Page 1206 – RTO Insider

February 12, 2018

PJM Stakeholders Decline to Change Market Path Rules

By Rory Sweeney

VALLEY FORGE, Pa. — Stakeholders at last week’s Market Implementation Committee meeting denied four proposals to revise PJM’s rules on evaluating designated market paths for energy sales coming into and out of the RTO, indicating a preference for status quo.

Tim Horger of PJM and John Dadourian of Monitoring Analytics, the RTO’s Independent Market Monitor, presented proposals, along with Steve Kelly of Brookfield Renewable and Ruta Skucas from the Financial Marketers Coalition. The proposals differed on how strictly they would monitor scheduled transactions and the amount of leeway or consideration that companies would receive to demonstrate that questionable transactions were appropriate. (See “Stakeholders Battle PJM, Monitor on Market Path Alignment,” PJM MIC Briefs: Jan. 10, 2018.)

PJM FTR Market Paths — Stakeholders listening at the Feb 7th PJM MIC | © *RTO Insider*

“Monitoring Analytics really thinks there needs to be an enforceable rule,” Dadourian said.

“We think the IMM and PJM are going a little too far. We don’t want to throw the baby out with the bathwater,” Kelly said. “We do agree with PJM and the IMM that intentionally breaking a transaction up into separate components to conceal the true source and sink should be defined as illegitimate activity and it should be repriced, so we’re definitely aligned on that matter.” However, Brookfield argued that companies should be allowed 10 days to prove their transactions are “legitimate” before they are resettled.

Skucas, representing a joint proposal from the FMC and American Electric Power, argued that there isn’t any data proving the existence of the issues the rule change is supposed to prevent. The proposal would exempt any transactions that are at least eight days long and would monitor activity at the company level rather than combining activity from all companies within a parent holding company.

AEP’s Dana Horton said that’s the reason his company signed on to the proposal.

“We have both regulated and unregulated subsidiaries in our corporation and we follow some strict policy guidelines on not communicating between the two, so the one side does not know trading positions on the other side, and this proposal from PJM would lump them together with no way of knowing we’re in violation until after the fact,” he said, adding that PJM’s plan wouldn’t offer a way to review and explain the issue.

Dayton Power and Light’s John Horstmann agreed.

“I think it’s a legitimate question. … You may put two and two together long before any entity within a single large corporation will [because of FERC’s code of conduct rules], and potentially punish them even though they didn’t even know the combination of transactions created a problem. I haven’t heard how we’re going to address that, other than we’re going to send you to FERC because you should have known better. It’s not that easy,” he said.

Horger presented an alternative proposal that would focus only on daily and hourly transactions and exempt large corporations like AEP that have legal separations between their affiliates.

Skucas and Monitor Joe Bowring agreed that the alternative proposal unnecessarily included a reference to possible referrals to FERC.

Carl Johnson, representing the PJM Public Power Coalition, also voiced concern about companies inadvertently breaking the rules.

“We’re setting up a set of circumstances where market participants really couldn’t know that they’re going to be tripping violations,” he said. “While we completely get why the sham scheduling should be addressed, we don’t want to support a set of rules that make it [that] you just get caught and you have no idea what you did.”

Bowring said companies would know exactly what activity they should avoid.

“There would be a list and you would know what the list is,” he said. “It’s up to individual companies to monitor their own trading activity, and if they can’t do that, it’s not a problem with the rules; it’s a problem with their monitoring.”

“Or it’s a problem with the way the rules are set up,” Johnson interjected.

Bowring said it was “odd” that companies’ inability to monitor their overall activity is being offered as a reason to not have a rule against manipulation.

“We still have concerns with this whole construct that we’re setting people up to fail and get resettled,” Johnson said.

All four proposals failed to reach the necessary voting threshold of 50% to be considered at the Markets and Reliability Committee. The FMC’s came closest with 44% in approval.

Stakeholders then discussed if there’s any benefit to continued discussion to work toward consensus, but Citigroup’s Barry Trayers said stakeholders appear to be at an “impasse.” Skucas said there needs to be data to support the issue, but Bowring said the activity has been suppressed in recent years because the regulatory risk associated with a joint statement from the IMM and PJM that made it clear that such activity was manipulative.

“The alleged data is not going to show that problem because it’s being suppressed,” he said.

“If the problem has been suppressed, then why are we doing this?” Skucas responded.

“Apparently we’re not,” Bowring said.

Stakeholders then voted 69% in favor of retaining the status quo, and PJM staff said they would recommend closing the issue.

FTR Focus

Several items at the MIC meeting focused on financial transmission rights. Exelon’s Sharon Midgley presented a problem statement and issue charge to address her company’s concern with what it found to be an 18-fold increase in FTR forfeitures since a FERC decision in January 2017 required rule changes that PJM implemented several months later. Monitoring Analytics’ Howard Haas said he has not seen evidence of the issues identified in the problem statement. The proposal will be up for endorsement at next month’s meeting.

Direct Energy’s Marji Philips criticized PJM’s handling of remapping FTR paths when one of the nodes involved is eliminated. Philips said her company was presented with the issue several months ago and instead of finding an “electrically equivalent” substitute, PJM permitted them to terminate the FTR. She said other RTOs — specifically highlighting NYISO — find an equivalent.

“We think you ought to find an electrical equivalent, and coming back saying you can’t is not acceptable,” she said. “To some extent, I analogize this to a property right. We paid for it.”

Exelon, Vitol and DC Energy made the case for why long-term FTRs are beneficial to the market and should be retained. The presentation was in response to a proposal by the Monitor to review whether the products, which are available for each of the next three planning years or a combination of all three, are contributing to returning congestion revenue to load as intended.

Philips defended the Monitor’s proposal, saying that traders in her company profit off the product but also are concerned that “it may be wrong.” The products are far enough in the future that they’re “a joke from a modeling standpoint” and “not based on reality.”

“The reason that we continue to support the investigation is because … the right thing long term is to figure out whether these instruments are in any way impacting liquidity and revenue associated with [auction revenue right] and FTR allocations,” she said. “We participate because there’s a market out there and other people are participating in it and it’s not illegal and it’s perfectly sanctioned. But … we’re not sure that it’s right that we should be allowed to participate if at the end of the day we are impacting revenues that rightfully belong to customers or opportunities to get revenues that belong to the customers, and that’s our dilemma.”

PJM’s Chantal Hendrzak said the next step is to consider interests and design components.

February 12, 2018

PJM PC/TEAC Briefs: Feb. 8, 2018

VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting pushed PJM to expand its scope on several transmission-related issues, but staff resisted the effort in an attempt to keep a tight focus on specific rule revisions.

Stakeholders endorsed manual changes to revise PJM’s processes for new interconnection requests, but Ryan Dolan of American Municipal Power said the changes should go further.

The endorsed changes are part of a larger effort to replace an initial transmission study in the interconnection process with a more detailed feasibility study before moving to a costlier impact study. PJM’s Ed Franks said market participants won’t know the limiting elements on a line until a meeting later in the process, but Dolan argued they should be able to determine that information before submitting a project into the queue.

“I have no way of predetermining if a switch or another element [or] an entire line might be limiting me,” Dolan said.

“It’s relatively impossible to put that in the case. I think you can understand that,” PJM’s Aaron Berner said. “That’s a much broader topic.”

There were also concerns regarding PJM’s proposed Manual 14B changes because the RTO’s analysis found they would affect two flowgates, but Dolan argued the impact was potentially much greater and requested an analysis of the potential change to equipment.

“I fully understand the system is a dynamic system, but ultimately I think what we can only request be done right now is we at least take a snapshot of what we know currently of the system and how its topology is laid out, and we can make our decision based off of what is currently in our models,” he said.

Staff agreed to delay the endorsement vote for a month to provide that analysis.

Steve Huntoon, of Energy Counsel LLP, raised concerns about proposed changes to Manual 14A, which he called “overbroad and likely to result in a lot of confusion.”

“When I read the magnitude of this … there are some sweeping statements throughout here, and I’m very concerned about the implications of them,” he said.

Dolan also questioned the changes, voicing concerns about ratepayers being charged for more than their responsibility for necessary upgrades.

Berner again attempted to rein in the conversation.

“I think we’re straying from the manual here. The issues here are around how we process and handle our studies,” he said.

Berner suggested PJM provide participants additional education on the issue because some appear to be conflating withdrawal service and transmission service. Dolan said the education would be helpful because “now what I’m seeing here is they’re being grouped together here in one study process.”

“I just want to make sure that everybody at this committee is aware that non-firm transactions are contributing to overloads in the assessments,” Dolan said.

The Manual 14A revisions are planned to go for an endorsement vote at next month’s meeting.

PJM Proposes POI Solutions

Staff is proposing three options for resolving issues with points of interconnection (POI) for grouped generation projects, though none provides a perfect solution.

The first option would require a generation developer to sign on to the Tariff as a transmission owner for the line and a wires-to-wires POI where the gathering line connects to the grid.

John Brodbeck with EDP Renewables argued that FERC Order 807 creates ways for developers to avoid becoming TOs, but PJM’s David Egan disagreed.

“If you want the flexibility you’re asking for, you’re asking to have the TO construct,” Egan said. “The fact that you’re subdividing and doing whatever you want for your financing, really that’s your issue.”

Dayton Power and Light’s John Horstmann raised the concern that such requirements would change project calculations. For one thing, the developer would have five years to use up all the capability on a line it built or be required to open access to other developers.

“It’s a huge impact on the project,” Horstmann said.

The second option would require the local TO to assume control of the transmission infrastructure up to the connection point for the individual projects.

A third option would require the developer to combine all the projects into a single entity so it can sign a single interconnection service agreement.

“We currently have situations like this … and we typically have handled this as a shared facilities agreement,” Brodbeck said.

He asked if that was still an option or “if we’re becoming a TO, I assume … we get to vote as a TO, we get to walk around as a TO, and all these other things, right?”

Staff said they are working on splitting the manuals to pull out generator-specific revisions into a separate manual.

Capacity Factors

PJM is proposing several Manual 21 changes based on a review of data regarding generator performance.

Staff plan to shorten the summer generation testing period by one month, limiting it to July 1 through Aug. 31. They are also proposing to use the median capacity factor instead of the average capacity factor for both wind and solar resources, along with relying on the actual five-minute settlement values to estimate what output would have been absent curtailments of wind by PJM operations.

Capacity Factors PJM PC TEAC — PJM data shows that the average and median capacity factors for solar performance in the summer are fairly similar. | *PJM*

PJM’s Jerry Bell reviewed staff research showing that average solar capacity factors are similar to median capacity factor results, but average wind capacity factors are quite different from median results. The study analyzed both summer and winter performance for both generation types.

The data analysis also found that five-minute settlement values for wind resources, which are available to the generators, are very similar to state estimator results, which they don’t have access to.

Finally, an analysis of testing data showed that generators tend to test during the best possible conditions, or test early and then retest if conditions improve.

“I’m not saying there’s any malicious intent here, but there may be things that we don’t see because we can’t get a view of the energy balance,” Bell said.

Roseland Conflict

PJM staff made it clear early during the discussion on the Roseland–Branchburg–Pleasant Valley Corridor that they intended to wrap up the months of discussion about the project.

“Our intent would be to not bring this back to the TEAC after this point,” Berner said.

However, AMP wanted to outline its concerns. Dolan brought up the results from a recent FERC decision that showed the cost to rebuild the line has nearly doubled.

PJM staff said past estimates were based on the amount of time it had to produce the numbers and were done using different methodologies. They defended the decision to install a double-circuit structure but only string a single circuit because the cost of expanding to a second circuit in the future would be “significantly” higher than the 10% adder included in the current estimate.

Staff also defended their rejection of simply not replacing the line based on the initial results of their analysis of that plan.

“What we see here is enough to conclude that’s a bad idea,” PJM’s Mark Sims said. “Just doing the first round of analysis gives us a severe enough of a result.”

— Rory D. Sweeney

February 12, 2018

PJM Operating Committee Briefs: Feb. 6, 2018

VALLEY FORGE, Pa. — PJM staff told attendees at last week’s Operating Committee meeting that they are looking at ways to improve operations after reviewing the grid’s performance during January.

PJM’s Donnie Bielak and Joe Ciabattoni noted that the Tier 1 response to three spinning events during the cold snap that started the month before were substantially below the RTO’s estimates. At least 400 MW that were expected didn’t respond during each of the events, with as many as 1,660 MW failing to respond to a Jan. 7 event.

PJM has two tiers of reserves that are triggered sequentially when its dispatch software calculates a potential generation shortage. The Tier 2 response was much closer to the need. All estimated megawatts responded for two of the events.

Bielak said there are “preliminary discussions” internally regarding changes to address the issue and that “nothing is imminent,” but Calpine’s David “Scarp” Scarpignato called it “a pretty significant pricing issue” if anticipated reserves that never materialize are preventing scarcity pricing from triggering.

“I think this is going to need larger investigation by PJM and reporting out what you think the drivers of some of these numbers are,” he said.

Ciabattoni said staff did their normal outreach to the worst performers and found three main issues: poor communication from units’ market operation centers so they didn’t know to respond; “unrealistic” ramp rates attributable to equipment being out of service at the time; and spin max settings that were based on incorrect configurations.

“Our estimates are only as good as the data we get from our members,” he said. “When we did the outreach, we did find that there were data-quality issues.”

“These are bad estimates at the most critical time for scarcity pricing. Scarcity pricing is supposed to kick in during these conservative ops,” Scarp said.

Generators are addressing their issues, Ciabattoni said, and PJM is considering rule revisions to allow for raising the output target dispatchers send to units, known as the base point.

“PJM doesn’t change our base point when we go into a spinning event, so there’s not a direct signal to tell the unit to load,” Ciabattoni said.

Direct Energy’s Marji Philips asked why there were about 100 more planned outages than any other month in the past year.

“Both forced outage rates and total outage rates were elevated, and that’s primarily due to the cold weather we experienced in the first week of January,” Ciabattoni said.

He explained that if an operator needed to take an unplanned, or forced, outage but can wait until “a more opportune time, then we grant you what’s called a maintenance outage,” which is categorized as a planned outage.

The RTO’s off-peak load forecasting error of 2.79% in January was the highest in more than a year. The on-peak error was 2.38%, both of which were increased by the cold weather, Ciabattoni said. Their combined average of 2.58% was still well within PJM’s 3% monthly target threshold. The largest outlier was 7,000 MW on Jan. 15, which was the Martin Luther King Jr. Day holiday, he said.

PJM operating committee black start cold snap — In the 10 years that PJM has been measuring its “perfect dispatch” metric, there have only been two months in which the metric has estimated $0 production cost savings: January 2014 during the so-called “Polar Vortex” and January 2018 during the recent cold snap. | *PJM*

“Our model treats that as a holiday. In the past, that’s worked very well for us. This year, the load actually came in more like a normal workweek.”

The RTO also estimated no production cost savings from its “perfect dispatch” initiative for the first time since the cold streak during January 2014 known as the “polar vortex” and the second time ever in the 10 years PJM has been tracking the metric. Over those 10 years, PJM estimates its efforts to accurately forecast demand and dispatch generation as economically as possible has saved more than $1.4 billion in production costs.

PJM’s Ken Seiler said the RTO is compiling a report on grid performance during the winter that will be available by the end of this week.

Task Force on Mandating Primary Frequency Response Nearing Solution

PJM’s Glen Boyle announced that stakeholders have presented five proposals to address FERC’s requirement that most generation units be able to provide primary frequency response. The proposals are focused on four components: an exception process, an implementation plan, how performance will be measured and how units will be compensated. Stakeholders have differed on whether the service is already included in the compensation units receive in auction commitments or should receive separate compensation. (See PJM IMM Opposes Frequency Response Payment Bid.)

Stakeholders will vote on the packages after the task force’s next meeting on Feb. 28 and any that receive 50% endorsement will move on for consideration at the Markets and Reliability Committee. Boyle said few stakeholders have expressed much interest, so wider participation would be “appreciated.”

Lack of Adjustment Requests a Surprise

PJM’s Alpa Jani reminded stakeholders that the deadline for unit-specific parameter adjustment requests is Feb. 28 and expressed surprise at the lack of requests so far. She said the RTO expected many more requests from new base and Capacity Performance resources this year that haven’t materialized.

The process allows CP, base or replacement resources to submit adjustments to their commitments based on an actual operating constraint. Any newly approved adjustments will go into effect on June 1, while any existing ones will roll over from previous years.

Super Bowl Impact

Seiler was able to compile some analysis from energy demand during Super Bowl LII on Feb. 4. There was a 750-MW increase in load just prior to the start of the game, he said, and another 700-MW bump at halftime.

“There must have been a commercial that was kind of boring, so we saw another 200-MW jump about 30 minutes later,” he said, and then another 500-MW spike after the game.

Operators could tell the game was good because the load tails off quickly during bad games and the spikes don’t occur throughout the game, he said.

Black Start RFP

Staff held a special session of the OC after the meeting to walk through its request for proposals for black start service. The RTO initiates a black start RFP process every five years. The current request was issued on Feb. 1 for projects expected to be operational around May 2020.

PJM has developed a two-tiered approach for proposals to balance the resources proposed by bidders with staff’s need to see what is available across the RTO’s footprint without specifying where black start is needed. Initial proposals with basic information must be submitted by March 8. PJM would then decide whether to pursue that proposal, and those bidders would have until May 31 to submit a full, detailed proposal.

Units would receive revenue based on their actual costs to develop the project, plus a 10% profit margin.

— Rory D. Sweeney

February 12, 2018

Exelon Confident in Nuclear Support Programs

By Peter Key and Rory D. Sweeney

Exelon executives expressed confidence during a fourth-quarter earnings call that programs supporting the company’s nuclear generation fleet will expand into other states this year.

earnings Exelon ZEC — Joe Dominguez says Exelon sees positive momentum for policies that would benefit its nuclear fleet | © *RTO Insider*

“Since our last earnings call, we continue to see positive momentum for policy changes … at state, FERC and RTO levels,” said Joe Dominguez, vice president of governmental and regulatory affairs and public policy.

Dominguez said Exelon is focused on three goals: ensuring that resilient resources are compensated fairly; addressing the price formation flaws that PJM has identified; and preserving and expanding zero-emission credit (ZEC) programs and similar initiatives. All three would benefit the company, which has the largest nuclear fleet of any U.S. generator and has seen its plants undercut in power markets by cheaper natural gas and renewable energy.

According to its critics, Exelon is seeking subsidies for plants that are no longer economical to operate. But the company maintains that it is asking to be compensated for the reliability of nuclear generation, which can run constantly and don’t emit greenhouse gases.

CEO Christopher Crane said the company will continue to defend the ZEC programs in Illinois and New York and work to get similar programs enacted in New Jersey and Pennsylvania. The New Jersey Legislature is considering a bill that would subsidize the state’s nuclear plants.

Exelon also is urging FERC to adopt PJM’s price formation proposal, Crane said. PJM stakeholders endorsed the RTO’s problem statement and issue charge to examine price formation procedures for its energy markets at a Markets and Reliability Committee meeting in December.

Exelon ZEC earnings — Exelon’s Three Mile Island nuclear power plant is in Pennsylvania, where the company is working to get subsidies for nuclear generation.

The PJM-backed revisions would allow large, inflexible generators like coal-fired and nuclear to plants to set LMPs, which current rules prohibit. When such units are dispatched despite LMPs below their offers, they must seek reimbursement through uplift payments. (See PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)

Exelon earned $1.87 billion ($1.94/share) in the fourth quarter of 2017, compared to $204 million ($0.22/share) a year earlier. Its adjusted earnings per share were 55 cents, which fell short of the Zacks Investment Research consensus estimate of 62 cents.

Exelon’s revenue in the quarter was $8.38 billion, up from $7.86 billion a year prior and ahead of the Zacks consensus estimate of $7.6 billion.

Quotes courtesy of Seeking Alpha.

February 12, 2018

LNG Exporter not Concerned with ‘Momentary’ Glut

By Rich Heidorn Jr.

NEW ORLEANS — The company about to begin construction on a $15.2 billion LNG export terminal is not concerned about fears of oversupply, an official told the Gulf Coast Power Association’s MISO South regional conference Thursday.

MISO South GCPA LNG Tellurian — French | © *RTO Insider*

“It is true that at this point — with new supply coming on in different parts of the world, including the U.S. — there is a momentary glut of LNG,” acknowledged Jason French, vice president of government and public affairs for Tellurian. “However, virtually everyone who looks at it [agrees] there is going to be a … shortage of LNG by the middle of the next decade,” he said, noting that the number of countries importing LNG has grown to 47 from 29 in the last three years.

French formerly worked for Cheniere, whose LNG export terminal was based on 20-year take-or-pay contracts and $120/barrel oil prices.

“We’re starting to see smaller, modular designs. We’re not in a $120 oil environment so we have to be more competitive,” French said. Tellurian and other exporters are offering portfolios of short-term, mid-term and long-term contracts, he said, as well as taking on equity partners in the projects, unlike the typical 70% debt structure in the first export terminals.

“Sometimes you’ll hear negativity about our industry because of this momentary glut in supply. I tell you, people are steering you wrong when they tell you that, because the future is very bright for what we’re doing.”

Tellurian’s Driftwood terminal, on the Calcasieu River, south of Lake Charles, La., is expected to spend $400 million to $500 million in annual operations and maintenance expenses. Tellurian is currently in discussions with electric providers for Driftwood’s 167-MW load.

Driftwood LNG Project Map | *Tellurian Inc.*

Despite his confidence, French displayed some humility about his predictions, noting that much of Tellurian’s management came from Cheniere, which opened its Sabine Pass LNG import terminal — the nation’s first import facility — just before the domestic shale gas boom eliminated the need for imports. “We got this wrong once,” he said.

David Dismukes, executive director of Louisiana State University’s Center for Energy Studies, said capital expenditures in Louisiana and Texas resulting from cheap gas will total $318 billion between 2011 and 2025.

Dismukes said economic theory suggests that U.S. gas prices will rise to the global “proxy” as LNG exports increase, undermining industrial customers who have built new facilities in Louisiana to capitalize on cheap gas as a feedstock. Thus far, however, he said it has been the inverse, with global prices coming down to Henry Hub prices. “That’s not to say it’s going to be like that in permanency, but at least in the near term, we’ve seen this test out,” he said.

February 12, 2018

MISO Awaits FERC Following Remand on Tx Upgrade Funding

By Amanda Durish Cook

MISO says it will await a FERC decision after a D.C. Circuit Court of Appeals panel vacated a series of commission orders that allowed new generators in the RTO to self-fund network transmission upgrades.

In a 2-1 vote Jan. 26, Judges David Tatel and Laurence Silberman said the commission had failed to consider the arguments of Ameren and five other transmission owners who complained the policy forced them to accept “risk-bearing additions to their network with zero return.” The TOs argued that they essentially act as “nonprofit managers” of network “appendages,” and that under the Federal Power Act and the Constitution, FERC cannot force them to construct and operate generator-funded network upgrades.

FERC MISO Network Upgrades D.C. Circuit — Indiana transmission line | © *RTO Insider*

The case was handed back to FERC on remand; the court said FERC had not yet provided a suitable answer to the TOs’ complaint (16-1075).

Judge Judith W. Rogers filed a lengthy dissent supporting FERC and rejecting the petitioners’ argument that the commission’s orders require them to operate partly as a nonprofit business. “Not every regulatory decision requiring action by a regulated entity gives rise to a corresponding entitlement to a return,” Rogers wrote.

MISO spokesman Mark Brown said the RTO will continue to monitor the case, but it has no plans to act on the ruling until FERC issues an order.

“In the meantime, we are evaluating the implications for MISO and will be prepared to move forward upon final outcome,” Brown told RTO Insider.

But Ameren seeks a different, more immediate, outcome.

“Ameren looks forward to MISO filing revised tariff sheets to reinstitute the tariff provisions that were in effect immediately prior to the effective date of the vacated provisions, as expeditiously as practicable,” the company said in an email.

Under MISO’s Tariff, generation owners are responsible for funding 100% of network upgrades for projects below 345 kV and 90% for projects 345 kV and above, with the remaining 10% folded into the TO’s rate base.

The Tariff allows two methods for generation owners to fund the construction of network upgrades: either the TO fronts the capital, recovering costs over time through a charge on the interconnecting generator; or an interconnecting generator provides the capital. Under the generator funding option, the TO does not earn a return on financing network upgrades; the Tariff leaves it to the interconnecting generator to choose between the two funding options.

Originally, MISO allocated the costs equally between the generator and TO, but FERC determined that local transmission customers shouldered a disproportionate share of the cost of upgrades that stood to benefit more remote customers. FERC then issued a series of orders from 2015 to 2016 authorizing new generators to self-fund construction for network upgrades, regardless of whether grid owners wanted to finance it. The commission ruled that allowing TOs to choose a funding option — coupled with the power to levy subsequent charges to generators — might allow them to discriminate among generators.

The court, however, said the commission’s reasoning was “weak” and there was “neither evidence nor economic logic supporting FERC’s discriminatory theory as applied to transmission owners without affiliated generation assets.” It doesn’t make sense, the court said, that “FERC may compel transmission owners to operate the upgrades without an opportunity to earn a return.” The court noted that of the six petitioning MISO TOs, only one — Ameren — owns generation.

The court also found that not all network upgrade costs and risks are “baked in” when generators pay for them, and TOs must “bear liability for insurance deductibles and all sorts of litigation, including environmental and reliability claims.”

Rogers said her colleagues ignored the history behind FERC’s open access rules. “The court could hardly dispute that Ameren has ‘a competitive motive’ to favor affiliated generators over other generators. The commission addressed this circumstance in Order No. 888, and the Supreme Court thereafter observed that ‘utilities’ control of transmission facilities gives them the power either to refuse to deliver energy produced by competitors or to deliver competitors’ power on terms and conditions less favorable than those they apply to their own transmissions.’”

Relief

FERC told the court that its review was premature because the TOs could seek increased rates by filing Section 205 petitions. But the majority said that option would not provide the relief the TOs sought.

“First, FERC’s precedents do not provide compensation for several of the classes of risks that petitioners allege will accompany construction and operation of the network upgrade facilities. For example, fines and penalties for violations of mandatory reliability standards and environmental regulations are generally charged directly to the utility, not passed through to customers via rate increases. Further, FERC has stated that it takes a comprehensive view of a company, its employees and its operations when wielding its enforcement power against the utilities it governs. As such, compensation for the types of risks identified by the petitioning transmission owners may not be possible, even if proven in a future hearing.”

The court said it had no need to decide whether FERC is barred by the Federal Power Act or the Constitution from forcing TOs to construct and operate generator-funded network upgrades.

“Indeed, we should not do so until the commission has developed a record by considering that question itself,” the court said. “But we are troubled by the prospect of allowing the orders to continue in the interim.

“FERC may determine on remand that a transmission owner’s consent is required to impose generator-funded network upgrades, or that it would be unjust or unreasonable to force the transmission owners to accept increased risk with no increased return,” the court continued. “If it does not, Article III courts may subsequently require it to do so.”

February 12, 2018

Powelson, Regulators Talk Resiliency, Slam DOE NOPR

By Rich Heidorn Jr.

NEW ORLEANS — Regulators from Arkansas, Mississippi and Louisiana competed last week to heap scorn on Energy Secretary Rick Perry’s bid to boost coal and nuclear plants while praising FERC’s rejection of the Notice of Proposed Rulemaking.

Robert Powelson Rick Perry DOE NOPR — Powelson | © *RTO Insider*

The remarks came during a panel discussion with FERC Commissioner Robert Powelson at the Gulf Coast Power Association’s MISO South regional conference Feb. 8.

“When the administration chooses to protect coal — and omits the major fact that gas produced by fracking competes with coal — it’s political malpractice that puts my ratepayers at risk,” said Republican Ted Thomas, chair of the Arkansas Public Service Commission and the Organization of MISO States. “And it hacks me off.”

“A lot of time we [on the Louisiana Public Service Commission] don’t all agree,” said Commissioner Mike Francis, a Republican. “This particular issue gave us quite a bit of heartburn, and we unanimously objected.”

Louisiana regulators and the Mississippi Public Service Commission filed joint comments with FERC in October saying Perry’s proposal was based on unsupported conclusions, would harm ratepayers, undermine competition and intrude on state jurisdiction.

“This is hypocrisy run amuck,” said Mississippi PSC Chairman Brandon Presley, the lone Democrat on the panel. “How long have we been hearing about ‘Let’s make these decisions on the local level, get big government out of our lives.’ … And all of the sudden, in 15 days we’re supposed to upend the markets.

“I represent the poorest counties in the poorest state in the United States of America, and they don’t need this type of deal,” he continued. “They don’t understand why they should prop up an industry.”

Powelson said the stakes for FERC were clear when the commission voted unanimously to reject the NOPR and create a new docket to examine grid resiliency. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

“We either stand for … organized markets and the rule of law, or we don’t,” Powelson said. “We stood our ground, demonstrated to everyone in this room that regulatory certainty is alive and well at 888,” a reference to the address of FERC headquarters.

Powelson criticized some fuel partisans for “creating a lot of hysteria” in questioning the reliability of natural gas generation.

“I had to correct someone in my office [who said] that gas is not a baseload resource,” he said. “Now if you say that in Louisiana or Texas or Pennsylvania, they’re fighting words.”

‘Black Swan’ Events

Thomas said planning for high-impact, low-frequency “black swan” events is “one of the most difficult things to rationally deal with.”

“There should be regional differences with respect to this because different regions have different threats. Minnesota doesn’t need to pay a bunch of money for [protection from] hurricanes. California doesn’t need to pay a bunch money for [protection from] tornadoes,” Thomas said. “If you’re in the ice cream business, you have a different view than [if] you’re in another business. And to me this is the one place where microgrids actually make some sense — that if people need extra reliability then they can come up with a way to pay for it without changing the standard for everybody. So, your hospitals and folks that need it — there ought to be ways for them to bear that cost rather than spreading it around.”

Bear: No Resilience Problem in MISO

Speaking earlier, MISO CEO John Bear said the RTO is still developing its response to FERC, but it doesn’t expect major changes because state regulators and RTO members have ensured resilience through integrated resource planning.

“We don’t have a resilience problem. … We’re in a really good position right now as a region because of the hard work those folks have done. So I don’t think they need to come in and put anything in that’s significantly different from what we have today.”

However, Bear said MISO and its neighbors should improve their seams coordination to help the grid when it is “under stress” from severe weather.

“How those seams operate, the seams agreements and the way we use transmission, the way we dispatch between us … I think that’s the area where we really need to focus so that we’re all working together when those situations occur, as opposed to everybody’s looking inside their own tent and maybe working against each other.”

Tipping Point for Renewables?

In response to a question, Powelson said FERC may have to consider whether state renewable portfolio standards, subsidies for nuclear plants and incentives for offshore wind could reach a “tipping point” and begin to undermine wholesale markets.

“If you would have told me that a combined cycle gas plant with a 6,600 heat rate is facing problems in a market like California with renewables ramping up and that gas resource being dispatched [down] and not being able to handle marginal costs in that market, I would never have imagined that scenario,” Powelson said. “So it is something that is on our radar screen. … Over the next five years I think there will be some friction points going forward for us.”

Powelson also said the commission should reconsider whether capacity market incentives are properly designed. “Is a three-year [forward] capacity auction like PJM — does that really incent an investment, or should we be looking out five years in that construct?” he asked. “That’s a debate that I’ve teed up within the [FERC] building.”

February 12, 2018

Overheard at GCPA MISO South Conference

NEW ORLEANS — Competitive transmission, hurricane forecasts and maximum generation alerts were among the topics at the Gulf Coast Power Association’s MISO South regional conference Feb. 8. Here’s some of what we heard.

Bear Bullish on Hartburg-Sabine Project

MISO SPP maximum generation aler — Bear | © *RTO Insider*

MISO CEO John Bear predicted the Hartburg-Sabine Junction market efficiency project will produce better than a 1.35:1 benefit-cost ratio, although he acknowledged it did not have “broad” stakeholder agreement.

“I do think it’s the right answer. I think it really does help us with our reliability issues in the South, with load pockets; making sure that we can support the growth that we need from an economic standpoint, from a reliability standpoint, from a resiliency standpoint. It checks all those boxes.”

The RTO issued a solicitation for competitive bids on the estimated $130 million, 500-kV project in eastern Texas last week. (See Hartburg-Sabine Tx Project Open for Bids.)

MISO SPP maximum generation alert — Foreman | © *RTO Insider*

GCPA Executive Director Tom Foreman asked Bear why there hasn’t been more transmission built through MISO to deliver SPP’s growing wind generation to the east.

“The economics have to be right for both parties,” Bear responded. “There’s a lot of analysis underway to look at that, but we’ve got a lot of work to do to make sure it makes the most sense. With the amount of wind that’s on the system today and low gas prices, more wind doesn’t necessarily lower LMPs.

“Trying to understand how to operate [the SPP] seam reliably and efficiently is also really important,” Bear added. “We don’t have as mature a relationship working with SPP on that seam because it hasn’t been [there] as many years” as MISO’s seam with PJM.

Moving Beyond the ‘Cone of Uncertainty’

Chris Hebert, TropicsWatch manager for StormGeo, said the “cone of uncertainty” developed about 15 years ago to forecast hurricanes’ paths is no longer the state of the art.

MISO South SPP maximum generation alerts — Moderator Bill Mohl listens as Chris Hebert presents | © *RTO Insider*

Hebert explained that the cone is actually constructed by joining the edges of a series of circles, each representing a 67% probability of the storm passing through. As forecasting has improved, the cones have gotten narrower.

But that can lead to dangerous complacency, he said, noting that Hurricanes Katrina (2005), Ike (2008), Joaquin (2015), Matthew (2016) and Harvey (2017) strayed outside their predicted paths. “Being outside the cone doesn’t mean you’re safe,” he said.

Hebert said a consensus of models is better at indicating the current uncertainty and potential impact of storms.

Judith Curry, president of the Climate Forecast Applications Network, said she used “ensembles” of models and Monte Carlo sampling to help Florida Power & Light pre-position utility crews before Hurricanes Hermine (2016), Matthew and Irma (2017).

Curry said it’s too early to blame climate change for affecting either storm intensity or frequency. “It’s impossible to separate what might be global warming from natural variability,” she said, adding that data on warming’s impact on storms are unlikely to be clear until about 2050.

The consensus is that warming will cause an increase in storm intensity — including more Category 4 and 5 hurricanes — but that the overall number of tropical cyclones will decrease, Curry said. “If those predictions are true, we may have smaller overall impacts from hurricanes later in the century. But this is all very speculative. The climate models are nowhere near good enough to actually predict this,” she said.

MISO South Maximum Generation Event — Rainer | © *RTO Insider*

Sallie Rainer, CEO of Entergy Texas, discussed her utility’s response to Hurricane Harvey, which dropped 50 inches of rain in its service territory over eight days in late August and early September, flooding six major substations.

The experience is leading the company to seek more information about local watersheds, she said. “Understanding where those bayous and tributaries will dump the water when we’ve had 50 inches come in … and being able to lay that over our topology and our equipment [will show] what we need to protect … if we need to raise control houses, put floodwalls up.”

Entergy Talks Tax Savings

MISO SPP maximum generation alert GCPA MISO South — May | © *RTO Insider*

Phillip May, president of Entergy Louisiana, said the reduction in the federal corporate income tax from 35% to 21% will result in about $100 million in annual savings for the company’s customers. “We believe tax reform will have significant and meaningful benefits to our customers,” he said.

Max Gen Events

During a discussion on MISO’s maximum generation events in April 2017 and January 2018, Independent Market Monitor David Patton reiterated his call for the RTO to exercise more control over the scheduling of maintenance outages.

MISO SPP maximum generation alerts GCPA MISO South — Patton | © *RTO Insider*

Patton said an excessive number of planned outages contributed to 22 days of conservative operations in load pockets in spring 2017, including three days of maximum generation alerts in April 2017, which included an April 4 emergency max gen event following the loss of a large nuclear unit in the South during a period of high load.

“It would have been great if we’d started our outages earlier or spread them out, because we had more capacity than we knew what to do with in the peak period and then we scheduled ourselves into an emergency in terms of the outages in March and April,” he said. Under its Business Practices Manual, MISO can only “recommend [an outage] schedule that maintains system security and minimizes adverse impacts.” (See MISO South Outages Worry RTO, Monitor.)

Patton said the biggest problems occur when transmission and generation outages are scheduled simultaneously in the same area. “If you take a major line out of service and then you take a large generator that played a key role in relieving the flows into that area, you can end up with congestion that’s very difficult to manage and generates a lot of cost quickly.”

Patton, however, said the South would have been in worse shape had it not been part of MISO. “Having MISO operating the integrated region between the South and Midwest increases reliability in both regions,” he said.

He recommended that MISO purchase capacity in four seasonal tranches to ensure sufficient generation year-round and give resources options on when to accept capacity obligations. Load-modifying resources — demand resources and behind-the-meter generation that provide capacity — shouldn’t be summer-only, he said.

Most LMRs called up for the first time in a decade during the April 4 event failed to respond properly to scheduling instructions. (See 4 LMRs Face Penalties after MISO Max Gen Emergency.)

Richard Doying, executive vice president of operations, said MISO staff are preparing a white paper on whether it should be planning seasonally rather than its traditional focus on the summer peak. He noted that LMRs represent almost 10% of the RTO’s fleet.

— Rich Heidorn Jr.

February 12, 2018

SPP Briefs: Week of Feb. 13, 2018

SPP’s Market Monitoring Unit (MMU) last week conducted its first quarterly market report webinar, importing a practice MMU Executive Director Keith Collins used while at CAISO.

M2M Payments tariff revision spp board — Collins | © *RTO Insider*

Collins called the Feb. 8 webinar a success, noting it attracted 40 participants. It followed the January release of its quarterly report. (See SPP Market Monitor: Negative Prices May Require Rule Changes.)

“It is not only a great forum for us to present on our quarterly report, but it also allows for great interactive discussion between market participants and market monitoring staff,” said Collins, who joined the MMU last year.

Staff reviewed the report’s highlights, focusing, as the report did, on the SPP market’s growing frequency of negative price intervals. The MMU said the market’s practice of self-committing resources in the day-ahead market may be exacerbating the situation.

“We’re not saying negative prices are bad, but they are an indication of what happens on the system as a consequence of thousands of megawatts not participating in the day-ahead market,” Collins told participants. “When they show up in the real-time market, it can create this disconnect.”

Collins said the MMU will repeat the practice following each quarterly and annual market report. The calls are open to members, market participants and regulatory staff, among other stakeholders.

“Our goal is to improve the markets through education and understanding of market outcomes,” he said.

December MISO-SPP M2M Results in $4.2M in Charges

SPP recorded its third consecutive month of multimillion-dollar market-to-market (M2M) payments from MISO in December, staff told the Seams Steering Committee on Feb. 7. The month’s $4.2 million in charges pushed the amount of M2M payments to SPP past $36.8 million.

Permanent and temporary flowgates were binding for 531 hours in December. SPP’s Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border was once again responsible for the bulk of the charges.

The two RTOs began the process in March 2015. SPP last month said it has reimbursed MISO more than $2.25 million after resettlements of several M2M flowgates, and that it will continue to perform “limited” resettlements because of a memorandum of understanding between the two. (See “SPP Pays MISO $2.25M After M2M Resettlements,” SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018.)

Staff also briefed the committee on the Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee meeting. The RTOs’ staff and stakeholders will discuss improvements to the Coordinated System Plan, which has identified four potential seams projects in two previous iterations. None of the four survived regional reviews.

SPP is also trying to meet with Associated Electric Cooperative Inc. before March 9. Staff have drafted a scope that identified needs from its 2018 Integrated Transmission Planning Near-term Assessment that are “electrically significant to the SPP-AECI seam.”

Board Approves Non-Jurisdictional Tariff Change

The Board of Directors approved a Tariff revision that incorporates a refund obligation for SPP’s nonpublic transmission-owning utility members during a special conference call Monday afternoon.

The measure addresses a FERC directive that SPP require non-jurisdictional transmission owners to refund revenues received associated with their service, and that it enforce the membership agreement in court (EL18-19). The RTO has a Feb. 28 filing deadline in the docket. (See FERC Backs off Nonpublic Utility Refunds in MISO, SPP.)

The 20-person Members Committee was divided on its advisory vote to the board, with five members — Empire District Electric, Oklahoma Gas & Electric, Public Service Company of Oklahoma, Southwestern Public Service and Westar Energy — casting opposing votes.

The proposal, which was recommended by the Corporate Governance Committee, includes a provision that should there be a conflict between a FERC refund order and state statute, the refund amount would be deemed uncollectable. Members questioned why non-jurisdictional members should be treated differently than investor-owned utilities and whether their customers might pick up the tab for those entities unable to provide refunds.

“If our customers are overpaid and there’s a refund order, our customers are left with a short amount,” said OG&E’s Greg McAuley.

Kansas City Power & Light’s Denise Buffington, who represents IOUs on the CGC, said she supported the measure because of her understanding that the Nebraska Constitution prevents its entities from delegating authority to someone else.

“I’m OK with this if SPP can show how everyone else will be kept harmless,” she said. “I will be closely scrutinizing the SPP filing. If it doesn’t show harm to other members, we will be filing comments in the docket.”

— Tom Kleckner

February 12, 2018

FERC Orders Indiana Wind Project to the Back of the Queue

By Michael Kuser

FERC ruled Friday that the developer of a proposed 1,500-MW Indiana wind farm must go to the end of the interconnection queue to move its point of interconnection (POI) 2.9 miles.

The commission’s Feb. 9 order rejected Harvest Wind’s request for a waiver allowing it to change the POI without triggering the “material modification” language under PJM’s Tariff. FERC sided with PJM in requiring a new queue application and facilities study (ER18-615).

Colorado-based Renewable Energy Systems Americas acquired the Harvest Wind project after the previous developer agreed in late 2016 to move to a second POI after AEP Indiana Michigan Transmission said the original was not a suitable spot for the wind farm’s 765-kV switchyard.

RES Americas said it learned in fall 2017 that the new location, POI 2, had some of the same problems as the original location, including wetlands and endangered species concerns. In addition, noise from the switchyard’s transformers would be too loud because of nearby houses, the company said in its Jan. 5 waiver request.

The developer said its proposed interconnection, POI 3, is “electrically identical” to the current location because it is just 2.9 miles away on the same 765-kV transmission line.

PJM opposed the request, arguing that the waiver would delay other projects in the queue because of the size of the wind project and the need for transmission restudies.

The commission agreed with PJM, finding that “Harvest Wind has not sufficiently demonstrated that it acted in good faith. Harvest Wind states that it became aware in September 2016 that both POI 1 and POI 2 presented some complicating factors due to site topology, but at that time it did not believe these factors were insurmountable. … Moreover, Harvest Wind fails to explain why it did not discover these additional complications for almost a year after initially being put on notice that complications existed at POI 1 and POI 2, demonstrating a lack of due diligence on Harvest Wind’s part.

“Harvest Wind has not sufficiently demonstrated that granting the waiver request will not have undesirable consequences or harm third parties,” the commission continued. “We agree with PJM that changing the point of interconnection at this late stage would introduce uncertainty that could well impact other lower-queued interconnection customers and that such restudy of the point of interconnection would require reassessment of protection, requiring the expenditure of time and resources, thus burdening and harming other parties.”

RES Americas said in its waiver request that it might be forced to abandon the project if the waiver were not approved.

An RES Americas spokesman said the company was “planning to proceed with the project” but did not say why a delay might force it to abandon it.