NERC announced Monday that its Board of Trustees had accepted the resignation of CEO Gerry Cauley, effective immediately, following his arrest for domestic abuse.
The organization said General Counsel Charles Berardesco will continue to serve as acting CEO while the board seeks a search firm to recruit a replacement.
“NERC has a talented staff and an experienced leadership team that is well-equipped to continue the forward momentum on key initiatives,” Board Chair Roy Thilly said in a statement. “I am confident we will continue to meet milestones and expectations going forward. NERC remains committed to maintaining the reliability and resilience of the bulk power system.”
A NERC spokeswoman declined to comment when asked whether Cauley would receive any severance payment. “Any personnel action is confidential,” she said.
NERC CEO Gerry Cauley (center) and General Counsel Charles Berardesco (to Cauley’s left) attend a NERC board meeting in New Orleans Nov. 9, hours before Cauley’s arrest for domestic abuse. Also pictured are Board Chair Roy Thilly (to Cauley’s right), and board members Jan Schori (left) and Frederick W. Gorbet (foreground). | NERC
NERC had placed Cauley on a leave of absence after his arrest for battery, a misdemeanor, for allegedly assaulting his estranged wife in the early morning of Nov. 10. The police report documenting his arrest states that his wife, Jean Cauley, sustained bruises and scratches and was experiencing a great deal of pain in her back.
Jean, a former probation officer and child abuse investigator for the state of Florida, posted a comment about the incident on her LinkedIn page Sunday: “Who knew that when I married a CEO — and me with a background in law-enforcement — [I] would be a victim of a violent crime by her husband to the point of a back being broken,” she wrote. “It shows that no one is exempt from domestic violence and that we should all support each other as women.”
Cauley, 64, had served as NERC CEO since January 2010, and was often the face of the reliability agency in hearings before FERC and Congress. By Monday afternoon, however, his biography and photo had been removed from the web page listing the organization’s management.
BALTIMORE — State-federal tension over electricity policy is likely to continue even after current debates over nuclear and coal subsidies end, speakers told the National Association of Regulatory Utility Commissioners’ Annual Meeting last week.
Clark, an adviser for Wilkinson Barker Knauer who left the commission in September 2016, said there will be pressure for additional state interventions because of the impact of renewables on energy market prices. “Increasingly we see even … relatively new gas units that are stressed in certain markets. Any resource that has higher fixed costs and variable operating costs is going to be challenged in any sort of market where you have price takers with zero variable cost units that are at the margins.”
In addition, he said, FERC may begin asserting its authority on power “from the edge of the grid,” such as rooftop solar.
“Up until this point, FERC has kind of walled that off and basically … been able to ignore what happens since that’s been on the state jurisdiction side of things,” he said.
“It’s hard to argue that all of these exponentially growing resources at the edge of the grid — in which a sale is by default a sale for resale — [is not] federally jurisdictional activity. To this point it hasn’t been that big a deal. It’s becoming a very big deal.”
Ari Peskoe, of Harvard Law School’s Environmental Policy Initiative, said legal challenges to Illinois’ and New York’s zero-emission credits for nuclear plants “expose a question that courts have not addressed in the 20 years of restructuring: May a state provide an incentive for energy production without intruding on FERC’s exclusive jurisdiction over energy sales? Perhaps the state authority over generating facilities means just that — the facilities themselves, and not the energy that they produce,” he said.
“There’s little doubt that states can enact all sorts of command-and-control regulations over pollution from those facilities. States can issue emission limits or simply prohibit the burning of fossil fuels within their borders. But what about financial regulation of pollution and avoided pollution? And what about state regulation of utility portfolios? ls there some limit on state power that limits states just to those traditional integrated resource plan tools?”
Peskoe filed an amicus brief defending the Illinois ZECs. “Expanding the scope of FERC’s exclusive jurisdiction to swallow up ZECs, [renewable energy credits] and other emissions taxes and allowances will disrupt how the industry and how regulators have understood jurisdictional limits,” he said.
If the courts accept opponents’ reading of the Federal Power Act, “we can expect lawsuits about a range of state programs,” he said, adding, “Now concerns about market distortions from ZECs seem pretty quaint in light of [the U.S. Department of Energy’s] recent Notice of Proposed Rulemaking.”
Peskoe said that if ZECs survive the current legal challenges, “existing state policy would be relatively safe from these pre-emption challenges going forward. Then the action turns back to FERC and what FERC is going to do.”
He said FERC’s May 1-2 technical conference on integrating wholesale markets and state public policies “was a really positive step … so I hope that the DOE NOPR and whatever happens after it doesn’t sort of suck the air out of the room and that conversation keeps happening.” (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)
Clark said FERC must determine when state actions reach a “tipping point” for its markets. “Whether you think the ZEC is the tipping point or the DOE NOPR is the tipping point, there is a tipping point that FERC has to be concerned about in terms of its maintenance of the integrity of the wholesale market,” he said.
“What happens when say … coal-friendly states decide, ‘It looks like RECs and ZECs are the way to go. What we need now is a coal energy credit,’” Clark asked.
“We are called the Environmental Policy Initiative, so we don’t love the idea of coal credits,” Peskoe responded. “I’m somewhat comforted by the fact that about 30 states actually enacted RPS and, so far, zero states have enacted coal standards.”
Former Commissioner Marc Spitzer (2006–2011) was more succinct: “If they’re zero-emission coal, go for it!” he joked.
Spitzer, a partner with Steptoe and Johnson, also supported ZECs, saying states are “entitled to deference and forbearance.”
BALTIMORE — Speaking last week to an audience of consumer advocates, John P. Hughes, CEO of the Electricity Consumers Resource Council (ELCON), led off his critique of RTO stakeholder processes with a blunt assessment: “The main takeaway is it can’t be fixed.”
Other participants who joined Hughes in a panel discussion at the National Association of State Utility Consumer Advocates (NASUCA) annual meeting Wednesday were more optimistic.
Unfortunately, the speakers’ opening presentations at the discussion — cheekily titled “20 Years of RTO Meetings and We’re Still Not Done?” — swallowed up the entire 70-minute session. As a result, Denise Foster, PJM’s vice president of state and member services, never got a chance to respond to the critiques.
Room for Improvement
AARP’s Bill Malcolm, a former MISO manager of state regulatory affairs, opened his presentation by praising RTOs for improving generation dispatch and eliminating rate pancaking.
But he said they should be required to follow open meetings laws and enact ethics reforms, including a ban on revolving-door hiring. He also called for tightening cost controls. “RTOs don’t print money,” said Malcolm, AARP’s senior legislative representative for state advocacy and strategy integration. “It’s ratepayer dollars at the end of the day.”
He also said RTOs should add ways to better represent residential ratepayers in stakeholder proceedings, including establishing an RTO-funded organization like the Consumer Advocates of PJM States (CAPS).
“Let’s make a good thing better,” Malcolm said.
Unstable Market Design
Hughes, whose organization represents industrials, said a large manufacturer might have only one or two electricity buyers for national or international operations — making it impossible to monitor the hundreds of RTO stakeholder meetings annually.
“The market design has never — and may not ever — be stabilized. Therefore, the stakeholder process will forever be the resource hog that it is today,” he said, citing capacity markets as an example.
“It is the wrong solution to the problem, caused by not having shortage pricing or surge pricing. And since the capacity market doesn’t really work, it’s under continual attack for tweaks and fixes that will go on forever unless we come up with a different market design — which I don’t think will happen.”
Hughes said almost all the proposals that go through the stakeholder process are efforts to increase charges to ratepayers. “The current driver of market design changes — which is [the call for] price formation, including the new [Department of Energy Notice of Proposed Rulemaking] — is very low-cost shale gas. There seems to be a conspiracy to deny consumers the benefit of this resource,” he said.
Hughes said ERCOT — which has a board seat reserved for industrial consumers — is the only governance structure his group likes. Industrials’ presence on the board means “you gain respect in the whole food chain,” he said.
PJM Study
Christina Simeone, director of policy and external affairs for the Kleinman Center for Energy Policy at the University of Pennsylvania, spoke about her May 2017 study on PJM’s governance, which asks “Can Reforms Improve Outcomes?”
Among her conclusions: PJM’s stakeholder process is very effective on less contentious issues but is less effective on the most contentious issues that are subjected to sector-weighted votes.
Because of affiliate voting, the lower committees are subject to a “huge supply-side bias,” she said, citing the now-closed Seasonal Capacity Resources Senior Task Force, where 190 votes were cast by 34 respondents. Just 10 companies can prevent any proposal from passing at the lower level, she said.
But while suppliers can muscle their proposals through the lower committees, she cited a Pennsylvania State University study that found a load-side bias at the upper levels, where End Use Customers and Electric Distributors have formed a tight voting coalition. “What ends up happening is all the proposed solutions are supply-side biased and then they get knocked down by the load-side bias at the higher level. This is a phenomenon I think we’re seeing more and more,” she said.
She said RTO management has an interest in preventing political backlash over price volatility and blackouts, “so the organization may seek to prevent those things, perhaps at any cost.”
She recommended that states have a vote through their governors and that PJM review the makeup of its five sectors, noting the dispersion of stakeholders representing the fastest-growing industry segments: renewable energy (Generation Owners), energy efficiency (Electric Distributors, Transmission Owners and Other Suppliers) and demand response (Other Suppliers).
“In competitive markets, new market entrants are very important. However, they’re being lumped in with everybody else and that does a disservice to both the larger firms and the new market entrants because of vote dilution. The larger the sectors get, the less impact any individual firm can have on the process.”
She said FERC should require RTOs to re-evaluate their governance process regularly to comply with the “ongoing responsiveness” principle of FERC Order 719.
FERC on Thursday rejected a rehearing of MISO’s subregional flow limits and accepted the RTO’s method for calculating the limits.
The commission declined to rehear its December 2016 dismissal of a complaint seeking to overturn the results of MISO’s 2016/17 planning year capacity auction. A coalition of transmission customers had argued that subregional transfer constraints where MISO flows must cross FERC Backs MISO on Transfer Limit, Seeks Details.)
MISO calculates the transfer limits between its Midwest and South regions by deducting firm reservations from 2,500 MW of available capacity flowing from South to Midwest and 3,000 MW estimated to be available in the opposite direction. The initial limits were set out in a settlement with SPP that became effective in early 2016.
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Several MISO stakeholders and the Independent Market Monitor argued that the RTO’s subregional constraint calculation is flawed, with a group of transmission-dependent utilities in Wisconsin arguing that the subtraction of all firm transmission service reservations “incorrectly assumes that those holding the reservations will use them all the time, even when it would be counter to their economic interest.” The Monitor agreed that the calculation is too conservative.
In its Nov. 16 order, FERC pointed out that while it’s possible that not all firm transmission customers will use their service simultaneously, it’s also possible they could.
“All parties appear to agree that the regional directional transfer limits established in the settlement agreement are a reasonable starting point for the calculations,” FERC wrote. “We agree … MISO’s proposal requires it to make two reductions, when applicable, to the regional directional transfer limits: (1) a reduction, based on a feasibility analysis, for reliability purposes; and (2) a reduction by the amount of firm transmission service reservations in the prevailing direction.”
Multiple companies submitted alternative proposals for calculating subregional constraints, but FERC declined to examine their fairness.
“There may be more than one just and reasonable methodology that MISO can use to calculate subbegional constraints. We need not analyze whether the various alternative proposals are also just and reasonable,” the commission said.
FERC also clarified — at WPPI Energy’s request — that its finding regarding the 2016/17 auction should not be construed as “conclusive proof” that MISO’s approved methodology will be considered the best course for future capacity auctions.
Monitor Concerned with Cost of Midwest-South Constraint
The order comes as the Monitor is reiterating concerns about the cost of the SPP contract path with respect to make-whole payments.
“We’ve been coming at MISO with concerns about the RSG [revenue sufficiency guarantee] on the North-South constraint for some time now,” Monitor David Patton said.
Patton said the constraint contributed to $3 million in revenue sufficiency guarantee payments in April 2017 alone.
“It’s a vexing constraint because it’s not a physical constraint; it’s an agreement,” Patton said during an October Market Subcommittee meeting.
He said the constraint created about $9 million in RSG payments from September through mid-October, with $6 million of that paid to a single company. “These are wasteful costs,” he added.
Earlier this year, MISO conducted a study to evaluate the benefits of constructing transmission to link the Midwest and South areas. The RTO concluded that not one of 35 potential projects could pass the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits. (See “No Tx Coming for North-South Constraint,” MTEP 17 Proposal: 343 New Transmission Projects at $2.6B.)
FERC’s Office of Enforcement opened 27 investigations in fiscal year 2017, 10 more than the year before, according to its 11th annual report released last week.
The report includes for the first time examples of surveillance inquiries that did not lead to investigations.
In a presentation to the commission Thursday, Enforcement staff said the brief summaries of several instances in which the office’s Division of Analytics and Surveillance (DAS) contacted market participants about potential violations were included in the report in response to requests by several regulated entities. They are similar to the examples the Division of Investigations (DOI) has provided on investigations closed without action in past reports. (See Market Manipulation Cases Dominate FERC Enforcement.)
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“OE anticipates that regulated entities can leverage the example surveillance inquiries to achieve a better understanding of when and why DAS makes inquiry calls, the principles and evaluations used by DAS in making a determination to refer an inquiry to DOI and transactional behavioral patterns that were not deemed by DAS to be problematic or potential violations,” Enforcement’s John Miller told the commission.
The report masks the identities of the market participants and the markets in which the incidences occur. In one example, DAS flagged large, loss-making increment offers (INCs) at an RTO hub made by a market participant who held a leveraged financial transmission rights path sourced at the hub.
“The market participant explained that the observed INCs covered a period of a planned outage, and that the virtual position shifted a non-leveraged real-time position to the day-ahead market where the market participant hedged commodity risk,” the report said. “After verifying the relevant information, the inquiry was closed with no referral to DOI.”
DAS’ computerized triggers produced more than 300,000 alerts on RTO and bilateral trades, only 31 of which resulted in inquiries. Of those, four resulted in referrals to DOI.
The report also included examples of and statistics on violations that were self-reported. The Office of Enforcement received 80 self-reports last fiscal year, most of which were made by RTOs/ISOs. Most of these were minor violations resulting from human or software error. The examples were included to “emphasize the importance of self-reporting by providing credit that can significantly mitigate penalties if a self-report was made,” the report said. “Staff continues to encourage the submission of self-reports, and views self-reports as showing a company’s commitment to compliance.”
Of the 27 investigations opened last year, 15 involve potential market manipulation, 16 involve potential tariff violations, four involve potential violations of a FERC order and two involve potential violations of a FERC filing requirement.
Staff closed 16 investigations, 11 without further action because of lack of evidence. One of these was into bidding behavior in ISO-NE’s eighth Forward Capacity Auction in 2014, the results of which stood because of a tie vote of the commission. Commissioners Tony Clark and Norman Bay had voted to throw out the results. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
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The other five were closed through commission-approved settlements that resulted in more than $51 million in civil penalties. The largest of these, $41 million, was paid by GDF SUEZ Energy Marketing for offering generation below cost to capture make-whole payments in PJM. GDF also disgorged $40.8 million in unjust profits to the RTO. (See GDF SUEZ to Pay $82M in PJM Market Manipulation Settlement.)
The settlements also included $2.7 million assessed on K. Stephen Tsingas and $9 million on his company, City Power Marketing, for making risk-free up-to-congestion trades to profit off PJM line-loss rebates. However, the company is defunct, and FERC agreed not to pursue Tsingas for the additional amount. (See Trader Agrees to Pay $2.7M in Win for FERC.)
They did not include the $105 million Barclays Bank recently paid to settle claims it manipulated the Western markets a decade ago, which occurred after the end of FY 2017. FERC had originally sought $470 million. (See FERC Settlement Cuts Barclays Market Manipulation Fine.)
Asked by reporters on Thursday why FERC agreed to such a steep cut, FERC Chairman Neil Chatterjee said he wanted to avoid years of litigation. “My priority was to get the disgorgement money back to those that have been harmed and deter similar conduct in the future,” he said. He noted that the $70 million civil penalty against the bank was the third largest the commission had ever levied. Barclays also disgorged $35 million to states’ low-income home energy assistance programs.
FERC last week accepted six revised power purchase agreements among Entergy subsidiaries following Entergy Arkansas’ withdrawal from the company’s multistate system agreement.
The company sought in May to amend the PPAs, each of which had been previously filed with FERC because they are being transferred under provisions of the company’s tariff and involve the Grand Gulf Nuclear Station in Mississippi. Under the tariff that replaces the longstanding Entergy system agreement, the resale of power purchased from Grand Gulf must earn FERC approval.
Entergy Arkansas withdrew from the agreement in late 2013 when it joined MISO; the rest of the company’s Gulf Coast operating companies followed suit and set staggered dates to abandon the agreement, prompting Entergy to create a company-wide tariff that governs PPAs among its affiliates. (See FERC OKs 2018 Entergy System Agreement Exit.) The system agreement had been the basis for planning and operating the Entergy utilities’ generation and transmission facilities as a single system since 1982.
Grand Gulf station | Entergy
In accepting the amended PPAs, the commission determined that the language is similar to Entergy’s previously approved agreements and in compliance with Nuclear Regulatory Commission requirements (ER17-1160, et al.). In addition to Entergy Arkansas, the PPAs include Entergy Louisiana, Entergy New Orleans and Entergy Mississippi.
The commission also directed the company to submit a compliance filing specifying the date on which the amended PPAs began to fall under the new tariff rather than the system agreement. FERC noted that Entergy may have meant to fill in Dec. 19, 2013, the date of Entergy Arkansas’ withdrawal from the agreement.
The commission’s order makes the PPAs’ acceptance official. FERC staff had provisionally accepted the company’s filing in June when the commission still lacked quorum.
FERC Orders Compound Interest Refund in Entergy Bandwidth Issue
Entergy’s fading system agreement was at the center of another FERC ruling last week when the commission rejected a compliance filing the company made to provide refunds on the bandwidth payments it received from its operating companies (ER10-1350-006). Entergy submitted the filing a year ago to comply with a commission order to calculate interest on refunds related to the payments. (See FERC: Further Compliance Filings for Entergy, MISO.)
FERC determined the company miscalculated the interest on the refund due back to its Louisiana affiliate. In February 2016, Entergy refunded Entergy Louisiana $27 million in payments, paying the principal but not the interest, and recording the amount in its refund compliance filing. The parent company last November additionally refunded compounded interest, but only up until the Feb. 16 principal payment date. The Louisiana Public Service Commission noticed that the company did not pay interest on the initial missing interest payment and protested the filing, asking that interest-on-interest payments of $25,761 be made for most of 2016.
Entergy argued that interest should have only been calculated from the date of collection until the date refunds are made.
FERC last week ordered another compliance filing, ruling that the company must “calculate interest compounding on the interest component of the payments at issue until the date the interest payment is actually made.”
Entergy’s allocation of production costs among its half-dozen operating companies under its system agreement has been a source of disagreement for a decade. Payments are made annually by the company’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” solution that ensures no operating company has production costs more than 11% above or below the system average.
An appellate court ruling remanding back to FERC its 2013 order on PJM’s minimum offer price rule (MOPR) has created disagreement among stakeholders about how to move forward.
PJM requested in October that FERC approve its initial 2012 filing on the issue (ER13-535). The RTO had submitted a “hard-fought compromise package” that included two new categorical exemptions to the rule and eliminated a unit-specific one. FERC rejected the initial proposal but said it would approve it if PJM retained the unit-specific exemption and reduced a proposed three-year imposition of the MOPR on affected units to the existing one-year mitigation.
FERC approved PJM’s amended filing, but several stakeholders challenged the action and the D.C. Circuit Court of Appeals ruled in July that FERC overstepped its legal authority in telling the RTO what it would accept. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
PJM asked FERC to, on remand, “simply accept PJM’s original Section 205 proposal, unchanged, as just and reasonable.”
The commission’s requirements on the unit-specific exemption and mitigation period “have had no practical impact … on the auction results in the five annual auctions conducted since the commission’s initial order in this case,” PJM said in its Oct. 23 request.
FERC’s concern was “to catch possible future competitive offers that might fall through the cracks theoretically left by the two categorical exemptions,” PJM said, but five Base Residual Auctions and nine Incremental Auctions have occurred since then with no unit-specific offers submitted.
“We now know that those cracks, if they exist at all, are quite narrow,” PJM said. The commission can conclude that its “concern” about competitive offers slipping through “was overstated.”
Stakeholders were split on their opinions of PJM’s request. The Independent Market Monitor, NRG Energy and Public Service Enterprise Group argued that FERC had already rejected the RTO’s 2012 filing. Several generators said the filing should be approved but with a requirement that PJM address deficiencies in its MOPR within 90 days.
PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | PSEG
American Municipal Power and Old Dominion Electric Cooperative supported PJM’s plan, with ODEC arguing that the new self-supply and competitive-entry exemptions “must be maintained.”
“Otherwise, [load-serving entities] like ODEC face the unreasonable prospect of their loads paying twice for capacity, once through the investment in resources (owned or purchased bilaterally outside of the [Reliability Pricing Model] construct), and then a second time when those resources do not clear in the RPM auctions because they are unreasonably subject to the MOPR,” ODEC said.
FERC “upset the balance that had been struck by conditioning acceptance” on retaining the unit-specific exemption, it said.
“The commission’s authority to issue an order in the form PJM recommends is not in question,” AMP said. “That PJM’s stakeholders overwhelmingly supported the competitive-entry exemption and the self-supply exemption should weigh heavily in the commission’s consideration of how to proceed on remand.”
The PJM Power Providers Group (P3) said it supported the RTO’s request “in the interest of market certainty” and noted that other dockets exist or likely will come before FERC on the topic “to address broader issues.”
Several P3 members, including Calpine, Congentrix Energy Power Management, Dynegy and Eastern Generation, agreed with the group’s comments but voiced concern about “deficiencies with [PJM’s] MOPR process” and argued that FERC should give the RTO 90 days to address them.
“Recognizing that threats may exist to the efficient operation of PJM’s wholesale markets is an understatement, to say the least,” the generators said, noting the zero-emission credits for nuclear generation in Illinois and proposals for similar subsidies in Ohio, Pennsylvania and New Jersey.
“PJM must have in place an effective MOPR, applicable to both new and existing resources, to combat the very real threat of these state actions. It is incumbent on the commission to take decisive action on the issue of state-subsidized existing units by extending the MOPR to those units. Continued failure to do so is an abdication of the commission’s duties and responsibilities.”
PJM had acknowledged in its filing that its finding about unit-specific exemptions “does not rule out the possibility of future low-price competitive offers that do not qualify for the categorical exemptions” and that “that the nature of the potential threats to the efficient operation of its wholesale markets may have evolved since 2012, and accordingly, prospective changes to its MOPR, or its Tariff more generally, may be warranted — but not in this proceeding. PJM has an ongoing stakeholder senior task force considering such issues.”
The Monitor argued that FERC was correct to deny PJM’s original filing and that the court’s order didn’t vacate that decision.
“The commission’s determination that the MOPR was not just and reasonable without an exception for unit-specific cost review was logical,” the Monitor said. “The motion should be denied for the same reasons that the commission denied it initially.”
NRG and PSEG agreed that the court decision required PJM to return to its original MOPR rule, but split on what other mitigations are necessary. NRG said PJM should just move on with the original rule without retroactively examining the auctions since it was replaced. PSEG suggested a method to recreate the auctions and compensate affected participants.
PJM had argued that because all resources that sought a MOPR exemption pursued categorical exemptions rather than unit-specific ones, the auctions had not been impacted.
“NRG sees something very different: clear evidence that PJM’s proposed MOPR is toothless and does nothing to prevent uneconomic entry,” NRG said in its filing. “New entrants are making an already over-supplied market even more over-supplied — and are being totally exempted from any review to ensure that their low bids are economically justified. … In order to have a meaningful MOPR that protects the market from artificially low prices, there simply cannot be categorical exemptions so broad that any new generator could drive a truck through them.”
PSEG argued the issue is whether the categorical exemptions impacted auction prices differently than how the pre-existing unit-specific one alone would have. PJM should recreate the auctions using commission-approved proxy values for units “inappropriately granted one of the two categorical exemptions to establish the ‘but for’ auction price,” PSEG said.
Any “underpayments” that result would be payable to affected generators by zone; “however, the new entrants that relied upon the no-longer-available MOPR exemptions for a particular auction year would not be eligible for any additional amounts.”
FERC denied Baltimore Gas and Electric’s bid to recover $38 million in taxes deferred over decades, saying that “contrary to BGE’s assertion, we find that utilities do not have unfettered discretion to defer these tax amounts on their books for decades without timely seeking regulatory approval to collect them.”
BGE sought approval for three adjustments to its formula rate for how taxes are recovered (ER17-528). The revisions would have returned $4 million to customers related to tax rate changes but also collected approximately $42 million. The collections broke down to $29 million related to deferred tax liability for the equity component of allowance for funds used during construction (AFUDC) and approximately $13 million for an accounting adjustment to claw back tax benefits that were flowed through to customers at the time they originated, rather than relying on BGE’s current tax normalization methodology that collects tax liabilities and distributes benefits over time.
FERC said BGE took too long to make the adjustments.
“Although these accumulated amounts may represent legitimate deficiencies in accumulated deferred income taxes, we find that these deficiencies should have been captured in BGE’s formula rate since its implementation in 2005,” the commission said.
FERC cited 1981’s Order 144, which stipulated that all utilities use the normalization methodology. It additionally required them to begin the process of accounting for any tax excesses or deficiencies through rate adjustments. The order called for companies to make the adjustments in their next rate case following the order’s implementation or at least “within a reasonable period of time.”
“Had BGE properly addressed the tax deficiencies when its formula rate was initially filed in 2005, BGE may have been allowed to collect some portion of these deficiencies over the remaining life of the underlying plant assets that created the deficiencies,” the commission said.
BGE’s failure to “match” tax effects with the revenues that created them in a timely manner was “particularly noticeable” regarding the flow-through items because they are related to assets from prior to 1976, “most of which have been either fully depreciated or retired by 2016.”
“It is unclear if there are any relevant assets left on BGE’s books in 2017 to match the amortization period over the next 28 years,” FERC said.
RENSSELAER, N.Y. — NYISO year-to-date monthly energy prices averaged $34.89/MWh in October, a 4% increase from a year earlier, Senior Vice President for Market Structures Rana Mukerji told the ISO’s Business Issues Committee (BIC) on Wednesday.
Locational-based marginal prices (LBMPs) averaged $28.35/MWh for the month, down 4.1% from September and up 27% from October 2016. The ISO’s average daily sendout was 398 GWh/day, compared with 437 GWh/day in September and 391 GWh/day a year earlier.
New York natural gas prices rose nearly 4% in October, averaging $2.36/MMBtu at the Transco Z6 hub. Prices were double those of a year ago, although still “historically low,” Mukerji said.
Distillate prices rose 14.9% year on year, with Jet Kerosene Gulf Coast averaging $12.30/MMBtu, down from $13.40 in September. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $12.86/MMBtu, compared with $12.80 in September.
The ISO’s local reliability share was 14 cents/MWh, down 2 cents/MWh from the previous month, while the statewide share remained unchanged at -50 cents/MWh. Total uplift costs were lower than in September.
External Capacity and Imports
Reviewing the Broader Regional Markets report, Mukerji highlighted NYISO’s effort to clarify the minimum deliverability requirements for PJM resources seeking to export into the ISO’s installed capacity (ICAP) market. He noted that during an October ICAP Working Group meeting, the ISO provided an overview of the current approach to assessing the deliverability of external resources into the New York Control Area for purposes of qualifying eligible capacity within the market.
NYISO is also modifying the documentation requirements for capacity imports across the PJM AC ties, with a planned effective date of May 1, 2018. The process change will require submission of documentation on the day the ICAP Spot Market Auction results are posted to demonstrate that external resources with capacity awards relating to imports across the PJM AC ties have firm transmission service for the month.
The ISO also is considering whether an Atlantic Economics proposal, or an alternate formula-based model, may be viable for calculating locality exchange factors (LEFs). NYISO has engaged General Electric to investigate the viability of potential refinements to the current methodology for determining LEFs.
NRG’s Kelli Joseph Elected Vice Chair
The BIC last week elected Kelli Joseph, NRG Energy’s director of market and regulatory affairs, to serve as vice chair of the committee for the 2017/18 term.
Joseph advocates on behalf of NRG at NYISO and the New York Public Service Commission and worked at NYISO as a grid operations senior analyst prior to joining NRG in 2014. She attended Houghton College and earned a Ph.D. in political economy at the University of Virginia and an international MBA at the IE Business School in Spain.
BIC Approves Developing New LCR Methodology
The committee also voted for NYISO to continue developing a new methodology to determine locational capacity requirements (LCR), subject to updating the net cost of new entry curve to be used in the ISO’s baseline assumptions.
Zachary Stines, associate market design specialist for the ISO, told the BIC that the new optimization methodology results in increased stability as generation changes occur within the system. He said the ISO sought to develop capacity requirements that maintain reliability while minimizing the total cost of capacity at the level of excess condition, i.e., the applicable minimum installed capacity requirement, plus the capacity of the relevant peaking plant.
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David Clarke of the Long Island Power Authority opposed the proposed methodology, saying it is based on an unrealistically low estimate of net CONE on Long Island.
Mark Younger of Hudson Energy Economics wanted the ISO to commit to refreshing the database with the current net CONE values so that the optimization uses the same CONE as that used in the energy market. Stines said the ISO would do so early in 2018.
Questions on Integrating Public Policy Task Force
NYISO Senior Manager for Market Design Michael DeSocio’s progress report from the Integrating Public Policy Task Force (IPPTF) elicited a half-hour of stakeholder dissension over the ISO’s definitions of “harmonizing” versus “accommodating” public policy.
NYISO and the New York PSC jointly formed the task force in October to create a forum for stakeholders to discuss pricing carbon into the wholesale electricity market along the lines described in a previous Brattle Report. (See New York Stakeholders Question Carbon Pricing Process.)
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Representing New York City, attorney Kevin Lang of Couch White, expressed concerned about the lack of transmission planning in the task force process, given the amount of offshore wind being sought by the state. Younger agreed, saying that new transmission will be required for the grid to absorb increased amounts of new renewable energy and that nobody should assume the issue has been settled.
“Even if you price carbon, it’s unlikely to be high enough to incent renewables development,” said NRG’s Joseph. “We need to be talking about design changes; that’s why we proposed a two-tier market. Not instead of carbon pricing, but while we are at it, look at capacity markets.”
In response to a question about whether the task force had a coherent mission, DeSocio said it is focused on fulfilling the goals of New York’s Clean Energy Standard.
The IPPTF’s next public hearing is scheduled for Nov. 20 in Albany.
Pacific Gas and Electric has signaled it will challenge a California administrative law judge’s recommendation that the utility be granted only about 10% of the $1.8 billion in recovery it requested for the retirement of the Diablo Canyon nuclear plant in San Luis Obispo County.
The California Public Utilities Commission has scheduled final oral arguments for Nov. 28 over a joint settlement agreement filed by PG&E and interest groups regarding the plant, which the utility has proposed to shut down when its federal operating licenses expire in 2024 and 2025. PUC Administrative Law Judge Peter Allen on Nov. 8 approved the retirement plan but proposed that PG&E be allowed to recover about $190 million of the nearly $1.8 billion in requested rate recovery detailed in the settlement. Allen’s decision has no weight until voted upon by the five-member commission.
“While the proposed decision preserves several elements of the joint proposal, it differs in regards to certain key areas, including the employee, community and energy replacement programs,” PG&E said in a Nov. 8 statement, adding that it “strongly disagrees with these proposed adjustments.”
The utility said it thinks the proposed settlement is appropriate, and “we look forward to advocating for this in our comments back to the CPUC and during final arguments at the end of November.”
PG&E first filed the settlement it forged with environmental, labor and anti-nuclear groups in August 2016. It would replace output from the 2,240-MW facility with a portfolio of renewable resources, energy efficiency measures and energy storage. (See PG&E Files Diablo Canyon Shutdown Request.)
The utility requested approval to recover $1.3 billion for energy efficiency procurement, $363 million for employee retention and retraining, $85 million to mitigate impacts on the local community, $19 million for license renewal activities, and unspecified canceled capital project costs.
Allen’s proposed decision rejected the energy efficiency money and approved $172 million for employee retention and retraining, $19 million for license activities, and a portion of canceled project costs. He recommended that issues related to the procurement of replacement capacity be handled in an integrated resource planning proceeding.
The judge sided with the Office of Ratepayer Advocate (ORA) and Energy Producers and Users Coalition (EPUC), which noted that state policy already requires PG&E to first meet its resource needs through all available energy efficiency resources. PG&E has proposed to increase its approved energy efficiency goals by more than 53% for 2018-2024, which ORA and EPUC indicated would only be possible by lowering PUC’s cost-effectiveness threshold.
“ORA and EPUC make a good point — it is not clear that PG&E could actually procure over 50% more energy efficiency than a goal that is already supposed to include all cost-effective energy efficiency (unless PG&E procures energy efficiency that is not cost effective),” Allen said. “There is no reason to approve a $1.3 billion rate increase for a proposal that will most likely either fail to achieve its goal or will achieve a goal not worth reaching.”
Allen’s Nov. 8 proposed decision also took issue with a settlement provision that would replace the property tax paid to San Luis Obispo County with $85 million in ratepayer money, arguing that PG&E has no obligation to pay the taxes once the facility shuts down and that utility rates should be used for utility — and not government — services.
PG&E proposed shutting down both units at Diablo Canyon by 2025.
PG&E has proposed to replace Diablo Canyon with greenhouse gas-free resources in three tranches: 2,000 GWh of energy efficiency; 2,000 GWh of energy efficiency and renewables; and a voluntary 55% renewables commitment from PG&E. The utility said additional resource procurement could be required to replace Diablo Canyon, the two units of which began operating in 1985 and 1986. The plant is used as a system resource and not for local reliability, and its output is exported on the bulk transmission system.
The settlement is supported by the Natural Resources Defense Council, Friends of the Earth, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees and the Alliance for Nuclear Responsibility.
Protests against the settlement were filed by California Large Energy Consumers, Californians for Green Nuclear Power, EPUC, several cities, the Sierra Club, Shell Energy North America, SolarCity, public interest groups and others.
After a 25-day public comment period, the ALJ’s proposed decision will be forwarded to the PUC. PG&E has requested that the commission reach a decision on the settlement by the end of the year.
