Page 1505 – RTO Insider

November 24, 2015

PJM Markets and Reliability Committee Briefs

WILMINGTON, Del. — The Markets and Reliability Committee last week delayed a vote on proposed manual changes over concerns that they could restrict energy efficiency participation in the capacity market. Members requested an additional education session on the issue.

The revisions aim to prevent EE resources from being counted both as capacity resources and as reductions in the load forecast. PJM proposes to use an add-back mechanism to accommodate continued EE participation when a new load forecast model is adopted.

Energy efficiency resources may be used to replace the commitment of a similar resource because such commitments would have been accounted for by the add-back. However, when it comes to using EE resources to replace non-EE capacity resources, they would be limited to the difference between the add-back of the third incremental auction for a delivery year and the cleared quantity of energy efficiency resources in that same auction.

“The concern is that the add-back might be greater than what might clear,” said Jeff Bastian, manager of capacity market operations.

Several members expressed concern that the eligibility requirements outlined in the changes restrict the time periods that EE resources may offer.

“I have an issue regarding the eligibility and the way EE is treated as a capacity resource. It becomes ineligible in the same year that it cleared in the [Base Residual Auction],” said Carl Johnson, representing the PJM Public Power Coalition. “I struggle to think of a resource that is ineligible depending on when it is offered in.”

“The resource is unique in that it can get buried in the load forecast,” explained Stu Bresler, PJM senior vice president for markets. “We’re doing everything we can to preserve EE as [a Reliability Pricing Model] option. The other option is to not include it in the auction.”

Bruce Campbell of EnergyConnect said he opposed the changes.

“I think it’s a really dangerous path to go down to say we’re not going to let resources participate as RPM resources because it will make our forecast look bad,” he said. “That’s just wrong.”

Responded Bresler: “The bottom line is if we don’t include it in the load forecast three years ahead, we miss the chance, and it’s been rolled in by the time that year comes around.”

The educational session on the revisions proposed for Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification is tentatively scheduled for Dec. 9.

Members Approve Manual Changes

Members endorsed the following manual changes:

Manual 01: Control Center and Data Exchange Requirements. Adds requirements and changes terminology to be consistent with North American Electric Reliability Corp. standards. Adds two communications requirements: voice communications between transmission owners and distribution providers in the transmission owner area, and between transmission owners and generator operators. Adds term “interpersonal communication” for voice communication. Identifies satellite telephones as preferred method of communication. New section requires that communication failures lasting 30 or more minutes be reported within 60 minutes of detection. Makes minor edits for clarity. Removes dated reference to “floppy disk.”
Manual 03: Transmission Operations. Changes resulting from bi-annual review include project updates, edits and reorganization of sections. Updates generator voltage schedule to define coordination. Changes will be implemented Dec. 1.
Manual 12: Balancing Operations. Updates due to new instantaneous reserve check implementation. Eliminates mention of MISO as the interconnection time monitor. Replaces the term “supplemental reserve” with “secondary reserve.” Changes will be implemented Dec. 1.
Manual 13: Emergency Operations. Updates day-ahead scheduling reserve requirement to 5.7% from 5.93% for Reliability First Corp. effective Jan. 1. Other changes made for consistency. Removes requirement that generators connected below 230 kV participate in voltage reduction.
Manual 14B: PJM Regional Transmission Planning Process. Updates for compliance with NERC standards.
Manual 14B: PJM Regional Transmission Planning Process. Changes reflect new process of considering energy market uplift in development of the Regional Transmission Expansion Plan.

New Load Forecast Model, Related Manual Changes Adopted

With three abstentions, members endorsed revisions to Manual 19: Load Forecasting and Analysis to reflect updates to the PJM load forecast model.

The changes add variables to account for trends in equipment and appliance saturation and energy efficiency; revise weather variables; update weather station assignment to zones; and revise the weather normalization procedure.

PJM will be publishing a white paper in 2016 to provide more detail on the forecast model.

PJM’s Tom Falin said the impact of the change in solar generation is being quantified, and the committee will be asked to endorse related manual changes in December.

Subcommittee’s Proposed Changes to Governing Documents OK’d

The committee endorsed modifications, clarifications and revisions to 12 terms in PJM governing documents.

November 24, 2015

Northern Pass Facing Challenges over Siting

By William Opalka

The developers of the Northern Pass transmission line may have to fight in court before they turn the first shovel of dirt on their project to deliver Canadian hydropower to the New England grid.

The Society for the Protection of New Hampshire Forests on Thursday sued Northern Pass Transmission to prevent it from using land the society owns. The lawsuit says Northern Pass does not have the legal right to access Forest Society lands and should be permanently barred from using it.

The suit came three days after New Hampshire environmental officials said that the developers’ siting application is incomplete because they had not shown they have property rights along the entire 192-mile route.

The letter from the state Department of Environmental Services to the New Hampshire Site Evaluation Committee said the application lacks “proof that the applicant will have a legal right to undertake the project on the property if a permit is issued.” The department was asked to weigh in on the application due to the project’s “alteration of terrain” and wetlands disturbances.

Northern Pass filed the siting application last month, starting a process that is expected to take 14 months. Developers hope to put the line in service in 2019. (See Northern Pass Files for Siting Approval, Revises Cost.)

In announcing the Forest Society’s lawsuit, President Jane Difley said the group “has a legal and ethical obligation to defend” its land against commercial development.

“Northern Pass cannot show that it has the property rights it would need to build the facility it is looking to permit through the Site Evaluation Committee. Nor does Northern Pass, as a merchant transmission project, have the ability to use any form of eminent domain to acquire those rights,” Difley said in a statement.

The lawsuit asks the Coos County Superior Court for a declaratory judgement that Northern Pass has no right to excavate along Route 3 in land known as the Washburn Family Forest. The land is in an 8-mile section near the Canadian border where the developers have proposed to bury the line. The Forest Society is also seeking intervenor status before the siting committee.

“Northern Pass is a private entity seeking to make use of Forest Society lands for the exclusive use of Hydro-Quebec,” said the group’s attorney, Tom Masland. “It is our strongly held view that they cannot do so without the Forest Society’s permission.”

The society says the project, as a merchant transmission line not deemed necessary by the state Public Utilities Commission, is not entitled to use highway rights of way the same way as other utility infrastructure.

“We are disappointed but not surprised that the Forest Society has today taken legal action to circumvent the N.H. Site Evaluation Committee’s authority,” Northern Pass said in a statement. “We are confident that our [siting committee] application meets the standards outlined in N.H. statutes and SEC rules, and that the Forest Society’s claims to the contrary have no basis in fact or law.”

Northern Pass also said that use of a public road is a legitimate use for projects that would benefit the region by providing access to affordable electricity.

“It is hypocritical that the Forest Society has long argued for additional underground construction but is now challenging our proposal to do just that,” the developers said.

The New England Power Generators Association also raised objections to the project in a letter to the site committee.

It said the relationship between Northern Pass and its parent company Eversource Energy raises “concerns about potential undue preference and a slanted playing-field harming competitive outcomes for the electricity marketplace and consumers. This is particularly true when a competitive energy affiliate may use property, services or receive other benefits provided by utility ratepayers for utility purposes.”

A Northern Pass spokeswoman said it is not uncommon for applicants to be asked for additional information.

“We are confident that any potential issues will be resolved in a timely manner and our application will be deemed complete by the SEC,” Lauren Collins said.

The project is in a 60-day window for the siting committee to determine if the application is complete.

The Environmental Services Department said enough information was provided to begin its technical review while the application’s deficiencies are addressed.

November 24, 2015

Utilities: Removal of Net Metering Caps Violates Law

By William Opalka

New York utilities last week challenged an order by regulators to temporarily remove the 6% cap on net metered solar-powered systems, saying the move violated state law by failing to provide adequate notice and that the regulators did not adequately justify that the move was in the “public interest” (15-E-0407).

The utilities asked for rehearing of the New York Public Service Commission’s Oct. 16 order that removed caps statewide while the commission develops a long-term solution to determine the value of distributed solar. (See Net Metering Caps Temporarily Lifted in NY.)

“The order contravened the statutory requirement that limits the commission’s role to increasing the ‘percent limits’ of the net metering cap, not removing them,” the petition alleges.

One of the six distribution utilities, Orange and Rockland Utilities, said in the summer that it was close to reaching its limit of 6% of load for net-metered systems.

The PSC responded with an administrative notice in the New York State Register on Aug. 5 seeking comments on the O&R petition. “The commission … may extend relief, in whole or in part or as modified or related, to other electric utilities,” the notice said, naming the other five.

The utilities contended last week, however, that “there was no reasonable basis to assume that a request for comments on a compliance filing made by a single utility would be the basis for the commission implementing a new generic policy with respect to net metering, especially considering the manner in which the commission had properly noticed and duly considered its intended action to increase the net metering cap on two prior occasions.”

First raised from 1% to 3% in June 2013, the cap was boosted to 6% in December 2014.

Commissioner Diane Burman dissented from the PSC’s October order, saying the process used to adopt it failed to give adequate notice to the public or other utilities that a sweeping change was under consideration.

The utilities also say that state law authorizing the PSC to raise the cap restricts the commission to impose a “percent limit.”

“Although the commission characterizes its action as a ‘floating’ cap … this nomenclature does not change the fact that the actual and practical import of the order is that there is no cap at all during the interim period and the commission thereby exceeded the statutory constraint,” they wrote.

November 24, 2015

FERC Denies Rehearings on ISO-NE Pay-for-Performance

FERC denied rehearing of three orders related to ISO-NE’s Pay-for-Performance program that is intended to boost reliability starting in 2018. In jump ball proceedings, FERC had said neither ISO-NE’s nor the New England Power Pool’s proposals in themselves addressed performance adequacy, but the commission adopted elements of both.

The first order directed ISO-NE to adopt a modified version of its proposed market design (ER14-1050, EL14-52-001). The commission accepted ISO-NE’s Tariff revisions regarding the increased reserve constraint penalty factors, the treatment of energy efficiency resources and ISO-NE’s proposal to retain the capacity performance payment rate and the dynamic de-list bid threshold.
In the second order, FERC denied rehearing on a commission order regarding an ISO-NE compliance filing (ER14-2419, EL14-52-002). Connecticut and Rhode Island had argued that the order failed to ensure that the dynamic de-list bid threshold is reasonably calibrated in light of the increased reserve constraint penalty factors. The commission said their assumptions are based on an oversimplification of the relationship between the penalty factors, resource performance and the inputs into the dynamic de-list bid threshold formula.
FERC also denied rehearing of a complaint by the New England Power Generators Association that alleged that the interaction between the penalty factor and ISO-NE’s peak energy rent mechanism is unjust and unreasonable (EL15-25). The PER requires suppliers to issue rebates to customers when energy prices exceed a strike price. The penalty factor, a component of the real-time dispatch and pricing algorithm, serves as a cap on the price that ISO-NE may pay to procure additional reserves. The commission found in its earlier order denying the complaint that NEPGA had not met its burden under Section 206 demonstrating that the existing Tariff provisions were unjust and unreasonable. (See FERC Upholds ISO-NE New Entry Pricing; Rejects Challenges by Generators.)

— William Opalka

November 24, 2015

PJM Generator Risk Proposal Faces Resistance

By Suzanne Herel

WILMINGTON, Del. — An initiative that would allow generators to avoid underperformance penalties in the redesigned PJM capacity market was met by pushback from members who said it was premature and could undermine the new reliability product.

The problem statement presented by Bob O’Connell on behalf of PPGI Fund A/B Development would allow generators to minimize penalties by netting them against over-performing generators.

O’Connell introduced the initiative in October, saying the Capacity Performance rules allow companies with multiple generators to offset poor performance with over-performing units but does not allow after-the-fact offsets, such as bilateral trades, that could help smaller generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)

“I’m not sure why it makes sense to the market to retroactively switch around performance,” Market Monitor Joe Bowring said during a discussion at the Markets and Reliability Committee meeting. “Capacity Performance is about performing at the time you’re supposed to perform.”

Bankruptcy Threat

“We have a performance obligation to meet those,” responded O’Connell, who agreed to delay a vote on the initiative to try and address stakeholder concerns. “But to the extent that a unit has a legitimate problem that forces it to be out of service during one of these periods of time, the exposure that unit faces with possibly having to buy back its position in real time and pay a penalty … exposes it to financial stress.

“It doesn’t make sense to push that financial stress to the point that they can’t meet their obligations financially. … Sitting back until half a dozen units go into bankruptcy is something that’s not effective from a reliability standpoint or an investment standpoint.”

O’Connell said customers ultimately would benefit because the proposal would allow generators to reduce the risk premiums they will otherwise include in their offers.

“The only way to handle underperformance now is to write a check,” he said. “Give the insurance company a way to physically offlay that risk.”

Tangible Problem?

Rene Demuynck of the New Jersey Board of Public Utilities asked for proof of a problem or of consumer benefit.

“We’re at a loss as to what the failure of Capacity Performance is right now except to avoid the obligation that you want to avoid and cleared the market on,” he said. “What is the tangible problem?

pjm — Storms flooded Central Maine Power’s substation in Bath in September 2015. Source: Central Maine Power

“Consumers are being asked to pay upfront with the understanding that units would offer their capacity and, when most needed, deliver the capacity,” he said. “I would suggest that the risk of negative penalties would be substantially diminished, and therefore the incentive to perform would be substantially diminished. There’s no perceived reason we can see to even consider this, and before [FERC] addresses other issues that are pending.”

Susan Bruce, of the Industrial Customer Coalition, said the problem statement was one-sided.

“When we talk about Capacity Performance, we talk about risks and rewards,” she said. “I see this as looking at the risk side.”

While there may be legitimate issues there, she said, “This is so narrowly drawn that it doesn’t look at the other side of the equation, the customer side of the equation. … There’s nothing in this to recognize the other side of the ledger.”

O’Connell protested that since he introduced the idea for the problem statement at the September MRC meeting, he hadn’t received any calls or questions about how it might be changed to include the customer side. “How long do I have to wait?” he asked.

“At that last meeting there was a chorus of concern,” Bruce responded. “To be honest, I was sort of hoping it would go away.”

Brian Garnett of Duke Energy supported the problem statement, saying it would be a way for smaller generators to hedge financial risk in the way that larger generators can.

Alan Ellison of Veolia added that his company’s Grays Ferry Cogeneration plant in Philadelphia could go bankrupt if it stumbles in the new market.

Premature

Jim Jablonski of the Public Power Association of New Jersey said the problem statement was premature.

“Is it time to be tweaking it already?” he said of Capacity Performance. “Or should we wait for a sensitivity analysis?”

“PJM does have some concerns regarding the substance of the problem statement,” said Stu Bresler, PJM senior vice president for markets, noting that a fundamental piece of the new product’s design is unit-specific evaluation of performance.

“I don’t have an opinion how long we should wait,” he said. “But I certainly agree that experience would be helpful.”

The committee plans to vote on the problem statement at its December meeting.

November 24, 2015

FERC: PJM Entitled to Recoup Line-Loss Credits

By Michael Brooks

PJM is entitled to recoup $28 million in line-loss credits paid to virtual traders, FERC ruled last week, reaffirming a 2011 decision that the D.C. Circuit Court of Appeals ordered it to justify.

In its response to the court’s 2013 remand, the commission found that repayment of the refunds would not have a negative impact on the PJM market (EL08-14). If anything, FERC said, “recoupment will have a positive effect on the market because market participants know they will not be permitted to retain erroneously paid refunds.”

PJM told the commission that it has already recovered $9 million of the approximately $37 million the RTO paid out to virtual traders through its marginal loss surplus allocation (MLSA), which refunds a portion of transmission loss charges to companies who contribute to the fixed costs of the grid.

PJM collects transmission loss charges to account for electricity lost as it flows over the lines, but because the RTO treats every transmission as the last in the system, its collections exceed actual losses. MLSA was approved by FERC in 2006 to account for this.

FERC decided in 2008 that up-to-congestion traders were entitled to the refunds but reversed its policy in 2011. The D.C. Circuit upheld the reversal but told the commission it had to justify why the traders should be required to pay back their refunds. (See Split Decision for Financial Traders on PJM Line-Loss Collections.)

“We have determined that the virtual marketers … should be required to repay refunds, with interest, to put the parties back in the positions in which they would have found themselves if the commission had not erred in requiring refunds in the first place,” FERC said.

In its remand, the court agreed with virtual traders Black Oak Energy, EPIC Merchant Energy and SESCO Enterprises — whose December 2007 complaint originally spurred FERC to allow them to collect refunds — that the commission’s order to repay the refunds threatened to undermine the markets.

“Recoupment interjects regulatory uncertainty into a setting in which participants rely on the finality and predictability of commission rulings to assure a well-functioning marketplace,” the companies told FERC in 2014. They complained that the order reflected a new policy, one without any time limits, parameters or sufficient notice.

FERC said, however, that it found sufficient legal precedent for its decision, citing cases in which it has required parties be made whole after it had made an error.

The commission also said that the companies “were on notice that the refunds paid based on the initial commission order were in question” and that they “had sufficient reason to preserve those funds in the event that the commission (or a court) subsequently reversed the commission’s initial determination.”

A Long, Messy History

FERC’s 2011 reversal resulted in a Pandora’s Box of market manipulation cases for the commission’s Office of Enforcement.

It was through the MLSA that Powhatan Energy Fund made millions making what FERC contends were riskless UTC trades to cash in on the credits. (See PJM UTC Case Likely Headed to Court After FERC Notice.)

The company is now battling FERC in federal court over the commission’s effort to collect $34.5 million in penalties and disgorged profits. In a brief to the court filed last month asking it to dismiss the case, Powhatan argued that FERC “approved the inclusion of virtual traders in the allocation of [transmission-loss credits] with no limitation other than that the traders pay into the fixed costs of the system, which as the commission expressly recognized, would include UTC transactions.”

“Despite having had the opportunity to circumscribe the very conduct at issue in this matter, the commission did not ask PJM to limit or qualify the virtual traders’ receipt of rebates for UTC transactions, nor did the commission issue any pronouncement or order advising virtual traders that it would consider trading for the rebates wrongful conduct,” Powhatan told the Eastern District Court of Virginia.

FERC countered in its own brief, saying that it had rejected an MLSA method that credited all virtual transactions for fear of it leading to an increase in trades meant solely to cash in on the credits. “It would be impossible for a reasonable person acting in good faith to read these orders and conclude that the commission was indifferent to whether traders engaged in circular trades solely to collect MLSA, regardless of whether those trades paid for transmission or not,” FERC told the court.

City Power Marketing, fined $15 million for similar allegations, filed a motion in the D.C. Circuit Nov. 2 to dismiss the case. In September, FERC issued the same charges against Coaltrain Energy. (See FERC Charges Third Firm with UTC Scam in PJM.)

November 24, 2015

FERC Grants SPP Waiver

FERC last week approved SPP’s request to correct and resettle $13.1 million of transmission-service invoices dating back to 2009, waiving a one-year limit in the RTO’s Tariff. “The requested waiver is a one-time request related to [discrete] software issues, which SPP has resolved,” FERC said (ER15-2295).

Approximately $4.4 million of resettlements outside the one-year limitation date back to 2012, when SPP told FERC a transmission customer’s inquiry led to the discovery of miscalculations of transmission losses and reactive compensation across DC ties with ERCOT and the Western Area Power Administration. The RTO said the software error affected invoices between January 2009 and May 2013.

–Tom Kleckner

November 24, 2015

FERC Denies Rehearing on NY Buyer-Side Mitigation

By William Opalka

FERC on Thursday denied a merchant transmission owner’s request for rehearing of a 2013 order that denied its complaint that NYISO improperly implemented its buyer-side market power mitigation exemption test. However, the commission granted a limited clarification and directed NYISO to make an additional compliance filing (EL12-98).

Hudson Transmission Partners filed the complaint against NYISO after the exemption test was employed for the developer’s 660-MW HVDC merchant transmission line between Ridgefield, N.J., and New York City, which went into service in 2013. The developer had argued that the NYISO Tariff defining “generator” did not apply to its “controllable line.”

“The commission addressed HTP’s argument in the November 2013 order and found that the NYISO Tariff’s references to generators are intended to include controllable lines,” FERC wrote, also citing commission precedent.

FERC also clarified whether a holder of unused unforced deliverability rights (UDRs) has the ability to retain or sell them. The NYISO Tariff permits a UDR holder to either use the rights to offer generation from outside the NYISO footprint into the NYISO installed capacity auctions, or to return its UDRs to NYISO for a given year.

“We agree with HTP that retention of such unused rights in this circumstance, i.e., when the offered ICAP does not clear, does not constitute market manipulation without additional showings under the commission’s anti-manipulation rule,” FERC wrote.

The order said that NYISO fulfilled its compliance requirements to provide the specific scaling factor used for the HTP Project. But it required an additional filing “reflecting Tariff provisions that provide the conceptual basis and general framework for a scaling factor and that are sufficiently broad and flexible to allow for the kinds of variations that exist with respect to UDR projects.”

November 24, 2015

FERC Rejects Environmentalists’ Rate Complaint vs. Duke

FERC rejected a North Carolina environmental group’s request to reconsider its decision not to investigate the group’s market manipulation allegations against Duke Energy (EL15-32).

The North Carolina Waste Awareness and Reduction Network (NC WARN) had complained that Duke was building excess power plants instead of purchasing power from neighboring utilities, resulting in unjust rates. It asked that the commission fund a study evaluating the benefits of Duke joining an RTO. In its request for rehearing, the group asserted the study would show that the creation of a southeastern RTO would result in savings for customers.

FERC denied NC WARN’s request for lacking certain filing requirements, including a “statement of issues.”

“This requirement is not a mere formality,” the commission said. “Rather, the purpose of this requirement is to ensure that the filer, the commission and all other participants understand the issues raised by the filer, and to enable the commission to respond to these issues and avoid wasteful litigation.”

— Michael Brooks

November 24, 2015

ERCOT, MISO, SPP All Record New Wind Peaks

ERCOT, MISO and SPP all set new generation records for wind in the last two weeks.

SPP has seen the most increased activity, setting six new generation peaks this season. The latest came Nov. 15, when SPP eclipsed 9,000 MW of generation for the first time with 9,013 MW. The RTO generated a record 38.3% of its electricity from wind energy Nov. 4.

MISO set its latest record peak with 12,613.9 MW on Nov. 19, breaking the previous mark of 12,006 set Oct. 28. Todd Ramey, the RTO’s vice president of system operations and market services, told an informational forum last week that wind generated 4.1 TWh in October, up from 2.9 TWh in September and 3.6 TWh in October 2014.

ERCOT reported a new high of 12,641 MW of wind at 9:36 p.m. Nov. 16 — representing more than 75% of its installed wind capacity — and accounting for almost one-third of its electricity production.

ERCOT’s previous high came Oct. 22, when it generated 12,238 MW, meeting 36.8% of its load at the time.

The RTOs are home to many of the top wind-producing states, with the Dakotas, Iowa, Kansas, Minnesota, Nebraska, Oklahoma and Texas all generating between 6.9% (Nebraska) and 28.5% (Iowa) of their energy from wind in 2014, according to the American Wind Energy Association.

— Tom Kleckner and Amanda Durish Cook