November 17, 2024

FERC Approves SPP Shortage Pricing Changes

By Tom Kleckner

FERC on Wednesday accepted SPP’s proposed Tariff revisions related to shortage pricing, rebuffing the protest of one key stakeholder.

Submitted in response to FERC Order 825, SPP’s changes removed ramp-sharing obligations and other Tariff provisions that prevent shortages caused by insufficient ramp capability from triggering shortage pricing. The RTO also removed certain constraints and their associated violation relaxation limits (ER17-772).

But the commission also rejected SPP’s proposed provisions creating a demand curve designed to set scarcity prices for energy shortages, ruling that the changes fell outside the scope of Order 825. FERC said the order did not require SPP to change its shortage pricing levels, only that it initiate procedures when a shortage is indicated.

The commission provided SPP 30 days to submit a compliance filing that either removes the demand curve provisions or explains how they comply with Order 825. It also directed removal of SPP’s suggested definition of “scarcity pricing,” allowing the RTO to propose a change or modify shortage-pricing levels in a separate Section 205 filing.

Order 825 requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. SPP was one of several RTOs that already settles those transactions in five-minute intervals. (See FERC Issues 1st RTO Price Formation Reforms.)

Golden Spread Electric Cooperative protested SPP’s changes, contending that the filing did not fully comply with Order 825 because it did not address the RTO’s practice of committing additional capacity through the reliability unit commitment (RUC) process or through manual operations that can prevent potential scarcity pricing events. The co-op said this practice is not transparent, creating uplift charges and a disincentive to make efficient operations and investment decisions.

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FERC has suggested SPP address through its stakeholder process concerns over its RUC and manual commitment practices during scarcity conditions. | © RTO Insider

Golden Spread argued that SPP should procure fewer resources through the RUC and manual processes, and instead rely on the submission of competitive offer curves in the day-ahead and real-time markets. It asked FERC to require that SPP eliminate RUC and manual commitment practices that mask scarcity pricing conditions and address any commitment outside of the normal markets.

The commission disagreed, dismissing Golden Spread’s concerns as being outside the proceeding’s scope. FERC noted Order 825 did not require the co-op’s suggested modifications to RUC or manual commitment processes, but it agreed Golden Spread “has raised an important issue that SPP should consider exploring through its stakeholder process.”

Zero Uplift Charges for Resources Dispatched to Zero

The commission also approved SPP’s proposal to exempt generating resources dispatched to zero from paying uplift charges, ruling the plan is consistent with the RTO’s existing provisions that ensure de-committed resources are not charged for uplift (ER17-520).

FERC found that resources dispatched to zero at SPP’s instruction make identical energy contributions to the real-time market as de-committed resources. “Thus, it is reasonable that both be treated the same with regard to uplift charges,” the commission said.

SPP member Golden Spread supported the Tariff revisions but asked the commission to require further changes to allow quick-start resources to voluntarily de-commit and buy back their day-ahead position from the real-time market without being assessed uplift charges, or adapt the security constrained economic dispatch software to accommodate those resources’ unique nature.

FERC rejected that request, saying it was beyond the scope of the Section 205 proceeding.

MISO, IMM Report Efficient Summer Months

By Amanda Durish Cook

ST. PAUL, Minn. — Three days shy of summer’s end, MISO’s staff and Independent Market Monitor convened to commend RTO operations personnel for a successful season.

MISO market monitor summer peak
Patton | © RTO Insider

Monitor David Patton said MISO’s real-time operations did a fine job of navigating summer’s Hurricane Harvey, Tropical Storm Cindy, the Aug. 21 solar eclipse and short bursts of high temperatures.

“We haven’t had any meteorites, but almost everything else under the sun,” Director Paul Bonavia joked during the summer operations presentation at the Sept. 19 meeting of the Markets Committee of the Board of Directors.

Vice President of System Operations Todd Ramey said MISO used its new hurricane action plan for the first time, maintaining communication and receiving updates from local operators near the storm. MISO held realistic hurricane simulations with MISO South operators during May and June, a first for the RTO, which ordinarily holds less-detailed hurricane drills.

“Hurricane Harvey proved to be mostly a rain and major flooding event. It did have some impact on transmission in the Eastern Texas area … but we maintained reliability throughout,” Ramey said.

Patton said despite occasional weather outbursts, the summer was “a little bit less eventful than past summers.” He called the 120.6-GW summer peak load on July 20 “very manageable” and “well below” the 125-GW forecast. A 6% rise in natural gas prices from last summer was offset by a 5% decrease in real-time energy prices due to mild temperatures and lower-than-expected average load.

The Monitor commended MISO’s ability to not declare any maximum generation events during the summer despite multiple operating reserve shortages from contingencies. He also praised MISO for producing more accurate day-ahead forecasts and more complete resource commitments when compared to last year. He told the board that while severe weather during June led to islanding in MISO, the RTO “was able to model the units in the islands and send appropriate prices during the events.”

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Markets Committee of the Board of Directors meeting in progress | © RTO Insider

Patton also said MISO managed real-time congestion costs effectively during the summer, as they fell from $463.5 million last summer to $334.5 million this summer, in part because of moderate load.

Divergence on ELMP

But the Monitor differed with MISO on the efficacy of the RTO’s extended locational marginal price (ELMP) program, which this spring was expanded to include resources with one-hour start-up times. The program was previously available only to 10-minute fast-start resources.

The ELMP effort is not fulfilling its potential, resulting in only a 29-cents/MWh price increase in the real-time energy market since its expansion in spring, Patton said. The Monitor has long called on the RTO to expand ELMP to allow all generators with two-hour minimum run times to set prices.

MISO said the Monitor’s price-setting expansion would not be worth the expensive software change, but Patton said his change would have increased LMPs by $7/MWh, reflecting the true cost of using peaking units.

CEO John Bear said MISO only expected modest price impacts using ELMP, and the program has already exceeded the RTO’s expectations.

Ramey pointed out that MISO’s ELMP was judged a success in the recent U.S. Energy Department electricity markets report.

“I think FERC and others will be very interested in expanding this,” said Patton, who called ISO-NE’s price formation efforts “a Ferrari” in comparison.

CAISO Load-Shifting Product to Target Energy Storage

By Jason Fordney

FOLSOM, Calif. — CAISO has launched what will be a years-long initiative to develop a program to pay storage resources to absorb excess renewable generation from the grid and make the energy available later, creating a new profit stream strongly desired by energy storage companies.

Storage companies such as Tesla have been urging CAISO to develop the new product as way to incentivize clean energy and reduce solar curtailments. During certain times of day, large solar surpluses on the ISO’s system can sometimes produce negative wholesale electricity prices and require curtailing output that could be stored and used at other times.

The load-shifting product will be the focus of the third phase of the ISO’s Energy Storage and Distributed Energy Resources (ESDER) program. CAISO changed the focus of the initiative to a behind-the-meter load-shifting product rather than the excess load-consumption product that had previously been discussed.

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Goodin | © RTO Insider

CAISO Manager of Infrastructure and Regulatory Policy John Goodin warned about a potential inherent flaw in developing an excess load consumption product.

“You can set up an incentive to where it is profitable just to waste energy,” Goodin said during a briefing of the ISO’s Board of Governors.

A load-consumption product could incentivize buyers to waste energy when a wholesale negative payment is higher than the retail payment. The purpose of the load-shifting product, however, is to incentivize productive use of excess renewable generation, Goodin said.

“That is good for the economy, it is good for the environment and seems like sound public policy,” he said, adding that the storage community supports the load-shifting concept. Load-shifting resources — such as a battery — could consume load when prices are negative, and the stored energy could be released behind the meter for demand management or sent to the ISO system, among other possibilities, he said.

The board last month approved a set of market rule changes that comprised phase two of the ESDER initiative, developed during a year-long process. (See New CAISO Rules Spell Increased DER Role.) That package will be sent to FERC for approval.

During the ESDER 2 initiative, Tesla and other storage companies urged CAISO to develop a new distributed energy resource product that would pay storage for absorbing excess solar generation, but the ISO declined at the time, saying more information was needed. (See Storage Advocates Urge CAISO on DR Product.)

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Tesla and other energy storage companies are helping CAISO to develop a load-shifting product | Tesla

To consider the specifics of the new product, the ISO has held four meetings with storage stakeholders, including the California Energy Storage Alliance (CESA), Stem, Tesla and Green Charge. Stakeholders are finalizing the desired features of the product, and the ISO will establish working groups to fill in the details. CAISO is identifying gaps in its Tariff and current resource modeling capabilities to aid in the effort. Implementation is targeted for 2019.

CESA Director of Policy and Regulatory Affairs Alex Morris told the board that CAISO staff have over the past month worked diligently with the storage community on the proposal. “From our point of view, this is going to provide very helpful service to the CAISO, while also beneficially shifting loads,” Morris said, adding that he is hoping for rapid implementation.

“There really should be a special urgency to this product because there currently isn’t a market participation pathway for that type of behind-the-meter resource,” Morris said.

The board asked a few questions about the new product, such as how pricing would work, but did not take any votes as the proposal is in its early stages. The initiative would also require a round of comment and approval by FERC after an extensive stakeholder process that will include participation by the California Public Utilities Commission.

MTEP 17 Proposal: 343 New Transmission Projects at $2.6B

By Amanda Durish Cook

ST. PAUL, Minn. — MISO plans to recommend that its Board of Directors approve 343 new projects estimated at $2.6 billion as part of the RTO’s annual transmission plan.

This year’s draft project round-up comes in 40 projects short of MTEP 16 but costs about the same, directors and stakeholders learned at a Sept. 19 meeting of the board’s System Planning Committee.

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Curran (left) and Moeller | © RTO Insider

MISO Vice President of System Planning Jennifer Curran said the top 10 priciest projects in MTEP 17, ranging from $26 million to $149 million, are spread “fairly evenly” across the footprint, with three in Michigan, two each in Louisiana and Wisconsin, and one each in Iowa, Arkansas and eastern Texas.

While the RTO included only half of those projects for baseline reliability reasons, the Iowa and Wisconsin projects both originated from generator interconnection requests, showing that interconnections are increasingly becoming major transmission projects themselves, Curran said. MTEP 17’s most expensive project, a new $149 million 500-kV line from Hot Springs to Happy Valley in Arkansas, is meant to relieve reoccurring thermal overloads.

MISO MTEP market efficiency projects SPP Board of Directors
| MISO

Curran said just one MTEP 17 contender may qualify as a market efficiency project. The $129.7 million project involves construction of a new substation in eastern Texas equipped with a 500/230-kV transformer. The facility would accommodate a new 500-kV line running from Hartburg, Texas, as well as a reconfiguration of the existing Sabine-McFadden and Sabine-Nederland 230-kV lines to fully relieve area congestion and reduce the amount of voltage and local reliability make-whole payments needed in the West of the Atchafalaya Basin load pocket. Some MISO stakeholders this month complained about what they perceived as late-stage modeling changes to the project. (See Late Changes to Texas Project Frustrate MISO Participants.)

Curran said the project will undergo additional stakeholder review before coming back for board approval in early December.

No Tx Coming for North-South Constraint

MISO’s collection of MTEP 17 studies this year included a footprint diversity study, an extra analysis specifically designed to identify viable transmission projects to connect the RTO’s Midwest region with MISO South. However, Curran said not one of the study’s 35 potential projects could pass the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits.

“The physical congestion, while it exists, isn’t enough to justify a fairly expensive transmission project. I think there are other benefits that aren’t being considered, but that’s the nature of this process,” Curran said.

Curran said that over the course of the study, MISO “learned a lot about the nature of the flows” near the North-South transfer constraint.

FERC Approves SunZia Rate Authority

By Jason Fordney

FERC on Wednesday approved negotiated rate authority for a proposed 515-mile transmission project intended to carry renewable output from Arizona and New Mexico to “key interconnections” capable of serving markets farther west.

In its decision, the commission reissued and revised the rate authority it had initially granted the SunZia transmission project in 2011 (ER17-522).

As proposed, the SunZia project consists of up to two 500-kV lines in Arizona and New Mexico, running more than 500 miles to high-voltage interconnections within those states. The first phase would include an AC line with 1,500 MW of capacity, and a second phase consisting of another AC circuit with the same rating or a 3,000-MW DC line. The project’s current owners are SouthWestern Power Group, ECP SunZia, Shell WindEnergy and Tuscon Electric.

After originally obtaining rate authority in 2011, SunZia Transmission entered talks to sign on First Wind Energy as an anchor customer for up to 1,500 MW of capacity on the line. First Wind was subsequently acquired by SunEdison, which last year declared bankruptcy.

That prompted SunZia to apply for revised negotiated rate authority as transmission provider on behalf of its merchant owners. The company also sought permission to enter into an agreement with an anchor customer for up to 100% of the project’s merchant capacity. Half of the capacity of the line was to be allocated to one or more anchor customers, and the remainder made available through open season auctions. Anticipated development costs up to the beginning of construction are estimated to be as high as $75 million.

SunZia had to demonstrate that service on the project would not show preference to any particular bidder. The company held an open solicitation for the first phase of the project, selecting wind developer Pattern Energy Group as the preferred customer. SunZia said it expects Pattern will become a co-owner of the line, and majority merchant owners would become co-owners of the Pattern project.

“We find here that SunZia Transmission’s selection process was transparent and not preferential neither toward Pattern Development nor unduly discriminatory against other potential customers,” FERC said. “Notably, SunZia Transmission has demonstrated that all interested parties were treated comparably, provided with the same information and given opportunities to discuss the Project with SunZia Transmission.”

FERC in 2013 changed its approach to evaluating applications for rate authority, retaining its current “four factor” analysis, but said that anchor customers could be allocated 100% of the capacity and could be an affiliate of the transmission developer.

SunZia said the line is “likely to serve renewable resources predominantly. At all times, the merchant capacity and interconnections have been available without preference for any particular kind of resource.”

The company is targeting the first quarter of 2018 to commence construction on the first line, which is expected to go into service in 2020. The U.S. Bureau of Land Management last year granted a right of way for the project.

FERC Accepts Entergy Revision on ‘Moot’ Settlement

By Amanda Durish Cook

FERC has accepted a compliance filing from Entergy on a settlement meant to resolve a more than 20-year-old dispute between the utility and the Louisiana Public Service Commission — a settlement that may or may not be moot.

On Wednesday, FERC accepted Entergy’s revision to make the settlement’s “just and reasonable” standard of review provision applicable to third parties, a change FERC ordered last September (EL00-66-021).

Galvez Building housing the Louisiana Public Service Commission | © LA.gov

The issue dates to 1995, when the Louisiana PSC and New Orleans City Council filed a successful complaint with FERC, arguing that Entergy’s formula for determining peak load responsibility in its multistate-wide system agreement was unfair because it included interruptible load, in addition to firm load.

The Entergy System used to be more integrated, with Entergy’s operating companies’ transmission and generation facilities operated as a single electric system, and its system agreement consisting of several service schedules that allocated costs among the operating companies according to a responsibility ratio.

After a volley of appeals and remands involving the D.C. Circuit Court of Appeals, FERC ultimately required Entergy to remove all interruptible load from its cost allocation. However, after a series of conflicting rulings, FERC ultimately declined to order refunds, concluding that while the utility failed to have an equitable cost allocation, it did not over-collect. FERC explained that “in a case where the company collected the proper level of revenues, but it is later determined that those revenues should have been allocated differently, the commission traditionally has declined to order refunds.” It also found that “refunds would impose potentially unrecoverable costs” on the Entergy companies.

Entergy said that because the commission’s ruling not to order refunds “render[s] the performance of the settlement agreement moot,” FERC recounted. “Entergy states that the September rehearing order resolved those pending matters and while it is making the requisite compliance filing, the refunds for the 15-month refund period will not be paid.”

But the Louisiana PSC argued that FERC’s decision against refunds is “not a final, non-appealable” order and it’s still possible that refunds could be granted on an appeal the utility filed with the D.C. Circuit last year.

FERC said, however, that the Louisiana appeal was not the issue.

“While the parties hold differing views on the finality of the orders in this proceeding … the issue now before us for decision is whether Entergy’s compliance filing complies with the requirements” of its September order, FERC said.

Trade Panel Rules PV Imports Hurting Domestic Manufacturers

By Michael Kuser

The U.S. International Trade Commission (ITC) ruled unanimously Friday that increased imports of solar cells and components are harming domestic manufacturers, opening the way for tariffs that critics say could slow solar growth in the U.S.

The vote supporting Suniva and SolarWorld’s claim under Section 201 of the 1974 Trade Act moves the investigation to the remedy phase, which could give President Trump the foundation for implementing his “America First” agenda with tariffs and price floors on some imports.

The ITC said that all four commissioners found that imports of crystalline silicon photovoltaic cells from Mexico account for “a substantial share of total imports and contribute importantly to the serious injury caused by imports.”

The commission also ruled unanimously that imports from South Korea “are a substantial cause of serious injury or threat thereof” and that no significant harm resulted from imports from Australia, Colombia, Jordan, Panama, Peru, Singapore or countries under the U.S.-Dominican Republic-Central America Free Trade Agreement (CAFTA-DR). Three commissioners found no harm from imports from Canada, while Chairman Rhonda K. Schmidtlein did.

A flood of cheap imports has helped create a boom in U.S. solar installations, as total installation costs have fallen almost 70%. For example, in the past two years, National Grid has interconnected more solar than gas-fired generation in New York. (See Renewables Reshaping NY Grid, Policy.)

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Worker inspects solar panel at SolarWorld’s Hillsboro, Ore., factory | SolarWorld

SolarWorld Americas CEO Juergen Stein welcomed the ruling as an “important step toward securing relief from a surge of imports that has idled and shuttered dozens of factories, leaving thousands of workers without jobs. … We will continue to invite the Solar Energy Industries Association (SEIA) and our industry partners to work on good solutions for the entire industry.”

Suniva said it filed the complaint “because the U.S. solar manufacturing industry finds itself at the precipice of extinction at the hands of foreign market overcapacity. It will be in President Trump’s hands to decide whether America will continue to have the capability to manufacture this energy source.”

The companies say trade protection would aid domestic manufacturers and compel international makers to move production to the U.S., resulting in more than 100,000 new jobs.

But Friday’s ruling drew condemnation from SEIA and others, who say it will harm the burgeoning industry.

SEIA CEO Abigail Ross Hopper said the ITC’s decision disappoints nearly 9,000 U.S. solar companies and the 260,000 Americans they employ. “Analysts say Suniva’s remedy proposal will double the price of solar, destroy two-thirds of demand, erode billions of dollars in investment and unnecessarily force 88,000 Americans to lose their jobs in 2018,” she said. SEIA represents both companies that manufacture and those that install solar panels.

 

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Suniva panels on roof of Hewlett Packard data center in Georgia | Suniva

“The ITC decision to find injury is disappointing because the facts presented made it clear that the two companies who brought this trade case were injured by their own history of poor business decisions rather than global competition,” said Paul Nathanson, spokesman for the Energy Trade Action Coalition, a group that says it supports “access to freely and fairly traded products” that support American energy industry competitiveness. “The petition is an attempt to recover lost funds for their own financial gain at the expense of the rest of the solar industry.”

Potential Remedy Costs

The commission scheduled a remedy hearing for Oct. 3 and a vote on recommendations to the White House on Oct. 31, with the recommendations to be delivered to the administration by mid-November. The president has 60 days from delivery to decide on what, if any, measures he will take.

The commission could recommend an increase in a duty, imposition of a quota, imposition of a tariff-rate quota (a two-level tariff, under which goods enter at a higher duty after the quota is filled), trade adjustment assistance or a combination of such actions. It could also recommend that the president initiate negotiations with the exporting countries.

The White House said in a statement that Trump’s decision would be based on “the best interests of the United States.” It added that the “U.S. solar manufacturing sector contributes to our energy security and economic prosperity.”

A report by Timothy Fox of ClearView Energy Partners in August said that a commission ruling in favor of the two solar manufacturers could represent an escalation in green trade disputes. “President Donald Trump would likely impose some degree of trade remedies that could undermine the value proposition of new solar projects and may likely reduce solar deployment over the next four years,” Fox said.

The ClearView report calculated that the petition’s proposed 40 cents/W tariff and the proposed price floor of 78 cents/W would raise costs by 60 to 160%.

“President Trump’s general indifference towards renewable power could encourage him to pursue strong trade action,” the report said. “Politically speaking, he may be able to get away with raising the cost of solar products without risking losing many within his base.”

Safeguard Escape Clause

The ITC estimated that nearly 30 U.S. solar panel producers went out of business between 2012 and 2016, the period investigated. During the same period, global imports grew nearly five-fold, a surge led by China, whose imports increased by more than 700%, according to commission figures.

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Worker in SolarWorld’s Hillsboro, Ore., factory |  SolarWorld

Suniva and SolarWorld filed their petition under Section 201 of the 1974 Trade Act, a rarely invoked article also known as the “safeguard” or “escape” clause.

Global safeguard investigations do not require a finding of an unfair trade practice such as foreign subsidies or dumping. Although safeguard investigations are not country-specific, commissioners who find injury are required to make separate findings for countries with which the U.S. has free-trade agreements, including North American Free Trade Agreement signatories Canada and Mexico and the CAFTA-DR countries (Costa Rica, El Salvador, Guatemala, Honduras, Nicaragua and the Dominican Republic).

SolarWorld said in May that although anti-dumping and anti-subsidy duties have reduced Chinese and Taiwanese imports, global imports have continued to grow. “This surge mainly stems from substantial overcapacity added by Chinese-owned companies that located outside of China to avoid duties,” the company said.

Fox said the most significant distinction of the safeguard petition “is that it moves the final decision-making from agency economic bureaucrats at the [ITC] to White House political staff and President Trump.”

The safeguard authority was last used by President George W. Bush in 2002 to impose a tariff on imported steel. The levy was withdrawn 15 months later after the World Trade Organization ruled that it violated global trading rules.

Quorum Restored, FERC Holds First Open Meeting Since January

By Michael Brooks

WASHINGTON — With two new members, FERC commissioners spent much of the commission’s first open meeting since January introducing their teams and new staff members.

They also took the time to thank and praise staff members for their work between Feb. 4, the day after former Chairman Norman Bay resigned, to Aug. 9, when new Chairman Neil Chatterjee and Commissioner Robert Powelson joined to restore the commission’s quorum. During the so-called ‘no quorum period,’ the Office of Energy Market Regulation issued 200 orders under a limited delegated authority. Under the direction of then-acting Chairman Cheryl LaFleur, staff also worked to prepare filings on which they could not act for when a three-member quorum was restored.

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FERC Commissioners left to right: LaFleur, Chatterjee and Powelson | © RTO Insider

Since regaining its quorum, the commission has issued more than 90 orders and rulemakings, including 32 at Wednesday’s meeting. Throughout the meeting, however, Chatterjee and Powelson repeatedly alluded to the massive backlog of filings the commission still needs to act on, which Chatterjee told reporters is his “primary focus” during his tenure.

“As Rob and I were going through the Senate confirmation process, what we heard repeatedly was, ‘We need to get you guys through so we can get FERC working again,’” Chatterjee said. “What has been made clear to me from the moment I walked in the door … is that FERC has been working. It’s been doing tremendous work under acting Chairman LaFleur’s leadership and with the talented efforts of the staff here.”

Powelson said he was “thoroughly impressed with the professionalism and the institutional knowledge and the welcoming spirit” of FERC staff. “You all have been wonderful, and you are what makes this organization tick.”

“Almost makes me feel like we don’t need commissioners when you really see who does the work around here,” LaFleur joked.

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Protesters gathered outside FERC headquarters to protest the commission’s approval of natural gas pipelines. As has become common at FERC open meetings, protesters also interrupted, this time by breaking out into “We Shall Overcome.” The singers, as well as some silent protesters and some shouting at the commission, were ejected from the meeting room all at once, but the singers could heard from outside for some time as they were led out of the building. | © RTO Insider

LaFleur emphasized the amount of work staff did during the no-quorum period, highlighting the May technical conference on the effects of state policies on wholesale electricity markets; the investigation of potential violations by Energy Transfer Partners regarding its Rover natural gas pipeline in Ohio; and the response to damage at the Oroville Dam in California. (See Local Officials Appeal to FERC as Oroville Water Levels Recede.)

“To say that the first part of this year until my friends arrived was an odd and unusual time at FERC would be an understatement,” LaFleur said. “I always knew our staff had a [strong] work ethic, but it takes tremendous dedication to keep reading things, and writing comments, and writing convoluted memos, and drafting orders when there’s nobody to act on them.”

She also compared FERC’s work on “the big things” during the period — Order 1000, returns on equity, the Public Utility Regulatory Policies Act and hydro licensing — to a duck’s feet underwater: “It moves furiously, but you can’t see it.”

Asked after the meeting whether the commission was waiting on the confirmations of Kevin McIntyre and Richard Glick to tackle these issues, Chatterjee said he would indeed prefer to do that.

“That said, having been through the Senate confirmation process myself, and knowing the uncertainties of that process, certainly we’re prepared to move on some of these major issues if in fact the arrival of our colleagues is delayed in some way,” Chatterjee said. The Senate Energy and Natural Resources Committee forwarded McIntyre’s and Glick’s nominations to the full Senate on Tuesday. (See Senate Panel Clears McIntyre, Glick for FERC.)

But Chatterjee declined to comment on any specific issues or decisions. “I think we tend to go forward on items as they’re ready,” he said. “If they’re ready to go, and we have the votes to approve them … we can move forward.

“I’m optimistic that our colleagues will join us sooner rather than later, but we can’t suspend the commission’s work waiting on the Senate to act.”

Morenoff Feted

Commissioners called out many individual staff members during the meeting, but one name that came up among all three commissioners’ accolades was David Morenoff, FERC’s deputy general counsel.

Morenoff, who has been with the commission since 2006, served as general counsel during the no-quorum period, as well as during the interim period that LaFleur served as chairman after Bay was confirmed.

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LaFleur (left) congratulates Morenoff | © RTO Insider

“Neither of the periods that he was my general counsel were normal,” LaFleur said. “And his superb judgment and support were critical to me personally during both of those times.”

After introducing Morenoff’s replacement, James Danly, Chatterjee said, “I’d be remiss if I didn’t recognize the good work of former General Counsel David Morenoff. I’m grateful for his leadership and willingness to take on this important challenge, and I look forward to continuing to work with him as he returns to his duties as deputy general counsel. David has also been an invaluable resource to me from the moment I walked in the door.”

Toward the end of the meeting, LaFleur — already somewhat emotional from thanking her team for their work during the period — became choked up as she praised Morenoff for leading the Office of General Counsel and the respect he has garnered among its staff.

LaFleur — “with Chairman Chatterjee’s courtesy,” she said — awarded Morenoff the Chairman’s Executive Leadership Award.

FERC OKs Rules on Balancing, Interconnection, Remedial Actions

By Rich Heidorn Jr.

FERC on Wednesday approved revised NERC reliability standards on Balancing Authority Control (BAL-005-1) and Facility Interconnection Requirements (FAC-001-3) (RM16-13) and Remedial Action Schemes (PRC-012-2) (RM16-20).

The first order clarifies and consolidates existing frequency control requirements and will result in “more accurate and comprehensive” calculations of reporting area control error (ACE), FERC said. It will require balancing authorities (BAs) to maintain a minimum annual availability of 99.5% for calculating ACE. A BA unable to calculate ACE for more than 30 consecutive minutes must notify its reliability coordinator within 45 minutes of the failure.

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NYISO’s control room | NYISO

The second order ensures that remedial action schemes (RAS) do not introduce “unintentional or unacceptable” reliability risks. An RAS is a plan to respond to predetermined system conditions with corrective actions such as adjusting or tripping generation, tripping load or reconfiguring a system to maintain voltages or power flows and avoid cascading system failures.

The new rule requires reliability coordinators to complete reviews of new or modified remedial action schemes before they are placed into service. It also requires planning coordinators to evaluate each scheme within its planning area at least once every five years and mandates an area-wide database of RAS that must be updated annually.

Emergency Preparedness NOPR

The commission also issued a Notice of Proposed Rulemaking (NOPR) that would revise emergency preparedness and operations reliability standards on Event Reporting (EOP-004-4), System Restoration from Blackstart Resources (EOP-005-3), System Restoration Coordination (EOP-006-3) and Loss of Control Center Functionality (EOP-008-2).

The NOPR (RM17-12) is intended to ensure accurate reporting of events to the NERC event analysis group; delineate the roles and responsibilities of entities involved in system restoration processes; and identify the elements required in plans for continuing operations when primary control functionality is lost.

NERC said the revised standards will streamline the current rules and make them more results-based while also addressing concerns the commission expressed in Order 749 regarding system restoration training.

Comments on the NOPR are due 60 days after publication in the Federal Register.

FERC OKs Rule Changes on MISO-Manitoba Hydro Trades

By Rich Heidorn Jr. and Amanda Durish Cook

FERC issued seven orders Wednesday revising how MISO deals with its neighbors when incorporating power flows between the RTO and Manitoba Hydro.

The changes affect bidirectional external asynchronous resources (EARs). FERC defines an EAR as “a resource representing an asynchronous DC tie between the synchronous Eastern Interconnection grid and an asynchronous grid that is supported … through dynamic interchange schedules.” Only Manitoba Hydro’s generation currently meets the EAR definition in MISO.

Until 2015, the utility’s hydropower was a dispatchable import into the MISO footprint. In March 2015, however, the RTO and Manitoba began a bidirectional service that allowed the RTO to also export to its northern neighbor.

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Slave Falls Generating Station | Manitoba Hydro

MISO said the revisions to the baseline congestion management process align the treatment of export EARs with the treatment of import EARs in the market flow calculations under its congestion management process.

FERC on Wednesday approved revisions, effective June 1, 2017, to:

  • Attachment LL of the MISO Tariff (ER17-1302);
  • Rate Schedule 8, the Seams Operating Agreement between the RTO and Manitoba Hydro (ER17-1303);
  • Rate Schedule 46, the Coordination and Operating Agreement between the RTO and Minnkota Power Cooperative (ER17-1304);
  • The joint operating agreement between MISO and PJM (ER17-1305), including PJM’s revisions (ER17-1306); and
  • The JOA between MISO and SPP (ER17-1332), including SPP’s revisions (ER17-1333).

MISO’s proposed changes followed an August 2015 memorandum of understanding among MISO, PJM and SPP that addressed EARS and other seams coordination issues. The RTO and Manitoba subsequently agreed to amend their Seams Operating Agreement, and MISO received guidance from NERC that resulted in additional proposed changes to the congestion management process.

The revised MISO-SPP JOA creates a process under which MISO will, on request, conduct studies to determine the flowgates impacted by an EAR.

MISO’s revised JOAs with SPP and PJM add an additional notification requirement when an RTO permanently adds or removes a point of interconnection.

The changes to the MISO-PJM JOA also detail other information sharing obligations and align day-ahead energy market coordination and the auction revenue rights/financial transmission rights with market-to-market settlement practices, MISO said.