FERC last week affirmed an administrative law judge’s 2014 ruling finding fault with Entergy’s accounting in in its fourth annual bandwidth filing (ER10-1350).
The commission agreed with much of the judge’s order, which found Entergy did not properly include the fuel inventory balance as an input to the bandwidth formula for the 2009 test year and failed to include accumulated deferred income tax for its Waterford 3 nuclear plant west of New Orleans. The judge also ruled Entergy made an error in its accounting for the amortization period for the sale and leaseback of Waterford 3.
FERC gave Entergy — which was joined by the Arkansas and Louisiana commissions in intervening — 60 days to make a compliance filing.
Also last week, FERC denied the Louisiana Public Service Commission and Entergy’s request for a rehearing of its December 2014 order, which set for hearing and settlement judge procedures the use of Waterford 3’s accumulated deferred income tax in the bandwidth remedy (EL10-65).
Entergy’s allocation of production costs among its half-dozen operating companies under its system agreement has been a source of continuing disagreement.
The companies essentially operate as one system, although each has different operating costs. Payments are made annually by Entergy’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the system average.
Regulators in Entergy’s states have regularly challenged the annual bandwidth filings, which began in 2007.
D.C.’s largest consumer of electricity, the federal government, is urging the Public Service Commission to reject Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc. unless the applicants revise their settlement to provide benefits for non-residential customers.
“The terms of the settlement agreement are not consistent with the public interest because there are no direct benefits … for commercial customers, and the [customer investment fund] benefit for residential ratepayers is less than face value,” the General Services Administration said in an initial brief filed Dec. 16.
It also called for a two-year rate freeze and a cap on Pepco’s cost recovery on the development of four proposed microgrids.
“While the $25.6 million residential base rate credit is provided to cover base rate increases occurring from the merger closing through March 31, 2019, residential rates will increase during that period, and the terms of the settlement agreement anticipate that the credit may be insufficient to cover all residential increases approved during that period,” GSA said, predicting that any benefit would be offset by an ensuing “rate shock.”
To blunt a rate hike, GSA proposes a two-year freeze of distribution rate cases, through Dec. 31, 2017.
GSA noted that the effects of the settlement stretch beyond the district. Federal customers, which represent 25 to 30% of Pepco’s annual distribution and load delivery revenue, pay their utility bills with money from taxpayers in all 50 states and the district.
In response to GSA’s filing, Exelon and Pepco released a joint statement saying, “All customers, including the GSA, will benefit from merger commitments now before the commission, including improvements in service reliability, investment in sustainability and the economy of the district and synergy savings that will go back to customers through rates that are lower than they would be absent the merger.”
GSA: Comments Should Count
GSA’s comments came after the deadline for the agency to become a legal part of the case. But it asked the PSC to afford it as much weight as those from other intervenors, pointing out that it was given party status in the beginning of the proceedings and participated in settlement conferences ordered by the commission.
It also had filed a motion against re-opening the case after the applicants submitted a settlement agreement reached with Mayor Muriel Bowser’s administration and opposed the truncated rehearing schedule, saying it didn’t give the non-settling parties enough time to prepare an informed response.
Regardless of deadlines, comments continue to pour in to the PSC, which has said the case has received the most public input of any in the commission’s more than 100-year history.
Among them are more than 40,000 signatures of district residents that Exelon and Pepco collected in support of the merger as well as resolutions from neighborhood groups opposing the deal.
The merger, which would create the nation’s largest utility, was rejected in August by the D.C. PSC after being approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia.
In early October, the applicants reapplied with a settlement supported by former critics — Bowser, People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine — that included $78 million in public benefits. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
Bowser Comes Under Scrutiny
Last week, Bowser’s reversal was hit with a new volley of criticism when radio station WAMU reported that the head of a political action committee formed by her supporters had been hired by Exelon to lobby city officials to support the merger.
FreshPAC was able to skirt fundraising limits due to a loophole in D.C. law. It was disbanded in November after being accused of creating a “pay-to-play” political environment.
Horton (Source: GHA&J)
Records show that Exelon hired the committee’s chairman, Earle “Chico” Horton III, as a lobbyist on Sept. 30. The settlement was made public Oct. 6.
The Washington Post editorial board called on Bowser to release emails and other materials documenting the negotiations that went into the settlement.
“There is nothing illegal, or all that unusual, about companies hiring lobbyists with connections they think will serve their interests,” the Post wrote. “But what is legal is not always right, and the fact that someone who was raising thousands of dollars to advance the mayor’s interests was at the same time carrying water for a company that wanted something from the government is more than unseemly.”
A decision also is pending on an appeal of the Maryland Public Service Commission’s 3-2 vote approving the merger.
On Dec. 8, the Office of the People’s Counsel and the Sierra Club argued before Queen Anne’s County Circuit Judge Thomas Ross that the merger was not in the public interest. He is expected to issue an order on or around Jan. 8.
Public Service Enterprise Group and the PJM Power Providers Group (P3) asked the D.C. Circuit Court of Appeals last week to overturn two FERC orders approving PJM capacity market rules.
PSEG and P3 had disputed PJM’s use of an 8% cost of capital used in cost of new entry (CONE) calculations, saying it was too low because it relied on corporate-level data for publicly traded independent power producers and did not reflect riskier, project-level financing.
Separately, P3 appealed FERC’s refusal to rehear a 2013 order approving PJM’s revisions to a rule designed to mitigate buyer-side market power in the capacity market (ER13-535).
The ruling addressed the minimum offer price rule (MOPR), which PJM added to its auction protocols in 2006 amid concern that load could have an incentive to suppress market clearing prices by offering supply at less than a competitive level.
P3 challenged FERC’s rejection of PJM’s proposal to extend the MOPR mitigation period mitigation from one to three years. It also contended the ruling conflicted with its prior rulings on buyer-side market power mitigation regarding NYISO. (See FERC won’t Rehear PJM MOPR Ruling.)
The budget bill signed by President Obama on Friday — which appears to mark the beginning of the end for renewable energy subsidies — will accelerate the growth of solar power in the next several years, analysts say.
The bill extends the solar investment tax credit indefinitely, albeit at a reduced level after 2019.
The wind production tax credits were extended through 2019, also at reduced levels after 2016.
The Solar Energy Industries Association predicted U.S. solar power capacity will triple to 95 GW by 2022 as a result of the incentives — enough to supply 3.5% of the nation’s electricity, up from less than 1% in 2014. SEIA CEO Rhone Resch predicted solar jobs will grow from 200,000 to 340,000.
Greentech Media’s GTM Research is even more bullish, saying it expects solar capacity to quadruple to nearly 100 GW by 2021. The ITC extension will lead to $40 billion in incremental investment in solar between 2016-2020, it said.
“There’s no way to overstate this — the extension of the solar ITC is the most important policy development for U.S. solar in almost a decade,” said MJ Shiao, director of solar research for GTM Research.
By 2020, said Shayle Kann, senior vice president at GTM Research, “more solar will be installed each year than was added to the grid cumulatively through 2014.”
Wall Street agreed, with solar companies Enphase Energy, SunEdison and SolarCity each rising by 32% or more last week.
“With the extension of tax credits, solar becomes cost-effective for new customer demographics and in more states. Without it, it could take years for that to be true,” Shiao told RTO Insider. “With the ITC extension, the next five years will see 25 GW of solar that otherwise wouldn’t be installed.”
The bill extends the 30% solar investment tax credit through 2019, dropping gradually to 22% by 2021. The credit is eliminated for homeowners beginning in 2022 but continues indefinitely at 10% for commercial installations. Projects that come online by the end of 2023 will qualify for larger credits based on the year in which construction began.
Shiao said the extension provides a bridge to EPA’s Clean Power Plan, whose requirements don’t take effect until 2022. The CPP anticipates additional wind and solar energy making up for reduction in fossil fuel generation.
GTM Research said the extension will have the biggest impact on utility-scale solar, boosting deployments 73% through 2020 with utility-scale contracts dropping below $0.04/kWh.
Without the bill, the ITC would have dropped to 10% for non-residential and third-party-owned residential systems and zero for host-owned residential systems in 2017.
Bloomberg New Energy Finance said developers would have installed 11.9 GW of solar panels in the U.S. next year in a rush to beat the end of the ITC. With the extension, BNEF said, 2016 will likely see the addition of about 9.1 GW, a drop of almost one-quarter.
BNEF had predicted solar installations would drop by as much as 71% in 2017. It now predicts an increase of 5.5% over 2016.
IHS Technology said the U.S. solar installations would have dropped by 6.5 GW in 2017 from 2016 without the extension.
End Game for Wind?
The story is a bit different for the more mature and competitive wind industry.
The wind production tax credits were extended at 2.3 cents/kWh for 2015 and 2016, dropping by 20% in each of the following three years to 40% of the current level by 2019. Without additional congressional action, it would expire in January 2020.
The American Wind Energy Association said in a statement Friday that the bill ensures “stability for 73,000 American wind industry workers … and [wind] investors.”
AWEA said the PTC has helped more than quadruple U.S. wind power, with installed capacity rising from 16.7 GW at the beginning of 2008 to 69.5 GW by the third quarter of 2015. The organization credits the PTC with helping advance wind turbine technology, leading to a 66% drop in the cost of wind energy over the last six years.
Beth Soholt, executive director of the renewable energy advocacy group Wind on the Wires, issued a statement applauding Congress’ action.
“This extension gives these renewable energy industries the certainty they need to plan for the future and mitigates the boom-bust cycles that are so very detrimental,” Soholt said.
When renewable energy tax credits were allowed to briefly expire in 2013, wind farms saw a 92% drop in their installation and some 30,000 jobs were lost. After the PTC was renewed, the wind industry recovered all but 7,000 jobs by the end of 2014, according to AWEA data.
With the extension, according to BNEF, the U.S. will add 44 GW of wind capacity by the end of 2021, a 76% increase over the 25 GW it said would have been built without any subsidies.
Wall Street’s reaction to the PTC was more muted, with Vestas Wind Systems A/S, the world’s largest turbine maker, finishing last week up by more than 8%, albeit at a five-year high.
WILMINGTON, Del. — Outgoing PJM CEO Terry Boston presided over his final general session last week, tearing up as he recalled how power changed his family’s life growing up in rural Tennessee.
“On Sept. 9, 1939, electricity came to the Boston family farm. That meant things like the milk was in the fridge and not in the creek or the spring,” he said. “Nothing has improved our standard of living or our productivity more.”
“Power engineering is not rocket science. It’s much more important than that,” he said, drawing laughter from the audience.
Boston began his career in 1972 as a project engineer for the Tennessee Valley Authority, joining PJM as CEO in 2008. He will serve as CEO emeritus until the end of this month. Andy Ott, previously PJM’s executive vice president for markets, took on the job of president and CEO in October. (See Retiring PJM CEO Boston Lauded for Efficiency Improvements, Management Style.)
Boston was feted by PJM stakeholders, staff and members of the Board of Managers during a reception following the general session. (See related story, From Cold War to Black Sky: PJM General Session Fetes Boston, Discusses Emerging Threats.)
Katie Guerry of EnerNOC, the incoming chair of the Members Committee, and Susan Bruce of the PJM Industrial Customer Coalition presented Boston with a solar-powered globe of the world.
Boston also was presented with a letter from Pennsylvania Gov. Tom Wolf lauding him for creating “the industry’s most successful model for an electricity market.” U.S. Sen. Bob Casey (D-Pa.) and Rep. Ryan Costello (R-Pa.) also sent letters of commendation.
Board Chairman Howard Schneider lauded Boston for his intelligence, dedication and humility.
Boston and his wife, Brenda, will be splitting their time in retirement between Hawaii and their custom-designed solar-powered home in Tennessee.
“The whole PJM community is in the public service business,” Boston said. “It’s been the love of my life to work here.”
The PJM Board of Managers last week approved construction of seven transmission projects proposed in response to FERC Order 1000 competitive solicitations. The projects have an estimated cost of $490 million.
One, to address reliability violations in the AEP transmission zone, was selected from among 91 proposals received in response to the competitive window PJM opened in June to fix reliability, thermal and voltage violations. The board had approved 19 other projects from that group in October.
The board also approved six projects from among 23 proposals submitted under a second competitive window, which opened in August to address potential violations not included in the first solicitation.
With the addition of the projects to the Regional Transmission Expansion Plan, PJM has authorized $28.27 billion in additions and upgrades to resolve reliability violations and reduce congestion since 2000.
“Through the competitive windows, we are seeing more alternatives than we would have otherwise,” Mike Kormos, executive vice president for operations, said in a statement. “In some cases, as in this last review, we are seeing alternative solutions that address the problem at a lesser cost than originally estimated.”
FERC last week proposed reducing the amount of ownership information that companies must provide to obtain market-based rate authority.
The commission allows companies to sell power at market-based rates if they and their affiliates lack, or have adequately mitigated, horizontal and vertical market power. Current rules require applicants to describe the activities of all upstream owners, often requiring sellers to submit multiple amendments to their filings.
The commission’s Notice of Proposed Rulemaking would require applicants to provide ownership information only for affiliates necessary for the commission’s market power analysis (RM16-3).
Sellers would be required to identify and describe two categories of affiliates:
“Ultimate affiliate owner(s),” defined as the furthest upstream affiliate owner(s) in the ownership chain; and
Affiliate owners with franchised service areas or market-based rate authority, or that directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; physical coal supply sources; or access to transportation of coal supplies.
The NOPR also would clarify the types of ownership changes that must be reported to the commission.
The commission said the changes would be less burdensome for filers and more useful to FERC’s assessments.
Comments will be due 60 days from publication in the Federal Register.
WILMINGTON, Del. — When Terry Boston began working for the Tennessee Valley Authority in 1972, its bunkered control room was believed to be one of the targets near the top of the Soviet Union’s nuclear hit list.
Last week, when the retired PJM CEO said his goodbyes at a General Session on “Resiliency and Security,” the concern was not the Cold War but “black sky” risks and the need for “critical low-density engineering assets” to recover from them.
Three speakers talked about their work protecting the grid from natural and manmade threats.
Jeff Dagle spoke about the Pacific Northwest National Laboratory’s work using parallel processing to aid modeling of extreme events. The technology can help system operators comply with a new NERC standard requiring them to ensure that “multiple outages” don’t cause system instability.
“When you try to model these extreme events, you’re going deeper than traditional N-1 [contingencies]. You’re doing N-K type of analysis,” said Dagle, the lab’s chief electrical engineer for electricity infrastructure resilience. “So there’s many more thousands of possible events you want to simulate and try to understand. Unless you throw that on a parallel computer, you’re going to be there for a while waiting for an answer.”
The lab’s work with PJM to apply Bayesian model aggregation — the combination of multiple prediction models — to reduce forecasting errors in network interchange schedules won an R&D magazine award. “This has the potential to save big money” — tens of millions, Dagle said.
David Andrejcak said FERC has become “much more agile” since it formed the Office of Energy Infrastructure Security following the 2013 sniper attack on Pacific Gas & Electric’s Metcalf substation.
Andrejcak is deputy director of the office, which combines the agency’s expertise in electric, natural gas and oil infrastructure. The office identifies threats and examines infrastructure for potential weaknesses but has no enforcement role, unlike the Office of Electric Reliability, which oversees the development of mandatory reliability and security standards.
“By addressing these with the private sector owners, we find that we’re getting a whole lot more success,” he said. “We’re not involved in the standards process. We’re the collaborative branch of FERC.”
Andrejcak noted a Department of Homeland Security analysis that found that almost one-third of cyberattacks on critical infrastructure in 2014 involved the energy industry. “We’re a big target. No doubt about it,” he said.
The session’s keynote speaker was Jonathon Monken, vice president of U.S. operations for the Electric Infrastructure Security Council. The non-governmental organization worries about “black sky” hazards such as cyberattacks or electromagnetic pulses (EMPs) capable of generating a “widespread, long duration” outage that could result in mass migration.
Monken said broadcaster Ted Koppel’s book, “Lights Out,” which highlighted threats that could knock out the Eastern Interconnection for weeks or months, was useful in publicizing the need for preparations, such as assembling critical low-density engineering assets — engineers with expertise in electrical relays.
“We have not yet experienced a power outage that … [results in a] widespread long duration outage. We’re talking about months in terms of the outage. We’re talking about tens of millions [of people] in terms of the footprint.
“We don’t have the capacity to evacuate New York City much less the Eastern Interconnection,” Monken continued. “There’s a wide deficit in terms of the capability required to respond and recover from something of that magnitude and duration.
“I’d rather have an EMP event than just about any of the other ‘black sky’ hazards that include things like earthquakes and cyber[attacks],” he added. “Cyber is difficult because it’s very unpredictable and it’s very deliberate, whereas EMP is a statistical event — it won’t necessarily hit everything everywhere. You’ll have sporadic outages based on percentages.
“Cyber is very deliberate. They’ll only hit where it hurts the most.”
WILMINGTON, Del. — PJM will ask FERC to act within the next couple of months on its Capacity Performance compliance filings and any related outstanding hearing requests, Stu Bresler, senior vice president for markets, told the Markets and Reliability Committee on Thursday.
“PJM recognizes there is a fair amount of uncertainty among our asset owners and operators as to what will occur come June 1 and beyond,” he said. “The purpose of requesting FERC action is to achieve as much certainty as possible ahead of summer 2016.”
Staff expects to make the filing before Christmas.
Load Forecast to Include Distributed Solar
With eight objections and five abstentions, the committee approved manual changes that allow PJM to consider distributed solar generation in its load forecast.
“The reason PJM sees this as important is that this behind-the-meter generation of solar is by far the quickest growing component,” said PJM’s Tom Falin. “It’s really taken off the past three to four years … exponentially. We believe it’s important to recognize this phenomenon now in the forecast.”
In the near term, the model will affect only a few hundred megawatts, he said.
Steve Herling, PJM vice president for planning, said staff wants to act now so it is not caught flat-footed when solar’s growth increases.
“We don’t want to see the phenomenon like we did with energy efficiency variables, which we talked about for a couple of years and by the time we implemented a change it was a pretty substantial change,” he said. “We want to get it into the forecast so we can tweak it as it grows.”
PJM agreed to review the process in a year to see how accurate it is and if any changes need to be made. The revisions will be made to Manual 19: Load Forecasting and Analysis. (See “Distributed Solar to be Included in Load Forecast” in PJM Planning Committee and TEAC Briefs.)
In a related matter, the committee approved manual revisions that aim to prevent energy efficiency resources from being counted both as capacity and load reduction in the new forecast model. The changes will be incorporated in Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification.
The motion passed with 12 no votes and one abstention. Members had delayed the vote until after an additional education session regarding the proposed addback. (See “Members Ask for More Time to Consider EE Resource Manual Changes” in PJM Markets and Reliability Committee Briefs.)
Ways to Mitigate Risk in CP Market to be Studied
A controversial problem statement proposing to study ways capacity suppliers could minimize underperformance penalties by netting them against overperforming units was approved with 80% of a sector-weighted vote.
Those who supported the measure said it was needed to level the playing field between small and large companies and to encourage financial investment.
Opponents said it was a solution without a problem and threatened to unwind a core aspect of the Capacity Performance model.
Bob O’Connell, who brought the problem statement forward on behalf of PPGI Fund A/B Development, responded to consumer advocates who asked what the problem was by saying, “Investors are looking at the market and deciding whether to invest in the energy market or Hollywood films. If investors see too much risk in the market, they may wait several years to bring a project forward.”
Market Monitor Joe Bowring opposed the problem statement.
“This seems to me … an attempt to unwind some critical parts of Capacity Performance,” he said.
Lisa Moerner, of Dominion Energy Marketing, said the concept does not undermine the Capacity Performance construct.
“We plan to do everything we can to perform during an emergency event under CP,” she said. Such risk-mitigating opportunities just give generators more options to do so, she said.
“We’d much rather overperform than pay penalties,” she said. “If we can provide megawatt-hours rather than pay a penalty, how is that a bad thing?”
Jason Barker of Exelon said that while that company’s general policy is to endorse problem statements and let discussion take place, it would be voting against the problem statement.
“This is really an attempt to rewrite Capacity Performance before the ink is even dry and before we’ve had a day of performance under this plan,” he said.
“If you follow the problem statement through to conclusion, it would provide incentives for market participants to underinvest in generation assets, threatening reliability, and enable those market participants to go into a secondary market and find replacement capacity at lower cost than the established non-performance penalty.
“The level of investment and the level of risk should be reflected in capacity market offers.”
Committee Approves Manual Changes
Members endorsed the following manual changes:
Manual 10: Pre-Scheduling Operations. The changes define a generator planned outage and restrict scheduling planned outages during peak maintenance season; define generator maintenance outage; define unplanned outage and clarify notification requirements; and correct the definition of non-synchronized reserve.
Manual 11: Energy & Ancillary Services Market and Manual 28: Operating Agreement Accounting. Changes reflect Tariff revisions approved by FERC regarding the energy market offer cap that went into effect Monday (ER16-76). Cost-based offers for incremental energy are capped at $2,000/MWh and allowed to set prices. Costs above that cap will be recovered through an after-the-fact review and make-whole payments. Market-based offers for individual units are allowed to rise with their cost-based offers. (See PJM Members OK $2,000/MWh Energy Market Offer Cap.) There was one abstention and one objection to this issue.
Manual 14D: Generator Operational Requirements. Revisions reflect the annual review of the manual as well as revisions to the reactive testing process. Revises and renames the wind farm communication model, making it applicable to all jointly owned resources to avoid confusion among control room operators. Adds definitions of generator planned, maintenance and forced outages. There was one “no” vote on this issue.
Manual 39: Nuclear Plant Interface Coordination. Updates are the result of a three-year review and include safe shutdown loading requirements developed by the nuclear generation owners’ user group.
EPA has overruled New York officials and ordered an additional air quality review for a dormant coal-fired power plant in the Finger Lakes region whose owners want to convert it to biomass and natural gas.
Owners of the Greenidge Generation Plant on Tuesday wrote to the New York Public Service Commission to say the EPA Region 2 administrator rejected the state’s finding that the change from coal to either biomass or natural gas is not a “major modification.”
Greenridge Plant (Source: DOE)
“The primary basis for EPA’s objection is that, if reactivated, Greenidge will be subject to the Clean Air Act’s … permit program as a new source,” EPA wrote on Dec. 7.
The 106-MW plant on Seneca Lake has been dormant for nearly four years. The owners are seeking to revive it and add a new supply line for natural gas. (See Finger Lakes Plant Seeks Gas Line for Repowering.)
The New York Department of Environmental Conservation had issued a draft permit that EPA said was incomplete.
“We strongly disagree with the EPA’s decision given that the New York Department of Environmental Conservation conducted a thorough and complete review before issuing this draft permit, concluding that Greenidge clearly meets all the federal and state standards for resuming full operation,” Greenidge spokesman Michael McKeon said in a statement. “We are currently analyzing the EPA’s response to determine how best to restart the facility as soon as possible.”
He said the company has 90 days to respond to EPA.
The state awarded Greenidge $2 million on Dec. 11 to renovate the plant in Dresden to allow it to burn 100% natural gas. McKeon said the plant would lose that grant — part of a five-year, $500 million Upstate Revitalization Initiative for the Finger Lakes region — if the delay lasts as long as a year.
