Page 1119 – RTO Insider

September 24, 2018

MISO Board of Directors Briefs: Sept. 20, 2018

CARMEL, Ind. — MISO will next week begin conducting the election for three open seats on its Board of Directors.

miso nominating committee budget — Nancy Lange | © *RTO Insider*

The RTO’s Nominating Committee has settled on incumbents Phyllis Currie and Mark Johnson along with Minnesota Public Utilities Commission Chair Nancy Lange. If Lange earns enough of the vote, she will replace outgoing Chairman Michael Curran, who has reached the three-term limit.

Before being formally selected by MISO’s Nominating Committee, Currie was elected as chair for 2019. (See MISO Board Selects Currie as New Chair.)

Madison Gas and Electric’s Megan Wisersky, who holds one of two stakeholder seats on the Nominating Committee, said the committee narrowed a pool of about 30 candidates to two candidates for each of the three open seats, including those held by Currie and Johnson. MISO turned to management firm Russell Reynolds for help assembling a candidate pool.

“The quality of the candidates was exceptional,” Nominating Committee member and Director Baljit Dail said.

“We look forward to another newbie,” Curran added.

MISO Senior Vice President and Secretary Stephen Kozey said polls will be open Sept. 27 to Nov. 2, with a quorum representing 25% of MISO voting members (at least 35 members). Candidates must receive a majority of member support after quorum to be placed on the board. For each candidate listed on the ballot, MISO members can vote “for,” “against” or “withhold.”

“Should a member fail to collect a majority of the voting, the Nominating Committee process would begin all over again,” Kozey said.

MISO membership will also vote during that time on whether to increase the board’s compensation beginning in 2019. The board, after consulting with Russell Reynolds, voted to give itself a $7,000 raise for all directors, raising the current base retainer from $89,000 to $96,000 per year. Currently, directors are paid $116,000, committee chairs get $124,000 and the board chair gets $131,000. The last director pay increase took place in 2016. (See Board OKs Pay Hike, Change to Independence Rules.) The board also voted to increase the chairman’s stipend from $15,000 to $20,000 in 2019.

Curran said increases to director compensation would be frozen for two years should the increase take effect.

Kozey said under MISO’s Transmission Owners Agreement and bylaws, it would take at least two-thirds of the quorum of voting RTO members to reject the compensation increase.

Board election and compensation results will be announced at the Dec. 6 board meeting in Carmel, Ind.

MISO Spending Closely Tracks 2018 Limit; RTO Ups 2019 Budget

After earlier forecasts of a small year-end overage, MISO is now on track to be $1.2 million under its $265 million expected budget in December.

MISO Chief Financial Officer Melissa Brown said the savings are primarily attributed to delays in planned investments.

The RTO is likewise expected to come in under its capital expense budget, likely spending $28.8 million of the allotted $29.6 million. The decrease comes from deferring some vendor work on its market platform replacement and reclassifying other capital expenses as operating expenses.

MISO staff are proposing a $269.6 million operating budget for 2019, a $4.7 million increase over last year. The RTO, however, is planning for a smaller capital budget, at $27.2 million.

The 2019 budgets include $81.2 million in both operating and capital spending on technology.

The total 2019 budget includes $20.5 million of spending on MISO’s market platform replacement project, broken down into $10.7 million in capital expenses, $4.2 million in operating expenses and $5.6 million dedicated to the salaries and benefits of staff working on the project.

MISO leadership said it will reveal in late 2019 its chosen vendor to construct the new platform. In June, the RTO said preliminary vendor General Electric was months behind schedule on developing the platform, especially on the complex software needed to clear the day-ahead market. (See MISO Platform Replacement Risks Delay, Budget Overrun.)

Curran asked that MISO provide the board updates on its preferred vendor and reasoning before releasing the information next year.

MISO Reviewing FTR Process

After PJM experienced a major default in its financial transmission rights market, MISO is ramping up an ongoing review of its own FTR market.

Officials said they began the review in 2017 and will continue to look for any weaknesses in its process. The evaluation is expected to extend into next year, and MISO said it plans to bring results of the evaluation to stakeholders.

Brown said staff are looking at other RTOs’ practices to identify the best combination of procedures.

FERC filings indicate PJM’s financial fallout from the incident that began with GreenHat Energy’s $1.2 million FTR default might become as high as $110 million. (See PJM Reeling from Major FTR Default.)

But MISO last week said its FTR market differs from PJM’s in one key way that may protect it against a significant default: MISO does not net auction bid prices with estimated congestion credit value. MISO said the netting difference results in a conservative credit calculation and higher collateral, preventing “thinly capitalized” parties from buying large portfolios.

“We believe this is a key component for minimizing the magnitude of a default,” MISO said.

Brown said bid prices in MISO are required to be collateralized.

“So you’ve got to bring the cash to play the game,” she told the board.

MISO also said it limits FTR terms to one year, while PJM allows rights for up to four years. It additionally pointed out that it estimates the value of transmission congestion more frequently than PJM, updating congestion estimates monthly rather than once per year.

In response to a question from Director Barbara Krumsiek about whether GreenHat could resurface to apply to operate in MISO, Brown said the screening process for credit worthiness would most likely exclude it early in the process.

Directors asked if there was a downside to being more conservative in its FTR market requirements.

Brown said MISO’s collateral requirment protects the membership class, not MISO, because the costs of a default would be passed on to members.

“I’m on the conservative side, just so we’re clear,” Director Currie said.

Director Thomas Rainwater said it appeared that MISO’s credit policy hasn’t diminished “robust” FTR market activity.

— Amanda Durish Cook

September 24, 2018

ISO-NE Asks FERC to End Clear River CSO

By Michael Kuser

ISO-NE on Thursday asked FERC to terminate the capacity supply obligation of Invenergy’s delayed 485-MW Clear River Energy Center Unit 1 combined cycle plant in Burrillville, R.I. (ER18-2457).

The RTO said it was exercising its right to terminate the CSO because the plant will not be operating in time for the beginning of the capacity commitment year beginning June 1, 2019.

iso ne cso invenergy clear river energy center unit 1 — Clear River Energy Center Rendering | *Invenergy*

Unit 1 obtained the CSO in Forward Capacity Auction 10, held in February 2016, but its commercial operation date is now scheduled later than June 1, 2021. Invenergy has covered the plant’s CSO for the capacity commitment periods beginning in 2019 and 2020.

Chicago-based Invenergy has been attempting since 2015 to get a construction permit for the plant from the Rhode Island Energy Facilities Siting Board (Docket No. SB-2015-06), a process delayed by opposition to the plant itself, the environmental sensitivity of the proposed site and the developer’s plans to secure extra water for operations.

On Sept. 21, the town of Burrillville asked the siting board to reject the advisory opinion submitted by the state’s Public Utilities Commission in favor of the project. Town Manager Michael C. Wood posted news of the RTO’s termination filing on the town’s website: “No doubt this is a big setback for Invenergy. Burrillville will thoroughly evaluate this action by ISO-NE, but we are not underestimating Invenergy.”

Last November, ISO-NE barred Unit 2 from offering into February 2018’s FCA 12 because of the permitting delays. (See ISO-NE Bars Invenergy Plant from FCA 12.)

If the commission accepts ISO-NE’s filing, the RTO said it “will terminate the CSO, draw down the financial assurance that Invenergy provided for Clear River Unit 1’s CSO and will remove the resource’s qualified capacity, which will render it ineligible to participate in the upcoming FCA 13 to be held in February 2019.”

FERC in January accepted an unexecuted large generator interconnection agreement filed by ISO-NE and National Grid for Clear River. (See FERC Accepts Disputed GIA for Rhode Island Generator.)

The RTO asked the commission to issue an order within 60 days of its filing, arguing that the grid operator and market participants “need certainty on the status of this resource” prior to FCA 13.

September 24, 2018

Overheard at ISO-NE Consumer Liaison Group Meeting

By Michael Kuser

WINDSOR LOCKS, Conn. — Climate change and the key role of heating and cooling improvements for energy efficiency were the hot topics of discussion among consumer advocates, state regulators and industry professionals attending a meeting of ISO-NE’s Consumer Liaison Group on Thursday.

iso ne consumer liaison group climate change — Attendees at the ISO-NE CLG | © *RTO Insider*

Combined residential, commercial and industrial building heating accounts for about 40% of CO₂ emissions in New England, followed by transportation at about 35% and the electric sector at 23%.

“Those are the big three wedges when you want to actually achieve the economy-wide greenhouse gas goals that we now have in statute,” said Commissioner Robert Klee of Connecticut’s Department of Energy and Environmental Protection.

The state’s Global Warming Solutions Act calls for reducing GHG emissions to 10% below 1990 levels by January 2020 and 80% below 2001 levels by 2050, and it was recently amended to reduce emissions to 45% below 2001 levels by 2030.

The state’s renewable portfolio standard and the Regional Greenhouse Gas Initiative have driven down emissions, “and Connecticut has just doubled down on that with legislation to make our RPS 40% Class I renewables by 2030,” Klee said.

The “new normal” of stronger and more frequent storms is also a challenge for planners and predictors, Klee said. “Those storms would normally happen years or decades apart, but Eversource [Energy] reported in a period of 16 months having four of the company’s 10 most devastating storms ever … [which] translates into [affecting] our rates and how much we’re all going to be paying for this.”

Heating and Cooling

Joseph Rosenthal, principal attorney for Connecticut’s Office of Consumer Counsel, moderated a panel on electrification of heating.

From 2013 to 2015, the state was promoting the use of natural gas “to find the right parameters to give consumers choice about whether to stay with oil or switch to natural gas and what kind of subsidization we would offer for that,” Rosenthal said.

Now Connecticut is moving into a new phase, talking about electrifying of the heating sector, he said.

DEEP Deputy Commissioner for Energy Mary Sotos said climate change drives the move to electrify heating to reduce GHG emissions, but the use of lower carbon content biofuels also provides opportunities to improve energy efficiency.

“One limitation on reaching the state’s GHG emissions target is how we measure biofuel,” Sotos said, noting that the advantages of biofuel lie in reduced emissions over the lifecycle, while the EPA tools her state uses only reduce emissions at the point of combustion.

“In the near term, unless we change those methodologies significantly, we wouldn’t necessarily get to claim credit for any changes made there,” she said.

Sotos’ remarks set the table for Chris Herb, president of the Connecticut Energy Marketers Association, a statewide group of fuel oil dealers, who said, “Forget everything you think you know about heating oil.”

On July 1, all New England states mandated the use of ultra-low sulfur heating oil, with a maximum sulfur content of 15 ppm, a 97% reduction from the previous standard, he said. The new fuels, mixed with 7% biodiesel on average, mean particulate emissions are reduced by 80%, nitrous oxide by 10% and CO₂ by 2%.

With biodiesel added, heating oil is no longer the fuel that people are used to, Herb said.

“It’s cleaner than natural gas,” Herb said, showing a slide comparing the 20-year atmospheric lifecycles of natural gas versus ultra-low sulfur heating oil, which his trade group is trying to rebrand as “Bioheat.”

Heat Pumps

Ronald Araujo, energy efficiency manager for Eversource, said heat pumps provide excellent benefits, given the right situation.

“Ground source heat pumps are very efficient,” Araujo said. “It doesn’t generate heat — it moves heat from place to place — but one disadvantage is it needs some external source to work with.”

Ground source heat pumps are more efficient than air source heat pumps because the temperature of the ground is relatively stable (about 50 degrees Fahrenheit), while the air temperature in New England can range from below zero to 100 with high humidity, either of which compromise efficiency.

“The reason heat pumps are so important is that they reduce emissions. They reduce emissions today, and they will also do it as the electricity sector continues to get cleaner,” said Emily Lewis O’Brien, Acadia Center senior policy analyst. “This is an important part of the equation … but you can’t do it with heat pumps alone.”

O’Brien emphasized that in order to meet renewable energy goals, it would be relatively “simple” to bring all six states in New England, plus New York, into matching best practices in every area, from electric vehicle promotion, to solar development, to heating electrification and energy efficiency.

“And it’s important to align state incentive programs across the region, to make sure we’re all swimming in the same direction,” O’Brien said.

Fuel Security

Anne George, ISO-NE vice president for external affairs, highlighted recent developments at the RTO, particularly regarding fuel security and the issue of the difficulty of obtaining natural gas supplies during the region’s winter peak.

FERC in July tentatively accepted a cost-of-service agreement between ISO-NE and Exelon for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues related to cost justification (ER18-1639). The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. (See FERC Advances Mystic Cost-of-Service Agreement.)

“They did agree with how we were approaching the fuel security risk analysis, but they did not go along with us doing this outside of our typical Tariff language,” George said.

Elizabeth Mahony, of the Massachusetts attorney general’s office, spoke for her boss, Deputy Chief of the Energy and Environment Bureau — and CLG Coordinating Committee Chair — Rebecca Tepper, who was busy dealing with issues related to the multiple gas line explosions in the Merrimack Valley near Boston the previous week.

Mahony highlighted the election of a new Coordinating Committee at the next CLG meeting, to be held in Boston on Dec. 6. “Any CLG member who is an electricity end user, or directly represents ratepayers, or is a member of a consumer organization, or is a government consumer or ratepayer advocate is eligible to serve on the Coordinating Committee,” she said.

September 24, 2018

FERC Tells LEAPS to Get in Line

By Hudson Sangree

FERC on Thursday rejected a request by developers of a proposed $2 billion pumped storage project for a declaratory order entitling it to cost-based rate recovery as a transmission asset in CAISO.

The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition for its Lake Elsinore Advanced Pumped Storage (LEAPS) project was an end run around the ISO’s transmission planning process (TPP) (EL18-131).

ferc caiso pumped hydro leaps — Lake Elsinore | *City of Lake Elsinore*

“We dismiss Nevada Hydro’s petition and find that a request to designate LEAPS as a transmission facility is premature at this time,” FERC wrote. “LEAPS has not been studied in the CAISO TPP to determine whether it addresses a transmission need identified through that process, and, if such a need were met, how the facility would be operated. Absent such information, the commission cannot make a reasoned decision on whether LEAPS is a transmission project and thus eligible for cost recovery under the [transmission access charge].”

CAISO said FERC should not accept Nevada Hydro’s analysis that LEAPS is a cost-effective solution to transmission planning needs, noting that the company’s benefits study relied heavily on revenues from market-based services such as energy market sales, regulation, load following, capacity, spinning and ramping. The CPUC said it is unlikely that pumped storage will be the most cost-efficient means of meeting reliability, grid integration or greenhouse gas reduction targets between now and 2030.

Nevada Hydro cited FERC’s Western Grid ruling and its 2017 policy statement in seeking the project’s classification as a transmission asset. (See Storage Can Earn Cost- and Market-Based Rates, FERC Says.)

The $2 billion LEAPS project, which entered CAISO’s interconnection queue in 2005, has had a long and controversial history, with local governments and many residents opposed to its construction on the natural 3,000-acre Lake Elsinore, adjacent to the Cleveland National Forest in Southern California’s Riverside County.

This is the second time Nevada Hydro has failed to obtain FERC approval to advance the project. In the 2008 Nevada Hydro case, the commission rejected a request that CAISO assume operational control over the facility and found that the developers failed to show why it should be treated differently from other pumped hydro facilities that had not been granted rolled-in transmission pricing.

In seeking the declaratory order, Nevada Hydro said it, not CAISO, would maintain operational responsibility for LEAPS.

But the commission said that change did not entitle the project to circumvent the ISO’s planning process.

“Requiring LEAPS to be reviewed through the CAISO TPP is consistent with the commission’s policy that regional transmission planning processes should identify transmission needs and solutions in a coordinated, nondiscriminatory process that is open to all interested stakeholders,” the commission said. “We note that CAISO has committed to studying LEAPS as a transmission proposal, both as a means to address reliability needs (if it is submitted in an appropriate request window of CAISO’s TPP and if the proposal specifies the CAISO-identified reliability constraints the project could mitigate), and as an economic planning study request.”

The project would include 500-MW of pumped storage, the Talega-Escondido/Valley-Serrano 500-kV Interconnect and a 30-mile line to transmission systems owned by Southern California Edison and San Diego Gas & Electric. Its hydroelectric license application is pending before FERC (P-14227-003).

September 24, 2018January 3, 2024

FERC Sides with Minnesota City on Transmission Project Cost Recovery

By Michael Brooks

FERC on Thursday affirmed an administrative law judge’s decision to assign a Minnesota city’s portion of the 345-kV Hampton-North Rochester line (H-NR) to Northern States Power’s pricing zone, rejecting arguments by NSP parent Xcel Energy (ER14-2154-006, ER15-277-005).

The H-NR line was completed in September 2016 as part of the Hampton-Rochester-La Crosse (HRL) transmission project into Wisconsin. The city of Rochester, Minn., through its Rochester Public Utilities (RPU) municipal utility, owns 14.7% of the line; NSP, Southern Minnesota Municipal Power Agency (SMMPA) and Dairyland Power Cooperative are co-owners, at 49.5%, 23.4% and 12.4%, respectively.

The line was included in MISO’s 2008 Transmission Expansion Plan, and the RTO asked FERC in 2014 to add RPU as a transmission owner in NSP’s zone, where the line is located, enabling the city to receive its annual transmission revenue requirement (ATRR) for the line from the zone.

MISO’s Tariff specifies that within each zone, transmission rates are based on the sum of the revenue requirements for facilities “located within that pricing zone.” Xcel argued that the language did not refer to the facilities’ physical locations, but rather the zones the facilities’ ATRRs are “allocated” to for ratemaking purposes. The company pointed out that the word “physically” does not precede the word “located” in the language. Thus, Xcel argued, the Tariff does not mandate that H-NR should allocated to NSP’s zone.

In his initial decision in May 2017, ALJ David H. Coffman found this unpersuasive, pointing to the dictionary definition of “located.”

“The plain meanings of the terms ‘located’ and ‘allocated’ are not remotely similar,” he wrote.

Xcel took exception to the ALJ using dictionary definitions to support his conclusions. But the commission said Coffman was merely using them as evidence of common sense interpretation of the words.

“We are unpersuaded by arguments seeking to differentiate the use of the word ‘located’ in different contexts with respect to the interpretation of” the Tariff, FERC said. “Such arguments stray from the ordinary meaning of the word and also introduce additional problems, notably different interpretations of the word ‘zones’ with respect to the location of load and the location of transmission facilities. …

“Transmission facilities are not ethereal concepts but fixtures that cannot be moved from zone to zone,” FERC added. “Accordingly, given this context, interpreting the word ‘located’ as ‘existing in a particular place’ is logical.”

Xcel also argued that because Dairyland was allowed to allocate its ATRR for both H-NR and HRL to its own zone, where its load is located, RPU’s ATRR need not be allocated to NSP’s zone. Rather, it could have been allocated to SMMPA’s zone, where RPU’s transmission facilities and load are located.

The ALJ, however, noted that the MISO Tariff allows an exception if the TOs agree upon a different allocation and FERC approves the agreement, as occurred in February 2017 for HRL. (See FERC OKs Settlement, Opens Docket in Dispute over Minn.-Wis. Tx. Project.) That agreement excluded the ATRR allocation for H-NR, which could not be resolved at the time.

JPZ Agreement Dispute

In a related order, FERC ended its examination of the joint pricing zone (JPZ) agreement among TOs in NSP’s zone, after NSP added RPU as a party to the agreement pending the resolution of the ATRR dispute (EL17-44). NSP had balked at adding RPU even after FERC approved it as a MISO TO. The commission had warned in February 2017, when it began its investigation, that revisions to the MISO Tariff or Transmission Owners Agreement (TOA) could be necessary to prevent such exclusions in the future.

Under the TOA, MISO distributes revenue to each JPZ’s host TO, which then distributes it among each TO in its zone. The RTO had been distributing revenue to NSP based on RPU’s approval as a TO in the zone, but because NSP had not added RPU to the agreement, the company was withholding the city’s revenue.

While RPU acknowledged that its situation had been resolved, it told FERC that the TOA gives host TOs “the opportunity to leverage the need for a JPZ agreement against a new, typically smaller, transmission owner seeking to recover some or all of its transmission revenue requirement from that zone.”

“This leverage is often coupled with claims of undue cost shifts and various allegations of unjust and unreasonable rate impacts or cost allocations to make it difficult for a smaller transmission owner such as RPU to integrate into MISO,” RPU said.

FERC disagreed. “There is neither evidence that such denial, or use of that threat to affect the terms of cost allocation, is widespread, nor evidence that the host transmission owner responsibilities have either precluded new transmission owners from receiving their respective ATRRs that have been accepted by the commission or would have a chilling effect on new transmission owners’ interest in joining MISO, as RPU suggests.”

The commission, however, reiterated that “a JPZ agreement should reflect commission-accepted transmission rates. … Therefore, any dispute associated with a new transmission owner’s ATRR should not delay the filing of a JPZ agreement to include a new transmission owner to the zone.”

Chairman Kevin McIntyre recused himself from both orders.

September 23, 2018

FERC Rejects CAISO Congestion Revenue Scaling Plan

By Hudson Sangree

FERC last week approved CAISO’s plan to reduce the capacity available in its congestion revenue rights auctions but rejected a proposal to cut CRR payments that had garnered opposition.

The commission approved CAISO’s proposal to reduce transmission system capacity available in the annual CRR allocation and auction processes from 75% to 65%, which was unopposed. But FERC rejected as unjust and unreasonable a plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges (ER18-2034).

The rejection means CAISO may have to seek additional changes to fix a system it says unfairly charges ratepayers around $100 million annually, largely to fund speculators’ profits.

caiso congestion revenue rights crrs — Ratepayer auction revenues compared with congestion payments for auctioned CRRs | *CAISO Department of Market Monitoring*

CRRs are financial instruments that can be used as a hedge against congestion charges or as an investment to speculate that the congestion rent will be greater than the purchase price. Shortfalls between CRR revenues and payouts resulted in ratepayers making up a difference of approximately $500 million over five years, the ISO has argued.

Under the scaling plan, CAISO would have compared the congestion revenue and revenue from counterflow CRR holders for each constraint to the payments due to prevailing flow CRR holders for that constraint. When it did not collect enough revenue to pay prevailing flow CRRs the full value for an hour, the ISO would reduce the payments proportionally.

CAISO proposed scaling CRR payments only in the prevailing flow direction, not payments due from counterflow CRR holders on the same constraint. Because counterflow CRRs fund prevailing flow CRRs, CAISO said discounting counterflow CRRs could increase revenue insufficiency.

The scaling plan was opposed by Calpine, the Western Power Trading Forum, the Alliance for Retail Energy Markets and others.

“As protesters note, the commission has long held that counterflow and prevailing flow CRRs should be netted against one another such that the expected net value of two obligation CRRs of equal megawatts from A to B and B to A will be equal to zero,” FERC wrote, citing its 2006 ruling on CAISO’s Market Redesign and Technology Upgrade (MRTU) and a 2016 order on PJM’s financial transmission rights market. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)

“Consistent with the commission’s findings in the MRTU and 2016 PJM FTR orders, we continue to believe that a symmetric approach is just and reasonable, while an asymmetric approach has not been shown to be just and reasonable.”

The commission added that CAISO’s proposal would have the “undesirable” effect of making the CRR product less transparent.

“Market participants could face difficulties valuing a counterflow hedge relative to a prevailing flow hedge, since one would be discounted while the other would not,” the commission said. “This lack of transparency could discourage market participants from bidding for counterflow CRRs, which could reduce liquidity and could, in turn, exacerbate the CAISO CRR market’s current market efficiency problems,” such as the auction revenue shortfalls.

The capacity release reduction proposal will cut the amount of CRRs made available in the annual auction while increasing those available through the monthly auction. In approving the plan, the commission noted that it “shifts the release of CRR capacity from the annual auction to the monthly auction, where CAISO has more information concerning the topology of the transmission system. CAISO’s analysis shows that a 10% decrease in available annual capacity would decrease the amount of CRRs that are likely to be infeasible in the day-ahead market and reduce CRR revenue insufficiencies.”

CAISO’s Board of Governors had approved the CRR rule changes in June. (See CAISO Board Approves More CRR Auction Changes.)

The issue has pitted the ISO’s Department of Market Monitoring against financial traders, which the department says were the biggest beneficiaries of the current market design.

In the first half of 2016, the Monitor said, financial traders made $22.7 million in profits, more than doubling their investments as they paid 49 cents into the ISO’s auctions for every dollar earned. Over the same period, power marketers and generators took in about $3.9 million and $800,000, respectively, paying 82 and 85 cents for every dollar of congestion revenue earned. (See CAISO Monitor Seeks Congestion Rights Revenue Auction Reform.)

Thursday’s order was the second time this year that FERC has addressed CAISO’s attempts to upgrade its CRR auctions.

In June, FERC approved a separate set of CRR rule changes, including limiting allowable source-and-sink pairs for CRR transactions to those that align with typical supply delivery paths. (See FERC OKs Tighter Rules for CAISO CRR Auction.)

Transactions using non-delivery sources and sinks, such as between two generator locations, represent about 81% of auction shortfalls, the ISO noted in arguing for the change.

September 23, 2018

NEPOOL: FERC Can’t Change Press, Public Ban

By Rich Heidorn Jr.

FERC can’t overturn the New England Power Pool’s longstanding ban on public and press access to stakeholder meetings, NEPOOL told the commission Thursday.

In a motion to dismiss RTO Insider’s protest seeking to open meetings to the public and press, NEPOOL said FERC lacks jurisdiction to force changes and that RTO Insider lacks standing to challenge the rules.

“NEPOOL does not engage in the transmission or sale of electric energy in interstate commerce, nor does it operate any facilities that are used for such purposes,” it said. “As such, NEPOOL is not a ‘public utility,’ and its supposed ‘press ban’ is not a ‘rate, charge or classification’ related to the transmission or sale of energy. These provisions of the [Federal Power Act] do not provide any basis for RTO Insider’s complaint.”

On Aug. 13, NEPOOL asked FERC to approve amendments to its Agreement to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings (ER18-2208). The group drafted the revisions after RTO Insider reporter Michael Kuser applied for membership in NEPOOL’s Participants Committee as an End User customer in March.

nepool iso ne ferc press ban — DayPitney attorneys David Doot and Patrick M. Gerity authored NEPOOL’s defense of its rules barring the public and press from attending stakeholder meetings. | *Day Pitney*

RTO Insider responded to NEPOOL’s filing with a Section 206 complaint Aug. 31 asking the commission to overturn the organization’s ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

NEPOOL’s 57-page filing, which it submitted in both dockets, cites the D.C. Circuit Court of Appeals’ 2004 order rejecting FERC’s attempt to force CAISO to replace its governing board. The D.C. Circuit vacated FERC’s action and remanded the case, ruling that “FERC … does not have the authority to reform and regulate the governing body of a public utility under the theory that corporate governance constitutes a ‘practice’ for ratemaking authority purposes.”

NEPOOL also said RTO Insider’s request that FERC open the organization’s meetings or strip it of its FERC-authorized role as ISO-NE’s stakeholder body is a “collateral attack” on prior commission orders giving NEPOOL its role in the RTO. While NEPOOL claimed FERC had no jurisdiction to force it to change its rules, it did not challenge the commission’s authority to order ISO-NE, which it noted “is the FERC-jurisdictional public utility,” to adopt a new stakeholder body.

Former FERC Chairman Pat Wood III and former Commissioner Nora Mead Brownell have said they were unaware when they approved NEPOOL as ISO-NE’s stakeholder body in 2004 that NEPOOL barred the public and press from its meetings. According to former Chairman Jon Wellinghoff, FERC commissioners also were unaware of the ban in 2008 when they approved Order 719, which requires that RTO/ISO processes be inclusive, responsive and represent minority interests. (See Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL.)

Seven Intervenors File Comments

NEPOOL was among seven intervenors filing comments in the docket opened by RTO Insider. All but one of the others — including consumer, environmental and press freedom advocates — joined in calling for the opening of the meetings.

Also calling on the commission to open the meetings were a dozen members of the House of Representatives. Their Sept. 18 letter said NEPOOL’s proposal to codify its unwritten ban on public and press coverage “at best … is misguided; at worst it is an unconscionable restraint on the critical need for transparency in the New England energy and electric markets. … Codifying such a ban is antithetical to principles of good governance and the mission of FERC.

“The current NEPOOL practice of publicly releasing meeting agendas, draft resolutions and background materials prior to meetings, as well as official records and meeting minutes following meetings, is not an adequate substitute for attending and understanding the meeting itself,” they continued. “Planning for the electric grid is an inherently governmental function and justifiably must be transparent to the greatest extent possible.”

The letter was signed by Rep. Frank Pallone (D-N.J.), the ranking member of the House Energy and Commerce Committee; Rep. Fred Upton (R-Mich.), the chairman of the committee’s Subcommittee on Energy; Rep. Bobby Rush (D-Ill.), the ranking member on the subcommittee; seven of nine members from Massachusetts’ delegation; and one representative each from Rhode Island and Vermont.

In their filings, NEPOOL member William P. Short III and the Reporters Committee for Freedom of the Press essentially repeated arguments they made opposing the ban in NEPOOL’s docket. (See NEPOOL Alone in Support for Press, Public Ban.)

‘Not Informal Brainstorming Sessions’

But the New Hampshire Consumer Advocate, Public Citizen and a joint submission by environmental groups Earthjustice, the Conservation Law Foundation and the Sustainable FERC Project expanded on their earlier filings.

The environmental groups noted that FERC previously ordered modifications to the NEPOOL Agreement in a 1997 order directing the organization to eliminate a requirement that members “‘be engaged in or propose to engage in the wholesale or retail electric business in New England,’ noting that it had prohibited geographic limitations on membership in power pools in a prior order.”

New Hampshire Consumer Advocate D. Maurice Kreis said that NEPOOL’s “jump ball” rights to submit filings opposing ISO-NE makes it more powerful than other RTO stakeholder bodies. “In legal terms … NEPOOL is as powerful as ISO New England is with respect to the market rules that govern how electricity and related products are traded,” he said.

The jump-ball provisions “belie the impression NEPOOL seeks to convey here of serving merely as a kind of debating forum whose decisions rise and fall purely based on their persuasive value,” he added. “Meetings of the principal committees of NEPOOL are not informal brainstorming sessions.

“There are also potential First Amendment implications of a commission-approved restriction on the speech and publication activities of NEPOOL meeting attendees. While NEPOOL is not itself an instrumentality of government, ‘private speech prohibitions can still implicate the First Amendment when given the imprimatur of state protection through civil or criminal law,’” he said, citing the Supreme Court’s landmark 1964 ruling New York Times Co. v. Sullivan.

Conflicts of Interest

Tyson Slocum, energy program director for Public Citizen, challenged NEPOOL’s contention that an “overwhelming majority” of NEPOOL participants voted to ban journalists. Of the 113 NEPOOL participants who were eligible to vote during the June 26 NEPOOL meeting to consider banning reporters, “more voted to abstain (58) than the number casting votes for (32) and against (23) COMBINED.”

Slocum said some current and former NEPOOL officers that supported the ban “earn outside income selling ‘intelligence’ about NEPOOL proceedings, creating financial conflicts of interest.”

“Twenty of the 32 votes in favor [of the ban] were represented by lobbyists who either serve as NEPOOL officers or were recruited by NEPOOL to serve as an expert witness on behalf of NEPOOL’s advocacy to ban journalists. This is an alarming concentration of voting power by lobbyists who have a financial self-interest to maintain a ban on the public and journalists. … NEPOOL’s restrictions on public and media access allow those with restricted access to possess valuable information about NEPOOL activities that are nonpublic, which they can then sell for lucrative amounts to interested parties.”

Slocum noted that almost 80% of NEPOOL’s 2018 budget is generated through membership fees and expenses and that NEPOOL members in the Transmission and Publicly Owned sectors can collect these expenses from ratepayers. “While NEPOOL likes to characterize itself as a ‘private, voluntary association,’ its reliance on ratepayer money — when combined with FERC-delegated authorities — mean NEPOOL is not entitled to be treated as a normal ‘private’ association for purposes of admitting the general public and journalists into its policy-related meetings.”

Consultant Challenges ‘Mischaracterization’

Aside from NEPOOL, the only filing that did not support opening the meetings was one by consultant Erik Abend, who said he was seeking to correct the “mischaracterization” of his business in RTO Insider’s complaint.

Abend, the primary NEPOOL committee member for the Small Renewable Generation Group in the Alternative Resources Sector, acknowledged that he provides “high-level explanations, analysis and advice” on issues discussed at stakeholder meetings, both to his clients and to non-NEPOOL members through a weekly summary published to a secure website for the Northeast Energy and Commerce Association (NECA).

Abend said his role does not meet NEPOOL’s proposed definition of “press” and that his summaries “do not directly quote or paraphrase any statements made by market participants during any of the NEPOOL committee meetings. … As with the summaries that I provide directly to my NEPOOL member clients, the information contained in these summaries for NECA are drawn directly from materials that are publicly available from the ISO-NE and NEPOOL websites.”

Meetings are ‘Not Secret’

In its filing, NEPOOL said it was entitled to “discriminate” in allowing consultants to attend meetings while barring the press because the former “do not endanger the tradition of open dialogue in NEPOOL meetings by publicly reporting on the statements of other members.”

NEPOOL said RTO Insider lacks standing to challenge its rules because it does not participate in New England “either as a market participant or an end-use customer.” It also said the company could not contest the organization’s refusal to admit its reporter, Michael Kuser, a Vermont resident.

It insisted its meetings are “far from secret. The date, time and location of NEPOOL meetings are posted publicly and are available online … [and] the agendas and materials for each meeting are almost all circulated well in advance.”

It noted that its participants include consumer-owned utility systems, public interest groups, state consumer advocates and representatives of end-use consumers, and that state regulators and elected officials can attend in person or through delegates.

The group said it balances “two types of ‘transparency’ – (i) transparency to the non-stakeholder general public; and (ii) transparency among its meeting attendees.”

September 23, 2018

New Direction for MISO’s Energy Storage Task Force

By Amanda Durish Cook

ST. PAUL, Minn. — Having fulfilled its original mandate, MISO’s Energy Storage Task Force (ESTF) will get a new lease on life: as an expert advisory panel on increasingly sophisticated storage issues.

The move means the task force will begin developing white papers on technical storage issues and approaching other stakeholder committees about recommended agenda items.

MISO’s Steering Committee last week endorsed the change to help resolve an identity crisis that arose this spring after the task force wrapped up its key mission of identifying discussion topics on FERC Order 841 compliance to be assigned to larger stakeholder committees.

The committee approved a revised ESTF charter last month that allows the group to evaluate energy storage issues rather than simply identifying them for committee assignment. It can also make recommendations directly to MISO and stakeholders, without first approaching the committee. (See MISO Grants Storage Task Force More Authority.)

But stakeholders and ESTF members began asking if the task force should stop reporting directly to the Steering Committee and perhaps report to another committee actively discussing electric storage. Under MISO’s Stakeholder Governance Guide, the Steering Committee is tasked with assigning new grid issues to stakeholder committees.

Although the ESTF will not change its reporting relationship, the changes mean ESTF leadership can now reach out to larger stakeholder entities like the Resources Adequacy Subcommittee and the Market Subcommittee to discuss possible storage agenda items and updates ahead of meetings, as suggested by Xcel Energy’s Carolyn Wetterlin during a Sept. 19 Steering Committee meeting.

Wetterlin pointed out that many storage issues naturally overlap stakeholder committees despite MISO’s redesign that discourages duplicate discussions among committees.

The ESTF, at the Steering Committee’s direction, will also explore the possibility of creating white papers on technical storage issues that went largely undiscussed while the group dealt with Order 841.

miso energy storage task force order 841 — Tia Elliott | © *RTO Insider*

Committee Chair Tia Elliott said after FERC first issued the order, MISO was working quickly to identify various storage issues and place them into the most appropriate stakeholder committee. She said that immediate need may have overshadowed the potential for the ESTF to discuss storage participation models and innovation beyond Order 841. She suggested the ESTF could now take on those periphery issues and work with MISO to create white papers.

“I want to make sure that stakeholders are not being stymied by the process, and bureaucracy is not holding up the ESTF’s work. I’ve heard offline discussion that red tape is getting in the way, and that was never the intent of the stakeholder redesign,” Steering Committee Vice Chair Audrey Penner said.

Entergy’s Yarrow Etheredge said white papers would be helpful to explore technical details, such as how exactly storage can function as transmission. “I think there’s a role for the storage task force there, but unfortunately, they’d have to discuss issues already assigned to another committee,” she said.

Northern Indiana Public Service Co.’s Bill SeDoris said it would be helpful if the task force wasn’t required to go before the Steering Committee every time it wants to raise a possible issue for another stakeholder committee to discuss.

Elliott said the committee will examine whether the practice of obtaining its approval before moving issues to other committees is working as intended. In the meantime, she urged ESTF Chair John Fernandes to come forward with storage issue assignments as needed and said the committee could hold special conference calls to assign new issues.

Fernandes said he didn’t mind if the task force continued to report to the Steering Committee; however, he said bureaucratic limitations should not stifle discussion in committee meetings.

“Even as a storage guy, I wouldn’t predict what’s going to happen with storage two years out. It’s moving that quickly. … Flexibility is key,” Fernandes said. “I think everybody appreciates that this is a little tricky right now.”

Fernandes said the ESTF’s next meeting will tackle ideas on how storage will be charged for transmission reservations and discuss how hybrid storage setups might interact with the MISO system.

September 23, 2018

Advisory Committee Divided on MISO Outage Authority

By Amanda Durish Cook

ST. PAUL, Minn. — MISO’s Advisory Committee appeared split last week over whether the RTO should assume greater authority in granting planned outages, with many members offering alternative and complementary ideas to increased outage control.

Following a tradition established three years ago, the Sept. 19 Advisory Committee “hot topic” discussion began with a theme song.

miso advisory committee planned outages — MISO Advisory Committee discussion | © *RTO Insider*

“I couldn’t find a song with ‘maximum generation alert,’” MISO Director of Resource Adequacy Coordination Laura Rauch said to laughter.

She eventually settled on Stealers Wheel’s “Stuck in the Middle with You” to capture the situation.

“We have a generally aging generation fleet, and that’s increasing outages and worsening coordination of those outages,” Rauch said.

According to its Business Practices Manual, MISO can only “recommend [an outage] schedule that maintains system security and minimizes adverse impacts.” But in its 2016 State of the Market report, the Independent Market Monitor raised the need for MISO to have a bigger say in outage scheduling, kicking off an off-and-on discussion ever since. (See “Generation Outages,” MISO in Harmony with IMM State of the Market Report.)

Discussion moderator Julia Johnson, president of regulatory advising firm Net Communications, took a more optimistic approach, playing “The Power” by Snap!

“We’ve got to figure out who is ‘the lyrical Jesse James,’” Johnson said, urging stakeholders to offer their best ideas to minimize outage impacts.

Some Advisory Committee members said the situation has become such that MISO members cannot effectively coordinate outages to avoid emergency conditions.

But Minnesota Public Utilities Commissioner Matt Schuerger said the Organization of MISO States does not support giving MISO expanded authority in approving outages, with the group saying that the RTO should “articulate a compelling need before any new authority is considered.” OMS maintains that MISO already is allowed to analyze generator outage requests and recommend outage scheduling changes as needed.

Kevin Murray, representing the Coalition of Midwest Transmission Customers and MISO’s Eligible End-User Customers sector, said he understood regulators’ hesitancy to “turn over the keys to the car.” But he said in his 27 years in the business, he had never seen MISO call a NERC Level 2 emergency like the one seen during the previous week. (See MISO in Conservative Ops After Emergency Declaration.)

“We shouldn’t be having these events on a Saturday. We need to do some soul searching,” Murray said. He also pointed to FERC and NERC’s recently announced inquiry into the January cold snap that resulted in generation outages and loads that approached summertime levels in MISO South. (See FERC, NERC to Probe January Outages in MISO South.)

“The writing is on the wall. … Either we do something, or they do something,” he said.

Several stakeholders said MISO should act to better coordinate outages before winter arrives, saying solutions from its comprehensive Resource Availability and Need project will arrive too late to avoid another outage-related emergency.

Clean Grid Alliance Executive Director Beth Soholt, of the Environmental sector, said MISO should study the cost of outages on the system. Robert Mork, of the Indiana Office of Utility Consumer Counselor, reminded executives of a mission statement that includes cost consciousness.

Murray said MISO might consider obtaining dispatch control of smart thermostats and electric vehicle charging stations to lower load when needed. “I would encourage people not to think about this one-dimensionally,” he said.

North Dakota Public Service Commissioner Julie Fedorchak suggested MISO begin collecting aggregate load and generation availability estimates from utilities for both the month and week ahead.

Wisconsin Public Service’s Chris Plante, of the Transmission-Dependent Utilities sector, pointed out that in some weeks, MISO’s maintenance margin is a negative number, indicating that generation operators have already taken too many outages. The RTO’s maintenance margin shows the amount of generation that can be taken out of service for a given time period without risking resource adequacy.

Representing the TDU sector, Madison Gas and Electric’s Megan Wisersky said it also believes MISO shouldn’t be handed control over outage scheduling.

“You want your unit on to make money from it. Generators tend to be very unique beasts, and you may only get consultants and specialists on your site at a specific time,” Wisersky said. “When MISO asks a unit to come off an outage, the unit is sometimes in pieces on the turbine floor. We’re not capricious in this … they’re not casual decisions.”

Murray said MISO’s new capacity advisory warning is a good step to help mitigate the effects of outages because units, if ready, will want to re-enter the market to scoop up the better prices available in a capacity shortage.

Multiple stakeholders said they would like MISO to attach economic signals to outage timing. Murray said the RTO could add to its markets an additional economic demand response product, which identifies a price to incent some load to get off the system. He also encouraged discussing an economic consequence if generation resources are unavailable during peak times. He brought up PJM’s Capacity Performance rules, though he said he wasn’t advocating use of a similar penalty in MISO.

Plante said MISO should revisit its proposal to create a seasonal capacity market to get a better idea of resource availability. He said MISO’s current capacity accreditation based on the summertime peak might not be the best route for resources such as wind facilities, which have their most productive months outside of summer.

Michael Curran, chair of the MISO Board of Directors, urged the RTO and stakeholders to “get everything on the table,” suggesting that the solution to poor outage coordination will be multifaceted, with more entities assuming more outage authority.

September 23, 2018

FERC Rejects Rehearing in MISO-PJM Export Issue

By Tom Kleckner

FERC last week denied a rehearing request but clarified an underlying order addressing MISO’s multi-value transmission projects (MVPs) (ER10-1791).

PJM, American Municipal Power and PJM transmission owners appealed the 2016 ruling, which came in response to the 7th U.S. Circuit Court of Appeals’ 2013 remand of a previous FERC order. The commission’s ensuing order determined that a limitation on MISO’s export pricing to PJM for MVPs was no longer justified, clearing the way for MISO to recover costs for those projects benefiting PJM customers by charging a fee on exports to PJM. (See MISO to Begin Charging Tx Fees on PJM Exports.)

In the order on remand, FERC said that given the growth of wind energy, as well as the need for PJM entities to access the resources and for MISO to deliver those resources to PJM, it was “appropriate to allow MISO to assess the MVP usage charge for transmission service used to export to PJM.”

ferc miso pjm multi value projects mvp — Construction work on Ameren’s Illinois Rivers transmission project, a 345-kV line that included five multi-value projects. | *Plocher Construction*

MISO created the MVP category in 2010 for projects that address more than one reliability or economic need across multiple transmission zones. It originally intended to allocate project costs to all of its load and exports, but FERC excluded the export charge because of concerns over rate pancaking.

The commission rejected claims that it used the same evidence to justify the MVP charges’ application in the order on remand as it did to previously reject them. FERC said it reconsidered its previous determinations on this issue, including, but not limited to, findings made in previous decisions on the rate pancaking issue.

The commission said it centered its original decision on FERC Order 2000’s factors for determining appropriate RTO configuration, but it did not consider how the market-to-market (M2M) process affects those issues. In the order on remand, FERC found that the M2M process allows the RTOs to more efficiently address the inefficiencies and other issues arising along their seam, and noted that the grid operators added many “general improvements to coordination” between them since 2016.

FERC rejected PJM’s request to clarify that MISO must use the RTOs’ joint operating agreement process to review any MVP whose costs would be assessed on exports to PJM through the MVP usage rate, saying it was “based on a false premise.” The MVP usage rate is assessed only to customers voluntarily taking transmission service under the MISO Tariff and does not allocate the cost of every MVP to PJM.

The commission granted PJM’s clarification request regarding potential double recovery of the cost of certain MVPs, saying that when an MVP is selected in both RTOs’ regional transmission plans as an interregional transmission project, only the portion of an MVP’s cost allocated to MISO may be recovered in the MISO MVP usage rate.