Page 1173 – RTO Insider

May 15, 2018

CPUC OKs Temporary Increase in Aliso Canyon Injections

By Jason Fordney

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.

The CPUC at its November 9, 2017 meeting in San Francisco (left to right): Martha Guzman-Aceves, Carla Peterman, President Michael Picker, Liane Randolph, Clifford Rechtschaffen | © *RTO Insider*

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.

CPUC Southern California Gas Gas Injections CPUC — 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.

May 13, 2018March 6, 2024

Time for New FERC Enforcement Rules?

By Rich Heidorn Jr.

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.”

May 13, 2018

MISO Stakeholders Outline Early Storage Impacts

By Amanda Durish Cook

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.

MISO energy storage FERC Order 841 — Carias | © *RTO Insider*

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.

May 13, 2018

MISO Monitor Floats Plan for Partial-year Capacity Resources

By Amanda Durish Cook

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.

MISO CAISO Market Monitor Clean Power Plan — Chiasson | © *RTO Insider*

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.

May 13, 2018

PJM Prices up Sharply in Q1, Monitor Says

By Rich Heidorn Jr.

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.

PJM REV Natural Gas Market Monitor — 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.)

May 13, 2018

Panel Debates Need for Changes in FERC Merger Policy

By Rich Heidorn Jr.

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.

False Positives?

EBA FERC Merger Policy — Naeve | © *RTO Insider*

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.

May 13, 2018

Playing the ROE Slot Machine

By Rich Heidorn Jr.

WASHINGTON — FERC’s delay in responding to a 2017 appellate ruling vacating its order on New England transmission rates has created the risk of an endless series of “pancaked” rate cases, a panel told the Energy Bar Association’s annual meeting last week.

The D.C. Circuit Court of Appeals’ April 2017 Emera Maine ruling overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners at 10.57%. The court said the commission failed to adequately explain why the previous 11.14% rate was unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)

Emera Maine ROE Return On Equity EBA — Plaushin | © *RTO Insider*

“We’re in a huge amount of uncertainty right now. The Emera decision has essentially taken everything and flipped it up into the air, and now we’re all waiting to see what happens next,” said Nina Plaushin, ITC Holdings’ vice president for regulatory, federal affairs and communications. “It’s as close to a thriller as you get in doing utility regulation.”

In the 2014 ruling, the commission voted 4-0 to change the way it calculates ROEs for electric utilities, moving to a two-step discounted cash flow (DCF) process it has long used for natural gas and oil pipelines that incorporates long-term growth rates. But the commission split 3-1 over its first application of the new formula, tentatively setting the ROE for the New England TOs at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range (EL11-66-001). (See FERC Splits over ROE.)

FERC rejected the TOs’ argument that the commission lacked authority to change the ROE without showing it is outside the zone of reasonableness.

“There’s no protection from being in the range [of reasonableness], so any complaint can come in and [cite] a number that’s slightly lower than your number and then you’re in a hearing,” Plaushin said. “And that’s why this Emera remand is so important, because we need to figure out how we’re deciding what goes to hearing and what doesn’t. It can’t just be that I proved a number different than yours.”

Customers filed new complaints even as previous ones were still pending, she noted, because of the 15-month limit on refunds under the Federal Power Act. The clock starts on the date of the utility’s rate filing.

Plaushin said the zone of reasonableness can differ based on changes in interest rates and other inputs, or as utilities are added to or subtracted from the proxy group.

In June 2016, she noted, an administrative law judge determined 10.68% as the top of the range in a complaint against MISO TOs. This was little more than three months after another ALJ, ruling on the third complaint against the New England TOs, found the top of the range at 12.19%, with 10.9% as the midpoint.

“It just doesn’t seem to make sense. It just has to do with the fact of when they filed. … [New England] got lucky. They filed when there was a good number. And one of the things the commission will [have] to consider is: Do you really want to get into a situation where people are trying to game their ROEs by doing multiple filings just so they can track volatility?”

David E. Pomper of Spiegel & McDiarmid, who argued the Emera case for Massachusetts, predicted there will be more complaints challenging rates. “I’m certain of that,” he said. “There’s a lot of ROEs out there that are still way above the cost of equity.”

He agreed with Plaushin about the risk of a never-ending cycle of filings.

“I think that probably something we can all agree on is … if the results of the litigation changes dramatically from case to case, there’s something wrong with the way you’re reaching decisions,” he said. “That creates incentives to keep filing in the hope that you’ll get lucky.”

“The solution will be in the answer to the remand in Emera,” Plaushin said in an interview later, acknowledging FERC’s response was slowed by its loss of a quorum last year. “Hopefully that will establish better parameters, so we don’t have as many serial cases.”

Former FERC Commissioner Suedeen Kelly, a partner at Jenner & Block, who moderated the session, noted the increase in ROE challenges since 2011. The panel also featured Robert S. Kenney, Pacific Gas and Electric’s vice president of regulated affairs, who discussed the impact of ROEs on his company’s ability to adapt to distributed energy resources and protect the grid from cyber threats.

May 13, 2018

MISO Market Subcommittee Briefs: May 10, 2018

CARMEL, Ind. — MISO’s long-term project to replace its market platform is now getting down to specifics, stakeholders learned last week.

Uninstructed Deviation — Reister | © *RTO Insider*

RTO technical staff are currently devoting time to creating a better market user interface — the nonpublic webpages MISO uses to accept energy bids and offers, MISO Senior IT Director Curtis Reister told the Market Subcommittee on Thursday.

The new interface is expected to work with Internet Explorer, Microsoft Edge, Chrome and Firefox. Reister said MISO sometimes forces users to use older versions of browsers for combability with the old interface.

He could provide no release date for stakeholders to peak at the new interface but said the RTO would keep them updated on progress.

MISO CEO John Bear last month said he expects about 200 employees to spend 100,000 hours total on the platform replacement project.

Final Uninstructed Deviation Proposal

MISO’s final proposal for dealing with generators’ uninstructed deviations from dispatch instructions appears to strike a balance between the views of RTO staff and stakeholders.

The plan calculates a generator’s uninstructed deviation by comparing the time-weighted average of its real-time ramp rate with its day-ahead offered ramp rate, while allowing for a 12% tolerance from set point instructions.

The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance. (See Monitor Backs MISO Uninstructed Deviation Proposal.)

The change would mean that a generator that fails four or more consecutive five-minute dispatch intervals within an hour by either providing excessive or deficient energy will not automatically lose its eligibility for make-whole payments.

Uninstructed Deviation MISO — Howard | © *RTO Insider*

In response to the concerns of some stakeholders that wind and solar resources would be flagged for producing excessive energy, MISO crafted an exception to its uninstructed deviation proposal. MISO Market Quality Manager Jason Howard said the RTO only plans to assess excessive or deficient energy charges on dispatchable intermittent resources during intervals when the resources are economically dispatched below the RTO’s forecast. Dispatchable intermittent resources that use their own forecasts will be charged for excessive or deficient energy like any other resource under the proposal.

Howard said the move could help eliminate any intentional under- or over-forecasting by intermittent resources in order to collect make-whole payments, an issue the Independent Market Monitor has repeatedly raised.

“I don’t think that we’re done here. We’re going to have other discussions about forecasting and intermittent resources,” Howard said.

MISO now plans to file with FERC to reflect the change by the third quarter of this year, with the new uninstructed deviation calculation in place by early 2019.

Multiple stakeholders thanked MISO staff for taking extra time to develop a compromise proposal.

— Amanda Durish Cook

May 13, 2018

MISO, PJM Plan 2 Studies for Seams Projects

By Amanda Durish Cook

MISO and PJM will pursue two separate interregional studies this year to identify potential joint transmission projects, the RTOs said last week.

One six-month study process would look for small cross-border projects, while a two-year effort would seek to uncover potential major interregional projects, stakeholders learned during a May 11 conference call held by the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).

2nd Round of TMEPs

The shorter-term study will identify targeted market efficiency projects (TMEPs), a project category the RTOs created in 2017, subsequently approving a five-project portfolio in December. This category of smaller interregional projects is intended to target historical congestion along the RTOs’ seams.

Seams PJM MISO Market Efficiency Projects — | © *RTO Insider*

Staff from both RTOs said the study would concentrate on historically binding flowgate constraints that have amassed at least $1 million in congestion charges. MISO and PJM have experienced about $500 million in congestion payments on more than 200 market-to-market flowgates in 2016 and 2017. PJM interregional engineer Alex Worcester said $200 million of that congestion will be addressed by planned upgrades, both by regional fixes and the five planned TMEPs.

“But there’s a bulk $300 million of congestion left on the seams that can be investigated,” Worcester said.

The second TMEP study will be conducted much like the first, and the RTOs hope to complete review of historical congestion along the seams by the end of June, Worcester said. The study will examine why flowgates were binding and determine whether transmission outages caused the problem.

The RTOs have committed to working with equipment owners associated with the congestion this July to zero in on which equipment is limiting the flow of electricity and discuss potential upgrades. By October, the RTOs hope to have completed an evaluation of project ideas and submit project recommendations for approval by their respective boards of directors.

TMEPs must cost less than $20 million, be in service within three years of approval and provide historical congestion relief that is equal to or greater than construction cost within the first four years of operation. The construction cost is divided between MISO and PJM based on the percentage of congestion relief benefits.

The two RTOs approved a $20 million, five-project TMEP portfolio last year, with projects in Illinois, Indiana, Michigan and Ohio; all are upgrades to existing systems. Project costs are on average allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)

Northern Indiana Public Service Co.’s Miles Taylor asked if MISO and PJM would consider speeding up the process to get projects approved by the end of summer.

MISO’s Adam Solomon said his RTO may be open to the idea, but he added it would be difficult to expedite the process, considering that the grid operators must complete an analysis and obtain approval from both boards before moving forward with TMEPs.

Some stakeholders asked the RTOs to consider generation retirements when studying historical seams congestion, as retiring generation could alleviate congestion on its own. Solomon said the study process is already equipped to collect that type of information.

2-Year IMEP Study

MISO and PJM have also agreed to begin a more traditional two-year coordinated system plan study to identify more expensive seams projects called interregional market efficiency projects (IMEPs), none of which have been approved by the RTOs.

For the more involved study, Worcester said each RTO will develop an economic regional model and study project suggestions submitted by stakeholders. IMEP proposals must be submitted to both regional processes, with the proposal window open from Nov. 1, 2018, to Feb. 28, 2019, according to PJM Tariff rules. Board approval of potential IMEPs would take place by the end of 2019.

Before approval, proposals will be reviewed multiple times: first to determine eligibility, then to calculate interregional cost allocation and the share of regional benefits. A third review tests the projects against each RTO’s regional criteria, while the fourth and fifth evaluations involve getting approval from both the staff and boards for both RTOs.

“It seems like one of the goals MISO and PJM have is to remove the triple hurdle. What I’m seeing here is a five-hurdle,” Wind on the Wires’ Natalie McIntire remarked. “It just seems like we should have less review.”

Worcester said only three of the reviews result in a pass/fail outcome for a project. The first review simply determines if the project would be eligible under IMEP requirements, while the second only serves to get an idea of project cost benefits, he said.

MISO and PJM last conducted a coordinated system plan in 2016 and 2017, ending the process without recommending any projects. One serious contender, a proposed 30-mile, 138-kV line near the Indiana-Illinois border, ultimately failed the joint 5% generation-to-load-distribution factor test, which requires each RTO to show that at least one of its generators has at least a 5% impact on the affected flowgate. (See MISO, PJM Ponder Interregional Study.)

Axe 5% GLDF Test

As a result of the last two-year study, the RTOs plan to revise their joint operating agreement to remove the 5% generation-to-load-distribution factor test, instead letting each of their regional processes determine flowgate impacts. Solomon said the edits will also remove references to a MISO-PJM joint model study requirement, as the joint model was eliminated in FERC compliance filings in response to a 2013 complaint from NIPSCO on the RTOs’ interregional process. (See “No Joint Model,” FERC Signals Bulk of NIPSCO Order Work Complete.)

Solomon said MISO and PJM want the revisions in place before opening the IMEP project proposal window in November. For that to happen, Solomon said the changes should be on file with FERC no later than July.

May 11, 2018

MISO LOLE Study Overestimates Auction Capacity

By Amanda Durish Cook

CARMEL, Ind. — A recent MISO study slightly overestimated actual capacity offers in the 2018/19 Planning Resource Auction, stakeholders learned this week.

MISO LOLE Capacity Import Limit — Buchanan | © *RTO Insider*

The RTO’s loss-of-load expectation (LOLE) study predicted about 143.3 GW of capacity in the Planning Resource Auction, while the auction itself attracted about 141.8 GW in offers, MISO Resource Adequacy Senior Engineer William Buchanan reported during a May 9 Resource Adequacy Subcommittee meeting.

MISO said three factors played into the difference between the study results and auction outcome:

PJM completed its third Incremental Auction in early March after the LOLE analysis was complete, which increased exports.
The LOLE used forecasts submitted in November 2016, while the PRA relied on forecasts with reduced load growth submitted in November 2017.
The LOLE study was completed before the latest round of Attachment Y retirement notice submittals, which were not included in modeling.

Buchanan also said a year-over-year decrease in transmission losses shaved peak load by about 426 MW.

MISO cleared 135 GW of capacity during the 2018/19 PRA last month, with nine of its 10 local resource zones clearing at $10/MW-day. The lone outlier was Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)

In more detailed results released this week, MISO cleared slightly less than 49 GW of coal capacity, down 3.3 GW from last year’s cleared volumes, while natural gas capacity was up about 2 GW at 51 GW. Cleared wind capacity remained relatively static at 2.2 GW, while solar capacity more than doubled from 180 MW to 461 MW. Nuclear capacity remained steady at 12.5 GW.

Capacity Import Limit Change

Some MISO stakeholders said they were caught off guard by an unexpected drop in capacity import limits used in the auction compared with preliminary auction data.

Consumers Energy’s Jeff Beattie asked why the auction’s actual CILs changed from the first published limits by “hundreds of megawatts.” He said the changes were a departure from previous years, when draft preliminary and final preliminary CILs remained relatively static.

“Zone 5 changed by more than 500 MW in the capacity import limit,” Beattie said.

Harmon said the RTO simply updated the limits for known exports out of the system to non-MISO load as it became aware of the changes. He said MISO may investigate requiring stakeholders to provide more information earlier.

From February to mid-March, when limits were finalized, MISO’s preliminary CILs fluctuated anywhere from 752 MW in Missouri’s Zone 5 to no change in Michigan’s Zone 7.

Vistra Energy’s Mark Volpe said MISO could do more to telegraph the limit changes to its stakeholders ahead of the auction.

“We did not hear a discussion as to why they changed. MISO needs to be more transparent,” Beattie said.

Laura Rauch, MISO manager of resource adequacy coordination, said the RTO would try to improve transparency in next year’s auction.

Exelon’s David Bloom said he was “begging” MISO to make preliminary PRA data easier to locate on its website.

MISO will meanwhile continue to make predictions for out-year capacity import and export limits, but it will use a new process of analyzing only those zones expected to bind on their import or export limits — or fall short of procuring local clearing requirements. MISO’s Matt Sutton said the RTO will now review those zones with its Loss of Load Expectation Working Group (LOLEWG) and then perform analyses on selected zones. Results will first be shared with the LOLEWG.

Sutton said the technical design of the new process will also be taken up at the LOLEWG.

MISO last month said it would revise its practice of forecasting long-term capacity import and export limits after proposing in early spring to discontinue them. (See “Reprieve for Out-year Import and Export Limit Estimates,” MISO Resource Adequacy Subcommittee Briefs: April 11, 2018.)