Page 1553 – RTO Insider

May 7, 2015

PJM to Recoup up to $15 Million in Mistaken Lost Opportunity Costs

By Suzanne Herel

VALLEY FORGE, Pa. — PJM will seek to recover up to $15 million in lost opportunity costs erroneously paid to generators that were on forced outages and not eligible for the credits, Chief Financial Officer Suzanne Daugherty told the Market Implementation Committee on Wednesday.

While Daugherty said the mistaken payments most likely extend beyond April 2013, the Tariff allows the RTO to recoup only 24 months’ worth.

“We will be contacting companies before any billing adjustments will go through,” she said. “This is not an immediate billing adjustment.”

The compensation applies to combustion turbines that are scheduled in the day-ahead energy market but are not committed in real time. However, if they are not able to operate in real time, they are not eligible for the credit.

Daugherty said in an interview that the issue came to light by chance several weeks ago.

“We were investigating a certain scenario that wasn’t even related” when staff came across instances in which generators had incorrectly or inconsistently recorded their forced outages in the eMKT system as compared with the eDART and eGADS systems, Daugherty said.

“EMKT is what we use to see if you’re eligible,” she said. Now, “we’re trying to go through and find the anomalies amongst them.

“It could be process issues, it could be training – we have no idea why they might not all have been reported consistently,” she told the committee, noting that it is the generators’ responsibility to report outages.

It will remain the generators’ responsibility to report outages, although PJM is considering adding a process that would flag discrepancies among the entries in the three systems, Daugherty said.

Daugherty said it will take weeks to refine the data and identify how many generators are affected and what their individual charges will be. The current estimate, she said, is that the total will not exceed $15 million.

In the meantime, she advised generators to check their own records. “If you got paid LOC in a time you reported a forced outage, you should know you’re likely to have a billing adjustment,” she said.

PJM stakeholders recently approved tighter rules on lost opportunity costs, correcting a provision that allowed generators to recoup start-up and no-load costs that they hadn’t accrued. The rule change is intended to remove incentives for units to clear in the day-ahead market but not in the real-time market. (See PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained.)

May 5, 2015

FERC: Idled NY Plants Can Lose Interconnection Rights

By William Opalka

NYISO can force idled generators to allow use of their interconnections for reliability purposes, the Federal Energy Regulatory Commission ruled last week, saying that such actions do not constitute an unconstitutional “taking” under the Fifth Amendment.

The commission approved most of the tariff revisions NYISO proposed in its July 2014 filing, which was intended to clarify its rules regarding generator outage states (ER14-2518).

“We find that NYISO’s proposed tariff provisions concerning the termination of existing interconnection agreements and the requirement that a generator’s interconnection points can be temporarily used by the transmission owner during an outage do not constitute takings under the Fifth Amendment to the U.S. Constitution and, therefore, do not require ‘just compensation’ to affected generators,” FERC wrote.

The proposal defines generator outage states, including how long they may remain in them and their eligibility to participate in the capacity market. NYISO said the changes will incentivize generators to make repairs quickly and return units to the market, and provide grid operators more certainty when planning system reinforcements and expansions.

The ISO’s proposal would allow it to terminate a generator’s eligibility to participate in the installed capacity market after six months in a forced outage if repairs have not been started.

It also defined a “mothball outage,” referring to units voluntarily removed from service for reasons not related to equipment failure; they are also ineligible to participate in the ICAP market.

“We find that, in general, NYISO’s proposal to formally define various outage states, with related changes, will help increase predictability and transparency, and help ensure that the only units participating in the ICAP market are those that reasonably expect to be able to provide capacity during the delivery period,” the commission said. “We note that, although protesting parties take issue with various aspects of the proposal, they acknowledge that NYISO’s proposal is, in large part, beneficial to NYISO’s markets.”

The Independent Power Producers of New York challenged the proposal, saying it would interfere with contractual rights they had negotiated with transmission owners. While the group supported the six-month rule for participating in the ICAP market, it said FERC should reject a requirement that generators on outage respond to reliability needs by returning to service or making their interconnection points available.

The commission, however, said that the rule “will help resolve imminent reliability issues.”

Cost Provision Rejected

However, the commission rejected NYISO’s proposal that generators that fail to return to service in the time required pay costs incurred to install an alternative reliability solution.

IPPNY argued that the proposal would unfairly overcharge generators. It asked the commission to order a requirement that a generator pay the difference between the cost of the reliability solution and the amount customers would have paid if the generator had returned to service on time.

The commission said it recognized that a penalty structure may be appropriate to ensure generators return to service quickly.

But it said that “imposing the full cost of the alternative reliability solution on the generator is not just and reasonable because NYISO has not demonstrated that requiring a generator to pay the full cost provides a reasonable penalty for a generator not returning to service on the agreed upon date.” The commission urged the ISO to work with stakeholders on an alternate proposal.

The order is effective May 1, subject to a compliance filing NYISO must make within 30 days.

May 5, 2015June 15, 2023

Forum Explores Challenges of Distributed Resources

By William Opalka

NEW YORK — Distributed resources are receiving too much blame for the utility industry’s problems, current and former regulators said at the Infocast Grid Transformation Summit 2015 last week.

“I think the main problem is the declining sales of energy,” said Betty Ann Kane, chairman of the D.C. Public Service Commission. Kane said distribution-only utilities facing declining revenue due to their dependence on volumetric rates will find it difficult to modernize the system for rooftop solar and other distributed resources.

“We have started to move gradually — and I would say too gradually — away from the volumetric charges to have a customer charge pick up more of the costs,” she said.

In D.C., the monthly service charge for meter reading and grid connection has gone from $6 to $12 since 2007 and is headed toward $20, Kane said.

Other speakers at the conference, which drew about 100 people to the ONE UN New York hotel, spoke of renewable energy’s progress — and the backlash against it.

“There have been efforts in a number of states to pull back on [renewable portfolio standards],” said former Federal Energy Regulatory Commission chairman Jon Wellinghoff, now a partner in the law firm Stoel Rives. “On the other hand, there have been efforts to increase renewables. One of the most notable is California, which recently set its goal to 50%.”

Wellinghoff noted that renewables’ declining costs mean the mandates are less necessary than before.

“At the wholesale level we’re seeing wind at less than 3 cents/kWh and the average at utility-scale solar generation is less than 7 cents/kWh. That’s an average for all the contracts signed in 2014, while some are at 5 cents,” he said.

Fixed Costs vs. System Benefits

Wellinghoff also disputed claims that net metering and renewable subsidies result in low-income customers subsidizing wealthier customers able to afford rooftop solar. Wellinghoff cited studies showing that distributed resources provide net benefits to the grid.

“The problem is they’re not analyzing the entire benefits to the system with these distributed systems,” Wellinghoff said of critics. “You can’t look solely at the costs of energy, of retail rates versus wholesale costs. It’s avoiding new generation, it’s avoiding new transmission.”

“I think the concern about the cross-subsidization is solar is overplayed,” Kane agreed.

NREL Study

The National Renewable Energy Laboratory in Golden, Colo., is studying the operational challenges facing utilities on a 1-MW system with distributed solar, smart devices, electric vehicles and other technologies.

Bryan Hannegan, associate director of energy systems integration for the lab, described the questions NREL is attempting to answer: “When you have a more distributed and dynamic grid, how do you operate that in a way that doesn’t sacrifice reliability and affordability that consumers have come to expect, while pursuing the clean energy objectives we’ve set out for ourselves as a nation?”

May 5, 2015

FERC Fines Maxim Power $5M in Switching Scheme

By William Opalka

The Federal Energy Regulatory Commission last week fined Maxim Power and one of its employees in a fuel-switching scheme that occurred in the summer of 2010.

Maxim was fined $5 million and employee Kyle Mitton was fined $50,000 for overcharging ISO-NE by offering into the day-ahead market with a price for oil-fired generation when in fact it was burning cheaper natural gas (IN15-4).

Only three members voted to impose the penalty, with Commissioner Tony Clark, who had previously expressed skepticism, dissenting. (See FERC Seeks $5M from Maxim Power; Clark Dissents.) Chairman Norman Bay, formerly head of the Office of Enforcement, did not participate in the decision.

“We find that respondents intentionally engaged in a fraudulent scheme, through misrepresentations and material omissions, to obtain and protect payments established by offers based on the price of oil, even though they ran the Pittsfield unit on lower-priced natural gas, which should have set their compensation,” FERC wrote.

The plant involved is a 181-MW dual fuel generator in Massachusetts, which was operating under a reliability must-run agreement at the time of the violations.

“As a result of Pittsfield’s high offer price, the grid operator often chose less expensive options and did not select Pittsfield to generate. Nevertheless, Pittsfield was often needed to ensure system reliability and so was requested to run despite its higher price,” FERC said.

Clark acknowledged that Maxim’s activities appeared “suspicious,” but he said Enforcement did not prove the case to his satisfaction. He also cited doubts about Mitton’s culpability.

“Staff’s case linking Maxim’s supply offers to a willful intent to deceive the Independent Market Monitor thus rests on the notion that while Mr. Mitton’s responses may have been technically correct and ultimately truthful, Mr. Mitton did not anticipate what information the Independent Market Monitor was really seeking and therefore his responses were too narrow and not as forthcoming as they should have been,” Clark wrote. “To me, such a fact pattern does not a $5 million penalty make.”

The majority disagreed, calling Mitton’s role “crucial to the fraudulent scheme.” The key to the dispute, it said, is a series of emails between Mitton and the Internal Market Monitor.

“Mitton personally sent emails to the IMM that conveyed the impression that Maxim needed to submit offers for the Pittsfield plant based on high oil prices because of supposed concerns about natural gas supply, even though Mitton was frequently able to procure much cheaper natural gas on those days, and even though Mitton himself had often purchased large amounts of natural gas before submitting day-ahead offers for Pittsfield,” the decision said.

Attorneys for Maxim and Mitton could not be reached for comment.

May 5, 2015June 15, 2023

Walkemeyer Transmission Projects Wins SPP OK

By Rich Heidorn Jr.

The SPP Board of Directors approved staff’s recommendation that it authorize construction for a 21-mile 115-kV line from Walkemeyer to North Liberal as part of a reliability solution in southwestern Kansas. The proposal had received almost 64% support from the Markets and Operations Policy Committee in April, falling short of the 66% needed to recommend it to the board.

The board had approved the project in January but asked staff to evaluate an alternative proposed by Sunflower Electric Power that would have delayed the line, instead relying on operating guides for Sunflower’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations.

Staff evaluated three options:

Option 1 would add a new substation with a 345/115-kV transformer on the Hitchland–Finney 345-kV line and a new 1-mile 115-kV line from the substation to Walkemeyer at an estimated cost of $17.8 million. Cimarron would be dispatched for up to 58 MW when needed to avoid violations.
Option 2, the staff recommendation, included option 1’s new substation and transformer but would add the Walkemeyer-North Liberal line for an additional $17.5 million, avoiding the need to rely on Cimarron for reliability. Although it had higher upfront costs, staff said option 2 was about $900,000 cheaper than option 1 on a net present value (NPV) basis over 40 years ($68.4 million vs. $67.5 million in 2015 dollars).
Option 3, which would have relied solely on the Cimarron plant, had an NPV of $78.5 million and only “marginally” solved voltage violations, staff said.

Following the MOPC meeting, staff reevaluated the options using an 8% discount factor, which reduced options 1 and 3 to an NPV of $49 million and $47 million, respectively (2015 $).

Al Tamimi, Sunflower’s vice president of transmission planning, policy and compliance, said the use of the operating guide and a phase shifter could delay the need for the Walkemeyer-North Liberal project until 2030.

Lanny Nickell, vice president for engineering, said staff’s recommendation was driven largely by the age and the slow response time of the Cimarron plant, which includes a 61-MW gas unit built in 1963 and a simple-cycle 15.5-MW combustion turbine added in 1967.

Although Sunflower has projected operation until 2030, “we don’t know how long this [plant] is going to last,” Nickell said.

In addition, he said the larger, 52-year-old unit requires a 30-hour startup time. “If we’re wrong — if we estimate demand too low — it’s too late to start that unit” to respond to real-time problems, Nickell said.

He added that Cimarron has averaged six days of forced outages annually during the summer months over the last three years.

Nickell called the Walkemeyer line a “no-regrets” option. “With options 1 and 3 there’s an opportunity for regrets in depending on generators that may not show up,” he said.

Sunflower disagreed. “Sunflower staff believes that SPP’s ‘no-regret’ solution contradicts its concerns with compliance with the newly effective TPL-001-4 reliability standard, and the use of Cimarron River Station to meet that standard contradicts SPP’s recommendation to include Phase II in the [Integrated Transmission Plan 10-Year Assessment] instead of the ITP [Near-Term Assessment],” the company said in a statement.

The reliability standard, which the Federal Energy Regulatory Commission approved in October 2013, allows transmission planners to plan for “non-consequential” load loss following a single contingency. (See FERC OKs Rules for “Non-Consequential” Load Loss.)

May 5, 2015June 15, 2023

SPP Board of Directors/Members Committee Meeting Briefs

The SPP Regional Entity, which is seeking a renewal of its delegation agreement with the North American Electric Reliability Corp., is trying to assuage NERC’s concerns over the RE’s independence.

“As far as I know, it’s the negotiating team at NERC that has communicated” NERC’s concerns, RE Trustees Chairman John Meyer told the SPP’s Board of Directors/Members Committee meeting Tuesday.

SPP’s current five-year delegation agreement expires Dec. 31. It calls for renewal if SPP passes a NERC audit to ensure that SPP “continues to meet all statutory and regulatory requirements necessary to maintain its eligibility for delegation.” Either party may terminate the agreement by giving written notice at least one year before the end of the term.

Ron Ciesiel, general manager of the RE staff, said SPP officials were given a revised pro-forma delegation agreement about two weeks ago that removed the automatic renewal provision. He said RE officials plan to discuss it with NERC at an upcoming meeting.

SPP is the only RTO or ISO that also enforces reliability rules as a NERC regional entity. The Federal Energy Regulatory Commission raised its own questions about the RE’s independence in a 2008 audit. (The Texas Regional Entity was formerly a division of ERCOT, but it became an independent corporation in 2010.)

The audit concluded that SPP RTO management had supervisory control over SPP RE employees and that RTO employees had influence over NERC compliance monitoring and enforcement policies. The commission required SPP to hire a full-time RE manager and to eliminate all reporting relationships between RE employees and RTO employees. (Full disclosure: RTO Insider Editor Rich Heidorn Jr. was a member of the FERC team that conducted the audit.)

NERC did not respond to requests for comment.

Finance Committee Considering Changes to Administrative Fee

The SPP Finance Committee is considering a change in the way it sets the RTO’s administrative fee rate.

Since FERC’s approval of SPP as an RTO in 2004, it has set the rate at a level designed to recover its annual budget plus or minus amounts necessary to true-up prior periods.

The fee has grown steadily along with the RTO’s increased level of services.

Because SPP projects operating budget expense levels to be more level and predictable than in prior years, the Finance Committee is considering two alternatives: continue the status quo floating rate, or a stable rate approach that would enable funding for contingency, reserves and capital expenditures in the annual budget.

The status quo will generally result in a lower rate in the near term and is consistent with SPP’s existing policy to maintain “generational equity.”

The stable rate proposal would improve the predictability of rates from year to year but will result in SPP’s recoveries being either higher or lower than expenses.

SPP expects a stable rate approach would result in a higher rate initially than the status quo because of a modest reduction expected in the status quo rate following the addition of the Integrated System load in October 2015. Under an example provided by the committee, the stable rate could rise from $0.38/MWh in 2015 to $0.39/MWh for 2016-2020, while the floating rate could fluctuate between $0.37/MWh and $0.38/MWh (see chart). The floating rate could result in operating cash shortfalls of as much as $79 million in 2020, versus $39 million under the stable rate.

Capital expenditures were projected to drop from $29 million in 2015, to $19 million next year and $15 million annually for 2017-2020, under the example.

The analysis did not include any financing to cover capital expenses or cash shortfalls.

Finance Chairman Harry Skilton said a level administrative fee would mean SPP keeps more cash on hand. “The question is what do we do with it?” he asked in inviting stakeholder feedback on the options. “Do members want SPP to borrow rather than them borrowing? We do have a fantastic credit rating.”

Skilton also said SPP may have to increase its pension contributions by $1 million beginning in 2016 due to the adoption of the 2014 mortality tables published by the Society of Actuaries, which predicts longer lifespans for retirees.

New Members Welcomed in Iowa, Minn., SD

Members approved three cooperatives for membership: Corn Belt Power, which provides power to nine distribution cooperatives and one municipal electric cooperative in 41 counties in northern Iowa; East River Electric, which serves rural areas of 41 counties in eastern South Dakota and 22 counties in western Minnesota; and Northwest Iowa Power, which provides power to seven distribution cooperatives in western Iowa.

MMU Hires Law Firm for Independent Representation

SPP has hired a D.C. law firm, Michael Best, to represent the Market Monitoring Unit, said Josh Martin, chairman of the Oversight Committee.

To ensure its independence, the MMU must have a different law firm than what the RTO uses, Martin said.

“There should be no question about the independence of the MMU,” Martin said. “If they need to make filings to FERC, they have the appropriate resources to do so.”

Markets and Operations Policy Committee Recommendations Approved

The board accepted the following Markets and Operations Policy Committee recommendations:

Approve new rules on how mitigated offers will be calculated for generators that fail market power tests, a solution that includes default values for variable operation and maintenance costs (Revision Request 69). (See SPP MOPC OKs New Rules for Calculating Mitigated Offers.)
Approve the selection of three futures scenarios for the 2017 Integrated Transmission Planning 10-Year Assessment to measure the impact of the Environmental Protection Agency’s proposed carbon emission rule. (See ITP10 to Include 3 Scenarios for Clean Power Plan.)
Reject a request from Western Farmers Electric Cooperative for a waiver from a rule barring base plan transmission funding for generation projects that push wind’s share of capacity above 20% of summer peak load. The Regional State Committee also voted to reject the waiver but agreed with other stakeholders that the 20% threshold should be reconsidered. (See Wind Waiver Rejected; SPP Members will Revisit Assumptions.)

Board Expands; Eckelberger, Skilton Re-elected

In a special Members Committee meeting, stakeholders voted to add up to three external seats to the Board of Directors, which currently includes six external directors plus SPP President Nick Brown. SPP spokesman Tom Kleckner said the change gives the board “flexibility … to add someone if the appropriate candidate comes along.”

The Corporate Governance Committee also nominated Board Chairman Jim Eckelberger and Vice Chairman Harry Skilton to new three-year terms. The election will be in October.

The Members Committee also added six member representatives as it expands to 20 from 15 and fills one vacancy: David Hudson, Xcel Energy (representing investor-owned utilities); Mike Risan, Basin Electric Power Cooperative (cooperatives); Stuart Lowry, Sunflower Electric Power Corp. (cooperatives); and Kristine Schmidt, ITC Great Plains (independent transmission companies), were elected to two-year terms, while Kelly Walters, Empire District Electric Co. (IOU), and Bob Harris, Western Area Power Administration – Upper Great Plains Region (federal power marketing agency), were elected to eight-month terms.

— Rich Heidorn Jr.

May 5, 2015January 21, 2024

SPP Board Rejects Short-Term Study; Impact on Quick-Start Units Debated

By Rich Heidorn Jr.

SPP’s Board of Directors rejected a recommendation to create a short-term reliability unit commitment (RUC) study as part of the intra-day RUC process (Revision Request 49).

The study would provide results for 15-minute intervals, allowing operators to make unit commitments with more granularity than the current one-hour study. SPP staff said it would reduce the number of real-time manual commitments.

The study won the backing of the Markets and Operations Policy Committee last month but ran into stiff opposition last week from representatives of Golden Spread Electric Cooperative and Nebraska Public Power District, who said they feared the new tool might exacerbate losses they are suffering as a result of SPP’s dispatch of their quick-start units.

The quick-start units, which cost at least twice as much as regular combustion turbines, can be at full capacity in five minutes or less.

Golden Spread said that SPP should first fix its real-time balancing market software so that it recognizes quick-start resources as always “online” and available to the market. When the units are dispatched manually by operators through the RUC process instead of economic dispatch, they cannot set prices in the real-time market.

“So they just get the market price — which normally is much lower than the actual price — and need to be made whole,” Ron Thompson of Nebraska Public Power District said in written comments on the proposal. “If there is [an] issue and the unit does not perform as intended, the ‘make whole’ payment may be less or potentially not occur and the unit owner will be subject to much higher operating cost than what the market paid.”

At times, Golden Spread’s quick-start 168-MW Antelope units near Abernathy, Texas, are covering half of SPP’s regulation, Mike Wise, Golden Spread’s senior vice president of commercial operation and transmission, told the committee.

Wise said starts for the 18 Wärtsilä reciprocating engines at Antelope increased to almost 13,000 between March 1 and Dec. 3, 2014, compared with about 3,000 starts during the same time period in 2013, before the start of the Integrated Marketplace, a four-fold increase. About 41% of the starts in 2015 resulted from RUC instructions by SPP operators.

“They shouldn’t be getting RUC’ed at all,” Wise said. “They should be dispatched by the day-ahead or real-time market.”

Wise said SPP should create a ramping product to create the proper economic signals for quick-start and other fast-ramping resources. “This market should have a ramping product that is the envy of the country. We have got the wind resources that are the envy of the country,” Wise said. The short-term study “is not the answer. The ramping product that we are working on is the answer.”

One director asked about deferring to the new tool until the ramping product is developed. “I don’t want to make a bad situation worse,” he said.

Richard Dillon, director of market design, said it will likely be months before there is a proposed ramping product for members to consider and that once approved, it will take considerable software development to implement.

Chief Operating Officer Carl Monroe said the tool would automate “something we’re already doing manually. It doesn’t change [Golden Spread’s] situation at all.”

With the rejection, the measure was returned to the MOPC.

May 4, 2015

Supreme Court Agrees to Hear Demand Response Appeal

By Rich Heidorn Jr.

WASHINGTON — The U.S. Supreme Court said Monday it will reconsider the D.C. Circuit Court of Appeals decision threatening the Federal Energy Regulatory Commission’s authority over demand response.

The court made its decision after a conference Friday on FERC’s petition for a writ of certiorari.

The court agreed to consider two questions:

Whether FERC “reasonably concluded that it has authority under the Federal Power Act, 16 U. S. C. 791a et seq., to regulate the rules used by operators of wholesale electricity markets to pay for reductions in electricity consumption and to recoup those payments through adjustments to wholesale rates.
“Whether the Court of Appeals erred in holding that the rule issued by [FERC] is arbitrary and capricious.”

A ruling is expected in about 12 months, following briefs this fall and oral arguments in the fall or next spring.

Retail, not Wholesale

Last May, the D.C. Circuit vacated FERC Order 745, which set rules for compensating DR in RTO energy markets. The court said DR is a retail product and thus subject to state, not federal, jurisdiction (Electric Power Supply Association v. Federal Energy Regulatory Commission).

FERC’s petition said the Supreme Court should take the case because of the growing importance of demand response.

“Even read most narrowly — as invalidating only FERC’s authority to regulate the level of compensation paid by wholesale market operators to demand response providers in energy markets — the decision … threatens significant damage to the nation’s wholesale electricity markets,” FERC said. (See FERC Files EPSA DR Appeal with Supreme Court.)

FERC said its regulation of DR participation in wholesale markets “is essential to the commission fulfilling its statutory responsibility to ensure that [wholesale] rates are just and reasonable” and that the EPSA ruling also threatens the participation of DR in wholesale capacity markets.

Opponents’ Brief

In a brief opposing the petition, attorneys for the Electric Power Supply Association and others said that those supporting review had provided “no compelling basis” for reconsidering the appellate ruling.

“Notwithstanding petitioners’ sky-is-falling assertions, the decision … does not have the kind of exceptional importance that warrants this court’s intervention,” it said.

“Instead, they merely disagree with a D.C. Circuit decision that correctly identified FERC’s rule for what it is: a clear intrusion on the states’ exclusive authority over retail sales, in a backdoor effort to overcome the states’ unwillingness to adopt a regime for retail rates that mirrors FERC’s preferred regime for wholesale rates.”

Order 745 required RTOs and ISOs to pay DR the same prices as generation. The opponents cited a comment by former FERC Chairman Jon Wellinghoff during a technical conference: “I have no assurances as to when the states will put dynamic retail prices with the controversies that are going on [and] all the political problems with getting those in place.”

In a reply brief on behalf of FERC, Solicitor General Donald Verrilli said Wellinghoff “was merely responding to the suggestion that wholesale demand response could impede efforts to develop retail-level demand response technology.”

“The purpose of the rule is to correct inefficiencies and improve pricing, reliability and competitive conditions in wholesale energy markets,” Verrilli wrote.

Arbitrary and Capricious

The opponents also said the petition was flawed because it did not ask the court to review the D.C. Circuit’s alternative holding that FERC’s final rule must be vacated as arbitrary and capricious even if it did not exceed FERC’s jurisdiction.

Verrilli noted that the D.C. Circuit’s primary holding barred the commission from reissuing the rule while the secondary holding would allow FERC to “repromulgate the rule with a response to the court’s holding on the payment formula, or could adjust the payment formula.”

The Supreme Court nevertheless took on that second question. It allotted one hour for a yet-to-be-scheduled oral argument.

At least four justices must agree to hear a case for the court to grant certiorari. The court said Justice Samuel Alito did not take part in the consideration of the petition.

PJM Capacity Auction will Include DR

PJM General Counsel Vince Duane said the court’s action means PJM will include DR in the 2018/19 Base Residual Auction. On April 24, FERC approved PJM’s request to delay the auction pending a ruling on the RTO’s Capacity Performance proposal. (See FERC OKs PJM Request to Delay Capacity Auction.)

“We will run a capacity auction either under the CP rules or under the old rules,” Duane said. “Despite that uncertainty, one thing that has become clear is that we will have DR participate, as it always has, as a supply-side resource.”

Duane said the granting of certiorari does not mean the court will ultimately overturn the D.C. Circuit ruling. Duane noted that the court ruled 7-2 April 21 to uphold the Ninth Circuit Court of Appeals in a case concerning FERC’s jurisdiction under the Natural Gas Act, ONEOK, Inc. v. Learjet, Inc.

“It seems hazardous to assume that because the court takes the case that it’s likely to overturn” EPSA, Duane said.

Duane said the way the court worded the first question it will consider suggests it will provide a definitive ruling on whether any limitations on FERC’s jurisdiction over DR in the energy market also apply to the capacity market.

Reaction

FERC Chairman Norman Bay praised the court’s action. “The integration of demand response is important to the nation’s competitive wholesale electricity markets and reliable electric service,” he said in a statement.

Wellinghoff, now a strategic advisor to the Advanced Energy Management Alliance, issued a statement expressing confidence that the Supreme Court will overturn the D.C. Circuit. “The lower court’s decision to vacate FERC Order 745 is inconsistent with the law and undermines the rights of customers to make smart choices about how they consume energy,” he said.

EPSA CEO John Shelk said the association “and its partners in the unprecedented coalition that successfully challenged FERC Order 745’s demand response provisions look forward to defending the D.C. Circuit’s well-reasoned decision in the Supreme Court.”

May 2, 2015

Appellate Court Rejects EPA Rule on Back-Up Generators

By Rich Heidorn Jr.

WASHINGTON — A federal appellate court Friday threw out the Environmental Protection Agency’s 2013 rule exempting diesel generators providing demand response from air emissions limits.

“Because EPA too cavalierly sidestepped its responsibility to address reasonable alternatives, its action was not rational and must, therefore, be set aside,” a three-judge panel of the D.C. Circuit Court of Appeals ruled unanimously in a challenge by Delaware environmental regulators.

At issue is an EPA rule that exempted reciprocating internal combustion engines providing “emergency demand response” from emissions limits for up to 100 hours each year. (National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines; New Source Performance Standards for Stationary Internal Combustion Engines, 78 Fed. Reg. 6,674, Jan. 20, 2013).

The rule, which replaced a prior 15-hour exemption, noted that using such generators, which are typically powered by diesel fuel, “as part of emergency demand response programs can help prevent grid failure or blackouts.”

Erroneous Assumption

EPA said it loosened the rule based in part on PJM’s comments in a prior rulemaking indicating that resources needed to be available for a minimum of 60 hours annually to participate in the RTO’s emergency load response program.

That was an incorrect conclusion, the court ruled, noting that PJM had clarified in comments to EPA in 2012 that the 60-hour minimum does not apply to individual engines and that engines may be aggregated to meet the 60-hour requirement.

“EPA seems to have either intentionally discounted PJM’s later explanation of its requirement or simply confused the later comment for the earlier one,” the court said. “Another commenter brought the possible confusion to EPA’s attention, but EPA did not specifically respond, saying it considered demand-resource needs ‘in all areas of the country, not just PJM.’ And yet, EPA significantly grounded the 2013 rule in a PJM requirement that does not exist for individual engines.”

EPA had no immediate comment, saying it was still reviewing the court’s decision.

EPA issued the rule under sections 111 and 112 of the Clean Air Act. The Delaware Department of Natural Resources and Environmental Control filed a challenge complaining that emissions from emergency demand response programs significantly worsened ozone pollution in the state and alleging that at least 90% of the pollutants contributing to Delaware’s failure to comply with National Ambient Air Quality Standards come from pollutants transported from other states.

‘Opposite Effect’

Delaware and other challengers, including the Electric Power Supply Association and Calpine, said that demand response based on backup generators was hurting both the environment and grid reliability, counter to EPA’s arguments.

The court summarized the arguments: Because backup generators are exempt from emissions controls, they can underbid conventional generators in capacity markets, resulting in underinvestment by traditional generators, which undermines grid reliability. The reduced power supply increases the number of power emergencies, resulting in an increase in the use of “dirty” backup generators.

“In short, petitioners and the intervenor argue that instead of protecting the nation’s air resources and improving grid reliability as EPA claims, the 2013 rule has the opposite effect.”

PJM’s Independent Market Monitor was among the rule’s critics when it was proposed, telling EPA that the 100-hour exemption would distort both the capacity and energy markets.

“Some have asserted that an exemption for [backup] generators participating in demand-side response programs provides benefits to the organized wholesale electricity markets,” the Monitor wrote. “Those arguments have no merit. On the contrary, providing the exemption will have negative consequences for efficiency and reliability.”

In its comments to EPA, Calpine contended the proposed rule “would incentivize the procurement of diesel-fired [behind-the-meter] generators masquerading as ‘demand response’ in electricity capacity markets and thereby displace clean generating resources.”

Calpine said backup generators are not necessary for reliability in organized markets because “the market will simply procure other resources instead of [a behind-the-meter generator] that has not had to internalize the costs of emissions controls.”

An August 2012 report submitted to EPA by Northeast States for Coordinated Air Use Management, a non-profit association of air quality agencies, said that “demand response programs appear to be shifting a portion of overall electricity demand from traditional generating resources that supply the grid to more dispersed, unregulated diesel generators.”

The court also noted “evidence in the administrative record” that backup generators represent almost 15% of demand response in PJM. PJM officials could not be immediately reached for comment on the ruling.

‘Arbitrary and Capricious’

The court said the rule was arbitrary and capricious because EPA failed to respond to comments raising concerns about its impact on the grid or to those suggesting that the 100-hour limit was based on faulty evidence.

“EPA also did not consider the alternative of limiting the exception to parts of the country not served by organized capacity markets. We should further note that EPA did not obtain the views of [the Federal Energy Regulatory Commission} or [the North American Electric Reliability Corp.] on the reliability considerations upon which EPA based the exemption.”

The court also criticized EPA for providing contradictory answers when challenged. It said that the agency dismissed suggestions that it work with FERC on the reliability impact of the rule, contending that the rule’s purpose was to address emissions and that it was not its responsibility “to determine which resources are used for grid reliability.”

“EPA cannot have it both ways,” the court said. “It cannot simultaneously rely on reliability concerns and then brush off comments about those concerns as beyond its purview.”

In reversing the 100-hour exemption, the court said EPA can file a motion requesting either that the current standards remain in place or that it be allowed time to develop interim standards “if vacating these portions of the 2013 rule will cause administrative or other difficulties.”

May 1, 2015

Eversource: Northern Pass Delayed Until ’19; Earnings Up

Eversource Energy said Wednesday that its proposed Northern Pass transmission project won’t be operational until the first half of 2019.

The company had previously said the 187-mile, 1,200-MW line would be delivering Canadian hydropower to the New England energy market by 2018.

The delay is due to the longer-than-expected release of a U.S. Department of Energy draft environmental impact statement, Eversource officials said during the company’s earnings call. The statement had been expected in April, but the company is now expecting its release by June or July.

Approvals are expected in late 2016, with construction beginning shortly thereafter and expected to take about two years. However, even if the project maintains its construction schedule, line testing could not take place during the winter of 2018-2019 and would be delayed until spring, officials said.

Q1 Earnings Up

Eversource reported first-quarter earnings of $253.3 million ($0.80/share), compared with $236 million ($0.74/share) a year ago. These figures include integration costs of $4 million in 2015 and $5.8 million in 2014 related to the merger of Northeast Utilities and NSTAR. Excluding those costs, Eversource earned $257.3 million ($0.81/share) versus $241.8 million ($0.76/share).

The legal name change of Northeast Utilities to Eversource Energy was approved at the company’s 2015 annual shareholders meeting on April 29. Its stock started trading on the New York Stock Exchange under the ES ticker symbol in February. The company also reported that Standard & Poor’s upgraded its corporate credit rating to A.

— William Opalka