Page 1037 – RTO Insider

May 23, 2019

NERC Panel Delays Action on BAL Standard Request

What to Do When ACE Conflicts with Interconnection Frequency?

By Rich Heidorn Jr.

The NERC Standards Committee on Wednesday postponed action on Arizona Public Service’s request to amend BAL-002-3 (Disturbance Control Standard — Contingency reserve for recovery from a balancing contingency event) after several members said they wanted to add the technical justification for its rejection to the record.

APS’ standards authorization request (SAR) proposed that compliance with BAL-002-2 requirement R1 would be reached once interconnection frequency has recovered, saying the change was needed to prevent the recovery of one event from contributing to the creation of another event.

Asked by the SC to provide a technical review, the Operating Committee in March recommended rejection of the SAR, citing advice from its the Resources Subcommittee (RS). “The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of [the] standard, which is the demonstration of the deployment of reserves to recover from reportable balancing contingency events (RBCEs),” the OC said, adding, “The concerns raised in this SAR can be addressed by other means.”

Sean Bodkin, NERC compliance policy manager for Dominion Resources Services, asked for the delay, saying the technical reasons for the rejection should be added to the record. Other committee members also sought additional information on the “other means” cited by the OC.

“I’m not a BAL expert, but it looked like [APS] had a legitimate concern,” said Steve Rueckert, director of standards for the Western Electricity Coordinating Council.

Duke Energy Carolinas’ Tom Pruitt, chair of the RS, said there are simpler and more effective solutions to the situation identified by APS.

“There is an option to go through compliance guidance and develop a compliance guidance document. … There is an option for a BA [balancing authority] with the existing standard to simply execute an emergency assistance agreement with one of its neighbors for this situation. No modification of the standard at all is needed…

“The bottom line is, [under the SAR,] the BA would be exempt from balancing his BA area and that goes right to the heart of the job of a balancing authority,” Pruitt continued. “If he’s not required to balance his BA, we’re missing the boat here.”

Gary Nolan, an APS regulatory compliance adviser who wrote the SAR, told the SC there were “some differences of opinion and some misunderstandings” of his company’s concerns.

APS was not seeking to have a BA shirk its responsibilities, he said, but attempting to draw attention to a situation in which a BA’s area control error (ACE) is low while the interconnection frequency is high.

“BAL-001 R2 has a balancing authority … responding to what the interconnection needs as opposed to what the balancing authority needs. … When [interconnection] frequency is high, a balancing authority is asked not to correct their ACE and make frequency worse but rather to — if their ACE is low, it’s okay for them to remain low if [interconnection] frequency is high,” he explained.

Nolan said BAL-002 could be read to direct a BA in that situation to “increase their generation — or possibly, if it gets to a point where they’re very near to the deadline, they may need to shed load in order to recover their ACE in time. … Shedding load should be something we would be abhorrent to and not want to do. … That’s not going to help the interconnection … when frequency is high.”

“I get it, and I can see where there’s an issue,” Rueckert responded. “But we need to remember that the Standards Committee is not a technical committee; we’re kind of a process committee, and I don’t know that we should be making a decision on this SAR on technical terms. I think that is the RS and the OC.”

Bodkin agreed. “I know I am completely unqualified to make any technical justification on the BAL standards and that’s the reason I actually wanted to see the technical information from the RS in the record.”

Revised Standards Grading Tool Approved

The SC also approved a revised Standards G rading Spreadsheet for the Periodic Review Standing Review Team to use in evaluating standards’ requirements.

A working group formed last September revised ambiguous questions; eliminated duplicate questions; converted multipart questions into single questions; and added a reference section linking to source documents. It is the first update of the tool since its development in 2016.

However, the tool won’t get used immediately because of the decision to suspend the review team’s work until next year to avoid conflicts with the Standards Efficiency Review. (See “Standards Grading Process on ‘Pause,’” NERC Standards Committee Briefs: March 20, 2019.)

May 22, 2019

Xcel Latest MISO Utility to Pledge Zero Coal

By Amanda Durish Cook

Minnesota’s Xcel Energy is aiming to be coal-free by 2030, supported by extending service of its nuclear plant and using more natural gas-fired generation, the utility announced Monday.

The company announced that it will close its two remaining coal plants a decade earlier than originally scheduled but extend operation of the Monticello Nuclear Generating Plant on the Mississippi River into 2040, 10 years after the plant’s current license expires. The nuclear extension will require both state and federal approvals.

The 511-MW Allen S. King Generating Station near the Twin Cities will close in 2028, while the 876-MW Sherco III unit of the Sherburne County (Sherco ) Generating Station will close in 2030, Xcel sai d in a press release. The company has already said it will shutter the 680-MW Sherco I and 682-MW Sherco II in 2023 and 2026, respectively. It plans to build a new natural gas plant on the Sherco site.

The announcement comes as Xcel comes closer to securing the purchase of the gas-fired Mankato Energy Center from Southern Co. for about $650 million — a move originally opposed by the Sierra Club, which removed its comments in opposition after Xcel’s Monday announcement (18-702).

The company said the changes will take place while it triples its renewable portfolio, with plans to add 1,850 MW of wind by 2022 and about 3,000 MW of new solar by 2030.

Xcel said the acceleration of eliminating coal dependence “is another milestone in the company’s clean energy transition.”

The company will submit the retirement proposals, included in its 15-year resource plan, to the Minnesota Public Utilities Commission on July 1. The company has said it plans to reduce carbon emissions to 80% below 2005 levels by 2030 and go completely carbon-free in 2050.

“This is a significant step forward as we are on track to reduce carbon emissions by more than 80% by 2030 and transform the way we deliver energy to our customers,” said Chris Clark, president of Xcel Energy in Minnesota, North Dakota and South Dakota.

After the Xcel retirements, Minnesota will be left with just one coal plant, Minnesota Power’s 1,000-MW Boswell power plant in Cohasset.

Xcel’s move also comes after Minnesota Gov. Tim Walz announced in March that the state would strive to use 100% clean energy by 2050, joining Wisconsin, which has a similar goal. The company joins a spate of MISO member companies that have pledged to go coal-free or carbon-free, including MidAmerican Energy, DTE Energy, Consumers Energy and Southern Co. Other MISO companies have deep carbon-reduction goals, including American Electric Power, Alliant Energy, Ameren, NextEra Energy and WEC Energy Group.

As a result, some MISO organizations and companies have asked the RTO to better account for significant renewable goals or decarbonization commitments in its transmission planning. (See MISO Going Back to the Futures for MTEP 20.)

May 22, 2019

RC West Moving Smoothly Toward July Handover

By Hudson Sangree

FOLSOM, Calif. — CAISO’s RC West has been shadowing Peak Reliability as the ISO prepares to take over reliability coordinator functions throughout most of the West by the end of this year.

The first phase of the two-month shadow operations — in which RC West employees have been mirroring Peak workers around the clock “in listening mode mainly” — will conclude soon, Tim Beach, RC West’s director of operations, told the organization’s Oversight Committee on Tuesday.

So far, RC West has been included on nearly every call, including an energy emergency alert (EEA) event just a few hours into the process, Beach said. “We’re very happy about that,” he said.

The next phase starts June 1, when RC West and Peak reverse roles. RC West employees will talk to balancing authorities, and Peak will step in “if they don’t like how things are going,” Beach said.

Nancy Traweek, executive director of system operations at CAISO, told the committee that the Western Electricity Coordinating Council had provisionally approved the ISO’s bid to serve as an RC and that the matter is now in NERC’s hands. NERC and WECC plan to observe RC West’s shadow operations in the coming weeks, Traweek said.

Everything is going as planned, she told the committee.

RC West has secured agreements from 39 entities in the Western Interconnection, including Arizona Public Service, PacifiCorp and Seattle City Light. Its footprint stretches from the Canadian border into northern Baja California, and from the Pacific Ocean to the Rocky Mountains.

CAISO, RC Transition Fraught with Pitfalls, WECC Hears.)

CAISO plans to become the RC for California and Baja California on July 1. BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside California on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.

The Oversight Committee had its first in-person meeting in March, when it elected its chair, Michelle Cathcart, vice president of transmission system operations with the Bonneville Power Administration, and vice chair, Steve Cobb, director of transmission and generation operations at Arizona’s Salt River Project. (See CAISO RC Oversight Committee Elects Leaders.)

The commit t ee plans to meet monthly throughout 2019. Its members represent the transmission owners and balancing authorities in RC West.

At Tuesday’s meeting, Cathcart led a discussion about the possibility that WECC might revive its former RC operating committee and play a role in coordinating functions between the West’s three new RCs. The proposal is in an early stage, she said.

The plan didn’t appear to generate much enthusiasm among committee members, Cathcart noted. “I’m not hearing a lot of excitement in this room,” she said.

May 21, 2019

NYISO Management Committee Briefs: May 20, 2019

RENSSELAER, N.Y. — NYISO’s Management Committee on Monday recommended that the Board of Directors approve a Comprehensive Reliability Plan (CRP) that identified no reliability needs over the coming decade but did point to risks that could develop over the period.

NYISO Senior Manager for Reliability Planning Kevin DePugh presented a summary of the 2019-2028 plan, which included a scenario on the reliability impacts of proposed environmental regulations on 3,300 MW of peaking units, predominantly in New York City (Zone J) and Long Island (Zone K).

The state’s Department of Environmental Conservation earlier this year proposed to lower allowable NOx emissions from simple cycle and regenerative combustion turbines (SCCTs) during the ozone season, beginning May 1, 2023. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

NYISO, Consolidated Edison and PSEG Long Island said losing all the peakers without replacement resources or system reinforcements would threaten reliability in pockets in New York City, Long Island and southeast New York.

“Starting in 2023, with the first implementation phase of the rule, pockets in New York City would be deficient of supply for up to 14 hours in a given day at a peak amount of 240 MW, while pockets in Long Island would be deficient 320 MW possibly for 15 hours in a given day. With full implementation of the peaker rule assumed in 2025, the New York system as a whole would significantly exceed the probability of one loss-of-load event in 10 years due to a supply deficiency of at least 700 MW in southeast New York,” the report said.

“One thing generators will have to do by [March 2020] is put in compliance plans, and if they plan on closing a plant, they would have to submit a deactivation notice to the ISO,” DePugh said.

If NYISO can prove the loss of such a unit will create a reliability need for which it can find no alternative solution, it can get a two-year extension to keep the unit online, followed by an additional two years if necessary, DePugh said.

Working with Con Ed, the Long Island Power Authority and PSEG LI, the ISO found at least 700 MW of capacity needed in Zones J and K to meet loss-of-load expectation criterion, assuming the state’s AC Transmission projects are completed on schedule by December 2023. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

Local transmission alone cannot fully solve the needs, and upgrading the transmission path from UPNY-SENY into Zones J and K would likely bring the New York Control Area at or only marginally below the LOLE criterion, the report said. It would not address the local transmission constraints identified in J and K.

“The solutions could be a mix and match of different things,” DePugh said, including a combination of local transmission, resource additions and load reductions.

MMU Recommendations

Pallas LeeVanSchaick of the Market Monitoring Unit reviewed the CRP, as required by the Tariff, and confirmed that transmission security and resource adequacy needs could arise if a number of plants retire.

“There are really six load pockets, three in New York City and three on Long Island, where additional resources would be needed,” LeeVanSchaick said.

The CRP found the violations could be avoided through a variety of solutions, including by retaining 1,280 MW of peaking capacity in specific areas.

The MMU recommends NYISO adopt three significant market reforms, starting with modeling in the day-ahead and real-time markets Long Island transmission constraints — which the ISO currently manages with out-of-market actions — and developing mitigation measures to address them.

“A lot of congestion on Long Island is managed outside the market, which doesn’t provide much transparency about congestion bottlenecks or incentives for investment,” LeeVanSchaick said. “There are certain areas where it is less expensive to build generation than other areas, so price signals have to be adequate to attract investment where it is needed for reliability.”

The Monitor also recommends the ISO model local reserve requirements in New York City load pockets and consider rules for efficient pricing and settlement when operating reserve providers also provide congestion relief benefits.

NYISO-PJM JOA Revisions

The MC approved revisions to NYISO and PJM’s Joint Operating Agreement, as recommended by the Business Issues Committee. The revisions will go to the ISO’s board in June ahead of a joint FERC filing.

Under the changes, the determination of redispatch settlements would exclude several flowgates, said Cameron McPherson, the ISO’s operations analysis and services analyst.

FERC last September granted a one-year waiver of the JOA to permit the addition of the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. (See “NYISO, PJM Revising JOA for Tie Line Issues,” NYISO Business Issues Committee Briefs: March 13, 2019.)

The proposed JOA revisions were developed to address the concern raised in the waiver request and to improve other components of the M2M coordination process — in particular, the rules for performing entitlement calculations.

New External SRE Penalty

The MC also approved a new external supplemental resource evaluation (SRE) penalty regime that would boost the ISO’s ability to call on external resources that have sold capacity to New York. The changes, approved by the BIC in April, will take effect in the third quarter.

Amanda Carney, NYISO capacity market design specialist, presented the proposal and said all external capacity suppliers required to offer their energy at an external proxy must bid at the offer floor, be operating and available, and flow the scheduled transaction.

Any external capacity supplier that fails to meet the criteria will be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours in which a supplier fails to respond.

Howard Fromer, director of market policy for PSEG Power New York, said he hoped that NYISO would include in its FERC filing a mention of stakeholder concerns about being scrutinized for performing the bidding “gymnastics” called for under the proposed penalty scheme.

LeeVanSchaick said the Monitor is aware of those stakeholder concerns and that the ISO would mention them in the filing.

Under the new penalty provisions, the ISO will calculate deficiencies monthly, using the total number of SRE call hours in a given month that the resource could be online for and the total number of megawatts of shortfall in that month, Carney said.

Collateral Change for Foreign Market Participants

The MC on Monday approved a Tariff change restricting the posting of cash collateral to entities based in the U.S. and Canada.

The changes affect only four market participants, said Sheri Prevratil, manager of corporate credit.

Market participants that do not meet Tariff requirements for unsecured credit must post cash, letters of credit or surety bonds as collateral.

In the event of a bankruptcy, the ISO’s ability to retain a company’s cash collateral is dependent on applicable bankruptcy laws. Given the potential number of jurisdictions at issue worldwide, it is not feasible for the ISO to evaluate laws in all jurisdictions to ensure its interest in cash collateral would be adequately protected, Prevratil said.

The board will consider the measure in June ahead of a planned FERC filing.

— Michael Kuser

May 21, 2019

FERC Sets Conference on New England Fuel Security

By Rich Heidorn Jr.

FERC has agreed to New England’s request for a public “prefiling” meeting to discuss the region’s plans for long-term fuel security.

The staff-led session at FERC’s headquarters in D.C. on July 15 will include three, 90-minute presentations by ISO-NE, New England Power Pool stakeholders and state officials followed by questions from commissioners and staff (EL18-182, ER18-2364, et. al.).

ISO-NE, NEPOOL and the New England States Committee on Electricity (NESCOE) jointly requested the meeting in April, saying ex parte rules had prevented them from discussing with the commission their efforts to develop a long-term, market-based energy security plan, as the commission ordered last July. ISO-NE’s proposed Tariff revisions are due Oct. 15. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

“The solutions and alternatives under consideration are complex,” the request said. “It would be particularly helpful if the region can preview its proposals and issues with commission staff, both to assist the commission’s understanding of the issues and to receive any preliminary feedback and direction.”

The commission’s July 2 show-cause order instituted a Federal Power Act Section 206 proceeding after finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022.

ISO-NE last month issued a white paper on the challenges the region faces because of its increasing reliance on natural gas-fired generation — which may be unable to obtain fuel in the winter — and intermittent renewables. The paper said ISO-NE’s efforts to encourage gas-fired generators to invest in dual-fuel capability or LNG storage had proven inadequate because of “misaligned incentives.”

“Making these discrete investments, if they meaningfully reduce the risk of electricity supply shortages (and therefore the risk of high prices), entails up-front costs to the generator — yet reduce the energy market price the generator receives,” the RTO explained.

As a result, the RTO is proposing:

Expanding the one-day-ahead market into a multiday-ahead market that optimizes energy (including stored fuel) over several days.
Creating new ancillary services in the day-ahead market to compensate generators for providing the flexibility of energy “on demand” to manage uncertainties during the operating day.
Creating a seasonal forward market to provide resources with incentives to invest in supplemental fuel supplies for the winter.

The paper said the RTO is “in the early, conceptual stages of evaluating designs” for the forward market and that its “immediate focus is to first work with regional stakeholders to develop the … multiday-ahead markets and their integrated new ancillary services.”

RTO officials discussed the multiday-ahead proposal with stakeholders at NEPOOL’s Markets Committee meeting May 7.

May 20, 2019January 24, 2024

FERC Ends Examinations of TO Tax Calculations

By Amanda Durish Cook

FERC on Thursday terminated its investigations into the tax calculations included in transmission rates after several MISO transmission owners made compliance filings to remove a two-step averaging methodology that could inflate rates by underestimating tax credits.

The commission accepted compliance filings in part for MISO TOs ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas & Electric (EL18-138), as well as American Transmission Co. (EL18-157) and International Transmission Co. (EL18-159). It also fully approved filings submitted by CAISO TOs GridLiance West (EL18-158) and Southern California Edison (EL18-164).

All the TOs proposed to end the use of a double averaging formula to calculate accumulated deferred income taxes (ADIT).

FERC last year ordered compliance filings and opened a Section 206 proceeding investigating TOs’ use of the practice. (See FERC Acts on Transcos ’ Revised Tax Calculations.)

Some MISO TOs were using a two-step averaging methodology in their projected test year calculations of ADIT balances, but FERC said the practice makes deferred income tax credits appear lower than they should be, possibly raising rates because averaging the prorated ADIT value for the year with the beginning-of-year ADIT balance “produces a result that is disproportionately skewed towards the beginning-of-year balance.” (See FERC Broadens Challenge to TOs ’ Tax Calculations.)

FERC got a bit more than it bargained for when the MISO TOs submitted compliance filings that also revised their annual ADIT true-up calculations.

The commission rejected the MISO TOs’ proposed revisions to apply the IRS’ proration methodology to their annual true-up calculations, saying the effort was beyond the scope of compliance.

“The filing parties’ proposal to prorate certain MISO TOs’ annual true-up calculations is not necessary to comply with the remedy … and is thus outside the scope of this compliance proceeding,” FERC said.

It directed the TOs to make further compliance filings that include the revised ADIT calculations, this time leaving out “any other modifications or revisions.”

The commission said if the TOs still want to revise their transmission formula rates to apply the proration methodology in their true-up calculations, they could make separate filings for FERC review.

METC Filing Rejected

In a proceeding separate from the other MISO TOs, Michigan Electric Transmission Co. (METC) failed to earn FERC’s stamp of approval over its attempt to address the ADIT issue (EL19-16). In that order, the commission said that while METC’s proposed removal of two-step averaging complied with FERC’s directive, the company’s request to include the IRS’ proration methodology in its true-up calculations for all of 2019 amounted to retroactive ratemaking because the company had submitted its filing on Jan. 22.

“Although we are rejecting METC’s filing, we note that it may refile its proposal to apply the IRS’ proration methodology to its true-up calculations, provided that its proposed revisions apply prospectively, in a separate [Federal Power Act Section] 205 filing. The commission will evaluate the proposal at that time,” FERC said.

Robert Mullin contributed to this article.

May 20, 2019

PJM Revisits Gas Pipeline Contingency Plan

By Christen Smith

VALLEY FORGE, Pa. — PJM asked for stakeholder feedback last week about how to reshape its gas pipeline contingency plan, three months after FERC turned it down for lacking specificity and clarity.

“We talked with FERC staff to get a read on what they want to see in a new proposal,” Thomas DeVita, PJM senior counsel, told the Market Implementation Committee on Wednesday. “We got an insight to their thinking. … The key point is the commission wants to see a meeting of the minds between generators and pipelines.”

On Feb. 19, FERC rejected the stakeholder-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or alternative fuel source because of pipeline breaks or the loss of compressor stations (ER19-664). The proposal included nine cost categories of switching costs, including park-and-loan service charges and overrun charges.

PJM’s Market Implementation Committee meeting on May 15 | © *RTO Insider*

The commission said PJM’s definition of penalty was “unreasonably narrow and unsupported” because pipeline tariffs delineate between penalties and fuel-switching costs in different ways, meaning what appears to be an appropriate cost for one pipeline could be considered a penalty for another. FERC also faulted PJM for not including events that might trigger fuel-switching directives in its Tariff and for lacking procedures for dealing with such contingencies through the Capacity Performance market design. (See FERC Rejects PJM’s Gas Contingency Pipeline Proposal.)

DeVita said commission staff discouraged PJM from submitting an itemized list of switching costs, as it did in the first filing, and instead focus on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs. Rich Brown, manager of PJM’s system operator training, said FERC’s focus on authorization and fuel burned reflects the commission’s insistence on ensuring reliability is maintained during any switch.

David “Scarp” Scarpignato of Calpine said that approach would not protect his company’s interests.

“I’m not comfortable that we just leave it open and send it to FERC with no guidance on what’s a coverable cost and what’s not,” he said. “Just getting over the hurdle of notice is not enough to give us confidence that our costs will be recovered.”

In a January filing with FERC, Duke Energy and East Kentucky Power Cooperative said they generally supported the idea of compensating generators for switching fuels, but they worried that PJM’s enumerated categories didn’t capture all the possible costs. Without an exhaustive list, they said, generators lacked financial incentive to make the switch or the ability to recoup expenses after-the-fact.

Marji Philips, Direct Energy’s director of RTO and federal services, told the MIC that if generators know PJM will order the switch — instead of generators making the call themselves — the cost of fuel switching is transferred to customers instead. The filing isn’t clear as to whether generators who can’t perform will incur CP penalties, either, she said.

“This is so fundamentally flawed,” Philips said. “It is not pipelines that do the switching. It’s whoever owns the capacity on the pipeline. We need to rethink this and reframe how we think about this.”

The Independent Market Monitor and the PJM Industrial Customer Coalition further alleged that the RTO’s gas-electric coordination remains an information-sharing process, therefore PJM can’t give operational instructions to pipelines. Moving customers with firm contracts off some pipelines — while others with lower levels of service remain unaffected — may discourage the former group of market sellers from taking proper steps to obtain reliable back-up fuel sources, they said.

The D.C. Office of the People’s Counsel crafted the Operating Agreement and Tariff changes detailed in the rejected filing after earning a majority of stakeholder support at the December meeting of the Markets and Reliability Committee.

The supermajority vote was a victory for load interests who opposed a Calpine-authored plan endorsed at the MIC in November. That proposal would have developed a formula for cost recovery to be filed with FERC that did not include pipeline penalties.

Although ongoing services generally include cost recovery formulas, DeVita said FERC may interpret the “rare” event of generators seeking fuel-switching reimbursement as incomparable.

“We are very concerned about cost to load,” said Adrien Ford of Old Dominion Electric Cooperative. “We are also very concerned about generators mitigating their own risk. We are in no man’s land now.”

May 20, 2019

FERC Ends Notices of Alleged Violations

By Michael Brooks

WASHINGTON — FERC on Thursday officially rescinded its controversial policy of allowing its Office of Enforcement to publicly disclose its investigations of possible misconduct and their subjects’ identities, ending a practice in place since 2011 (PL10-2-003).

The commission in 2009 authorized Enforcement to issue a Notice of Alleged Violations (NAV) after the subject of an investigation had the opportunity to respond to the office’s preliminary findings. Enforcement issued its first five NAVs on Jan. 25, 2011, four of which dealt with alleged market manipulation in ISO-NE’s Day-Ahead Load Response Program.

NAVs, however, were not like indictments: They were issued before Enforcement staff had finished their investigations and reached their conclusions in the case. Prior to 2011, the commission only disclosed the existence of an investigation and its subjects’ identities when it approved the issuance of an Order to Show Cause (OSC). NAVs also did not need to be approved by the commission itself; instead, they were issued after approval from the director of enforcement.

FERC said it had “acknowledged the potential risk of reputational harm that might result from the issuance of a NAV but sought to strike a balance between protecting the confidentiality of investigations and promoting the public interest of heightened transparency.”

But the commission found that issuing NAVs generated little information for Enforcement’s investigations. And since the policy’s adoption, the commission found that other sources, such as data provided by RTOs under Order 760, have been more useful.

“Accordingly, the commission finds that the potential adverse consequences that NAVs pose for investigative subjects are no longer justified in light of the limited transparency NAVs have generated and the more effective, alternative means of adding transparency that the commission has developed since the NAV order.” These means include providing guidance through orders on settlement agreements, OSCs and orders assessing civil penalties.

At FERC’s open meeting Thursday, Commissioner Richard Glick said the policy had been unofficially ended for some time. Indeed, the last time Enforcement issued a NAV was in April 2018, the only one that year. (See FERC Investigation Shows PSEG Violated PJM Bidding Rules.) Prior to that, the office on average issued seven to eight per year.

While Glick acknowledged that NAVs had provided limited value, and joined in the unanimous vote to end the practice, he said that “the Office of Enforcement must act aggressively when there is evidence of market manipulation or other malfeasance that could adversely impact our jurisdictional markets, and I intend to review any future proposals affecting Enforcement’s role with that in mind.”

Asked by reporters after the meeting whether the commission was considering any other changes to Enforcement policies, Chairman Neil Chatterjee declined to comment.

May 20, 2019

FERC Approves Expansion to Freeport LNG Export Terminal

By Michael Brooks

WASHINGTON — FERC voted 3-1 on Thursday to approve the construction of a fourth liquefaction unit at the Freeport LNG export terminal in Brazoria County, Texas (CP1 7 -470).

The unit, called a “train” in the LNG industry, will allow for the export of an additional 5.1 million metric tons per annum (mtpa), equivalent to about 0.74 Bcfd. Currently, the facility has a capacity of 15.49 mtpa (2.14 Bcfd), according to FERC.

The approval of the so-called Train 4 Project marks FERC’s fourth approval of an LNG project this year, following last month’s approval of the Driftwood and Port Arthur projects, and February’s approval of the Venture Global Calcasieu Pass project. And as has become common, the order elicited celebration from Chairman Neil Chatterjee, a reluctant concurrence from Commissioner Cheryl LaFleur and a dissent from Commissioner Richard Glick over the commission’s reticence to assess the project’s impacts on global climate change.

“I’m proud of the efforts by the commission and its staff to process today’s and our previous LNG orders,” Chatterjee said in a statement. “Exporting LNG from the United States can help increase the availability of inexpensive, clean-burning fuel to our global allies who are looking for an efficient, affordable and environmentally friendly source of generation.”

FERC disclosed in its order that its environmental assessment (EA) of Train 4 estimated that operation of the project may result in emissions of up to 491,500 metric tons per year of carbon dioxide equivalent, increasing national emissions by about 0.01%. “Currently, there are no national targets to use as benchmarks for comparison,” the commission said.

This was enough to secure LaFleur’s vote, though she warned that the order, as with previous LNG approvals, are vulnerable to judicial scrutiny. She also noted that an additional risk existed for Train 4 because the commission issued an EA instead of an environmental impact statement (EIS). Under the National Environmental Policy Act, federal agencies issue an EIS when they find that an action will have a significant impact on the environment.

“This tension between the finding of no significant impact, and the commission’s failure to assess significance of climate change impacts, heightens the risk that a court could vacate and remand this project, simply on the basis of which environmental document was prepared,” LaFleur said in her concurrence.

At Thursday’s meeting, Glick noted that Chatterjee has said that the Natural Gas Act doesn’t give the commission authority to analyze the impact of natural gas infrastructure on climate change. He then turned and appealed directly to Chatterjee, suggesting that they “work together to send some draft legislation to Congress to fix the problem and clarify that FERC does have such authority.”

Asked by reporters about Glick’s remarks after the meeting, Chatterjee dismissed the idea, saying “there is a 0% chance that such legislation could get through the United States Senate. We have so many things to focus on, that to me is not a worthwhile thing to spend time on.”

Commissioner Bernard McNamee said the approval was “another great achievement.” He emphasized “that we have considered all the environmental effects, including greenhouse gases. I know there’s a disagreement about … how those should be measured. … But a disagreement about that does not mean they were not considered.”

May 20, 2019

Refund Hearing Ordered in Pseudo-Tie Complaint

By Amanda Durish Cook

Refunds appear imminent in a three-year dispute over MISO and PJM’s past practice of double-charging pseudo-tied generation for congestion fees after FERC last week ordered settlement proceedings to determine how much the RTOs must remit to address the redundant costs incurred from 2016 onward (EL16-108).

The issue stretches back three years to when Tilton Energy lodged a complaint against the RTOs for assessing overlapping congestion charges on pseudo-tied resources. American Municipal Power, Northern Illinois Municipal Power Agency, Dynegy and Illinois Power Marketing soon filed similar complaints. FERC consolidated the proceedings.

The RTOs introduced a temporary rebate program in 2017, then began including pseudo-ties in the day-ahead scheduling process in 2018 to end redundant congestion costs. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.) In March, MISO got FERC approval for a second piece of the solution, where participants with pseudo-tied resources can use the day-ahead market to hedge against real-time congestion.

In its order, FERC noted that it has already accepted two filings apiece from MISO and PJM to address overlapping charges and has since discovered that those proposals have eliminated the congestion overlap. But those corrections come too late for the transmission customers already assessed those charges, FERC said.

“We find that the potential for overlapping or duplicative charges for congestion existed prior to the effective dates of the revisions,” the commission said.

As such, FERC established settlement procedures to determine the appropriate refunds owed to owners of pseudo-tied generation. The commission said if the involved parties don’t settle, a settlement judge will decide the case by May 18, 2020. FERC set a refund effective date of Aug. 25, 2016.

FERC: MISO Congestion and Admin Charges Appropriate

However, the refunds will not include the costs of MISO’s non-duplicative congestion and administrative charges that Tilton also challenged.

Tilton claimed MISO violated its Tariff by erroneously using financial schedules to assess charges on pseudo-tied generation, arguing the schedules are meant to represent contracts between two market participants and that the RTO is not a counterparty to the pseudo-tie transactions.

The company said MISO circumvented a Tariff provision and implemented Business Practices Manual language when it used its financial schedules to record transmission transactions for pseudo-tied generation “despite the nonexistence of a bilateral transaction that is a prerequisite for the use of a financial schedule.”

Tilton also argued that MISO’s assessment of real-time congestion costs against generation pseudo-tied from MISO to PJM is improper because the charges cannot be hedged and are “inconsistent with market fundamentals.” The company asked FERC to put a stop to MISO’s assessment of congestion and administrative charges.

In response, MISO argued that Tilton failed to show the RTO was acting counter to its Tariff and said the complaint should be thrown out. It also said Tilton failed to initiate dispute resolution procedures prior to filing the complaint, a break with commission precedent.

“Although Tilton has purchased long-term firm transmission service from MISO to PJM, paying for transmission service does not exempt Tilton from paying for congestion and losses,” the RTO explained.

The commission sided with MISO, ruling that Tilton must pay to use the RTO’s system.

“We conclude that MISO’s assessment of congestion costs and administrative charges on Tilton does not violate the MISO Tariff. Specifically … we find that the MISO Tariff authorizes MISO to assess congestion costs and administrative charges on pseudo-tie transactions. We also find that it was not a violation of the MISO Tariff for MISO to use financial schedules as a vehicle for imposing congestion and administration charges on Tilton,” FERC said.

The commission pointed out Tilton is a MISO transmission customer taking transmission service “to facilitate its pseudo-tie transactions” and is thus required to pay applicable charges.

Pseudo-tie transactions that use the the RTO’s system nevertheless contribute to its real-time congestion, FERC added.