Critics: Trump Tariff to Cut Solar Growth, Jobs

By Jason Fordney

President Trump’s new tariff on imported solar cells and modules will slash domestic solar output by 6.7 GW by 2021 and wipe out tens of thousands of jobs, a major solar trade industry association said Tuesday.

“We are not happy with this decision,” Solar Energy Industries Association (SEIA) CEO Abigail Ross Hopper said during a conference call.

The move could have a “significant impact” on new solar markets and eliminate 23,000 U.S. manufacturing jobs this year, Hopper said. She anticipated the decision could spur a complaint with the World Trade Organization over the tariff, and “we should be watching with great interest should another country choose to pursue that path.”

FERC trump solar cells tariffs — Critics say the Trump Administration’s new tariff on solar equipment will hurt the domestic industry

“This administration really grappled with understanding that solar is creating jobs,” Hopper said.

Bill Vietas, president of RBI Solar in Cincinnati, Ohio, said: “There’s no doubt this decision will hurt U.S. manufacturing, not help it. 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.”

But the Trump Administration contends that China has used its own incentives and subsidies to flood the United States with underpriced solar cells and modules, hurting domestic manufacturers. Based on recommendations from the International Trade Commission (ITC), the tariff starts at 30% for the first year and drops by 5% each year over the following four years, with the first 2.5 GW of imported solar equipment exempt.

The White House on Monday issued an announcement from U.S. Trade Representative Robert Lighthizer that Trump approved the ITC’s recommendation to impose the tariff on imported solar cells and modules, as well as washing machines. ITC found that “artificially low” priced solar cells and modules from China has spurred solar growth in the United States and that China has used incentives, subsidies, and tariffs of its own to dominate the global solar equipment supply chain.

Chinese manufacturers’ share of global solar production grew from 7% in 2005 to 61% in 2012, according to U.S. government statistics. The United States imposed anti-dumping and other duties in 2012 and 2013, but Chinese producers evaded those tariffs by moving production to other countries.

“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, and “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,” the notice said.

The tariffs are not as high as those proposed by solar companies Suniva and SolarWorld Americas. ITC initiated the investigation in May 2017, after Georgia-based Suniva filed a petition 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.

SEIA said that out of 38,000 solar manufacturing jobs in the United States, 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.”

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.

January 24, 2018

CAISO Moves Ahead With Load-Shifting, DR Products

By Jason Fordney

CAISO is delving into the next phase of a years-long effort to integrate more storage and demand response (DR) into its markets.

Up next: a new load-shifting product intended to reduce renewable curtailment and overgeneration, among other ideas.

CAISO FERC Demand Response energy storage — Storage is seen as critical for enabling integration of more renewables onto the CAISO-grid | *SCE*

The ISO Board of Governors last year approved Energy Storage and Distributed Energy Resources Phase 2 (ESDER 2), which will provide distributed energy resources and a storage foothold in the ISO’s markets. (See Ne w CAISO Rules Spell Increased DER Role.)

CAISO and its market participants now will confront new complexities during the scoping phase of ESDER 3. Storage companies are heavily involved in developing a load-shifting product to allow behind-the-meter (BTM) resources to participate in DR, but CAISO also will evaluate resources other than storage. The ISO is focused on BTM storage where charge and discharge can be metered and monitored directly.

The industry’s goal is to have a product launched by spring 2019, Ted Ko, of storage company Stem, said at a Jan. 16 ESDER workshop. The intent is to have the “minimum necessary design” to allow storage and other resources to participate in load shifting — the practice of charging batteries during periods of low demand and negative prices and discharging during ramps. During previous meetings and workshops, stakeholders developed a definition of a “shift resource” that can demonstrate its ability to shift loads. Stakeholders also are exploring issues around registration, metering, bidding, and settlement.

“This is 1.0,” Ko said of the load-shifting product. “We are not trying to design the full product.” He also said the ISO should not intend to solve all the problems in the first round.

“Let’s try really, really hard to not make the perfect be the enemy of the good,” he said

Storage companies have increased their pressure on CAISO to develop the load-shifting product, which was deferred from ESDER 2. (See Storage Advocates Urge CAISO on DR Pr o duct and CAISO Load-Shifting Product to T arget Energy Storage.)

Aside from the load-shifting product under the ESDER 3 demand response track, CAISO is also addressing DR modeling limitations, dealing with weather-sensitive demand response resources and recognizing load curtailment provided from BTM vehicle charging equipment.

ESDER 3 will also examine “multiple-use applications” that allow DR and DER to “stack” services across different wholesale and retail market segments, increasing their potential for compensation. CAISO wants to use that track of the initiative to enable 24×7 participation for distributed energy resources and create a wholesale market participation model for microgrids.

CEC Announces Microgrid Grants

DER last week got another boost when the California Energy Commission issued a notice of propo s ed a ward of $22 million in grants to deploy microgrids, the first batch in its latest $44-million competitive microgrid solicitation. (See Californ i a Aw a rding $45 Million for Microgrids.)

The proposed recipients include Native American tribes, Lawrence Berkeley National Laboratory, University of California, San Diego Unified Port District, Electric Power Research Institute, and others. The funding is contingent upon approval by the full commission.

January 23, 2018January 24, 2024

Calls Grow for Capturing Utilities’ Tax Savings

The number of state officials and utilities announcing actions because of the Tax Cut and Jobs Act signed by President Trump last month keeps growing.

The bill cut the federal corporate tax rate from 35% to 21%, and many public officials want to make sure utilities pass their savings from the bill on to their customers.

As of Jan. 8, regulatory bodies in at least 11 states had opened proceedings or taken other actions related to the tax bill, and elected officials in at least two other states had called for them to. Also, at least nine electric and gas utilities had said they planned to pass their savings on to their customers. (See Utilities Likely to Pass Tax Bill Gains to Customers.)

Since then, a coalition of elected officials, consumer advocacy officials and utility regulators from 18 states has written FERC a letter calling for an investigation into the “justness and reasonableness” of utility rates considering the tax act. (See “States Asking FERC to Investigate Rates in Light of Tax Cut,” Federal Briefs.)

The Organization of MISO States joined the chorus on Monday. (See related story, OMS Urges FERC to Pass Tax Cut Benefit to Ratepayers.)

At Thursday’s open meeting, Commissioner Robert Powelson expressed his support for a pass-through of utilities’ savings. “I hope we do our part to make sure these tax benefits are accrued to energy users here in America,” he said.

Chairman Kevin McIntyre told reporters after the meeting that he agreed with Powelson’s sentiment and that the commission was considering its options.

Also, the Texas Public Utility Commission has taken its first steps in determining how to share the tax cuts with ratepayers. (See PUCT Briefs: Regulators Begin Addressing Utility Tax Savings.)

Here’s a round-up of other recent actions by regulators and companies:

Midwest

The North Dakota Public Service Commission on Jan. 10 ordered Montana-Dakota Utilities, Otter Tail Power and Xcel Energy to let it know by Feb. 15 their savings from the tax bill so it can return the money to ratepayers.

Ameren Illinois said it filed a petition with the Illinois Commerce Commission to be allowed to pass its tax bill savings on to its natural gas customers and planned to file one to be allowed to pass them on to its electric customers too.

Oklahoma Gas & Electric said savings it realizes from the tax act will cover about $68 million of a $72 million rate increase it asked for on Jan. 16.

Kansas City Power & Light and Westar Energy said they will file requests with their state regulators to be allowed to pass their savings on to their customers. Kansas City Power & Light’s parent, Great Plains Energy, and Westar Energy are continuing to pursue their merger. (See Great Plains, Westar File Revised Merger Plan.)

East

The Delaware Public Service Commission on Jan. 16 approved a petition filed by the state’s Public Advocate to make sure consumers receive the benefits of any savings realized by utilities. The order directs utilities to estimate the impact of the new tax law on their cost of service, and to propose procedures for reducing their rates to reflect those impacts by March 31.

Delmarva Power, which had already committed to pass along its savings from the tax bill to Maryland ratepayers, said it would adjust its natural gas and electric rate increase requests in Delaware to reflect its savings from the bill.

Dominion Energy said Jan. 2 if its deal to purchase SCANA goes through, it will reduce the rates of SCANA’s South Carolina Electric & Gas subsidiary by more than $7/month with some of the money coming from savings from the tax bill.

Public Service Enterprise Group said in an 8-K filing Jan. 11 that it will realize a one-time benefit of $660 million to $850 million from the tax bill. A day later its Public Service Electric and Gas subsidiary asked New Jersey regulators to approve a 1% increase in its base electric and gas rates, which it said reflects the fact that it is “passing along savings from recent tax law changes.”

National Grid said on Jan. 11 it would reduce its request for an electric and gas base distribution rate in Rhode Island from $71 million to $45 million because of savings from the tax bill.

The company on Monday said its Niagara Mohawk Power subsidiary has filed a request with the New York Public Service Commission to boost its revenue by $206 million in 2018-2019, before the impact of deferred credits. The request includes an estimated customer savings of $76 million from the tax cuts.

West

Pacific Power said Jan. 3 it will work with its regulators and stakeholders to pass its savings from the tax bill on to its customers.

Arizona Public Service said Jan. 9 it wants to use its savings from the tax bill to reduce its average residential customer’s monthly bill by about $4.70.

Green Mountain Power CEO Mary Powell said Jan. 10 that the company would pass along all its savings from the tax bill to its customers.

South

The Mississippi Public Service Commission has asked its Public Utilities Staff to consider possible rate reductions available to residents.

The Georgia Public Service Commission on Jan. 16 ordered Georgia Power to submit a report to it by Feb. 20 detailing how the utility will be affected by the tax bill.

Florida Power & Light said Jan. 16 it plans to use its savings from the tax bill to cover its $1.3 billion in Hurricane Irma restoration costs and may be able to use them to delay future rate increases.

— Peter Key

January 23, 2018April 11, 2024

McIntyre: Won’t Commit to Probe Leak to ‘Good Friend’

WASHINGTON — FERC Chairman Kevin McIntyre declined to say Thursday whether the commission will investigate how attorney William S. Scherman allegedly learned the contents of a pending order before its issuance Jan. 12. McIntyre described Scherman, a former FERC general counsel now with Gibson Dunn, as a “good friend.”

Commissioner Neil Chatterjee filed a memo on Jan. 12 reporting that Scherman had attempted to privately lobby him a day earlier on FirstEnergy’s request to transfer a struggling coal-fired generator from its merchant unit to a regulated affiliate. The commission’s order rejected the request as not in the public interest (EC17-88).

Chatterjee reported that Scherman called him on Jan. 11, “indicating his concern that the commission would shortly issue an order adverse to the interests of [FirstEnergy affiliate] Monongahela Power. Mr. Scherman also stated that he would prefer that the commission set the issue for hearing instead of issue an adverse order. As soon as I realized that Mr. Scherman’s communication concerned the merits of the contested proceeding, I terminated the communication and did not respond to Mr. Scherman’s statements. I then drafted this memorandum to memorialize the ex parte communication for the record.”

McIntyre Press Conference

RTO Insider asked McIntyre at his press conference following Thursday’s open meeting whether the commission would investigate who may have leaked the information to Scherman.

“I read that in [Chatterjee’s] statement and I am going to be discussing that with my staff,” McIntyre responded. “In the meantime, I just want to say that the system that we have in place for situations just such as that where there’s an ex parte communication worked perfectly. We have a system in place. Commissioner Chatterjee did exactly the right thing and the system worked. So as far as I’m concerned, I’m very satisfied with where it came out.”

Commissioners Cheryl LaFleur, Robert Powelson and Richard Glick told RTO Insider on Jan. 16 that Scherman had not attempted to contact them on the case. McIntyre said Thursday that he also had not been contacted.

“Bill Scherman and I are old friends. I consider him a terrific lawyer and a good friend,” McIntyre said. “In this instance, I had no contact with him about the matter.”

FirstEnergy merchant affiliate Allegheny Energy Supply had requested permission to transfer ownership of the 1,159-MW Pleasants Power Station to regulated affiliate Mon Power, with the latter assuming a $142 million obligation for pollution controls Allegheny installed at the plant. The commission’s unanimous Jan. 12 order concluded the deal was not in the public interest because it resulted from an “overly narrow” solicitation. (See FERC Blocks FirstEnergy Sale of Merchant Plant to Affiliate.)

Ex Parte Communications Common

Ex parte communications (one side only) are quite common at FERC — so frequent, in fact, that FERC’s secretary publishes a list of disclosures about every two weeks (RM98-1).

Most of the dozens of communications reported in the last year concerned pipeline projects and involved letters or flyers sent to commissioners rather than filed as formal comments in the dockets. Residents near the projects were the most frequent offenders, but chambers of commerce, economic development authorities and labor unions also were listed. The communications are filed in the dockets to document them but are not considered part of the evidence before the commission.

The commissioners also hear frequently from state and federal elected officials, but such communications are exempt from ex parte rules.

No Foul?

Ex parte phone calls to commissioners by members of the energy bar are not common, however.

“Everyone else in the FERC bar manages to follow the rules. FERC shouldn’t let cheaters get away scot-free,” said a former member of the commission’s general counsel’s office who asked not to be identified to protect his working relationships. “And Commissioner Chatterjee’s description gives the lie to the assertion that this was a gray area. Setting a matter for hearing as opposed to denying it is about as substantive as it can get.”

Scherman told RTO Insider last week that he had done nothing wrong and said the commission should change its ex parte rules, which prohibit private communications with commissioners in contested case specific proceedings. “Based upon my experience, I do not believe I engaged in any ex parte communications,” Scherman said in an email. (See FirstEnergy Lawyer Sought to Lobby Chatterjee on Plant Deal.)

Scherman declined to answer additional questions Monday morning but later asked that the story include comments on an unrelated matter (see Editor’s Note, below). First Energy has declined to comment.

Rule 2201, revised by FERC Order 718 in 2008, states that “in any contested on-the-record proceeding, no person outside the commission shall make or knowingly cause to be made to any decisional employee, and no decisional employee shall make or knowingly cause to be made to any person outside the commission, any off-the-record communication. … Commission employees who are found to have knowingly violated this rule may be subject to the disciplinary actions prescribed by the agency’s administrative directives.”

Who is the Mole?

FERC draft orders are typically circulated among the commissioners’ aides and staffers in divisions who are responsible for writing the legal and technical language of the ruling. The drafts are generally not secured with any kind of watermark that would indicate where a leaked copy originated.

The commission’s ethics rules state that staff “may not disclose nonpublic information, including draft orders and internal discussions, to the public.” Staff are also barred from disclosing “the nature or the time of any proposed action by the commission to anyone outside the commission.”

But Washington’s revolving door culture means that those who depart FERC leave behind former colleagues able to share information with them — carelessly or maliciously — in social settings.

A former FERC policy adviser who now works as a consultant said he thinks such disclosures are “very rare.”

“I feel like it would harm relationships to even put staff in that position by asking a question” regarding a pending matter, he said. “But clearly others do, and somebody [on FERC staff is] playing ball.”

The former adviser speculated that Chatterjee, a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), was slow to realize what he had gotten into when he agreed to talk to Scherman. “In the legislature, intelligence is the coin of the realm. And sharing intelligence is how you get intelligence. It wouldn’t surprise me if he started to get into that game a little bit and realized his entire reputation could be damaged” by sharing information.

An industry analyst agreed that improper disclosures are rare.

“The commission goes out of its way not to discuss matters with parties to a case,” the analyst said. “I tell my clients, ‘If you bring this up [in a meeting with FERC officials], you can expect to be shut down.’ FERC is fairly discreet. I think they are cognizant that [their comments] can move a stock.

“You can talk in hypotheticals [with FERC officials], but then you may find that what you have been told is not something you can take to the bank. I’ve had conversations where someone says, ‘Commissioner so-and-so told me X.’ It’s just one person’s opinion. A staffer close to one commissioner saying, ‘I think this is going to happen.’ That’s only one of five votes.

“My guess is somebody probably tipped Bill and that was inappropriate,” the analyst said. But FERC’s “pretty aggressive” deficiency letter, filed in the docket in June, indicated the commission’s skepticism of the Pleasants deal, the analyst added.

“The commission should be investigating whether Scherman did in fact obtain nonpublic information,” Tyson Slocum, director of Public Citizen’s Energy Program, said in an email. “If FERC refuses, the Senate Energy and Natural Resources Committee should step in.”

The Department of Energy’s Inspector General also has authority to investigate the commission. (See DOE IG Warns FERC Information Security ‘Severely Lacking.’)

An IG spokeswoman on Monday declined to say whether it was investigating the Scherman incident. “We are an independent organization. We take a number of factors into consideration when deciding to initiate an investigation,” she said.

Penalties, Prior Incidents

Rule 2201 allows the commission to bar Scherman from practicing before it: “If a person knowingly makes or causes to be made a prohibited off-the-record communication, the commission may disqualify and deny the person, temporarily or permanently, the privilege of practicing or appearing before it, in accordance with Rule 2102 (Suspension).” [See 18 CFR section 385.2201 (i)(2).]

Rule 2102 permits FERC to disqualify a person who is found “to have engaged in unethical or improper professional conduct.”

This is not the first time Scherman has been accused of flouting the commission’s ex parte rules. In 1992, congressional investigators suggested Scherman — then FERC general counsel — had whitewashed an ex parte meeting at which FERC staff discussed with sponsors of the Iroquois Gas Transmission System pipeline project ways to expedite the commission’s approval without notifying opponents of the project.

The meeting, on March 15, 1990, was requested by commission staff, according to an account in the Energy Law Journal, which said the applicants also met with at least one commissioner about the status of the application.

Martin Fitzgerald, special assistant to the general counsel at the General Accounting Office, told the House Government Operations Committee panel in 1992 that the discussions involved amendments to the application, the timetable for the commission’s review of new aspects of the project and a change in the project’s gas capacity, according to the Journal of Commerce.

Scherman, who was assigned to investigate the issue, reported on June 29, 1990, that the meeting dealt only with procedural matters and thus did not violate FERC rules.

But Environment, Energy and Natural Resources Subcommittee Chairman Mike Synar (D-Okla.) released a memo Scherman had written to FERC Chairman Martin L. Allday weeks before that report was issued — and before the investigation was complete — indicating Scherman had already reached that conclusion. A second GAO investigator told the subcommittee that FERC employees who were at the meeting said Scherman asked them only perfunctory questions about it, according to a Washington Post account.

The commission’s ruling on the pipeline application sided with Scherman on the characterization of the meeting (CP89-634), as did the D.C. Circuit Court of Appeals.

Second Incident

Scherman also was criticized for not disclosing that Transcontinental Gas Pipe Line Corp. had asked him and the commission’s deputy general counsel for oral argument prior to commission action on a rehearing request. A divided commission ruled in January 1992 that the request should have been treated as an ex parte communication and made public.

According to the order, the request was made following the commission’s September 1990 order denying Transco’s request for an oral argument. “Counsel for Transco orally asked the general counsel and the deputy general counsel of the commission for an oral argument prior to the commission acting on rehearing in this case. That oral request was not disclosed to the parties or to the commission. Subsequent to these communications, the general counsel and the deputy general counsel recommended to the commission that it grant an oral argument.”

Citing the Iroquois opinion, the majority said, “this is the kind of doubtful situation that should be treated as involving comments related to the merits in order to protect the integrity of the decision-making process.” The dissenting commissioners concluded the request for oral argument was procedural and thus permissible (TA85-3-29).

Editor’s Note from Rich Heidorn Jr.

After saying Monday morning that he had no further comment on the Chatterjee incident, Scherman emailed RTO Insider in the afternoon, saying he wanted to go on the record with criticism of me over my role as a FERC whistleblower in a 2006 incident.

The incident occurred after then-FERC Chief of Staff Daniel Larcamp negotiated a settlement to end an investigation by the commission’s Office of Administrative Law (OAL) under circumstances that suggested that Southern Co. and FERC management had engaged in ex parte communications.

As a staffer in FERC’s Office of Enforcement, I had been loaned to OAL’s trial staff to aid in the investigation, which concerned whether Southern was improperly sharing nonpublic information with the company’s marketing affiliate.

When I confirmed with my superiors that Larcamp’s settlement would have improperly allowed Southern to continue sharing nonpublic information — but was unable to persuade them to block it — I consulted with an attorney with the Government Accountability Project, an organization that represents whistleblowers.

Based on my attorney’s advice, I went public with my concerns through Rep. Henry Waxman, then the ranking Democrat on the House Oversight and Government Reform Committee. I also was quoted in the press. The commission ultimately rejected the settlement Larcamp negotiated and imposed tougher conditions.

Larcamp’s Entry

Larcamp entered the case in September 2005, after trial staff had obtained evidence indicating that Southern’s subsidiary, Southern Power, attended meetings at which sensitive information (i.e., plant retirements, present and future load characteristics, expected resource additions and industrial energy sales) was exchanged. This is information that Southern Power would not have been allowed to receive were it properly classified as a “marketing” affiliate under FERC’s regulations.

On Sept. 21, 2005, Larcamp declared himself “non-decisional,” meaning that, like trial staff, he was not prevented from talking to Southern under ex parte rules. Doing so, however, meant he could not discuss the matter with any commissioners or other “decisional” FERC staff.

Larcamp never met with the trial team to discuss the evidence in the case before beginning his settlement talks with Southern. The team did not even know Larcamp was talking to Southern until he abruptly informed OAL managers in November, while team members were deposing Southern officials in Birmingham and Atlanta. Staff were ordered to cancel the remaining depositions and return to D.C.

Larcamp said he was settling the case at the behest of then-Chairman Joseph Kelliher, who took the gavel two months after the case was initiated under Chairman Pat Wood.

“[Larcamp] said Southern thinks it has two votes on the commission in its favor on this issue,” according to an internal memo I provided to Waxman. “He said that if that didn’t work, Southern would likely apply political pressure. … But he said that even if the case goes forward, the chairman would not be eager to expedite it, and it would likely languish through 2007.”

Scherman’s Statement

Here is Scherman’s statement in full:

“In your short time at FERC, it was public information that you engaged in unethical and unlawful actions. As you know, at that time, I, along with others, publically [sic] stated that on the record. As you know, I, along with those who were at the FERC at that time, were highly critical of your improper and unethical conduct. As a result, you should recuse yourself from any potential story where I am involved given your obvious prejudice and bias. Seeking to settle an old score is unethical and unscrupulous conduct that exhibits actual malice. Any reputable ‘journalist’ would be disreputable by failing to include fully this on-the-record comment in any story that might run.”

For the record, I worked for FERC for eight years, from 2002 to 2010 (and had frequent contact with Scherman on matters concerning his client, Entergy). FERC never took any disciplinary action against me for my role. In October 2006, the commission unanimously rejected the settlement Larcamp negotiated and imposed tougher conditions (EL05-102).

Commissioner Suedeen G. Kelly, writing in a concurring statement, said, “It is well-known that the process leading up to the filing of this settlement was highly unusual and caused great controversy.”

Kelly cited comments that Administrative Law Judge Edward M. Silverstein made to a member of the commission’s trial staff during oral arguments following the settlement. “I’ve been here almost 15 years, and I’ve never been involved in a case in which somebody representing the commission — other than trial counsel — negotiated a settlement. And so, I think your position is unique and maybe even dangerous,” Silverstein said.

Six months after FERC’s ruling, Larcamp left the commission for a new job — with Southern’s law firm, Troutman Sanders.

January 23, 2018

ISO-NE Seeks Path to Mass. GHG Cost Recovery

By Michael Kuser

Massachusetts generators are worried they won’t be able recover the costs of purchasing additional greenhouse gas allowances after state regulators last month implemented stricter limits on emissions from fossil fuel plants.

ISO-NE is floating a proposed solution.

In a memo issued Friday to the New England Power Pool Markets Committee, the RTO said the early January cold spell has provoked concern among some generators “that they may consume all of their initial allocation of allowances and emit beyond that allocation before the end of the year.”

The generators are questioning their ability to recover costs for buying more allowances through bilateral trading once their initial allowances from the state are exhausted. The new rules require the utilities to purchase at least 16% of their electricity from clean energy sources in 2018, stepping up by a minimum of 2 percentage points annually until 2050. (See Massachusetts Tightens GHG Limits for Generators.)

ISO-NE GHG cost recovery — The 1,113 MW Canal Generating Station in Sandwich, MA is owned and operated by NRG Canal, an affiliate of GenOn Energy Management and NRG Energy | *EPA*

ISO-NE is proposing a possible recovery mechanism for instances when allowance costs cannot be reflected in a participant’s energy market supply offer. The proposal hinges on a waiver request that GenOn Energy Management filed with FERC earlier this month.

Immature Market

While generators can purchase additional GHG allowances from other participants through secondary markets, the Massachusetts program is only in its first year, and secondary trading is not mature — nor are there reasonably forecasted price ranges, ISO-NE said.

That contention mirrors one made by GenOn, an NRG Energy subsidiary, in its FERC filing requesting a limited, one-time waiver enabling it to seek additional cost recovery for purchases of emissions allowances required under the Massachusetts rule. The company said the waiver would allow purchases that might be needed for the continued operation of its 1,113-MW Canal Generating Station in Sandwich, Mass., “including operation this winter, if and as they become available from other allowance holders later in 2018 and into 2019 or, as a last resort, in an auction for 2019 Massachusetts GHG allowances (which could be used to cover a 2018 shortfall on a three-to-one basis).”

GenOn asked the commission to issue an expedited order on its request by Feb. 2 and sought a shortened comment period of 14 days (with comments due on Jan. 22).

Both ISO-NE and its Internal Market Monitor support the company’s request.

Possible Remedy

GenOn worked with the Monitor last fall to devise an additional GHG cost recovery mechanism under an ISO-NE rule that permits a participant to request additional cost recovery in the event its supply offer is mitigated in the energy market, leaving it unable to recover variable production costs.

The provision requires the participant to initiate a cost recovery request within 20 days of receipt of the first invoice for allowances for the applicable operating day. If additional allowances are bought more than 20 days after operation, the regulatory timing requirements would preclude their use for cost recovery of the additional allowances.

The RTO said it would support such a waiver, provided it can review the waiver request in advance and ensure it is limited only to an extension of time to file for cost recovery. The grid operator also clarified that the additional cost recovery must only cover the cost of purchasing additional allowances.

The Monitor and RTO added a final condition: that cost recovery would only be appropriate to the extent that energy market revenues earned for operation during the period covered by the purchased allowances are insufficient to cover the cost of those allowances, and only to the extent the revenue deficiency resulted from mitigation.

Legal Challenge

GenOn last week also joined with the New England Power Generators Association to file suit in Suffolk County Superior Court against the state for “regulating emissions from the electric generation sector in the same manner as all other sectors of the Massachusetts economy.”

The suit alleges that the state’s GHG rules “are arbitrary and capricious because they will increase statewide greenhouse gas emissions in direct contravention of the express purposes of the Global Warming Solutions Act.”

GenOn cited ISO-NE modeling of the impact of the rules on statewide GHG emissions demonstrating that generators in the region would maintain reliability by shifting electricity production from power plants in Massachusetts to other states. Relatively efficient clean-burning facilities in Massachusetts would therefore operate less, while inefficient and less clean resources in other states would run more.

Finally, the suit alleged that the state agencies exceeded their statutory authority in promulgating mass-based emissions regulations that remain in effect 30 years beyond the sunset date for any such regulations.

January 23, 2018January 17, 2024

Connecticut Regulators Signal Support for Millstone

By Michael Kuser

Dominion Energy could be one step closer to winning state financial support for its 2,111-MW Millstone nuclear plant in Connecticut.

The Department of Energy and Environmental Protection and Public Utilities Regulatory Authority on Monday issued a draft final report on the economic viability of the plant and signaled their support for state procurement of its energy output under a program reserved for renewable energy resources such as large-scale hydropower, wind and solar (S.B. 106).

The regulators concluded that the public procurement process for Millstone should “go forward” and asked industry stakeholders to submit comments on the report within three days — by Jan. 25 — so they can deliver a final report on Feb. 1.

“The competitive solicitation process created by the legislature is reasonable, and we will propose to the General Assembly that they pursue that process,” DEEP Commissioner Robert Klee said in a teleconference with reporters.

The legislature failed to pass a bill last June that would have allowed the Waterford plant to bid into the procurement process, unlike Illinois and New York, which last year voted to support nuclear plants through zero-emission credits.

The regulators said the procurement should go forward “with certain conditions to ensure that the state’s ratepayers are protected from paying above-market costs for resources that are not verified to be at risk of retirement.”

Conflicting Advice

Gov. Dannel Malloy in July ordered the agencies to assess the current and future viability of the Millstone plant and determine whether the state should provide financial support (17-07-32). In reaching their preliminary conclusion, regulators said they considered confidential documents from Dominion, and stakeholder comments on a study by Levitan Associates that found the plant will likely remain profitable through 2035. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)

In the past few months, state regulators have heard conflicting advice on the issue. The Electric Power Supply Association earlier this month filed comments with the state contending that Millstone’s profitability made any ratepayer subsidy unnecessary. EPSA cited a study by Energyzt Advisors that characterized Millstone as “perhaps the most profitable nuclear plant in the United States.”

The General Assembly submitted comments in January encouraging PURA and DEEP to “hedge against natural gas by opening a bidding process to receive bids from nuclear generating facilities, including Millstone, to purchase power directly by long-term contract.” (See Conn. Regulators Hear Conflicting Advice on Millstone.)

DEEP Analysis

The draft report said the current and projected economic viability of Millstone hinges on energy market revenues and plant operating costs.

PURA Chair Katie Dykes said the Levitan study used the best available public information to develop cost assumptions for the two Millstone units but lacked precision because of the absence of cost information from Dominion. The company submitted a two-page summary of short-term, forward financial projections in November and a longer, redacted document on Jan. 10.

While Millstone’s retirement would not trigger the need for new capacity in Connecticut specifically, it would spur a need for new generation capacity in New England as a whole. Replacement capacity procured through ISO-NE would likely be natural gas-fired, exacerbating security and system reliability issues because of the region’s heavy reliance on gas for power generation.

“It’s important that we are issuing this report just a few days after ISO New England released their own evaluation of the region’s exposure to risks of rolling blackouts if facilities like Millstone or Seabrook or LNG facilities were to be offline for a prolonged period or retire,” Dykes said. (See Report: Fuel Security Key Risk for New England Grid.)

A Regional Issue

If Millstone’s two units stopped operating, CO₂ emissions for the entire New England electric sector would increase by 80 million short tons, or 25%, through 2035, according to the regulators’ report. Replacing at least 25% of Millstone’s output with hydropower, demand reduction, energy storage and zero-emission renewable energy would be necessary for Connecticut not to backslide on its statutory greenhouse gas emissions reductions targets, and would cost the state’s ratepayers an estimated $1.8 billion, it said.

Even with that investment, regional emissions would increase by 20%. Replacing 100% of Millstone’s output with zero-carbon resources would cost Connecticut ratepayers approximately $5.5 billion, the draft report said.

In theory, regulators could use a variety of mechanisms to provide revenue stability for new and existing zero-carbon resources, including long-term power purchase contracts and ZECs.

At present, there are no mechanisms to retain Millstone and allocate the costs regionally. The RTO has indicated in this proceeding that Millstone would not be eligible for a reliability-must-run contract on a transmission security basis. And FERC earlier this month rejected the U.S. Energy Department’s Notice of Proposed Rulemaking that would have required RTOs to compensate nuclear and coal-fired facilities on a cost-of-service basis.

“It’s been unfortunate that the regional discussions at [the New England Power Pool] and at the ISO have not produced any actionable mechanisms to date that could ensure that the region’s ratepayers would be able to do their share in paying to retain these kinds of critical facilities, given that the entire region shares an incentive,” Dykes said.

Klee said the General Assembly would have 30 days to respond to the agencies’ proposal and that details of any forthcoming request for proposals would be worked out in the standard regulatory process.

January 23, 2018

NY Siting Board Approves 126-MW Cassadaga Wind Farm

The New York Board on Electric Generation Siting and the Environment last week approved a 126-MW wind farm to be built and operated by EverPower Wind in the state’s westernmost county.

The Cassadaga Wind project will occupy about 77 acres in Chautauqua County and consist of up to 48 high-capacity, 500-foot-tall wind turbines. The wind farm would interconnect to the state’s electrical grid along the 115-kV Dunkirk-Moon transmission line.

NYISO EverPower Wind Cassadaga Wind Project — | *EverPower Wind*

EverPower had proposed installing up to 62 turbines but lowered the number during the public review process, which included opposition comments from Amish residents and local equestrians. Many Amish do not use electricity from the grid, and the equestrians argued that siting huge wind turbines near their riding trails could spook horses, potentially injuring both animals and riders.

In May 2016, EverPower was the first company to apply for a siting certificate from the multiagency Siting Board, which was established under the Power NY Act of 2011 to streamline the permitting process for power plants 25 MW or greater. John B. Rhodes, chair of the Public Service Commission, also chairs the board.

The board said that the wind farm will improve fuel diversity, grid reliability and modernization of grid infrastructure, as well as benefit the host communities. The developer said the new wind farm will create “nearly 470 construction and full-time jobs with an annual payroll of more than $80 million, while paying more than $10 million to local governments and school districts over a 20-year period.”

— Michael Kuser

January 23, 2018

SPP, Mountain West Resolving ‘Contentious’ Issues

By Tom Kleckner

OKLAHOMA CITY — SPP COO Carl Monroe told the Markets and Operations Policy Committee last week that the RTO’s integration of Mountain West Transmission Group is on track to meet its October 2019 consummation timeline, pending reaching final agreement among the various parties.

A small negotiating team tasked with resolving a subset of five “real contentious” issues has reduced the list to two after an initial meeting, Monroe said. He would not elaborate on the issues at play, but Mountain West entities have suggested several governance changes that would emphasize the differences between the two interconnections. (See SPP, Mountain West Integration Work Goes Public.)

SPP Mountain West Peak Reliability — | *Colorado Public Utilities Commission*

Monroe said the team is “intent” on coming up with a recommendation that can be brought back to the Board of Directors and Members Committee here next week. “It does look like we’re getting closer,” he said.

Complicating matters somewhat, Monroe said, was Peak Reliability’s recent announcement that it would work with PJM to offer market services, and CAISO’s desire to offer reliability coordination in its footprint for half the price of Peak. (See CAISO to Depart Peak Reliability, Become RC.)

“That’s created a whole bunch of ripples in the West on the reliability side, and market side too,” he said. “We continue to have conversations as to what this means to Mountain West going forward.”

SPP’s Strategic Planning and Corporate Governance committees have been meeting with Mountain West representatives behind closed doors since October. Monroe assured members they would have a chance to add their input to any protocol and Tariff changes as they bubble up through the RTO’s normal stakeholder process.

SPP working groups will handle the Tariff changes, while the CGC will be responsible for the governance changes. Monroe said financial obligations won’t be discussed until both parties “are comfortable with the policy level.”

January 23, 2018

SPP Stakeholders Still Struggling on BTM Reporting

By Tom Kleckner

OKLAHOMA CITY — SPP’s Markets and Operations Policy Committee last week continued to hash through the difficulties of reporting behind-the-meter (BTM) load, a holdover issue from its previous two meetings.

In July, the committee directed a stakeholder group to address “inconsistency and uncertainty” over which BTM generation qualifies as network load. In October, the committee rejected the Regional Tariff Working Group’s proposal of a 1-MW threshold for reporting BTM network load, and the Board of Directors declined to reverse the decision on an appeal by Southwestern Public Service. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)

spp btm behind-the-meter load — | *Sunrun*

SPP staff shared with the MOPC and the Strategic Planning Committee initial results of a survey of network integration transmission service (NITS) customers. The survey focused on NITS load reporting, with an emphasis on grandfathered agreements (GFAs), BTM generation and “special circumstances.”

“It was unclear to us in whether all the behind-the-meter gen was identified, and then netted with the load,” said SPP COO Carl Monroe. “There was some controversy as to whether you can net the load with behind-the-meter generation.”

Monroe said staff are reviewing the survey responses and asking follow-up questions, such as:

What load and BTM generation is netted versus added?
Why are some grandfathered megawatts not being included in resident load? (Resident load is a term SPP uses to ensure all load is paying Tariff rates.)
What are the details of the “special circumstances”?

Monroe said the aim is to foster continued discussion and education, and to determine the consistency of members’ NITS reporting practices. He hopes to produce a final report in April.

“One of the real concerns is that stakeholders with network load may not really understand what needs to be reported. Your survey results may indicate a lack of knowledge,” said Golden Spread Electric Cooperative’s Mike Wise. “That is what I was hopeful of finding. You are really highlighting some of the folks in our footprint don’t understand the rules and don’t understand FERC’s requirements.”

“We just asked what people were doing. We didn’t proclaim what needed to be done,” Monroe responded.

At the same time, SPP’s legal staff met with FERC to gain a better understanding of what is and what isn’t net metering.

“As we thought, since SPP has a pro forma Tariff, all load, if reported, can’t be netted,” said General Counsel Paul Suskie. “If somebody thinks they have a good case because of behind-the-meter load, it can be filed at FERC. To our knowledge, no SPP member has ever done that.”

Suskie said his department is working to further clarify for members what the BTM rules are today, and “what it would be tomorrow if we make a filing at FERC.”

“Once we get the results finalized and understood, we can see which ones don’t line up with what we believe FERC has said through its pronouncements,” Monroe said.

MOPC Chair Paul Malone, of Nebraska Public Power District, pushed unsuccessfully for a face-to-face educational meeting to help bring some consistency to network load reporting and “make sure we have a legal understanding of what FERC requires.”

“That’s critical, because that’s what billing is based on,” he said. “I think some of it is just different interpretations,” he said. “Looking at the [survey] items, it’s no wonder. ‘GFAs’? Lots of issues there. ‘Special circumstances’? I think we’re getting murkier, rather than clearer.”

Kansas City Power & Light’s Denise Buffington pressed both the MOPC and the SPC as to whether the 1-MW exemption would go before the Board of Directors next week. Monroe reminded members the board took no action on SPS’ appeal; Suskie said SPS could still place the issue on the agenda.

“I thought we made a commitment that it should be on the agenda in January,” said Board Chair Jim Eckelberger.

An agenda and meeting materials for the board’s Jan. 30 meeting had yet to be posted as of Monday.

Suskie said staff will present the board with draft reporting rules based on its “pretty extensive” discussion with FERC and the survey results “later this month.”

Separately, MOPC approved a revision request (RR 251) from the Supply Adequacy Working Group that addresses three issues FERC used in once again rejecting SPP’s resource adequacy package last year. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)

The commission said:

SPP’s proposal failed to include requirements that all power purchase agreements are backed by verifiable capacity to meet the RTO’s resource adequacy requirement (RAR), and that provisions to allow SPP to verify the agreements are backed by capacity;
the proposed treatment of firm power purchases and sales in determining net peak demand is unduly discriminatory; and
SPP has not supported as just and reasonable its proposal to publicly post a list of load-responsible entities that had not met their RAR.

The motion was opposed by the Kansas Municipal Energy Agency, while 10 other members abstained.

January 23, 2018November 29, 2023

SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018

OKLAHOMA CITY — SPP’s Markets and Operations Policy Committee unanimously approved a Market Working Group (MWG) revision request (RR 245) that adds a major maintenance cost in mitigated start-up and no-load offers, resolving pushback from the RTO’s Market Monitoring Unit.

The MWG said the change allows market participants to include major maintenance costs associated with the number of starts or run hours in their mitigated start-up and no-load offers, resulting in the recovery of true variable costs.

The revision received a thumbs-up from MMU Executive Director Keith Collins, who said he was aware the Monitor had opposed previous versions of the change.

“The Market Monitor believes that changes made to 245 … are substantial differences that allow the Market Monitor to find this approach acceptable,” he said. “One, we’re not moving down the variable maintenance approach we tried last time, and two, we are talking specifically about major maintenance for start-up and no-load. This approach is consistent with how other RTOs address major maintenance.”

The MOPC’s endorsement allowed the MWG to recommend closing several action items and withdrawing two other revision requests it had been working on: RR 231, which addressed fuel-cost changes, and RR 214, which removed locally committed resources from the economic mitigation tests. The latter revision request, which also created a 10% cap for resources committed for local reliability, had been remanded back to the working group by the committee for additional review.

The MMU opposed RR 214, saying it discovered resources were “self-mitigating” to pass the conduct threshold test and avoid possible mitigation.

RR 245 “takes a little of what PJM is doing and what MISO is doing, and puts them together,” Collins said. “We like driving in the middle of the road.”

MWG Vice Chair Jim Flucke, of Kansas City Power & Light, said, “Given everything else we passed, 214 as written is no longer the right approach to the remaining issues we have.”

Golden Spread Electric Cooperative’s Mike Wise thanked the MWG for its work, saying, “This is taking SPP substantially forward.”

The MOPC approved the recommendation to withdraw the revision requests with three abstentions.

Members unanimously endorsed two other revision requests brought forward by the MWG:

- - MWG-RR247: Clarifies language to reflect how the market-clearing engine treats contingency reserves in the real-time balancing market when a contingency reserve event is deployed.
  - MWG-RR257: Responds to a FERC compliance requirement (EL16-110) requiring SPP to limit the eligibility for auction revenue rights and long-term congestion rights of network customers with service subject to redispatch. The changes will ensure network service subject to redispatch is treated comparably with point-to-point service subject to redispatch. (See FERC Again Rejects SPP Rules on ARRs, LTCRs.)

SPP Pays MISO $2.25M After M2M Resettlements

SPP has reimbursed MISO more than $2.25 million after resettlements of several market-to-market (M2M) flowgates and will continue to perform “limited” resettlements because of a memorandum of understanding between the two RTOs.

The resettlements stem from binding events on three flowgates along the SPP-MISO seam. SPP has accumulated $32.73 million in M2M payments through November since the two RTOs began the process in March 2015.

“Large dollars are transferring between SPP and MISO on a daily basis,” said David Kelley, SPP’s director of interregional relations. The resettled payments “shouldn’t have been paid to us to begin with, but we didn’t have a lot of criteria around it. We needed to ensure [M2M coordination] is grounded in some of [the MOU’s] principles.”

The RTOs executed the MOU last summer to improve M2M coordination after what Kelley called a “significant” amount of time and negotiation. They then revised the MOU to address power swings and capping its firm-flow entitlement provisions. FERC accepted the revisions in December (ER18-150).

Kelley reminded members that the commission directed the RTOs to begin M2M coordination with the implementation of SPP’s Integrated Marketplace in 2014. FERC cited the success of a similar process between MISO and PJM.

“We knew we had some room for improvement almost immediately because of the way the system operated,” Kelley said. “From the moment we threw the switch, we saw significant oscillations and power swings on some flowgates. We knew this wasn’t how it was supposed to work.”

“It’s all because Iowa wind is impacting our system,” SPP COO Carl Malone said, issuing a refrain familiar to many of his colleagues.

“I think we’ve ended up in a good place where the process should work much better,” Kelley said.

SPP and MISO will both file waivers with FERC to complete the resettlements.

Kelley also said SPP will “take a run at another filing” with FERC over two potential seams projects with Associated Electric Cooperative Inc. The commission last year rejected both projects, saying SPP had not shown its proposed cost allocations on a load-ratio share basis were “roughly commensurate” with the projects’ benefits. (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)

SPP staff have met with FERC staff to gain further insight as to why their filings were rejected. “It’s not a for-sure slam dunk [for SPP],” said General Counsel Paul Suskie, “but it’s worth another try.”

In the meantime, Kelley has kept open the lines of communication with AECI.

“We’ve reiterated our support and commitment, and they’ve reiterated their support and commitment as well,” Kelley said.

MOPC Agrees to Pull Basin Electric Project’s NTC-C

The committee unanimously agreed with staff’s recommendation to withdraw a notification to construct with conditions (NTC-C) for a Basin Electric Power Cooperative transmission project in North Dakota.

Staff said their updated load projections indicated there was no longer a need for the 33-mile, 345-kV Kummer Ridge–Roundup line. Staff studied winter and summer peak scenarios in 2022 and 2027 before making their decision.

The project began as a 115-kV line in SPP’s 2016 near-term assessment, but its NTC-C was modified by the Board of Directors in July 2016 to reflect the change in voltage to 345 kV. It has an estimated cost of $52.3 million.

The MOPC and board both approved Basin Electric’s request for an expedited re-evaluation in April 2017. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)

Staff also alerted MOPC about a change in a New Mexico project that came out of its 2014 High-Priority Impact Load Study. Tapping an existing 115-kV line to build a new 115-kV substation at Ponderosa Tap had been approved at a cost of $4.9 million. However, staff said the project costs were incorrectly designated as “direct assigned” and should be “base plan” funded instead. The cost was reduced slightly.

Stakeholders separately unanimously endorsed the 2018 Transmission Expansion Plan, sending it to the board for its approval. Members completed 36 projects costing $246 million in 2017, while SPP issued 71 NTCs for an additional $263.2 million in spending.

North Dakota Sponsored Upgrade Study Approved

The MOPC endorsed SPP’s sponsored upgrade study performed for Central Power Electric Cooperatives, a member company in North Dakota that purchases power from Basin Electric to serve its own six-member cooperative.

CPEC proposed changing a 115-kV breaker status from “normally open” to “normally closed” and completing a 115-kV loop between two Western Area Power Administration substations to correct a potential thermal violation in the 2026 summer models. Staff said CPEC would have to bear the costs of the upgrade and any mitigations.

SPP issued a report to CPEC, Basin Electric and WAPA in November.

NERC Stakeholder Teams to Review, Reduce Standards

‎Charles Yeung, SPP’s executive director of interregional affairs, told members they face a Feb. 2 deadline for submitting input to NERC on its standards streamlining effort.

The agency has formed three teams to review long-term planning, operations planning and real-time operations standards. The teams will provide recommendations on reducing the number of NERC standards — not including critical infrastructure protection standards — by the third quarter of this year.

The teams, which still have open seats, have scheduled one-hour webinars Jan. 24-25 for orientation and to discuss scope, timelines and other matters.

Consent Agenda Clears 10 Revision Requests

The MOPC approved a measure that documents market import service (MIS) as a transmission product in the Tariff; it has been offered in SPP’s Integrated Marketplace since 2014. RR 250 places all information related to reserving and scheduling MIS in one location as a new business practice.

Malone pulled the revision from the consent agenda, pointing to language that said MIS had not been implemented through Tariff language.

“The Tariff language being added is brand new,” he said. “I read that it didn’t exist until today. It looks like new service to me.”

Malone was joined in opposing RR 250 by the Municipal Energy Agency of Nebraska. ITC Holdings abstained from the vote.

The MOPC unanimously approved nine other revision requests on its consent agenda:

- - CPWG-RR249: Corrects, updates and clarifies unclear or outdated letter of credit language to make it more acceptable to financial institutions.
  - MWG-RR 18 2: Removes the term “control area,” which is no longer used by SPP, from the market protocols and the Tariff.
  - M WG-RR2 00: Removes bilateral settlement schedules (BSS) at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. The revision allows only BSS at a withdrawal point to be included in the OCL distribution calculation. It caps the BSS at the maximum amount of the real-time withdrawal minus any amount of grandfathered agreements and federal service exemptions.
  - MWG-RR2 4 6: Clarifies language explaining SPP’s congestion management efforts when declaring transmission loading relief (TLR) and removes a reference to an old system name. SPP does not have an active TLR for every congestion management event, but the protocol language will be updated to read “as soon as practicable,” and adds provisions for market-to-market coordinated curtailments in lieu of TLR market flow curtailment targets when appropriate.
  - MWG-RR253: Changes how dispatchable variable energy resources (DVERs) provide regulation down service. SPP said the change will lower structural barriers to DVERs providing regulation service and allow the system to operate more efficiently in times of high wind when SPP could use online turbines rather than requiring uneconomic commitments of other resources.
  - MWG-RR254: Updates the data requirements requested from SPP’s forecasting vendor to improve the wind and solar power forecast. Additional data requirements include individual wind turbine coordinates, turbine model characteristics, cold-weather packages, and turbine availability and de-rate submissions.
  - MWG-RR258: Recommends modifications to the list of frequently constrained areas (FCAs) and resources from the Market Monitoring Unit’s 2017 study. FCAs are electrical areas with one or more transmission constraints or reserve zone constraints that are expected to be binding for at least 500 hours during a given 12-month period and within which one or more suppliers are pivotal.
  - MWG-RR265: A compliance filing in response to FERC’s order on handling ramp shortages under Order 825. (See FERC Approves SPP Shortage Pricing Changes.) Modifies the methodology through which scarcity pricing reflects the value of regulation and operating reserves. The Tariff language was filed in October (ER17-772).
  - ORWG-RR162: Requires phasor measuring units (PMUs) at new generator interconnections to aid in oscillation detection, generator model validation and post-event analyses, as has become common practice among SPP’s peers.

The consent agenda’s approval also resulted in MOPC’s endorsement of:

- - A 34.9% decrease in SPS’ escalated baseline cost of $17.67 million to rebuild 22.1 miles of 115-kV line and a 115-kV circuit.
  - A 23.2% decrease, to $58.8 million, in the escalated baseline cost for SPS to build a new 47.2-mile, 345-kV line and a 345-kV substation.
  - A 23.4% decrease, to $28.5 million, in the escalated baseline for Nebraska Public Power District to build a new 35-mile, 115-kV line and complete various upgrades.
  - Charter revisions to the Reliability Compliance Working Group reflecting the SPP Regional Entity’s dissolution.

— Tom Kleckner