FERC OKs ISO-NE FCA 12 Filing; Rejects Protests

By Michael Kuser

FERC accepted ISO-NE’s informational filing for Forward Capacity Auction 12, rejecting protests from a demand response provider and renewable generators over qualification rules (ER18-264).

The commission’s Jan. 19 order agreed with the RTO’s list of resources that qualified for the Feb. 5 auction for the 2021/22 delivery year. It also approved the three capacity zones to be modeled, which are unchanged from FCA 11.

ISO-NE FCA 12 forward capacity auction ferc — | *ISO-NE*

Efficiency Maine Trust — a quasi-state agency that administers energy efficiency programs in Maine and is overseen by the state Public Utilities Commission — protested the RTO’s methodology for calculating existing capacity qualification values. The agency said ISO-NE inappropriately subtracts the amount of expiring measures from a demand resource’s qualified capacity from a prior FCA, rather than from the demand resource’s actual and known performance capacity, as reported in ISO-NE’s energy efficiency measure database.

ISO-NE rules define qualified capacity — the quantity for which a capacity supplier is compensated — as the lower of the resource’s summer or winter qualified capacity. When a capacity supplier’s summer and winter qualified capacity is significantly different, as is the case with the Efficiency Maine programs, the supplier will not receive compensation for the higher seasonal capacity unless it can pair the higher capacity with other resources in a composite offer.

Efficiency Maine said the RTO’s rules would deny it compensation for $3.7 million in capacity for FCA 12, although it said it has been able to reduce the loss to $1.5 million through composite offers covering its entire qualified summer capacity.

The commission said Efficiency Maine projects performed above their qualified capacity because measures installed after the initial clearing of the resources. “We agree with ISO-NE that Efficiency Maine should have sought to qualify any additional capacity prior to such additional measures being in service. Accordingly, to the extent that the Efficiency Maine projects’ overperformance is the result of Efficiency Maine’s failure to seek to clear new incremental capacity in the FCA, we find it inappropriate to now mitigate the consequences of that action (or inaction) through changes to the demand resource methodology.”

The commission also agreed with the RTO “that it would be inappropriate for the commission to require ISO-NE to use Efficiency Maine’s proposed methodology for the Efficiency Maine projects while still using the current demand response methodology for all other energy efficiency resources with expiring measures.”

Renewable Technology Resource Exemption

The commission also rejected a joint protest by CPower and Tesla, which combined to enter Tesla’s SolarCity rooftop generation into the auction.

The companies asked the commission to require ISO-NE to re-evaluate the renewable technology resource (RTR) designation for five solar projects and one combined solar and fuel cell project.

The projects passed the RTO’s qualification process and were assigned the default offer review trigger price (ORTP) — a price floor based on the cost of new entry — of $12.864/kW-month. CPower said it did not challenge the ORTP because it sought to use the RTR exemption to receive an offer floor price of $0/kW-month. RTO rules permit up to 200 MW of RTR exemptions annually to renewable resources receiving out-of-market revenue through state renewable portfolio programs.

In October, however, ISO-NE rejected CPower’s application as incomplete. CPower contended the additional information the RTO requested meant that new resources must already be accepted into a state RPS program and receiving revenue to qualify for RTR designation, contrary to the RTO’s Tariff.

ISO-NE responded that although CPower’s qualification package was sufficient to determine an appropriate capacity amount to qualify each resource, it lacked details necessary to determine whether each resource met the requirements for an RTR designation.

The commission sided with the RTO.

“Although CPower’s qualification package contains some location-specific information and that CPower’s RTR submittal contains general information on possibly applicable RPS statues and regulations, we agree with ISO-NE that neither sufficiently enable ISO-NE to determine the specific provisions and manner (e.g., on an individual or aggregate basis) in which the renewable projects seek RPS qualification,” the commission said. “We agree that such specificity is necessary for ISO-NE to have sufficient certainty that the renewable projects will still qualify as RTR resources by the time of the relevant capacity commitment period. Thus, we find that CPower failed to comply with the Tariff’s requirements to obtain RTR designation.”

Zones and Resources

As in FCA 11, ISO-NE will model three capacity zones in FCA 12: Southeastern New England (Southeastern Massachusetts, Rhode Island and Northeastern Massachusetts/Boston), which will be modeled as import constrained; Northern New England (Maine, New Hampshire and Vermont), which will be modeled as export constrained; and Rest of Pool (Connecticut and Western/Central Massachusetts).

The installed capacity requirement (ICR) is 34,683 MW. After accounting for 958 MW per month of Hydro-Québec interconnection capability credits, FCA 12 will procure a net ICR of 33,725 MW.

ISO-NE qualified 5,605 MW of new resources and 35,007 MW of existing resources: 30,702 MW from intermittent and non-intermittent generation; 82 MW from imports; and 3,224 MW from demand resources.

The RTO said 2,309 MW of static de-list bids — one-year exemptions from the auction — were submitted for FCA 12.

January 28, 2018

PSO Rate Case a Concern for AEP’s Akins

‘Terrific Year’ for NextEra

American Electric Power beat Wall Street’s expectations with a positive yearend earnings report last week, but CEO Nick Akins spent much of a conference call with analysts focused on its Public Service Company of Oklahoma (PSO) subsidiary and its rate case before state regulators.

Akins referred to “disappointing” outcomes in its previous and current rate cases, which have left PSO with a regulated operating return on equity of 6.2% — the second-lowest among AEP’s operating companies and below an authorized ROE of 9.5%. He said AEP may invest its money elsewhere without improved returns, noting the company pulled “several hundred million dollars” of investment out of Oklahoma after PSO’s previous rate case.

PSO AEP earnings Nick Akins — PSO’s Tulsa Power Station | *Flickr*

“We have plenty of places to put our capital, and so Oklahoma would wind up being sort of in the red area,” Akins said during the Jan. 25 call. “That’s something we take very seriously because we want to make investment in Oklahoma.”

An administrative law judge has recommended a 5% ROE in PSO’s current rate case before the Oklahoma Corporation Commission, a “negative trend” Akins is hopeful will be reversed. If the OCC approves the ALJ’s recommendation, “That’s just another really bad message about investment in Oklahoma.”

Moody’s Investors Service recently downgraded PSO’s rating outlook from stable to negative, saying its “limited cushion … for deterioration in financial performance” would be “incrementally impacted” by the recent changes in federal tax law. “We now expect key credit metrics to be lower for longer,” Moody’s said.

“Now that PSO is on negative credit outlook by Moody’s, a positive result is even more important,” Akins said. “[PSO] doesn’t deserve the ROE recommendation and it doesn’t deserve the outcomes that we’re getting in Oklahoma. We’re going to let the commission speak on this. I really believe that the commission will be responsive, so let’s just wait and see what that order looks like.”

Also key to AEP’s future success in the Sooner State is its $4.5 billion Wind Catcher project, a 2-GW wind farm in the Panhandle that will deliver energy to PSO and its sister company, Southwestern Electric Power Co. AEP is seeking regulatory approvals in Oklahoma, Arkansas, Louisiana and Texas, while PSO is gathering community input on proposed transmission siting.

“We are in a very critical time in the life of this project,” Akins said. “In my mind, it would be an absolute travesty to let this unique hedge against the market pass, and I remain confident that it will get done.”

The Columbus, Ohio-based company reported fourth-quarter operating earnings of 85 cents/share, beating Zacks Consensus Estimate of 81 cents/share. AEP recorded a profit of $1.9 billion in 2017, triple the $611 million the year before, although sales were $15.4 billion, down from $16.4 billion.

Year-end earnings were $3.68/share, down from $3.94 from the year-ago period. AEP’s share price finished the week at $68.77, down almost 12% from its 52-week high of $78.07.

NextEra Reports $5.38B Profit in ‘Terrific Year’

NextEra Energy on Jan. 26 reported a 2017 profit of $5.38 billion, though that number was adjusted down to $3.17 billion after allowing for the effects of tax legislation and other unusual charges. Still, that was up from $2.88 billion in 2016.

The Florida-based company said its revenue increased to $17.2 billion, up from $16.2 billion in 2016.

“It was a terrific year,” said CEO Jim Robo.

However, the company’s adjusted fourth-quarter earnings came in at $1.25/share, falling short of the Zacks’ estimate of $1.31/share. The company reported fourth-quarter GAAP net income of $2.16 billion.

NextEra said its Florida Power & Light utility will reduce customer bills by using federal tax savings to forgo recovery of $1.3 billion in Hurricane Irma restoration costs. It said NextEra Energy Resources added a record 2.7 GW to its contracted renewables backlog.

NextEra stock gained $2.83 on Friday to close at $157.69/share, up 1.8% on the day. Its share price has gained almost 30% over the last 12 months.

— Tom Kleckner

January 28, 2018

FERC Denies CPower DR Audit Waiver

By Michael Kuser

FERC last week denied CPower’s request for a one-time waiver to replace the results of a failed demand response audit with those of a more successful one conducted a week later (ER18-185).

ISO-NE FERC demand response audit CPower — | *ISO-NE*

In its request, the energy management company said that it had asked ISO-NE on July 17, 2017, to perform an audit of its real-time demand response resources (RTDRs). But when the RTO initiated the audit July 19, a communications problem prevented CPower from receiving the audit dispatch signal, causing most of the company’s resources to fail to perform. CPower pointed out that ISO-NE is the only RTO in the country that does not back up DR dispatch signals with an email, text message or phone call.

As a result of the failed audit, CPower concluded the month with a demand reduction value of nearly zero.

ISO-NE’s Tariff requires seasonal testing of RTDRs to establish their capabilities and ensure they are available to respond during an emergency event.

The RTO suggested that CPower request a second audit to “mitigate partially” the negative impacts of the first. A July 26 audit demonstrated 94% of the claimed capacity that CPower had registered in the RTDR program, and the company asked the grid operator to replace the July 19 results with those of July 26.

ISO-NE denied the request, saying its Tariff stipulates that a second audit cannot replace an initial audit conducted during that same month. It further argued that allowing RTDRs “another bite at the apple” to replace a poor performance during an audit could compromise the significance of such audits or impact future performance.

The RTO also said that granting the waiver would harm third parties by requiring the resettlement of capacity payments away from resources that followed dispatch instructions and performed well during their audits.

FERC agreed with ISO-NE, saying that CPower’s request was “not of limited scope because it would require rerunning market settlements” and thereby affect other market participants. The commission also noted that allowing resettlement would result in preferential treatment for CPower compared with other RTDRs that also performed poorly in the audits.

“Further, granting waiver would have broad implications on the effectiveness of auditing rules. It could undermine the integrity of audits — which by their nature test performance during unpredictable conditions — and impact future performance of RTDR,” the commission said.

January 28, 2018

Tariff to Pinch US Solar Growth; Factory Surge Unlikely

By Jason Fordney and Rich Heidorn Jr.

President Trump’s decision to impose tariffs on imported solar cells and modules may not spur domestic manufacturing, but it will boost costs, slowing the fast-growing sector, analysts said last week.

The tariffs, based on recommendations from the International Trade Commission (ITC), start at 30% for the first year and drop by 5% each year over the following four years, with the first 2.5 GW of imported solar equipment exempt.

Bloomberg New Energy Finance and ClearView Energy Partners separately predicted the decision will boost the cost of utility-scale solar by 10% and home rooftop units by 4%. ClearView, citing data from the National Renewable Energy Laboratory, also predicted a 6% increase in the cost of distributed commercial solar projects.

GTM Research estimated it may cut U.S. installations by 11% over the next five years.

Expansion Plans

U.S. Trade Representative Robert Lighthizer announced Trump’s decision to impose tariffs on imported solar cells and modules and washing machines on Monday. Trump said they will create jobs in the U.S. “Our [manufacturers] have been decimated, and those companies are going to be coming back strong,” he said in a televised signing ceremony Tuesday.

Greentech Media reported that several of the 14 crystalline-silicon cell and module manufacturers in the U.S. have announced expansion plans: Texas-based module manufacturer Mission Solar Energy, which had to lay off workers in early 2017, said last week it is hiring 50 new employees to increase production and move to a 24/7 schedule. Earlier this month, California-based Solaria announced it had raised $23 million in financing to expand its manufacturing capacity. Tesla said last week it is “committed to expanding its domestic manufacturing” at its Gigafactory 2 in Buffalo, N.Y. And SolarWorld Americas of Oregon, one of two petitioners in the ITC case, resumed manufacturing in September after the commission ruled in its favor. The company says it will add 200 workers by the end of the year. (See Trade Panel Rules PV Imports Hurting Domestic Manufacturers.)

Skepticism

But some analysts said Trump’s move — even if it survives a potential challenge before the World Trade Organization — is unlikely to seriously dent the dominance of Chinese manufacturers, whose share of global solar production grew from 7% in 2005 to 61% in 2012, according to U.S. government statistics.

“Anyone expecting a U.S. manufacturing renaissance as a result of these tariffs is set to be disappointed,” said Hugh Bromley, a solar analyst for Bloomberg New Energy Finance. “A tariff lasting only four years and ratcheting down quickly is unlikely to attract any manufacturing investment that was not going to occur anyway.”

The four-year limit “doesn’t give somebody much incentive to build a factory” in the U.S., agreed Varun Sivaram, fellow for science and technology at the Council on Foreign Relations. Sivaram, author of an upcoming book on solar power, said the U.S. and other nations should be leapfrogging China by investing in new solar technologies.

ClearView also was skeptical of a manufacturing boost, citing data from the Clean Energy Manufacturing Analysis Center, which found that the U.S. has capacity to manufacture about 2.8 GW of solar modules per year — less than one-fifth of the 14.7 GW of solar capacity brought online last year. “Absent nations that are exempt from today’s remedies, domestic manufacturers seem unlikely to increase capacity swiftly enough to meet future demand (or even last year’s actuals),” ClearView said.

Section 201 of the Trade Act of 1974 authorizes the president to create tariffs or take other actions in response to an ITC determination that increased imports are a substantial cause of serious injury to domestic producers. The tariff was the first action by Trump to make good on his campaign promises to revise trade rules to rebuild U.S. manufacturing.

Opening the Floodgates?

Trump’s decision drew fire from members of Congress in both parties and from conservative free-market groups, including the Heritage Foundation, the R Street Institute and the American Legislative Exchange Council. “There’s a real chance that this opens the floodgates” to other industries petitioning the ITC, Chad Bown, a trade expert at the Peterson Institute, told The Washington Post. Clark Packard, trade policy counsel at R Street, said he feared the increase in prices will lead to calls for more domestic subsidies for solar.

Others worried it could spur a trade war as the Chinese retaliate. ClearView noted that previous trade remedies imposed by the U.S. under Section 201 were successfully challenged before the WTO, most recently forcing President George W. Bush to reverse duties on imported steel in 2001. South Korea and China said last week they are considering filing complaints with the WTO.

Sens. Martin Heinrich (D-N.M.) and Thom Tillis (R-N.C.), who joined with 14 Senate colleagues in a letter opposing tariffs, said last week they are considering legislative responses to Trump’s decision. “There’s no doubt that this is a significant speedbump for our solar industry,” Heinrich said in a statement.

Job Losses

The Solar Energy Industries Association (SEIA) predicted the tariff will slash domestic solar output by 6.7 GW by 2021 and eliminate 23,000 U.S. manufacturing jobs this year. The group said that out of 38,000 solar manufacturing jobs in the U.S., all but about 2,000 make something other than cells and panels, producing products such as “metal racking systems, high-tech inverters, [and] machines that [improve] solar panel output by tracking the sun and other electrical products.”

imported solar trump tariffs solar growth — Solar job growth since 2010 | *SEIA, Solar Foundation*

SEIA CEO Abigail Ross Hopper said during a media conference call Tuesday that while the group was unhappy with Trump’s decision, it was relieved he didn’t impose tougher sanctions requested by SolarWorld and fellow petitioner Suniva. The ITC had recommended import duties as high as 35%. (See Federal Trade Panel Recommends Solar PV Quotas.)

“I think this administration really grappled with understanding that solar is creating more jobs in this economy than many other industries and many other energy sources,” Hopper said.

Since 2008, grid-connected solar power has increased more than 38-fold to 42.4 GW, according to the Department of Energy, with more than 260,000 people currently employed. Solar’s share of U.S. electrical generation has risen from 0.1% in 2010 to 1.4% today and is forecast to exceed 3% by 2020 and 5% by 2022, according to SEIA and the Solar Foundation.

The cost to install solar has dropped by more than 70% since 2010, the groups said. In 2016, solar was responsible for 39% of all new electric generating capacity, besting all other technologies for the first time.

“There’s no doubt this decision will hurt U.S. manufacturing, not help it,” Bill Vietas, president of RBI Solar in Cincinnati, Ohio, said during the SEIA press conference. “The U.S. solar manufacturing sector has been growing as our industry has surged over the past five years. Government tariffs will increase the cost of solar and depress demand, which will reduce the orders we’re getting and cost manufacturing workers their jobs.”

Jessica Collingsworth, lead Midwest energy analyst at the Union of Concerned Scientists, said the tariff will hamper solar’s growth in Illinois under the Future Energy Jobs Act. The tariff “threatens the development under Solar for All, which is a job training initiative and solar deployment program for low-income and economically disadvantaged communities throughout the state,” she said. “More expensive solar panels will decelerate new solar installation, delaying Illinois’s transition to a clean energy economy.”

ITC Findings

The Trump administration contends that China has used its own incentives and subsidies to flood the U.S. with underpriced solar cells and modules, hurting domestic manufacturers.

The U.S. imposed anti-dumping and other duties in 2012 and 2013, but Chinese producers evaded those tariffs by moving production to other countries.

ITC initiated the latest investigation in May 2017, after Georgia-based Suniva filed a complaint citing domestic solar industry job losses and wage declines. The company, majority-owned by privately held Chinese firm Shunfeng International Clean Energy, declared bankruptcy last April.

The commission found that “artificially low” priced solar cells and modules from China have spurred solar growth in the U.S. and that China has used incentives, subsidies and tariffs of its own to dominate the global solar equipment supply chain.

“The ITC determined that increased solar cell and module imports are a substantial cause of serious injury to the domestic industry,” the White House said. “Although the commissioners could not agree on a single remedy to recommend, most of them favored an increase in duties with a carve-out for a specified quantity of imported cells.”

Prices for solar cells and modules fell by 60% between 2012 and 2016. “By 2017, the U.S. solar industry had almost disappeared, with 25 companies closing since 2012. Only two producers of both solar cells and modules, and eight firms that produced modules using imported cells, remained viable,” Lighthizer said.

Community Solar Growth to Continue

Trump’s “announcement does nothing to slow the momentum or dampen the excitement for community solar,” said Jeff Cramer, executive director of the Coalition for Community Solar Access. “More and more states are turning to community solar due to its proximity to customers, innovation in product designs and strong customer demand. We expect these advantages, combined with strong state-level support for projects, will result in community solar being able to weather these tariffs and remain a bright spot in the U.S. solar market.”

January 28, 2018

LP&L Finalizing Agreements in ERCOT Move

Lubbock Power & Light told Texas regulators last week that it continues to hammer out settlement agreements that will resolve most of the arguments in the utility’s proposed migration of 470 MW of load from SPP to ERCOT.

Chris Brewster, legal counsel for LP&L, told the Public Utility Commission on Jan. 25 that the utility has modified a settlement agreement reached Jan. 17 with PUC staff and several consumer groups. (See Texas Regulators Noncommittal After LP&L Hearings.)

ERCOT SPP LP&L Lubbock Power & Light — LP&L counsel Chris Brewster (center) updates the PUC on the utility’s settlement agreements | *PUCT*

He also said the utility has reached a separate agreement in principle on the SPP side that involves an upfront payment from LP&L to SPP and Southwestern Public Service, which serves Lubbock’s load under a pair of long-term contracts. Brewster did not disclose monetary figures or further details in the agreement, which had not been filed with the PUC as of Friday afternoon.

The Texas parties agreed the only outstanding issue in the proceeding (Docket 47576) pertains to who will build the $360 million in infrastructure ERCOT has projected would be needed to connect LP&L’s load with its system.

“The discussions are ongoing,” Brewster told the PUC. “The parties in West Texas have a perspective on that.”

The commissioners discussed whether to carve out the transmission construction issue separately, but they decided to allow Brewster a chance to include it in the settlement agreements. Brewster will update the PUC at its next open meeting on Feb. 15.

PUC Opens Rulemaking on Distributed Battery Storage

The commission voted to dismiss an AEP Texas request to connect battery storage facilities to the ERCOT grid (Docket 46368), instead opening a rulemaking to “develop a framework within which [it] can consider a broader range of technologies and study the potential impacts to the competitive retail market and energy-only wholesale market in ERCOT.”

Chair DeAnn Walker said in a memo that AEP’s proposal included issues that need “additional commission review and information,” and suggested the PUC “take a wider view of the innovative concepts raised in this docket as well as other potential technological solutions.”

An administrative law judge had approved AEP’s proposal to connect a pair of utility-scale lithium-ion battery facilities to the ERCOT system in West Texas, but the company ran into broad industry opposition when the ALJ ordered the facilities to be classified as distribution assets and included in AEP’s cost-of-service rates. (See PUCT Considering Rulemaking over AEP Battery Proposal.)

In her memo, Walker said she “firmly” believed the energy consumed by the batteries should not be treated as unaccounted for — or unmetered — energy, as AEP proposed.

“The rulemaking should address a method by which any energy necessary for the implementation of a solution can be measured and accounted for within the market,” she said.

Walker also suggested amending PUC rules to require a utility to obtain a certificate of convenience and necessity to use “non-traditional technologies to solve distribution problems.”

“We’re excited about seeing this technology get into our market,” said Commissioner Brandy Marty Marquez. “Batteries are the commonsensical response to the renewables we’ll see in our market.”

Commissioner Arthur D’Andrea said he had concerns about allowing “regulated utilities to play in this space.”

“The energy does overhang the market,” he said.

Commission Issues Favorable Entergy Orders

In a pair of actions related to Entergy Texas, the PUC signed off on a report analyzing the costs and benefits of MISO membership and approved the company’s request to build a 230-kV transmission line in southeast Texas.

The commission requested the report when it approved the transfer of operational control of Entergy’s assets to MISO in October 2012. The PUC declined Texas Industrial Energy Consumers’ proposal to impose reporting requirements on Entergy, agreeing with staff that it already can request information from the utility as it deems necessary.

— Tom Kleckner

January 28, 2018January 3, 2024

MISO Seeks Stakeholder Input on Foxconn Decision

By Amanda Durish Cook

MISO last week said it will hold off on a decision to expedite its review of a proposal to interconnect Foxconn’s massive electronics plant planned for southeastern Wisconsin until it gets more feedback from stakeholders.

The RTO’s studies of American Transmission Co.’s plan to interconnect the Foxconn plant concluded the project is suitable for recommendation to the Board of Directors under the normal approval timeline for the 2018 Transmission Expansion Plan. But MISO is stopping short of granting expedited status until it hears stakeholder opinions at a Feb. 14 Planning Advisory Committee meeting.

ATC submitted the request for accelerated approval, contending that the proposed $140 million Mount Pleasant Tech Interconnection Project to hook up the $10 billion electronic manufacturing plant with We Energies’ network cannot wait until the usual approvals at the end of the year as part of MTEP 18. ATC has proposed constructing a 14-mile 345-kV transmission line, a new 345/138-kV substation and new underground 138-kV lines to connect the substation to a smaller Foxconn-owned substation near the plant. The transmission developer said it received We Energies’ request to construct the infrastructure in mid-October and notified MISO of the need for expedited approval in late November.

MISO’s studies have found the project will have no adverse impact on system reliability, with the project meeting NERC and ATC local planning reliability criteria.

Minimal Economic Benefits

But MISO also determined that potential systemwide economic gains from the Foxconn project fall far short of the threshold for qualifying as a market efficiency project eligible for competitive bidding or broader cost allocation.

During a Jan. 25 conference call, MISO economic analyst Nicholas Przybilla said the RTO found the benefit-cost ratio of the project would likely be 0.009:1, well below the 1.25:1 requirement for market efficiency projects. He said the economic assessment was provided for informational purposes only, as the lead time and projected December 2019 in-service date are too short for consideration anyway.

Michigan Public Service Commission staffer Bonnie Janssen asked why the economic benefits were so low.

“There is a decent amount of interconnect in the area already,” Przybilla said.

Earlier this month, three Milwaukee aldermen questioned We Energies and ATC’s plan to pass the costs of the interconnection to ratepayers, given that the project stands to benefit just one large industrial customer. (See Milwaukee Signals Fight Against Foxconn Interconnection Plan.)

In response to a question from Kavita Maini, an economist for Midwest Industrial Customers, MISO said its study relied solely on ATC’s 230-MW load projection for the plant, rather than considering any other forecasts. ATC staff at the meeting said they determined that figure was credible after examining similar manufacturing plants in Asia.

Joseph Dunn, MISO West Region expansion planning engineer, said ATC provided an $130 million alternative proposal that would loop existing 345-kV lines into the new substation, but the RTO found the project would result in inferior reliability and more right-of-way approvals when compared to the original project.

If approved, ATC’s interconnection project will eliminate the need for the $12 million reconstruction of a 345-kV bus in Racine, Wis., that was originally approved in the MTEP 16 cycle. That smaller project also has a December 2019 in-service date, but MISO staff said it will be withdrawn should ATC’s project win approval.

January 26, 2018October 31, 2023

Northern Pass Cleans up in Mass. RFP

By Michael Kuser

Eversource Energy and Hydro-Québec were the big — and only — winners in a solicitation to provide Massachusetts with 9.45 TWh of renewable energy each year, state officials revealed Thursday.

The selection of the companies’ joint Northern Pass transmission project means that an additional 1,090 MW of hydropower will be delivered into the New England grid via a new 192-mile HVDC line.

The project contains no provisions for delivering other forms of renewables and was the only one selected among a handful of proposals dominated by hydroelectric output from Québec. (See Hydro-Québec Dominates Mass. Clean Energy Bids.) A separate Eversource bid that included Canadian wind energy was not accepted.

Massachusetts issued its solicitation for a high volume of hydro and Class I renewables (wind, solar or energy storage) last July.

Eversource Energy Northern Pass Transmission — Baker | © *RTO Insider*

“We collaborated with the legislature to propose and sign the bipartisan energy legislation that enables today’s procurement, and we look forward to working with all stakeholders involved to ensure it delivers a cost-effective and reliable energy future that makes substantial progress in reducing our carbon emissions,” Massachusetts Gov. Charlie Baker said.

The Massachusetts Department of Energy Resources worked with distribution utilities Eversource, National Grid and Unitil on the solicitation. Any contract awarded under the MA 83D request for proposals must be negotiated by March 27 and submitted to the state’s Department of Public Utilities by April 25.

All New Hampshire

Northern Pass Eversource — Northern Pass route map | *Eversource*

Northern Pass would run from Des Cantons, Québec, to Deerfield, N.H., where it will convert to AC and interconnect with ISO-NE.

The New Hampshire Site Evaluation Committee is scheduled to complete permit deliberations for the project Feb. 23 and issue a written decision by the end of March.

In a summary of its final application briefing filed with the committee Jan. 19, Eversource said that Northern Pass would “provide New Hampshire residents with more than $3 billion in benefits at no cost to the state’s energy customers,” employ 2,600 people during construction, and “reduce regional greenhouse gas emissions by more than 3.2 million tons per year, equal to the emissions of 670,000 cars.”

The province of Québec last month granted Hydro-Québec a permit to build the project.

Different Takes

“We are pleased with the decision announced today, and appreciate the thorough review by the Massachusetts bid evaluation team,” Eversource Executive Vice President Lee Olivier said in a statement Thursday.

“This is a major milestone in the energy transition underway in the Northeast. … Hydro-Québec’s clean, reliable power, along with our proven delivery capability were highly valued by decision-makers,” said Hydro-Québec CEO Éric Martel.

Eversource Energy Northern Pass — Dam | *Hydro-Québec*

Brian Murphy, business manager of the International Brotherhood of Electrical Workers Local 104, said that the project “not only brings tremendous clean energy benefits to our region but will also provide opportunity for thousands of working families in Massachusetts and New Hampshire. The IBEW looks forward to getting to work on the Northern Pass project in the coming months.”

Not everyone agreed with the Massachusetts decision.

“Providing long-term guarantees to the two largest utilities in the region is the wrong way forward for Massachusetts,” New England Power Generators Association President Dan Dolan said in a statement. “Eversource and Hydro-Québec are asking for Massachusetts consumers to guarantee them revenue through an above-market contract for electricity for the next two decades. Eversource wrote the RFP, and by picking their own project as the winner, have made consumers the losers.”

The Conservation Law Foundation last week tried to sway Baker against the project with a full-page ad in The Boston Globe, saying Northern Pass should be disqualified on environmental and ethical grounds, and accusing the developers of having misrepresented in its bid the level of public support the project enjoys in New Hampshire.

No Wind Today

Northern Pass’s win came one day after Maine Gov. Paul LePage imposed a moratorium on new wind energy projects in western and coastal Maine and set up a commission to study the effect of wind turbines on tourism. Jeremy Payne, executive director of the Maine Renewable Energy Association, called the governor’s action “an attempt to thwart billions of dollars of investment that is looking at Maine,” according to the Portland Press Herald.

Chris O’Neil, a Portland-based consultant and former state representative who often lobbies for wind energy opponents in Maine’s capital, told RTO Insider that Massachusetts did the right thing by ignoring Maine wind in its search for clean energy.

“The RFP scoring is more favorable to dispatchable power that can guarantee 9.4 TWh … because the ISO-NE has lost and is losing some 5,000 MW of baseload and peak load generation,” O’Neil said. “Wind cannot perform these baseload and peak load functions. What New England needs is the good stuff. But the ISO-NE would do well to move forward with the other two HVDC projects also.”

He was referring to Maine-based Emera’s proposed Atlantic Link, a 375-mile submarine HVDC transmission line from New Brunswick to Plymouth, Mass., to deliver 5.69 TWh of clean energy per year; and National Grid and Citizens Energy’s Granite State Power Link, a 59-mile HVDC line from northern Vermont to New Hampshire that would deliver 1,200 MW of new wind power from Canada.

But Wind is Coming

But if wind energy was a loser in the most recent solicitation, its prospects are brighter elsewhere. Baker last year signed a law requiring Massachusetts to contract for 1,200 MW of renewable energy, including hydro, onshore wind and solar. A separate clause in the Act to Promote Energy Diversity mandated that the state solicit proposals for at least 1,600 MW of offshore wind energy, which it did in December. Those projects will be selected in April with contracts due to be submitted at the end of July.

Bay State Wind, a joint venture between Ørsted and Eversource, proposed building either a 400-MW or 800-MW wind farm 25 miles off New Bedford. It would be paired with a 55-MW battery storage facility.

Deepwater Wind proposed two versions of Revolution Wind, a wind farm of consisting of about 25 turbines generating 200 MW, or a project double that size to generate 400 MW. Deepwater is proposing to firm up the project’s output through an agreement with the 1,200-MW Northfield Mountain hydroelectric pumped storage facility operated by FirstLight Power Resources.

Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners submitted proposals for 400-MW and 800-MW wind farms, with approximately 50 and 100 turbines, respectively. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

January 26, 2018

Sempra, Oncor Add More Parties to Settlement Agreement

By Tom Kleckner

Sempra Energy and Oncor said Thursday they have added three more parties to a settlement agreement covering Sempra’s proposed $9.45 billion acquisition of Energy Future Holdings, which includes the bankrupt company’s 80% ownership of Oncor.

The companies said Energy Freedom Coalition of America, Nucor Steel and Golden Spread Electric Cooperative have joined a settlement previously agreed to by six other parties in December. The settling parties have agreed that the acquisition is in the public interest, meets Texas statutory standards, and provides tangible and quantifiable benefits, Sempra and Oncor said. (See Sempra, Oncor Reach Deal with Texas Stakeholders.)

Oncor Sempra Energy Future Holdings — Oncor Switching Yard | *Oncor*

Texas Legal Services Center, a nonprofit law firm that provides free legal representation and advice to low-income persons and Medicare recipients, is the lone holdout intervenor.

The agreement includes regulatory commitments that preserve the existing Oncor ring-fence and the independence of its board of directors. It also extinguishes all debt currently held by EFH and Energy Future Intermediate Holding Co.

With the latest agreement, California-based Sempra moves another step closer to acquiring Oncor, Texas’ largest utility. The companies joined with Public Utility Commission of Texas staff on Jan. 5 to request that the PUC approve the acquisition, consistent with the governance, regulatory and operating commitments in the settlement agreement (Docket 47675).

During a brief discussion at the PUC’s open meeting Thursday, Chair DeAnn Walker told her colleagues she will be meeting with each FERC commissioner at the same time the PUC has scheduled its hearing on the merits of the deal. The PUC set the hearing for Feb. 21-23, but Walker’s FERC meetings are on Feb. 22, suggesting the PUC won’t need all three days.

“If it goes longer than half a day on the 21st, I don’t think any of us should be happy with the use of our time,” Walker said.

The PUC is expected to make a decision by early April. The EFH transaction is also subject to approval by the U.S. Bankruptcy Court.

Sempra agreed to acquire EFH last August. In September, the U.S. Bankruptcy Court for the District of Delaware approved EFH’s entry into the merger agreement with Sempra.

January 26, 2018

EDF Renewable Wins Platform for Queue Concerns

By Amanda Durish Cook

EDF Renewable Energy will get a shot at taking its gripes about MISO’s interconnection process to a wider group of the RTO’s stakeholders.

In a unanimous vote Wednesday, MISO’s Steering Committee agreed to forward the company’s grievance about the length of the interconnection queue for further discussion in the RTO’s Planning Advisory Committee.

Still, some committee members expressed concern over similarities between EDF’s request to examine interconnection timelines and its recent FERC complaint about the structure of the queue. (See Renewables Developer Escalates MISO Queue Design Dispute.)

EDF, which asked the Steering Committee for an issue assignment in November, is still advocating for a two-stage interconnection queue process, rather than the current three stages. The company on Wednesday again asked committee members to consider how MISO could increase the pace of interconnections after RTO planners won approval for a new, streamlined design last year.

MISO Director of Stakeholder Affairs Shawna Lake said the RTO still believes it’s “premature” to make changes to the recently FERC-approved design before completion of a full cycle of queue studies.

“There are very, very long delays happening now, and we’re thinking there’s a way to tighten this up,” Bruce Grabow, an attorney representing the company, said during the committee’s Jan. 24 conference call. For starters, MISO could require secured site control for new generation, instead of a deposit, he said. The queue currently contains 355 projects representing 60 GW, the largest number of prospective projects in a decade.

MISO FERC interconnection queue EDF Energy — Queued projects in MISO South region | *MISO*

EDF provided similar background earlier this month in its FERC complaint, which asked the commission to order a “workable” interconnection timeline to ensure that wind developers can secure federal production tax credits (PTCs) before they expire at the end of 2020.

But during Wednesday’s call, Grabow said EDF’s FERC complaint is entirely different from its committee request because the complaint focuses narrowly on speeding up studies only for wind developers and others impacted by PTC deadlines. Grabow predicted that even if FERC found fault with the queue process, queue entrants not relying on PTCs would continue within the current three-stage queue.

“There’s no way FERC would issue something that would impact the three-stage queue,” said Grabow, eliciting some skepticism from the committee.

Steering Committee Chair Tia Elliott suggested that EDF craft a fuller explanation of how the two arguments differ and where overlap might occur.

Two weeks after EDF lodged its complaint, RTO staff introduced a new feedback form designed specifically to capture stakeholder opinions on issues discussed during Interconnection Process Task Force meetings, in addition to other advice related to the queue. (See MISO Seeks Stakeholder Input as Queue Timeline Lengthens.)

MISO’s most recent predictions for the August 2017 cycle of projects in the queue indicate that most are expected to wrap up in February or March 2019, except in the Upper Peninsula area of MISO East, where projects are slated to finish this December. But in the wind-heavy MISO West region, projects are expected to clear the definitive planning phase (DPP) of the queue as late as July 3, 2019.

MISO FERC interconnection queue EDF Renewable Energy — Queued projects in MISO West region | *MISO*

The RTO’s queue reform was intended to reduce the number of days that interconnection customers spend in the DPP from an average of 589 days to 460. Customers that entered the August 2017 cycle are currently predicted to spend an average of 579 days in the DPP before signing an interconnection agreement.

January 25, 2018

SPP Market Monitor: Negative Prices May Require Rule Changes

By Tom Kleckner

SPP’s Marketing Monitoring Unit says it is concerned with a “marked increase” in the frequency of negative price intervals, and that market rules may need to be revised to address self-committing resources in the day-ahead market and the absence of some forecasted variable energy resources in the real-time market.

In releasing its most recent quarterly State of the Market report, the MMU said that with the prolific growth of wind generation, the frequency of intervals experiencing negative prices increased from 2.6% in 2015 to 7% through November 2017.

SPP MMU market monitor negative prices — Logan’s Gap Wind Farm | *AWEA*

“Negative prices may not be a problem in and of themselves, but they do indicate an increase in surplus energy on the system,” the Monitor said in its report. The market’s practice of self-committing resources in the day-ahead market may be “exacerbat[ing]” the situation, it said.

Negative prices can occur when there is excess power and renewable resources must be backed down so that traditional resources can meet their scheduled generation, the MMU said. It said unit commitment differences resulting from wind resources opting out of the day-ahead market but coming online in the real-time market can create differences in the frequency of negative price intervals.

In October, 17% of all real-time intervals had prices below zero, most occurring in the overnight low-load hours, with a “sizable” number of intervals having prices lower than -$25/MWh.

Negative prices in the day-ahead market are almost exclusively between -1 cent/MWh and -$25/MWh, the Monitor said.

The report also said:

Prices averaged $20.22/MWh (day-ahead) and $20.53/MWh (real-time) during the fall. October’s average price of about $18/MWh was the lowest monthly average since spring 2016.
The average monthly gas price at the Panhandle Eastern hub continued to hover around $2.60/MMBtu, as it has for the previous 10 months.
Fall’s all-in cost was $22.40/MWh, a 12% decrease compared to the fall 2016 level of $25.53/MWh. The gas price at the Panhandle Eastern hub dropped by 1 percentage point for the same period.
Coal-powered resources continued their downward trend, accounting for only 45% of energy produced in the fall, compared to 50% in fall 2016 and 52% in fall 2015. Wind generation continued its upward trend with 26% of energy produced last fall, compared to 20% in fall 2016 and 15% in fall 2015.
More than 11% of all intervals in the real-time market had no congestion, compared to 2% in fall 2016 and nearly 4% in fall 2015.

The MMU will host a webinar on Feb. 8 to discuss the fall report.