Page 1249 – RTO Insider

September 25, 2017January 18, 2024

Mountain West to Step up Talks with SPP on Joining RTO

By Tom Kleckner

Mountain West Transmission Group said Friday it has completed initial discussions about RTO membership with SPP’s management team and will begin public negotiations through its stakeholder process.

The conversations began shortly after Mountain West, a coalition of 10 utilities primarily serving Colorado, Wyoming and Nebraska, announced its intentions in January to join SPP. In a press release, Mountain West said it had determined that membership in the RTO could reduce customer costs and make more efficient use of its members’ transmission and generation assets.

Negotiations have reached the point where “[we] believe it is now appropriate to take our potential membership proposal to all SPP stakeholders,” Steve Beuning, Xcel Energy’s director of market operations, said in a statement on behalf of Mountain West.

SPP COO Carl Monroe said he was pleased Mountain West’s members had decided to proceed into the RTO’s stakeholder process. The next steps will include stakeholder, board and regulatory approvals, and revisions to SPP’s governing documents and processes, he said.

This will “ensure the people, technology and procedures are in place to ensure a smooth transition to [SPP] and our wholesale electricity market,” Monroe said. “We look forward to continuing our work with [Mountain West] … and providing them and their customers the value our members in the east have received for many years.”

A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. The utilities’ desire to eliminate pancaked transmission and participate in a modern market design started the group’s dialogue about RTO membership.

Representatives from the two organizations will review their work and next steps with SPP’s 95 members. They expect a months-long process for stakeholders to approve changes necessary to add new members. SPP took the same steps when it added the Integrated System in 2015 and Nebraska utilities in 2009.

The meetings will be held Oct. 13 in Denver and Oct. 16 in Little Rock, Ark. Registration will be available on SPP’s website by Sept. 29.

Mountain West has said it hopes to present a recommendation to SPP’s Board of Directors in January. The organizations could file with FERC in mid-2018, with full integration as soon as late 2019.

The Colorado Public Utilities Commission, which has regulatory jurisdiction over some Mountain West participants, has held two public information sessions on the proposal. (See SPP, Peak Reliability Pitch RC Services for Mountain West.) A third meeting scheduled for Oct. 20 in Denver will focus on governance, transmission planning, cost allocation and regulatory filings.

Mountain West’s 10 utilities — Basin Electric Power Cooperative, based in Bismarck, N.D.; Black Hills Energy’s utilities in Colorado, South Dakota and Wyoming; Colorado Springs Utilities; Platte River Power Authority in Fort Collins, Colo.; Public Service Company of Colorado, an Xcel operating company based in Denver; Tri-State Generation and Transmission Association, in Westminster, Colo.; and the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage (CRSP) Project — serve about 6.4 million customers and own 16,000 miles of transmission.

“While Mountain West remains optimistic that an RTO would benefit its entire membership, each Mountain West participant will ultimately need to individually evaluate whether potential membership benefits its customers,” the group said. “Each will pursue regulatory or governing body approval, as applicable.”

September 25, 2017

FERC Relieves CAISO of Statewide Plan

FERC last week approved CAISO’s request to be relieved of its requirement to develop a conceptual statewide plan as part of its regional transmission planning process. The commission at its meeting also ruled on two disputes regarding the Western Energy Crisis of 2000/01.

Western Energy Crisis FERC CAISO — CAISO has developed the statewide conceptual plan each year since 2010. | © *RTO Insider*

The commission approved CAISO’s request, made in June, to eliminate the need for the statewide conceptual plan, which the ISO says is obsolete because of federal planning processes. (See CAISO Seeks to Drop Outdated Planning Role.) CAISO has developed the plan each year since 2010 as part of its lead role in the California Transmission Planning Group (CTPG). But the implementation of FERC Order 1000 superseded the CTPG, which is no longer operating.

“We agree with CAISO that the implementation of Order No. 1000’s regional transmission planning and interregional transmission coordination requirements have supplanted the benefits of developing a conceptual statewide plan, and that the tariff provisions to develop a conceptual statewide plan are now redundant and therefore unnecessary,” FERC said in its order.

The commission last week also approved an uncontested settlement filed last December between certain California parties and MPS Merchant Services, the successor to Aquila Merchant Services and Aquila Power. “The settlement resolves claims arising from events and transactions in the Western energy markets during the period of Jan. 1, 2000, through June 20, 2001, as they relate to MPS,” FERC said in the order.

Separately, FERC approved another energy crisis settlement between San Diego Gas & Electric and sellers of energy and ancillary services in CAISO and the now-defunct California Power Exchange.

— Jason Fordney

September 25, 2017

Analysts Debate Potential Vistra Coal Retirements

By Tom Kleckner

AUSTIN, Texas — Vistra Energy’s acknowledgement last month that it may retire some of its coal fleet sparked a lively debate among speakers at Infocast’s Texas Renewable Energy Summit last week.

Like other coal and nuclear units in ERCOT, the plants operated by Luminant, Vistra’s generating division, are often priced out of a market in which cheap gas has sent energy prices to record lows.

Luminant’s three 1970s-era coal-fired plants — Big Brown, Martin Lake and Monticello, which total almost 5.3 GW of capacity — have capacity factors ranging from 44 to 59%, leading to speculation that some or all the plants may be retired. During the company’s second-quarter call in early August, CEO Curt Morgan told analysts, “Any decisions related to optimization of Luminant’s generation fleet will likely be made in the fourth quarter.”

ERCOT FERC Vistra Energy Coal Plant Retirements — Mitra | © *RTO Insider*

Neel Mitra, director of utilities and power research for Tudor, Pickering, Holt & Co., a Houston-based investment and merchant bank focused on the energy industry, told the conference Monday he expects Vistra will retire two of the three plants.

Others weren’t as bearish on ERCOT’s coal fleet.

“We’ve been hearing rumors about coal plant retirements for several years now,” said Morgan Stanley Capital’s Clayton Greer, who sits on ERCOT’s Technical Advisory Committee.

Tim Wang, a director with Filsinger Energy Partners, said the outlook has changed for fossil plants with the Clean Power Plan’s future in doubt.

“Prior to the 2016 elections, I thought it was definite we would see retirements fairly soon, but that’s gone away,” Wang said. “Really now, it’s just about economics. If you look at [Vistra’s] portfolio, you say, ‘If they retire those plants, what will they be left with?’

“If I were them, and a rational player, I’d say, ‘We need to acquire gas plants. We need to acquire gas before their valuations go up.’ Otherwise, you’re helping your competitors.”

Indeed. In recent months, Vistra has completed the purchase of a 1,054-MW combined cycle combustion turbine in Odessa and acquired two other combined cycle plants representing another 3 GW of capacity. Luminant now has almost as much gas capacity (7.5 GW) as it does coal (8 GW). All told, Luminant has about 18 GW of capacity.

Healthy Reserve Margins

Mitra’s comments came while he discussed ERCOT’s healthy reserve margins. The ISO currently has an 18.9% reserve margin, which it expects to drop to 16.8% in 2022, based on new builds and potential retirements. In its most recent Seasonal Assessment of Resource Adequacy, the ISO said it has nearly 86 GW of capacity available this winter, more than enough to meet a predicted peak demand of just more than 56 GW. (See “Seasonal Forecasts: Sufficient Generation for Fall, Winter,” ERCOT Briefs.)

ERCOT has more than 68.7 GW of thermal capacity, but wind energy now accounts for almost 20 GW of capacity and solar for another 944 MW. The continued influx of renewable resources has helped push inefficient fossil plants into seasonal or mothball status, as they are unable to compete with zero-marginal-cost wind during off-peak hours.

Only two coal plants in the ERCOT market are covering their fixed costs on an around-the-clock open-price basis, Mitra said, pointing to Luminant’s Sandow 5 unit east of Austin and its twin 800-MW units at Oak Grove, north of Houston. The units came online in 2009 and 2010.

Beth Garza of Potomac Economics, ERCOT’s Independent Market Monitor, said there is a lot of existing generation that is not recovering its costs.

“We’re in a sweet spot right now with lots of reserve and very low prices,” she said. “At some point, that has to change. We will see retirements and mothballs. The fear is, we’ll see lots of that happening at once and upsetting that balance.”

Mitra said he believes Vistra has been discussing an “orderly retirement plan” with ERCOT. However, an ISO spokesperson would only say the retirement process “officially begins” when a generation owner sends a notice of suspension of operations to ERCOT. Luminant declined to comment beyond Morgan’s statement.

Reliability Impact

“The regulators will have to start worrying about [retirements] relatively soon,” Mitra warned. He suggested improvements could be made to ERCOT’s operating reserve demand curve, which creates a real-time price adder reflecting the value of available reserves.

“In concept, it works pretty great. But in reality, you want to have increases to scarcity pricing in the summer, and we haven’t had that yet,” Mitra said. “[The ORDC] has to be a little bit more aggressive to incent new generation or coal plants to stay online. There has to be some sort of a reliability scare, but we haven’t really had one since 2011.”

Even if all three Vistra plants are retired, Mitra noted, it will only drop ERCOT’s reserve margin to 9.5%. He expects the market to tighten soon, given his belief that Vistra will retire coal generation, but only for on-peak hours. Wind generation will “continue to flood the ERCOT market during off-peak hours,” Mitra said.

Vistra emerged from Energy Future Holdings’ Chapter 11 bankruptcy in November as a tax-free spinoff. Long known as Texas Utilities and then TXU, the company was acquired in 2007 by EFH and its consortium of private-equity investors through a leveraged buyout. The deal went sour when energy prices collapsed, and EFH filed for bankruptcy in April 2014.

September 22, 2017

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.

SPP FERC Shortage Pricing SPP Tariff attachment Z2 — 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.

September 22, 2017

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.”

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.

September 22, 2017

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.

CAISO FERC energy storage — 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.)

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.

September 22, 2017

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.

MISO MTEP market efficiency projects SPP Board of Directors — 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.

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.

September 22, 2017January 3, 2024

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.

September 22, 2017

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.

September 22, 2017

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.)

solar trade commission suniva — 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.

“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.

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.