Page 1422 – RTO Insider

February 1, 2018

DC Circuit Rejects Appeal of Entergy Bandwidth Decision

By Tom Kleckner

The D.C. Circuit Court of Appeals on Tuesday refused to overturn FERC’s decision to require Entergy Arkansas (EAI) to make $11 million in retroactive payments to its affiliate companies.

The Arkansas Public Service Commission last month appealed FERC’s rejection of its request to exclude EAI from making the backdated 2005 “bandwidth” payments stemming from Entergy’s system operating agreement, which EAI exited in 2013 (EL01-88-013). (See Ark. Regulators Contest Entergy Bandwidth Payments.)

Entergy Arkansas Bandwidth Payments — | *Entergy*

The state regulator contended the agreement made no provision for assessing payments after withdrawal, which meant the utility had no continuing obligation to its sister companies.

A three-judge panel for the D.C. Circuit disagreed with the PSC’s argument, saying EAI’s withdrawal does not mean it “extinguished its obligation to make incurred bandwidth payments” (No. 16-1193).

The court said contract law principles “support FERC’s conclusion that a party’s accrued contractual obligations continue beyond its withdrawal from a contract.” It cited commercial code that provides that “all obligations which are still executory on both sides are discharged” upon a contract’s termination, but “any right based on prior … performance” — that is, any accrued obligation — “survives.”

The PSC “points to no case or authority suggesting otherwise,” the court said.

The judges also disagreed with FERC’s contention that it should refrain from deciding the case because it “lacks the finality and/or ripeness necessary for judicial review.” They said FERC’s earlier decision consummated the agency’s decision-making process and determined EAI’s obligations.

Delaying consideration of EAI’s liability “would not ‘permit better review of the issues,’” the court said, “because the issues on review largely revolve around contract interpretation uninfluenced by future events.”

The ruling was issued by Chief Judge Merrick Garland and Circuit Judges Sri Srinivasan and Patricia Millett, who heard oral arguments in December.

The Arkansas commission is evaluating the ruling and considering “the options we may have,” Executive Director John Bethel told RTO Insider. “We want to make sure the Arkansas ratepayers are fairly treated.”

Under the Entergy system agreement, which expired in 2016, low-cost operating companies made annual payments to the system’s highest-cost company. The “bandwidth” remedy was used to ensure that production costs for Entergy’s five utilities were no more than 11% above or below the system average.

February 1, 2018

CASPR Filing Draws Stakeholder Support, Protests

By Michael Kuser

Stakeholders have responded to ISO-NE’s filing of a proposed two-stage capacity auction with a flurry of comments to FERC — many of them opposing the measure.

The vetting process for the Competitive Auctions with Sponsored Policy Resources (CASPR) proposal, and the late changes made by the RTO, left state regulators and stakeholders divided. Vermont, Connecticut and Rhode Island opposed the CASPR proposal filed with FERC, while Massachusetts, New Hampshire and Maine supported it. (See ISO-NE Effort to Accommodate States Leaves them Alienated.)

The proposal (ER18-619) grew out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 to address state regulators’ concerns about ratepayer costs associated with policy-driven resources and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.

Bay State Division

The controversy has even split officials within Massachusetts. In separate comments filed Jan. 29, the state’s attorney general urged the commission to reject or change the proposal, while the Department of Public Utilities “strongly” supported it.

Attorney General Maura Healey said in her filing that “the current incarnation of CASPR does not allow for any regular or reliable integration of sponsored policy resources” into the Forward Capacity Market.

Healey asked the commission to reject CASPR “because it will lead to unjust and unreasonable rates for New England consumers, who will pay twice for the same capacity,” and remand it with an order for remedial action to incorporate a mechanism like the “backstop” proposed by the New England States Committee on Electricity, which would guarantee entry into the FCM every year for a minimum of 200 MW of sponsored policy resources.

She also suggested the commission could remand the proposal with an order to reinstate the renewable technology resource (RTR) exemption to the minimum offer price rule (MOPR), which CASPR proposes to eliminate.

The DPU, on the other hand, argued that CASPR would “provide a competitive, market-based approach” to allowing policy-driven resource into the FCM and “prevent direct harm to Massachusetts ratepayers and the inefficient development of more generation resources than the region requires, while preserving competitive price formation and nondiscriminatory participation in New England’s FCM.”

Conditional Support

In its Jan. 29 filing, NESCOE said the RTO’s “commitment to monitor CASPR’s performance and to propose appropriate remedies is critical — and a condition of NESCOE’s support.” The group also pointed to the RTO’s pledge to work with stakeholders to “refine or replace” CASPR if it fails to achieve its intended purpose of accommodating state entry over time.

“ISO-NE must revise CASPR if it falls short of its intent to accommodate the participation of state-sponsored resources or if it proves inflexible to the execution of state laws, which are not static,” NESCOE said.

Calpine sided with the New England Power Generators Association in supporting the proposal, calling it “a considered and reasonable compromise to allow state-sponsored new resources into the Forward Capacity Market, while minimizing the impact on competitive market pricing.”

In guardedly supportive comments filed Jan. 19, NEPOOL noted that its Participants Committee failed in December to approve the CASPR proposal, with a 57.75% vote in favor (60% being required to represent substantial approval).

Despite that shortfall in institutional support, NEPOOL said its stakeholder process on CASPR “narrowed, and in many cases resolved, a number of complex and interrelated issues, and certainly broadened the understanding and perspectives of all interests in the region.”

NEPOOL predicted FERC would confront disparate opinions and urged the commission “to exercise caution in parsing through these concerns and their interrelationship with each other.”

Does the FCM Matter?

Consumer advocacy group Public Citizen questioned the RTO’s motives and the overall need for the FCM.

“By prematurely submitting this CASPR experimental rate design against the wishes of its stakeholders, it appears as though ISO-NE is more concerned with preserving its competitive markets from the encroachment of non-market capacity additions, regardless of whether extending a ‘market-based’ mechanism over policy-procured capacity will result in just and reasonable rates,” the group said.

Public Citizen argued that “the question should therefore not be how to force policy-deployed capacity into the … market, but whether the capacity market is needed at all. Because non-market factors are clearly adding adequate capacity for New England.”

In a joint filing, he American Wind Energy Association, Conservation Law Foundation, Natural Resources Defense Council, RENEW Northeast, Sierra Club and the Sustainable FERC Project urged the commission to either retain the current RTR exemption or direct the RTO to provide a sufficient similar, alternative mechanism that would enable state-mandated renewable energy resources to participate in the FCM and make the market account for the capacity contributions of these resources should CASPR fail to do so.

The groups encouraged the commission “to re-examine the logic of applying the MOPR to clean energy resources being driven by legitimate state policies, which we believe inappropriately encroaches on state authority while lowering market efficiency and imposing unjust and unreasonable costs on customers.”

January 31, 2018January 22, 2024

Traders Seek Clarity in FERC Enforcement Under New Regime

By Rich Heidorn Jr.

ARLINGTON, Va. — FERC’s enforcement policy is unlikely to shift significantly despite the arrival of four new commissioners, a panel of present and former FERC staffers said Monday. But the commission should consider some process changes and provide more clarity in defining violations, several speakers said.

“I think the fundamentals of enforcement don’t change with any administration,” Tim Helwick, special counsel in FERC’s Division of Analytics and Surveillance, told the EUCI Financial Transmission and Auction Revenue Rights conference. “I think priorities can change with different personalities — it’s not a question of politics, just different personalities.”

Helwick’s comments came at the end of a 90-minute discussion before an audience of about 40 traders, regulators, and others that noted the growth of FERC’s enforcement unit since the Western Energy Crisis in 2000-2001. Once limited to a handful of staffers, FERC’s Office of Enforcement (OE) now numbers more than 200, with greatly expanded power to impose penalties under the Energy Policy Act of 2005.

“I think it’s too early to tell what type of change we’re going to see, and I don’t necessarily anticipate that we are going to see significant change,” agreed attorney Terence Healey, a partner with Sidley Austin and the only one on the panel without a FERC résumé listing. “You’re dealing with an agency that’s 200-plus folks that were there before the current administration. … I wouldn’t expect the fundamentals to change.”

Enforcement Director Larry R. Parkinson was appointed in April 2015, after five years as director of OE’s Division of Investigations.

He noted the commission’s annual enforcement report, released in November, indicated FERC would continue to focus on the same priorities in 2018 as in 2017: fraud and market manipulation; serious violations of NERC reliability standards; anticompetitive conduct; and conduct that threatens market transparency. (See Investigations up Sharply in FY 2017, FERC Report Shows.)

“I would take them at face value on that,” he said. “Whether certain cases on the edge should be brought, I could see changes like that.”

De Novo Procedures

He said the commission might consider changing its processes due to the number of enforcement cases ending up in federal court and because its decision to make early public disclosures about investigations has not worked as intended.

A 2009 policy change gave the Director of Enforcement authority to issue a Notice of Alleged Violations (NAV) that includes the identities of investigation subjects and a description of their alleged misconduct once the subject has responded to staff’s preliminary findings but before it finalizes its findings and the commission issues an order.

Previously, the commission kept investigations and the identities of investigation subjects private until FERC initiated an enforcement action or issued an order approving a settlement. FERC said it hoped the transparency would warn other market participants to steer clear of questionable trades and prompt them to bring evidence to staff.

“Maybe it’s time to rethink that. … because it’s something that’s not really produced what the commission intended it to be, which was to flag [concerns] for the market,” Healey said.

Healey also noted the increasing number of subjects choosing de novo hearings in federal court rather than having an administrative law judge rule on the merits of FERC’s allegations.

“At least six separate district courts have said if you remove [a case] to federal court, you get a trial” with the ability to supplement the administrative record created by Enforcement, cross-examine witnesses, and seek discovery, Healey said.

FERC had sought much more limited court reviews. (See FERC Loses Again on ‘De Novo’ Review.)

Healy said FERC could consider streamlining its process because it is subject to a five-year statute of limitations.

“FERC took the position that they satisfied the five-year statute of limits upon initiating an order to show cause,” he said. “ … We had a decision in the Barclays case that found it is satisfied when you file in federal court, and because of that, one of the respondents had his case tossed out.” (See FERC Settlement Cuts Barclays Market Manipulation Fine.)

The panelists said they saw no indication the new commission would consider licensing power and gas traders as is required of securities traders.

Licensing would be opposed strongly by traders and is “not likely in this administration,” said Chloe Cromarty, compliance manager for Mercuria Energy Trading and a former FERC analyst. “But all it takes is one big case to be a catalyst,” she acknowledged.

‘Vague Standard’

Panel moderator Shaun Ledgerwood, a principal in The Brattle Group and a former FERC economist and attorney, said the commission still has not provided a clear definition of “market manipulation.” Ledgerwood recalled asking for a definition during his job interview at FERC in 2008 and only being told, “You know it when you see it.”

“I thought, ‘Man, that’s a pretty vague standard,’” said Ledgerwood, who specializes in the economic analysis of market manipulation claims, “and as time has gone on, what I’ve seen is that the commission has tried to … show examples of what manipulation is … misrepresentation, gaming, cross-product manipulation … The reality is there is no definition yet of what exactly is manipulation nor — perhaps more importantly — what exactly is legitimate.”

Healey agreed: “We’re still struggling to try to understand what … FERC is going to view as manipulation. As of yet, we don’t have a district court that has actually opined on some of the back and forth on what fraud means.”

The lack of clarity creates headaches for compliance officials, Cromarty said.

She said her company runs its trades through screens to identify transactions that may trigger an investigation — for example, comparing proposed virtual transactions against financial transmission rights (FTR) positions or flagging trades involving new products or a marked increase in trade volumes.

“As a major FTR [financial transmission rights] trader, at any given time, we may hold more than 200,000 paths. Expecting one trader to know another trader’s position is not practical,” she said.

“One trader may hold an FTR position where another trader wants to execute some virtual trades — and we may be flowing physical power across that path as well,” she explained. “We’re making the decision to prohibit one trader from transacting — in my opinion, legitimately — in order to avoid tripping the [FERC] screens because any revenue we make from transacting in that way is not significant enough to justify the potential regulatory risk that we’re facing. From my perspective, I think that’s having a negative impact on liquidity.”

Ledgerwood agreed. “You know if you get involved in the [investigative] process, it’s likely to be protracted. Not only is that expensive, it also takes a lot of psychic energy away from traders and the companies and their compliance personnel.”

Healey and others said they recommend traders put their plans in writing when they adopt a new strategy or engage in a particularly complex transaction. “It’s not a silver bullet, but it does provide a contemporaneous account for the intent of the trader at the time,” Healey said. “So long as it’s truthful and contains all the information — otherwise it’s problematic for obvious reasons.”

RTO Officials Discuss FTR Changes

In an earlier discussion Monday, ERCOT’s Carrie Bivens, MISO’s Blagoy Borissov, and PJM’s Brian Chmielewski talked about how their regions addressed revenue shortfalls in their FTR markets, while a CAISO official acknowledged “revenue adequacy continues to be a challenge” in California.

Guillermo Bautista Alderete, CAISO’s director of market analysis and forecasting, said the problem is a “misalignment” between CAISO’s congestion revenue rights auction and its day-ahead market.

CAISO has said that ratepayers receive only 52 cents in auction revenues for every dollar the ISO pays out to FTR holders. (See Market Monitors Bring FTR Complaints to Congress.)

[Editor’s Note: RTO Insider Editor Rich Heidorn Jr. worked for the FERC Office of Enforcement between 2002 and 2010.]

January 31, 2018

Tax Breaks Spur Dominion Deleveraging

By Rory D. Sweeney

Dominion Energy CEO Thomas Farrell expressed confidence Monday that his company’s lobbying in Connecticut and Virginia are on track to benefit the company.

Executives speaking during the company’s fourth-quarter and year-end earnings call also outlined strategies to take advantage of the recently enacted federal tax breaks and spoke about the political uncertainty surrounding the company’s bid to take over SCANA, the South Carolina utility beleaguered by a failed nuclear project.

The company announced it performed right in the middle of its guidance for 2017, reporting operating earnings of $3.60/share. Mild weather throughout the year reduced earnings by $0.10/share, though weather-normalized electric sales for the year increased 1.7% over 2016, led by growth and sales to data centers and residential customers.

Unadjusted earnings were $4.93/share for the year, thanks primarily to tax reforms that created a $988 million gain from adjustments to a deferred tax liability. Revenues increased 4% for the year to $3.21 billion but fell short of a consensus forecast of $3.47 billion.

Regulatory Progress and a Mystery Bill

“We have worked with the regulatory agencies, including the sharing of confidential financial information, to convey the actual cost of operating two dissimilar units in a high regional labor market,” Farrell told analysts, referring to this month’s preliminary report from Connecticut state agencies that determined the profitability of Dominion’s Millstone nuclear facility in Waterford, Conn., can’t be confirmed without additional financial disclosures from the company.

Dominion Energy — Dominion expects Connecticut state agencies to acknowledge the financial instability of its Millstone nuclear generation station. | *NRC*

The report, jointly developed by the state Department of Energy and Environmental Protection and Public Utilities Regulatory Authority, recommends a statewide procurement of carbon-free electricity from new and existing sources. Without additional information proving Millstone’s instability, its bids would be analyzed on price alone. With that information, the bids could be evaluated on broader criteria. A final draft of the report is expected Feb. 1.

“We are looking forward to the opportunity to compete with other non-emitting generating resources in a state-sponsored solicitation for zero carbon electricity,” Farrell said.

Paul Koonce, who heads Dominion’s generation arm, sounded eager to shut down any speculation about how Millstone might be bid into the solicitation. After misinterpreting a question about whether the plant would be bid into the process as an inquiry into the amount of its bid, Koonce declined to specify, calling the information “obviously competitively sensitive.” He said the state’s final report will likely lead to a request for proposals issued around May “and then we will submit our bid as any others.”

Farrell also addressed the potential benefits of a bill advancing through the Virginia legislature but offered scarce details.

“Virginia moves legislation through in a very rapid pace normally, and I don’t think this will be an exception,” he said. “We think there are some very good things in it. There are some things that we will have to accommodate ourselves to, but overall we think it’s a constructive piece of legislation for our state and our customers.”

Farrell said it was “premature” to speak about it in any more detail because “there is still lots of work to be done on it,” but he assured analysts that “we’ll be in a position to talk about it, I think, more thoroughly on the next call” in three months.

Dominion’s executives said it’s hard to assess the impact of the federal tax cuts because the company operates in seven states. The company is assuming that the benefits will be passed through to customers for all of its state-regulated entities but acknowledged the improved profitability for all non-regulated and long-term-contracted businesses. However, the changes create “strong credit headwinds” for accrual-basis taxpayers like Dominion, and some of the benefit will be offset by delays in Dominion’s Cove Point LNG plant becoming operational, said Mark McGettrick, Dominion’s chief financial officer. He estimated the cuts will increase the company’s 2018 earnings by between $0.10/share and $0.15/share.

Tax Windfall

McGettrick confirmed that the federal tax breaks have allowed Dominion to begin plans to deleverage the holding company and clear away $800 million in debt. The cuts offset the delayed start at Cove Point, so the company could still issue $500 million in new shares earlier this month and reduce its capital expenditure budget by $1 billion while remaining committed to its current credit ratings, he said. He announced plans to increase the company’s credit facilities to $6 billion, which is in addition to a $500 million credit line being put together for its Dominion Energy Midstream Partners subsidiary in order to replace its existing credit line with the parent company.

“We’re committed to the ratings that we have. We will take the steps necessary to support that, and we took advantage of taxes to get a jump start,” he said.

While the credit expansion will increase liquidity, McGettrick assured the new shares were not issued to help finance the proposed SCANA takeover, which the company announced Jan. 3. The company will maintain a 6% to 8% growth rate through 2020, he said, and the SCANA deal could bump it above 8%.

“So with or without SCANA, we’re in terrific position with one of the best growth rates we believe in the industry and one of the highest dividend growth rates as well, but certainly SCANA would be a positive result for us,” he said.

Farrell said he expects SCANA’s shareholders to approve the deal in May and shrugged off what appeared to be a hostile hearing with South Carolina legislators earlier this month.

“We are optimistic that our proposal will be viewed favorably by lawmakers and regulators, and we can complete the transaction later this year,” he said.

Despite delays, executives were also upbeat about developments at Cove Point in Calvert County, Md. Construction is complete at the natural gas liquefaction plant, and the process to bring the cooling infrastructure online is underway. The plant will be in service by early March, Farrell said.

The company is also completing work on the $1.3-billion, 1,588-MW Greensville County Combined Cycle Power Station. The plant was 73% complete at the start of the year, with all major equipment in place, including the primary natural gas line. Metering and regulation controls are awaiting final approval, and the plant is expected to begin operating near the end of the year.

January 31, 2018

Solar Developer Contests Michigan PURPA Freeze

By Amanda Durish Cook

A solar developer is attempting to block a Michigan utility giant’s effort to halt its energy purchases under the Public Utilities Regulatory Policy Act (PURPA) for the next 10 years.

The conflict pits Cypress Creek Renewables against Consumers Energy, which supplies electricity to more than half of Michigan.

Consumers Energy in December asked the Michigan Public Service Commission (PSC) for permission to decline purchasing capacity from PURPA-eligible facilities, contending that it will not need any new generation over the next decade (U-18491). The company also requested that the PSC reset the value of Consumers’ avoided capacity cost to match MISO’s Planning Resource Auction price for all new PURPA-qualifying facilities’ offers to sell capacity. PURPA requires utilities such as Consumers Energy to purchase electricity from qualifying facilities at avoided-cost rates that reflect a utility’s own cost to build new generation.

In its filing, Consumers pointed to a 2017 case in which the Michigan commission ruled that the PURPA purchase obligation does not exist “if no additional capacity need is forecasted.” The company included a 10-year capacity proposition with its application.

But Cypress Creek this month filed in opposition to the plan, arguing that Consumers did not satisfy the grounds for a stay of PURPA obligations because the company could not prove it would be damaged in the absence of the waiver. The renewables developer also said a PURPA stay for Consumers would harm the public interest by hindering small solar development. Under PURPA’s implementation in Michigan, projects 2 MW and smaller are guaranteed a 20-year, fixed-price contract.

Cypress Creek’s complaint also contends that Consumers has itself admitted that it will need an additional 625 MW of renewable energy capacity to comply with Michigan’s 15% renewable portfolio standard.

PURPA michigan solar Consumers Energy Cypress Creek — Consumers Energy Campbell plant | *Michigan Building Trades Council*

Cypress Creek is joined in its arguments by the Environmental Law and Policy Center, which objected that Consumers’ 10-year capacity assumption “rests on faulty assumptions ― including an inadequate analysis of coal-plant retirements.” The environmental non-profit said Consumers failed to conduct a cost-benefit analysis on retirement of existing coal units, simply assuming that two units apiece at its Karn and J.H. Campbell plants will stay online through 2030. Consumers retired seven of its oldest coal plants in 2016, representing about 30% of its generating capacity.

$3 Billion, 700 MW

Cypress Creek said it has more at stake than Consumers in the debate over PURPA.

“The harm to Cypress Creek and other interested parties from granting a stay exceeds any harm to Consumers if a stay is not granted,” Cypress Creek said. The company said it is ready to invest $3 billion in low-cost, solar energy in Michigan through its affiliates, which already have approximately 700 MW of solar capacity under development in Consumers’ service area.

“These projects will be out on indefinite hold if Consumers’ request for a stay is granted,” the company said.

The company also alleged that Consumers’ timing of its application was opportunistic because the utility didn’t file for the waiver until after the Michigan PSC had set new avoided costs to file its application.

The PSC in November approved Consumers’ avoided cost rate at $117,203/megawatt year or $140,505/MISO zonal resource credit year (U-18090) but put the ruling on hold on Dec. 20, anticipating petitions for rehearing. A day later, Consumers filed its request for a stay.

“Consumers waited until after the Commission set new avoided cost rates to now claim that it does not have a capacity need,” Cypress Creek said.

Consumers maintains that PURPA will require it to purchase an additional 300 MW per year from qualifying facilities, burdening its customers “with up to $519 million of added expense over the next 20 years for a commodity that is unnecessary to serve their demand.”

Cypress Creek has found itself in a similar row over challenges to PURPA rates in Montana. The company has filed suit in both state and federal courts over the Montana PSC’s 2016 decision to first suspend, then slash PURPA rates and contract lengths offered to small solar producers. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)

January 31, 2018

IPPNY Unveils New Look, 2018 Priorities

By Michael Kuser

ALBANY, N.Y. — The Independent Power Producers of New York (IPPNY) rang in the new year Monday with a barbecue, a list of priorities, and a new logo.

Packed House for IPPNY’s annual Open House | © *RTO Insider*

“Topping the list regarding New York’s wholesale electricity market is the issue of pricing carbon,” said IPPNY CEO Gavin Donohue.

Donohue said IPPNY would work closely with the carbon pricing task force set up by NYISO and the state’s Public Service Commission (PSC) “[to monitor] the process for fair and open competition in the wholesale electricity market for all solutions, especially generation, transmission, and energy storage — and the viability of existing investments operating in the competitive market.”

IPPNY has sai d it “strongly supports” a carbon pricing approach that would add a carbon value to a resource’s commitment and dispatch costs based on its emission rate, with the price-per-ton set by the PSC.

IPPNY NYISO 2018 NYSERDA — Cusick | © *RTO Insider*

A number of elected state officials attended the Jan. 29 reception, including Sen. Joseph A. Griffo, (R-Rome), chairman of the Senate Energy and Telecommunications Committee, and Assemblyman Michael Cusick (D-Staten Island), chairman of the Committee on Energy.

PSC Commissioner Diane Burman also attended the event, which took place just hours after Gov. Andrew Cuomo released the state’s master plan for developing offshore wind. (See NY Offshore Wind Plan Faces Tx Ch a llenge.)

Entering his fourth year as chairman of his committee, Griffo said he looked forward to working with IPPNY on free market issues — and the state’s master plan for offshore wind could “conflict with” the philosophy of free enterprise. He questioned the wisdom of the proposal to put a state agency — the New York State Energy Research and Development Authority (NYSERDA) — in charge of contracting for the energy output of offshore wind farms.

IPPNY 2018 NYISO — Griffo | © *RTO Insider*

Griffo also said it was unlikely that he or IPPNY members would accept any form of utility-owned generation, which was one of seven market structure proposals in NYSERDA’s comments filed with the commission on Monday.

Cusick said he had “a good working relationship” with Griffo on several non-energy issues and looked forward to working together on energy.

“I just hope I’m not being set up here,” Cusick said, “but that’s just the instinctive reaction of a kid from Staten Island.”

Donohue said IPPNY was established in 1986 and last year he and other board members pondered “ways to breathe fresh life into the organization.”

The new logo was a product of that effort.

“Now at least we don’t look like a waste management company,” he said.

January 29, 2018

LaFleur Offers Views on SPP-Mountain West Integration

By Tom Kleckner

FERC Commissioner Cheryl LaFleur took time from a whirlwind listening tour of the Rocky Mountain region last week to visit the Colorado Public Utilities Commission and discuss the Mountain West Transmission Group’s desire to join SPP.

FERC SPP Colorado Public Utilities Commission Cheryl LaFleur Mountain West — FERC’s Cheryl LaFleur | © *RTO Insider*

Appearing Jan. 25 before the PUC’s fourth information session devoted to Mountain West’s pursuit of RTO membership, LaFleur recalled sitting in on what she said felt like the “100th meeting” of Mountain West stakeholders as they discussed the subject. SPP’s and Mountain West’s utilities are now deep into negotiations over membership, accelerating a process that began last January when the group announced its intention to join the RTO. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)

“You don’t go out on 200 dates if you’re going to break up,” LaFleur said. “There’ve been 100 since then, so it’s starting to seem pretty real.”

FERC’s most senior commissioner addressed questions from Colorado regulators, industry representatives and consumer advocates about jurisdictional issues, consumer representation in SPP and the new opportunities presented to Mountain West by recent structural developments in the Western Interconnection.

“These are exactly the kind of questions you should be asking,” she said. “There’s no time like now to ask questions of SPP, [of] the utilities that are coming to you for the authority to do this — of whomever is involved in this, because you have a critical role to play in making sure that what happens is right for the people in Colorado.”

The PUC has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado and Black Hills Energy, both Mountain West members.

No Rubber Stamp

Colorado Commissioner Frances Koncilja, who has been organizing the information sessions, said she will invite CAISO, Peak Reliability and PJM to a fifth forum, in either February or March, to explain “what they think they can do for Colorado citizens.”

“This is not a decision this commissioner is going to rubber stamp,” Koncilja said. “I want to know what all the alternatives are.”

While SPP is intent on becoming Mountain West’s reliability coordinator (RC), Peak Reliability, the group’s current RC, has recently proposed to offer market services in the Western Interconnection through a joint effort with PJM. Further complicating matters, CAISO has also given 18-months’ notice that it intends to leave Peak and offer its own reliability services for half the RC’s price. (See Peak, PJM Detail Western Market Proposal and CAISO to Depart Peak Reliability, Become RC.)

LaFleur said the prospect of multiple RCs in the West will require a concerted effort by regulators and others involved to maintain the “situational awareness” developed by years of having only one.

“It will take work with multiple RCs, but I suspect if we do the work right, it can be done in the same way as we have multiple RCs in the East,” she said. “It will take some careful work to make sure the situational awareness between RCs is sustained and that everyone’s treated fairly.”

Consumer advocate Larry Miloshevich, with Energy Freedom Colorado, asked LaFleur how nonutility stakeholders could make their interests heard in the face of decisions that he said were being made behind closed doors “for reasons that are not all that clear.” Come to FERC, she replied.

“I hate to sound like a civics book, but the citizens are not unprotected. [FERC’s commissioners] are sworn to protect them. That’s our whole job. We’re not here for the utilities,” LaFleur said.

“There are probably political reasons why [Mountain West] kind of sought to be its own thing rather than being with other parts of the West, but that’s not for me to judge,” she said. “Yes, file those arguments. We’ll listen to them.”

LaFleur referred to FERC doctrine, saying the move to join an RTO “is a voluntary decision by the members who go in.” She said the commission learned this the hard way after considering a nationwide standard market design in the early 2000s.

“There was a revolution, almost coast to coast, with people saying, ‘We’ll decide who we want to sign up with, not FERC,’” LaFleur said. “FERC said, ‘If this market thing is going to take off, we’re going to let people come together and make their own decisions.’”

The commissioner extolled the benefits of RTO membership, pointing out that organized markets now cover two-thirds of the country and include regions with and without electric competition.

FERC SPP Colorado Public Utilities Commission Cheryl LaFleur — | *SPP*

“It’s worked across all different models. Why? Because you’re deploying resources over a bigger footprint, so you can run your systems more efficiently with less reserves to bring your energy to customers and hopefully keep your lights on at lower costs,” LaFleur said. “All this change, all this wind, all this solar … it’s made people stand up and say, ‘Wow, there might be something in this for our customers too.’”

It just had to grow organically in the West.

“If this came from Washington, it would be DOA. We’ve seen that through multiple attempts,” LaFleur said. “The best thing FERC could do is say nice things when invited to go somewhere but not do anything. It appears the time is approaching when we might have to do something.”

January 29, 2018

ERCOT Technical Advisory Committee Briefs: Jan. 25, 2018

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week asked its Wholesale Market Subcommittee (WMS) to determine what went wrong during two recent market events.

On Jan. 22, ERCOT disabled the 69-kV contingencies being solved by the day-ahead market (DAM) software, with the exception of a contingency included in a real-time binding constraint during the previous 30 days. Staff issued a market notice at the time.

ERCOT TAC wholesale market subcommittee — ERCOT’s Technical Advisory Committee gathers for its January meeting | © *RTO Insider*

ERCOT’s Carrie Bivens said staff followed protocols by issuing the notice. “The alternative was aborting the DAM run,” she said.

On Jan. 23, real-time prices jumped to $5,800/MWh for 15 minutes, forcing ERCOT to deploy non-spinning reserves. Prices also exceeded the energy offer cap of $9,000/MWh during two five-minute intervals.

The ISO said it was the first time market prices reached the $9,000 price cap during two security constrained economic dispatch (SCED) intervals, pointing to ramping issues because of cold weather and higher-than-expected load around 7 a.m. Resource adequacy was not a problem, ERCOT said.

Staff’s David Maggio said ERCOT doesn’t intend to reprice the event, noting the systems were “working as expected.”

“We don’t see any issue with how things worked out,” he said.

Staff said the two events were unrelated, prompting Citigroup’s Eric Goff to respond, “They felt related to everyone.”

“The issue that caused the DAM software problem was unrelated to ramp constraining in real time,” Bivens said. “They just happened on the same operating day.”

The contingencies were restored Jan. 24 for the following operating day.

“We need a discussion at WMS, because you’re determining winners and losers when you turn off contingencies,” Morgan Stanley’s Clayton Greer said during the TAC’s Jan. 25 meeting.

The WMS next meets Jan. 31. The subcommittee will also provide real-time co-optimization training following its meeting.

ERCOT Sees 62% Drop in RUC Practices

ERCOT staff’s annual reliability unit commitment (RUC) report to the TAC last week revealed a more than 62% drop in the practice.

Maggio said that 562 instructed RUC resource-hours last year resulted in 534 effective RUC resource-hours, compared to 1,514 and 1,417, respectively, for all of 2016.

Of those resource-hours, 163 were successfully bought back, a clawback percentage similar to previous years. The total RUC make-whole amount was about $540,000, which was covered through capacity short charges.

The 534 effective RUC resource-hours were all a result of congestion (433), capacity (66) and Hurricane Harvey (35). No resource-hours were committed for ancillary service shortages, system inertia or extreme cold weather/start-up failures.

Maggio pointed to several recent improvements as causing the drop in RUCs, including reducing shadow price caps for transmission constraints from about $1 million/MWh to about $100,000/MWh and a nodal protocol revision request (NPRR744) that used a common trigger to fix the opt-out decision inconsistency between the SCED and settlements systems.

Staff and stakeholders are still working to improve both RUC functionality and transparency, Maggio said.

In other staff reports:

Assistant General Counsel Vickie Leady told stakeholders that staff have developed a definition of “affiliate” in line with the typical corporate use of the word. The proposed bylaw amendment clarifies when an affiliate relationship arises between two or more ERCOT members.
Members will be allocated almost $26,000 in resettlements from the Greens Bayou Unit 5 reliability-must-run contract, after certain costs were not fully settled before applicable true-up dates. The RMR, ERCOT’s first since 2011, was approved in June 2016 and terminated effective May 29, 2017.
Controller Sean Taylor said the ISO forecasts the system administration fee will be adequate and he “sees no need for a change” through 2019. Stakeholders had requested advance notice of any fee increases during the 2016-17 budget process.

Task Force Looks at Subcommittees’ Restructuring

Stakeholders agreed to form a task force to combine or restructure the TAC’s Retail Market (RMS) and Commercial Operations (COPS) subcommittees. The task force will begin its work Feb. 5, with the intention of reporting back to the committee for its Feb. 22 meeting.

Leadership from the two subcommittees met over the holidays and agreed on three options for restructuring them. The initiative is a result of the TAC’s annual structural review of its subcommittees and input from the Board of Directors’ Human Resources and Governance Committee.

Reliant Energy Retail Services’ Rebecca Reed Zerwas will lead the task force, after she was “‘volun-told’ to get this started.”

The RMS and COPS will continue in their current forms until a solution is endorsed by the TAC.

TAC Elects Helton Chair, Coleman Vice Chair

The committee unanimously elected Dynegy’s Bob Helton as its chairman, a position he has essentially held since September. Previously vice chair, Helton stepped into the role vacated by Adrianne Brandt, who left San Antonio’s CPS Energy to join Chair DeAnn Walker’s staff at the Public Utility Commission of Texas.

TAC Vice-Chair Diana Coleman, Chair Bob Helton | © *RTO Insider*

Diana Coleman, ‎senior market specialist with the ‎Office of Public Utility Counsel, was elected vice chair.

NPRR Clarifies ERCOT’s Jurisdictional Status Quo

The TAC unanimously endorsed NPRR861, which clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and market participants with respect to FERC. Possible actions include, but are not limited to, ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.

The PUC in December instructed the ISO to draw up the NPRR over concerns that transmission projects along the U.S. border with Mexico may threaten ERCOT’s electrical separation from the rest of the country and the PUC’s exclusive jurisdiction over the Texas grid operator. (See “Fending off FERC,” Texas PUC Challenging SPP-Mountain West Intertie Costs.)

FERC’s jurisdiction is derived from the Federal Power Act, which gives the commission broad authority to regulate interstate commerce by public utilities. FERC does not have plenary jurisdiction over the ISO because the energy generated in the region is not transmitted in interstate commerce, except for certain interconnections ordered by the commission that do not give rise to broader jurisdiction.

The committee also unanimously endorsed six other NPRRs, a system change request (SCR) and a nodal operating guide revision request (NOGRR):

NPRR819: Removes language referencing “data errors” for resettlement of the DAM and real-time market (RTM); gives the ERCOT board authority to direct a DAM resettlement parallel to its authority to direct an RTM resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
NPRR841: Determines in real time the day-ahead make-whole payment by incorporating the ancillary services infeasibility charge, approved with NPRR782, into the payment’s analysis.
NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone, used primarily for study purposes.
NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
NPRR852: Creates a more efficient approval process when updating the congestion revenue right activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the WMS.
NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
NOGRR169: Aligns the guide’s language with NERC Reliability Standard PRC-002-2 (Define Regional Disturbance Monitoring and Reporting Requirements) to determine required locations for NERC-required disturbance monitoring equipment. This relieves the burden on facility owners to adhere to two vastly different requirements for the same purpose.
SCR794: Updates how the SCED limit is calculated by the Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.

— Tom Kleckner

January 29, 2018

Montana PSC Racks up 2nd Lawsuit over PURPA Rates

By Amanda Durish Cook

Montana regulators last week found themselves at the center of yet another court case regarding the rates offered to the small solar producers — this one stemming from a 2016 decision to suspend those rates at the request of the state’s largest utility.

Cypress Creek Renewables filed suit in the U.S. District Court for Montana alleging that the Public Service Commission’s action violated the Public Utility Regulatory Policies Act by denying solar developers the right to earn the PURPA rates in effect when they originally committed to sell their power to NorthWestern Energy.

PSC PURPA — Cypress Creek construction site | *Cypress Creek Renewables*

Under PURPA, utilities like NorthWestern are obligated to purchase electricity from qualifying facilities at avoided-cost rates that reflect a utility’s own cost to build new generation. The federal law leaves it to each state to determine both the rate and when a legally enforceable obligation (LEO) begins, barring any conflict with FERC regulations.

In November, the Montana PSC voted to reduce the standard PURPA contract length from 25 to 15 years and cut the energy rate available to renewable energy projects up to 3 MW from $66/MWh to $31/MWh.

But that move came after the PSC voted to allow NorthWestern to suspend its PURPA rates in June 2016 after the utility complained that the rates exceeded its avoided costs for new generation. The PSC grandfathered in facilities that had completed their agreements with NorthWestern prior to the June 16, 2016, date of the order but added the stipulation that QFs must have obtained interconnection agreements before that date to earn the previous rates.

In its lawsuit, Cypress Creek says that 13 of its solar projects that had not obtained interconnection agreements by that date are still entitled to receive the old purchase rate and contract length.

“PURPA further requires that state energy regulators like defendants recognize that, where a QF unequivocally commits to sell its output to a utility, it establishes a ‘legally enforceable obligation’ on the part of the QF to sell, and on the part of the utility to purchase, the QF’s output at the utility’s avoided-cost rate, calculated at the time the obligation is incurred,” the company wrote.

Cypress Creek also argues that at a June 9, 2016, Montana PSC hearing, NorthWestern acknowledged it was obligated under federal law to enter into long-term contracts for the 13 projects under Montana’s previous PURPA rate.

The company’s argument relies on a 2016 FERC declaratory order that found the Montana PSC violated PURPA by requiring QFs to have power purchase agreements and interconnection agreements with utilities to create a LEO, finding that the arrangement give utilities too much control over when the obligation occurs. (See FERC Declares Montana QF Requirements Illegal.)

The Montana PSC maintains that its LEO standard is still state law and has called FERC’s order nonbinding unless it is upheld by a district federal court.

“The petitioners are essentially trying to enforce FERC’s declaratory order in which the [commission] took issue with the piece of the Montana PSC’s legally enforceable obligation test, which required a qualifying facility to obtain a signed interconnection agreement,” said Montana PSC Communications Director Chris Puyear. “Importantly, FERC said nothing of the commission’s decision to suspend the rate and contract terms available to qualifying facilities up to 3 MW in size.”

Puyear pointed out that the rate available to QFs is voluntary and can be suspended at any time.

Still, the PSC disagrees that Cypress Creek had a LEO to the old contract terms on the 13 projects, as the complaint argues.

“The commission’s standard is less rigorous than many other states, some of which require a qualifying facility to be near the end of construction before a LEO can be established,” Puyear said. “While the commission remains open to revisiting its LEO test in the future, absolutely no evidence has been presented which shows that the current LEO test disadvantages qualifying facilities.”

Cypress Creek sees it differently.

“Before this rate change, the [plaintiffs] had fully committed to sell their output to NorthWestern, creating their legally enforceable obligation to sell — and NorthWestern’s statutory obligation to purchase. … NorthWestern repeatedly conceded that it had reached a final (if unsigned) contractual agreement with the QFs prior to June 16, 2016,” the company said.

Cypress Creek said it received “continued” assurances from NorthWestern in May and June 2016 that the old rates and contract lengths would apply to the 13 projects.

The company — along with Vote Solar and the Montana Environmental Information Center — is also a co-complainant in a state case alleging that the PSC last year “drastically and unreasonably” reduced the state’s PURPA standard contract length and energy rate, dealing a fatal blow to future small solar development in Montana. (See Montana PURPA Solar Saga Continues in State Court.)

In January, Cypress Creek reported its strongest-ever construction growth rate, having built 1 GW of solar installations over the previous 18 months.

January 29, 2018

CAISO Launches Interconnection Initiative

By Jason Fordney

CAISO this month launched a sweeping set of updates to its interconnection policies, an annual process made increasingly complex by a rapidly changing resource mix.

The effort “will likely address some substantial concepts but also a myriad of minor concepts that have not been addressed in some time,” the ISO said of its 2018 Interconnection Process Enhancements (IPE) initiative.

CAISO TPD — CAISO launched its Interconnection Process Enhancements 2018 initiative this month | © *RTO Insider*

“Once we finalize the scope of the initiative, we will be able to determine the issues that will be included in this year’s process and the timing for development,” CAISO said.

The program is divided into six broad categories: deliverability; energy storage; generator interconnection agreements; interconnection cost responsibility and financial security; interconnection requests; and modifications.

A Jan. 17 issue paper defined the proposals that CAISO is considering. The document includes 42 potential topics and will be developed into a draft final proposal, but the ISO has not specified when it would be presented to the Board of Governors for approval.

The deliverability category alone contains nearly a dozen topic areas related to transmission planning, criteria for commercial viability and transparency into the availability of deliverability.

Other major tasks laid out in the IPE paper include:

Ensuring the development of the most viable projects;
Giving projects with power purchase agreements a greater opportunity for deliverability; and
Providing resource developers reasonable timelines for interconnection.

The ISO expects a March ruling from FERC on last year’s more narrowly tailored IPE package, which was expedited to obtain a ruling before the next transmission plan deliverability (TPD) allocation takes place in March.

A TPD allocation provides resources the transmission capacity required to deliver power during peak conditions and is a condition of receiving full capacity deliverability status, which is critical for eligibility to be counted as resource adequacy.

CAISO twice a year allocates TPD to generating projects that meet certain criteria. The 2017 IPE package proposes a third TPD allocation, which FERC is likely to approve.

The TPD allocation process works well during periods of high procurement, CAISO said. However, renewable procurements have recently slowed significantly, resulting in few projects meeting the criteria to qualify for a TPD allocation.

There are also uncertainties around renewable procurement that will affect the ability of a resource to obtain power purchase agreements. CAISO noted that the California Public Utilities Commission has proposed establishing a two-year resource procurement cycle to meet the targets of integrated resource plans, with the first procurement proposed for the end of 2018. But modeling used by the commission for the program shows a minimal need for renewable procurement until 2026 because California utilities are on track to meet — or exceed — renewable portfolio standard targets, the ISO said.

“The IRP will have significant impacts on interconnection customer’s ability to obtain PPAs for their projects,” CAISO said.

In a Jan. 24 presentation, CAISO discussed items that stakeholders requested be included in the IPE, including a proposal that would allow interconnection customers to replace their entire project with storage during the interconnection process. But CAISO has only approved up to 10% conversion to battery from an existing project during the process.

“A complete change of technology from existing technology requires a study to determine the new electrical characteristics and the impact to the grid,” CAISO said in explaining that it would not explore that topic in IPE 2018.

The energy storage category of IPE 2018 is focused on distributed energy resources, wholly replacing existing facilities and deliverability assessment for energy storage.

The ISO is taking comment on the IPE package through Feb. 7 and said stakeholders should suggest other items that might be included.