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.
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.)
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?
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.
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.
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.)
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.
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.”
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.”
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.
NextEra Energy has offered to buy Energy Future Holdings’ Oncor transmissions business, which is slated to be sold to an investment group led by Hunt Consolidated. NextEra made the offer in a filing with the U.S. Bankruptcy Court in Delaware, which is reviewing EFH’s Chapter 11 exit plan.
The sale of Oncor is at the heart of EFH’s $42 billion reorganization strategy, but the company has chosen the Hunt-led group as the buyer.
“NextEra’s alternative transaction is the only proposal that can provide several significant benefits to Oncor, its customers, its creditors and EFH,” NextEra wrote in its bankruptcy court filing.
Duke Completes Storage System on Site of Retired Coal Plant
Duke Energy, working with two other companies, has installed a 2-MW battery storage system on the grounds of its retired W.C Beckjord coal-fired plant near New Richmond, Ohio. Duke said the Beckjord site allowed the company to take advantage of existing transmission infrastructure that connected the battery system to the grid.
The battery storage system will be used in grid frequency regulation — to either release energy onto the grid instantaneously or absorb excess energy — without the grid operator having to dispatch a generator. The battery system is faster and cheaper than a power plant, which could take 10 minutes or more to ramp up.
Duke worked with LG Chem, which provided the lithium-ion batteries, and Greensmith, which provided the software necessary for the frequency synchronicity. It is Duke’s third battery storage system.
Susquehanna Unit 1 Back Online After Nov. 12 SCRAM
Talen Energy’s Susquehanna Unit 1 in Pennsylvania came back online Thursday night after being off for a week following an unscheduled automatic shutdown.
Talen reported that during routine testing of equipment on Nov. 12, one of eight large valves controlling steam from the reactor to the generator closed. The unit automatically shut itself down.
The company said it conducted other maintenance tasks while the unit was down. “We made the choice, while the unit was out of service during a period of mild fall weather and lower wholesale power prices, to advance some maintenance tasks we had planned for the refueling outage next spring,” said Jon Franke, Susquehanna site vice president.
Retired Talen Coal Plant Site Has Potential Buyers
Talen Energy is in talks with potential buyers of a site in Billings, Mont., where the defunct J.E. Corette coal-fired power plant is being dismantled.
The 153-MW plant, which operated for 47 years, was closed in April because it didn’t meet mercury pollution standards.
Talen, which acquired the site during its spinoff this year from PPL, did not identify the prospective buyers.
NRG Names Frotte Treasurer as Stock Continues to Plummet
Frotte
NRG Energy announced a small management shakeup Nov. 19 as its stock value closed below $12/share for the first time in 11 years.
NRG named Gaetan Frotte as senior vice president and treasurer. Frotte, who served as the senior vice president of finance and strategy of NRG Yield, replaces G. Gary Garcia, who left the treasurer position for undisclosed reasons at the end of June. Chad Plotkin, vice president of investor relations, will fill in for Frotte at NRG Yield.
The company is in the midst of cutting costs and shifting away from its renewable-power businesses. Although NRG turned a small profit in the third quarter, the company is struggling with declining revenues from its coal-fired power plants, while its solar business is draining money and still finding its footing.
PSE&G Gets OK to Replace 510 Miles of Gas Mains with Plastic
Public Service Electric and Gas has received regulatory approval for a $905 million plan to replace more than 500 miles of cast iron and steel gas mains with plastic mains over the next three years.
PSE&G said it wants to pursue the project while the price of natural gas remains low.
The work, set to begin after the ground thaws early next year, is expected to raise gas rates by about 1.5% annually for four years.
Eversource Customers in Mass. to See Cut in Electric Rates
The Massachusetts Department of Public Utilities approved a 28% rate decrease for some Eversource Energy customers. The residential rate on Jan. 1 will be set at 10.804 cents/kWh, compared to last winter’s price of 15.046 cents/kWh.
The typical monthly residential bill in the Greater Boston and MetroWest areas will be about $101, compared to $122 last winter. Average residential bills in the South Shore, Greater New Bedford and Cape Cod regions will fall from $124 to about $103.
Equinix Partners with NextEra, Invenergy to Power Data Centers
Equinix, a provider of interconnection and data center services, has signed power purchase agreements with affiliates of NextEra Energy Resources and Invenergy for wind energy in Oklahoma and Texas.
Equinix said the agreements will provide a combined 225 MW of capacity, fully powering all of the company’s data centers in North America by the end of 2016, and nearly doubling its worldwide purchases of renewable energy.
A NextEra affiliate will supply 125 MW of wind capacity that is expected to produce 556 GWh a year from the Rush Springs Renewable Generation Facility in Oklahoma.
Iberdrola USA plans to change its name to Avangrid following its merger with UIL Holdings, according to a filing with the Securities and Exchange Commission.
The subsidiary of Spanish energy giant Iberdrola indicated when it announced the merger with UIL that it would take on a new name. UIL owns United Illuminating in Connecticut and three New England gas distribution companies. Iberdrola USA, which has a large wind energy business, also owns Central Maine Power, Maine Natural Gas, New York State Electric and Gas and Rochester Gas and Electric.
Michael West, a spokesman for UIL, said the new name involves only the U.S. holding company. The utilities will continue to operate under their familiar names.
General Electric has officially moved its renewable energy headquarters from New York state to Paris following its $10 billion acquisition of the energy business of French conglomerate Alstom SA.
The move was a concession to the French government, and Alstom’s offshore wind business was regarded as the stronger business unit. The new renewable energy business will focus increasingly on offshore wind. GE’s onshore wind unit will remain in Schenectady.
FERC last week ordered RTOs and ISOs to file reports detailing their current practices and planned changes on five price formation issues, saying it needed more information before taking substantive action.
In September, the commission issued a Notice of Proposed Rulemaking that would require RTOs and ISOs to align their settlement and dispatch intervals, saying it was the first of a number of proposals on which the commission plans to act. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
FERC said last week that the RTO/ISO reports, due in 75 days, will help it identify best practices and inform its future actions. It asked for information on:
pricing of fast-start resources;
commitments to manage multiple contingencies;
look-ahead modeling;
uplift allocation; and
transparency.
“Identifying best practices for these five areas should provide incentives to maintain reliability, to facilitate accurate and transparent pricing, to reduce uplift, and for market participants to operate consistent with dispatch signals,” the commission wrote. “We have selected these areas because the discussion at the price formation workshops and the comments received after the workshops suggest that a number of RTOs and ISOs have sufficient experience with these areas such that we may be able to discern best practices and understand unintended consequences.
(Click to zoom.)
“The commission seeks this information not only to answer technical questions regarding how each RTO/ISO addresses these topics, but also to understand the reasons why each RTO/ISO has made its set of policy choices,” it added.
Commissioner Cheryl LaFleur said the issue is one of the commission’s most important initiatives, particularly because of the shift from coal to lower carbon resources. “I know there’s been a lot of anticipation and even impatience for action in this area,” she said. “This is the second in a series of orders; I don’t believe it will be the last.”
Commissioner Tony Clark said the energy markets “are our best performing and most mature markets.”
“So it seems to me that this is an appropriate manner in which to deal with this … so that we take it one bite at a time and we don’t have secondary unintended effects [that might occur] if we were to act all at once.”
Commissioner Colette Honorable noted that some have complained that work on price formation issues has “stalled” in RTO stakeholder processes.
“While we are working, I want to gently ask that [stakeholders] continue working, too, and that if you identify market flaws and other issues that need to be addressed, please continue to demonstrate your leadership.”
