position of saying ‘Let’s truncate — or potentially get rid of — the order-assessing-penalties process if that means getting to federal court more quickly.
“Certainly, among defendants, among market participants — I think a lot of people in the Enforcement staff — would be happy if we could get to federal court more quickly. But there’s a legal issue that the commission is going to have to face: Does the FPA allow the commission to get rid of this more involved order-assessing-penalties process? There’s a difference of opinion on that.”
CARMEL, Ind. — Stakeholders last week said they foresee MISO making multiple changes to its markets to accommodate storage in response to FERC Order 841.
MISO invited stakeholders to give presentations on storage integration under the order during a May 10 Market Subcommittee meeting. The RTO will explore how to best comply with the order during a more comprehensive meeting scheduled for June 6, a joint effort of its Reliability, Market and Resource Adequacy subcommittees.
NextEra Energy’s Holly Carias, also representing the Energy Storage Association, said MISO’s participation model should not exclude any type of resource that meets the definition of storage.
“I think it’s not simply enough to fit storage into the traditional generator definition,” she said.
Instead, Carias said, storage resources should be able to self-bid instead of being subjected to must-offer obligations, in order to prevent battery life from being cut short by unpredictable injections. She also said MISO might need to update rules on physical withholding given storage’s operational nature.
But Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that allowing storage resources too much flexibility in the market could open MISO up to attempts to game the system.
The RTO’s market platform replacement comes at an opportune time then, Carias said, as it will be able to handle how storage will change energy use.
“In 10 years, battery storage is going to be so cheap that it will disrupt how we use energy,” Carias said, adding that by 2025, storage prices are estimated to fall to about $100/kWh.
MISO Executive Director of Market Operations Jeff Bladen reminded stakeholders that Order 841 simply requires RTOs to open their markets to storage participation and does not mandate any market design changes, although MISO will nevertheless debate to facilitate storage additions.
“To be clear, our view at MISO is that we want to evolve our markets. The pathway to changing our markets is not Order 841 compliance; it’s our own Market Roadmap [improvements]. … I want to make sure we don’t lose sight of that,” Bladen said.
Vistra Energy’s Mark Volpe asked how MISO’s views on storage assets interconnected at the distribution level — and not currently subject to the RTO’s control — might evolve in light of Order 841.
“The question of FERC-jurisdictional assets is not one that we’re going to get into,” Bladen responded firmly.
He added that MISO would carefully dispatch any generation assets for which the RTO is granted operational control.
“We need to be to very confident that we’re not going to cause any harm or mayhem at the distribution level. We essentially have a Hippocratic Oath that we’re not going to do any harm at the distribution level,” Bladen said.
Customized Energy Solutions’ David Sapper said storage could inject energy to relieve the heightened, late-day loss-of-load risk hours predicted by a recent MISO study on increased renewable resource integration. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
“Storage could address those few hours that are becoming so worrisome,” Sapper said.
Nick Griffin of DTE Energy, which co-owns the Ludington Pumped Storage Plant in western Michigan, urged MISO not to leave pumped storage behind when considering Order 841.
“We certainly think pumped storage is part of the solution, and there might be additional flexibility to leverage to benefit MISO as well as MISO customers,” Griffin said.
Concepts like state-of-charge and charge times can easily translate into reservoir levels and pumping times, he said.
Xcel Energy’s Kari Clark, representing MISO’s transmission owners, said the RTO should study the possible impacts of storage on the transmission system.
Clark also said existing metering capabilities do not distinguish charging from delivery, and distribution utilities and RTOs should work together to update metering processes. TOs “don’t feel that the metering is quite there,” she said.
Storage in the Capacity Auction
Meanwhile, MISO could see its first energy storage resource offer into the Planning Resource Auction next year.
Storage resources can currently qualify as planning resources by qualifying as either emergency-only behind-the-meter generation or as the RTO’s new Stored Energy Resource Type II (SER Type II) category type. (See FERC OKs MISO Plan to Expand Storage.)
MISO Executive Director of Strategy Shawn McFarlane said that, as of mid-May, one market participant is going through the process of registering its storage as SER Type II. He urged other market participants thinking of registering a SER Type II to contact their MISO representative.
CARMEL, Ind. — MISO’s Independent Market Monitor last week floated a plan that would allow resources that are unavailable for the full planning year to offer into the RTO’s capacity auction.
Speaking during a May 9 Resource Adequacy Subcommittee meeting, the IMM’s Michael Chiasson said that capacity resources that become unavailable and fail to replace themselves — but are not needed for reliability — should incur a financial penalty rather than a Tariff violation. The penalty price should be baked into a resource’s facility-specific reference level calculation, he said.
Chiasson also proposed that MISO designate monthly limits on how much capacity can be disqualified without replacement in order to maintain reliability.
“If there’s not a reliability issue, let it be a penalty rather than it just being a Tariff violation,” Chiasson urged. “How many megawatts of room are out there? Then put a hard stop on it.”
But he said the treatment should not extend to generators that are unavailable during the summer peak.
“If they can’t be available for the summer peak, then they shouldn’t be a planning resource. That’s our view,” he said.
MISO’s Tariff currently requires capacity resources retiring or suspending prior to the end of the planning year to replace themselves with uncleared zonal resource credits. It allows credits from outside the local resource zone only when zonal import and export limits permit.
Chiasson said it may be difficult for generators to find 100% of their replacement capacity in their own zones.
“It could be that there’s nothing left to clear in your zone,” he said.
Failure to come up with replacement credits triggers a Tariff violation and counts against a resource’s physical withholding conduct threshold. However, MISO gives a pass on physical withholding consequences to capacity resources that cannot deliver after Feb. 28 because March 1 is viewed as the end of peak system conditions. Those resources are encouraged to obtain a facility-specific reference level that includes the cost of zonal resource credit replacement. Chiasson pointed out that MISO does not extend that option to partial-year capacity resources.
Some stakeholders note that a MISO monetary penalty determination might not be the end of the concerns for capacity resources available for part of the year, which could still face resource adequacy rule violations with their state regulators.
Alliant Energy’s Jamie Niccolls cautioned that the Monitor’s plan could introduce a new reliability risk by allowing offers from units that cannot perform for the entire planning year.
Chiasson said MISO could mitigate that risk by memorializing a monthly reliability limit calculation in its Tariff.
Niccolls also said it would be difficult for a resource owner to quantify the risk of being unable to replace capacity in setting the penalty cost in the unit’s reference level.
“All we expect people to do is to make a reasonable business decision,” Chiasson said.
January’s cold weather resulted in a sharp increase in natural gas and power prices in the first quarter, PJM’s Independent Market Monitor reported last week.
The load-weighted average real-time LMP rose to $49.45/MWh in the first three months of 2018, a 63% jump from the $30.28/MWh seen a year earlier, according to the Monitor’s quarterly State of the Market report. The increase reflected a nearly 136% jump in eastern natural gas prices versus the first quarter of 2017.
Day-ahead, monthly and annual, load-weighted, average LMP: June 2000 through March 2018 | Monitoring Analytics, PJM State of the Market Report, Q1 2018
Other metrics saw even bigger jumps, including energy uplift charges (up $57.7 million, 227%) and congestion costs (up $503 million, 318%).
PJM real-time, load-weighted, average LMP: January through March, 2018 | Monitoring Analytics, PJM State of the Market Report, Q1 2018
Revenues from auction revenue rights and financial transmission rights offset less than 62% of total congestion costs for the first 10 months of the 2017/18 planning period, the first in which new rules required the allocation of balancing congestion to load instead of FTR holders. ARR and FTR revenues had offset 98% of load’s congestion costs during the 2016/2017 planning period.
PJM reported monthly billings ($ Billion): 2008 through March 2018 | Monitoring Analytics, PJM State of the Market Report, Q1 2018
It was a good quarter for generators, as measured by net revenue. All types of generation saw higher margins, including combustion turbines (+324%); combined cycle (+61%); coal (+650%); nuclear (+70%); wind (+43%); and solar (+57%).
The Monitor made seven new recommendations in the first-quarter report:
Energy Market
Change the Tariff to allow generators to have fuel-cost policies that do not include fuel procurement practices, including fuel contracts. “Fuel procurement practices, including fuel contracts, may be used as the basis for fuel-cost policies but should not be required,” the Monitor said. (Priority: Low.)
PJM should change the fuel-cost policy requirement to apply only to units that will be offered with non-zero cost-based offers. The RTO should set to zero the cost-based offers of units without an approved fuel-cost policy. (Priority: Low.)
Energy Uplift
Uplift should only be paid based on operating parameters that reflect the flexibility of the benchmark new entrant unit in the capacity market. (Priority: High.)
PJM should eliminate the use of intraday segments to define eligibility for uplift payments and return to evaluating the need for uplift on a daily, 24-hour basis. (Priority: High.)
PJM should pay uplift based on the offer at the lower of the actual unit output or the dispatch signal. (Priority: Medium.)
PJM should implement a metric to define when a unit is following dispatch to determine eligibility to receive balancing operating reserve credits. (Priority: Medium.)
FTRs/ARRs
All congestion revenue in excess of FTR target allocations should be distributed to ARR holders on a monthly basis. (Priority: High.)
WASHINGTON — Should FERC should begin requiring supply curve analyses in its merger reviews? It’s a no-brainer to Cynthia Bogorad, who has attempted to submit them as an intervenor challenging acquisitions.
“I’ve got black and blue marks to show that that … has not been a very successful strategy, because you don’t have the data or the time to get the data in [the] 60 days” allowed for filing a protest, Bogorad, a partner at Spiegel & McDiarmid, said during a panel discussion at last week’s Energy Bar Association annual meeting.
“And the commission has in my experience been very reluctant to accept intervenor analysis. We’ve presented a strategic bidding analysis in a case that the commission just said, ‘No, don’t do that.’ So, I think …. the commission [requiring merging companies to provide the analyses] would be very important because it’s hard to get them in [evidence] otherwise.”
The commission said it was considering changes in its merger policy in a September 2016 Notice of Inquiry (RM16-21). It noted that its market power evaluation for mergers, which are regulated under Section 203 of the Federal Power Act, differs from that used in market-based rate applications under Section 205. The commission asked for input on several issues, including whether it should add supply curve and market share analyses to its reviews, and whether it should require applicants to submit consultant reports and other internal reports that assess the competitive effects of the merger, as the Justice Department does. (See FERC Considers Changes to Market Power Analyses.)
FERC currently requires merger applicants to perform a competitive analysis screen unless they can show that the acquisition does not increase their generation capacity in the relevant geographic markets or that the increase is de minimis. The screen includes a delivered price test (DPT), which has been essentially unchanged since its introduction in 1996 and generally focuses on the short-term energy market “with far less detail and attention given to the other relevant products,” FERC said.
Mike Naeve, a partner with Skadden, Arps, Slate, Meagher & Flom, said FERC’s screening already prevents acquisitions that have no competitive harm.
“If we decide on top of that we’re going to add three or four other screens … I think there would be a lot more false positives,” Naeve said. “And I also think the amount of time and money and effort to prepare and advise clients for these filings [will] go up astronomically. So, the question is: Is the current process so flawed that it needs to be fixed?”
Naeve also was not convinced that FERC needs to adopt DOJ’s tools.
“As long as I’ve been doing this, I don’t know [of] a transaction where the commission said this transaction looks fine with us … and the DOJ, using these other methodologies and tools … says, ‘Oh, there’s a problem there FERC that you missed because your methodology is too simple.’ I don’t think that’s ever happened.”
Amery Pore, an economist in FERC’s Office of Energy Market Regulation, disagreed with Naeve’s characterization of the potential changes, which the commission is still reviewing. The comment period in the NOI expired in December 2016.
Flexibility?
“I guess one way to read the NOI would be to see these additional tests as extra hurdles to jump through,” Pore said. “But alternatively, you could think of them as employing the flexibility that was actually considered back in 1996 when the DPT wasn’t intended, when it was implemented, to be the screen to use.”
“If these were alternative tools to show it really is a false positive and there aren’t competitive problems, then I think we would all say that’s worth doing,” Naeve agreed. “But I would also say you [should not] need to do it in your application unless you have a screen failure.”
Naeve said he’s seen intervenors opposing mergers submit “very simplistic” supply curve analyses.
“To do it right you have to take into consideration a lot of factors … like the [generators’] ramp rates [and] minimum run times and minimum down times; the fact that sometimes in an RTO-type market … a transmission constraint that raises prices on this side of the constraint actually lowers prices on the [other] side of the constraint, so if you have generation there you’re actually losing money. … There’s just a lot of factors [that affect] the profitability of withholding.”
“That’s why it’s hard for intervenors to do it in the 60 days they have to protest,” Bogorad replied.
Mark Niefer, deputy chief legal advisor in the Justice Department’s Antitrust Division, said it’s important to avoid inconsistencies between DOJ and FERC reviews because the potential harm to consumers is so high.
“You’re talking about markets that are tens of billions of dollars in size, such that a very, very small exercise of market power over a very short period of time can impose harm on consumers … that are in the tens of millions of dollars,” he said. “So, my own personal preference when conducting a merger analysis [is] to tend to try to avoid false negatives rather than false positives. I just think the stakes are too high. And I think history bears that out. If you look back at California — the exercise of market power [during the 2000-2001 Western Energy Crisis] pretty much put a damper on restructuring in the United States. … And I think that damper still is in place.”
The panel was moderated by Eric Korman, vice president of Analysis Group.
