A U.S. appeals court last week ruled Energy Future Holdings must pay hundreds of millions of dollars to certain bondholders, adding a cloud of uncertainty to the bankrupt company’s attempts to emerge from Chapter 11 protection.
Lamar Plant | Luminant
On Thursday, the 3rd Circuit Court of Appeals in Philadelphia reversed lower court decisions and directed EFH to pay holders of the company’s first-lien and second-lien notes. The bondholders had argued that by repaying its debt early in the bankruptcy proceeding, EFH owed them prepayment premiums — or make-whole payments — of $431 million and $351 million, respectively. The payments don’t include several years of interest.
The decision affects $6.2 billion in debts that were refinanced after EFH declared bankruptcy in 2014. The company has said that disallowing the make-whole claims is a condition of its reorganization and that the added litigation would reduce the funds available to other creditors.
The U.S. Bankruptcy Court in Delaware, which has jurisdiction over the case, is to begin hearings to consider confirming the Texas company’s reorganization Dec. 1.
EFH’s reorganization plan hinges partly on the sale of its Oncor wires business to Florida-based NextEra Energy for $18.4 billion. NextEra and Oncor filed for approval of the sale with the Public Utility Commission of Texas on Oct. 31. (See NextEra Energy Talks Up its Oncor Acquisition.)
It’s unclear whether the additional debt would affect NextEra’s acquisition of Oncor, which relies on eliminating debt and replacing it with equity.
EFH has already spun off its Luminant and TXU Energy businesses into a standalone company, since rebranded as Vistra Energy. (See Luminant, TXU Energy Emerge from Bankruptcy.)
Vistra Energy and NextEra both declined requests for comment by RTO Insider on the court’s ruling and its potential effect on the Oncor acquisition.
Meanwhile, NextEra and Oncor are plunging ahead with their merger application in Texas.
Friday, the state’s Public Utility Commission filed an order finding their application to be sufficient (Docket 46238) and an administrative law judge affirmed hearings before the PUC will begin Feb. 21.
The ALJ also granted all motions to intervene in the case. Those intervening include the Texas Office of Public Utility Counsel, NRG Texas, TXU Energy, Local 69 of the International Brotherhood of Electrical Workers, Texas Industrial Energy Consumers and a group of cities currently served by Oncor.
PUC staff has requested Oncor address a set of questions focused on the utility’s rating agency reports, its five-year capital plan and the tax status of the EFH spin-off.
FERC last week rejected Entergy Texas’ attempt to terminate a power purchase agreement with qualifying facilities at Goodyear Tire & Rubber’s Beaumont chemical plant (EL16-105).
Goodyear filed a complaint with the commission in August, alleging that Entergy Texas’ plan to terminate its PPA with the tire company’s QFs in Southeast Texas violated the utility’s obligation to purchase energy and capacity in accordance with the Public Utility Regulatory Policies Act of 1978.
Goodyear’s Beaumont Chemical Plant | Goodyear
Entergy contended it had the right to cancel the PPA based on FERC’s January order that terminated the utility’s obligation to purchase from QFs larger than 20 MW in MISO. (See FERC: Entergy not Required to Buy from Large QFs.)
Goodyear’s Beaumont/West QF was self-certified in 1987 with a net capacity of 13 MW. Its Beaumont/East QF was self-certified in 1999 with a net capacity of 18.8 MW.
Entergy argued that the two QFs should be considered as one. It noted that the QFs are located less than a half-mile apart on the same site and that their energy “is commingled behind the meter.”
Goodyear contended that because it had self-certified two cogeneration plants each smaller than 20 MW, the January order did not affect Entergy’s obligation.
The commission agreed. It said its January order concluded that “a QF’s size for purposes of being relieved of the mandatory purchase obligation is determined by its certified size.”
The commission’s January order was based on a 2006 ruling, which said that QFs with net capacity above 20 MW were presumed to have “nondiscriminatory access” to wholesale markets in RTOs such as MISO.
CARMEL, Ind. — MISO and PJM are close to implementing a targeted market efficiency project (TMEP) type and poised to approve six such projects with cross-regional benefits.
During the Nov. 15 MISO and PJM Joint and Common Market meeting, Jesse Moser, MISO manager of infrastructure studies, said the RTOs must make a FERC filing to change their joint operating agreement in addition to individual filings on how they plan to handle cost allocation.
Moser said the RTOs prefer making the necessary three filings simultaneously, but they would file standalone JOA changes before the end of the year if certain regional cost allocation details are not finalized in time.
“We’re happy to see this move forward,” Moser said.
The two RTO’s staff say the final six projects are expected to cost about $17.25 million and deliver $111.6 million in reduced congestion on market-to-market flowgates, an average 6.5:1 benefit-to-cost ratio.
The RTOs examined 50 market-to-market flowgates and produced the final six from a pool of 13 potential upgrades. The final six exclude the previously recommended Klondike-Purdue 138-kV project in north-central Indiana, which did not advance because of the discovery that the congestion the project was designed to relieve was outage-driven. (See 7 Sites Eyed for MISO-PJM Targeted Market Efficiency Projects.) “These are meant to be lower cost projects … that have near-term economic benefits,” Moser explained.
At a Nov. 17 conference call of MISO’s Regional Expansion Criteria and Benefits Working Group, transmission engineer Adam Solomon said the RTO will pursue a bifurcated cost allocation for the TMEPs. MISO proposes to assign cost to a local transmission pricing zone when the constraint is on the transmission of one or more transmission owners. For constraints wholly within PJM, MISO is seeking a postage stamp allocation for all of the MISO North region.
Solomon said MISO decided on a postage stamp for projects within PJM because all local transmission pricing zones would gain from lowered congestion.
PJM officials did not discuss their cost allocation plans at the meeting. Spokeswoman Paula DuPont said the regional cost allocation is being developed by PJM’s Transmission Owners Agreement-Administrative Committee.
The two-option proposal would apply to both RTO’s current batch of TMEPs. “We’re certainly open to looking at it in the future if we can get a better cost allocation,” Solomon said.
Shelly-Ann Maye, representing Midwest Power Transmission Arkansas, said she didn’t understand why a postage stamp allocation could be justified when local beneficiaries in MISO could be identified.
“These projects are avoiding future congestion in MISO, and that congestion gets pretty well spread out in the footprint,” Solomon explained.
Of the six TMEPs currently being considered, the Marysville-Tangy 345-kV project in central Ohio is the only project that would qualify for the postage stamp allocation, as it is located wholly within PJM, Solomon said.
| MISO
Solomon also said the cost allocation rules will only apply to the PJM-MISO seam. MISO staff said they plan to collect more SPP day-ahead market-to-market information and expect to begin discussions with SPP on a similar project type.
“Having this cost allocation spelled out in the JOA and Tariff, I think, will help these projects go through and we can get the benefit of those projects we’re forecasting,” Solomon said.
Wisconsin Public Service’s Chris Plante said his utility was hoping for 50% local pricing zone allocation and 50% postage stamp allocation for all TMEPs.
“We think this is the best proposal that we have at this point with stakeholder feedback considered,” Solomon said.
Retirement Coordination
Neil Shah, MISO adviser of seams administration, also said that both RTOs are planning to file a generator retirement coordination process with FERC by Dec. 15. Shah said the final language was largely unchanged from what was proposed last month. (See MISO Outlines Retirement Coordination with PJM.)
LA QUINTA, Calif. — While the loss of the San Onofre nuclear plant complicated California’s response to the closure of the Aliso Canyon natural gas storage facility last year, planners did benefit from actions taken in the wake of the plant’s 2013 shuttering, according to California Public Utilities Commissioner Catherine Sandoval.
“All of that work helped us to better withstand Aliso Canyon when the number one source of natural gas was no longer available,” Sandoval told an audience at the National Association of Regulatory Utility Commissioners’ 128th Annual Meeting.
In response to the shutdown of San Onofre — the largest generator in the state’s most populous area — officials ordered transmission upgrades, installation of synchronous condensers to facilitate the flow of electricity into the Los Angeles area and “a variety of things to help keep the system up and running electrically,” Sandoval said.
The loss of Aliso Canyon prompted the CPUC to authorize additional measures to shore up the region’s grid, including accelerated deployment of energy storage and expedited interconnection procedures. The state also stepped up implementation of demand response to shave summer electricity — and, by extension, natural gas — demand.
“This isn’t your father’s demand response; this is auto-DR,” Sandoval said. Among the most successful auto-DR programs: air-conditioner cycling, which allowed utility customers to select from a range of potential curtailments of their cooling units during periods of high electricity demand.
Aliso Canyon | California Governor’s Office of Emergency Services
The program yielded 300 MW in DR, Sandoval said. “That’s a peaker plant. So we were able to get a negawatt peaker through auto-DR,” Sandoval said.
Southern California weathered the summer without incident on either the gas or electricity system. Now planners are turning their attention to winter, when heating requirements create a second peak for gas demand not driven by electricity generation. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)
While Aliso Canyon owner Southern California Gas has been testing the storage facility for leaks, the CPUC still hasn’t authorized reopening. No set timetable has been established for bringing the facility back online.
“We really have to come up with new messages [for consumers] that are actually well-tailored to the winter side,” Sandoval said. “We have to think about what sorts of programs can we adopt to really ensure that there’s gas sufficiency so that we don’t run into problems, especially if we’re not able to bring Aliso back online.”
NYISO and PJM are finding that coordinating transmission across their border is not simple.
After an effort to make it easier for traders to schedule imports from New York failed at the Nov. 2 Market Implementation Committee meeting, stakeholders will resume efforts at a special MIC meeting Dec. 21.
Vitol’s Joe Wadsworth, who has championed efforts to streamline the process for several years, won stakeholder approval in April for a problem statement seeking ways to improve the method of reserving PJM spot-in (non-firm) transmission for energy imports scheduled day-ahead from NYISO. Spot-in service is free but limited and allocated on a first-come, first-served basis.
Additionally, the deadlines for requesting the service from PJM and learning the results of NYISO’s day-ahead energy auction are staggered such that participants looking to import power must reserve spot-in capacity from PJM before knowing how much they’ll need. PJM requests must be made at 9 a.m. to have any hope of success, yet the results of NYISO’s day-ahead market usually aren’t available until after 9:30 a.m.
| Josef Kubes / 123RF Stock Photo
This creates the risk that “there may not be enough spot-in service available for participants who received a cleared day-ahead schedule to import power into PJM,” the problem statement reads, which leaves them “scrambling” to find service. Failure to obtain transmission results in the import being curtailed, which “can create imbalances that must be settled against real-time prices.”
Armed with the problem statement, Wadsworth, PJM and NYISO began discussing potential solutions. NYISO, concerned about those potential imbalances creating costs for its members, proposed a market-based solution that would allocate the costs to PJM’s members.
Wadsworth also favored a market-based solution, but PJM decided, after researching potential solutions, that it would be a much more difficult implementation than the RTO preferred. As a compromise, Wadsworth and PJM developed a proposal that they thought addressed the problem without being overly complex: delay the earliest request for spot-in service from 9 a.m. to 10 a.m. so participants will know how much they need before they request it.
Wadsworth and PJM’s Chris Pacella presented the idea at the Nov. 2 MIC meeting.
“Maybe this is the simple change that eliminates all those risks,” Wadsworth said. (See “NYISO to be Consulted on Changing Spot-in Service Allocation Methods,” PJM Market Implementation Committee Briefs.)
Problem solved!
Software Changes
Except there was one catch: Pacella explained that PJM can make a deadline change for all imports, but that limiting the change to just NYISO would require time-consuming software changes.
PJM Independent Market Monitor Joe Bowring took issue with making a global change, saying it’s not consistent with the problem statement. When the issue first came up, he said, he attempted to argue that it should apply to all RTO interfaces, not just NYISO, but was “told explicitly” that was out of the problem statement’s scope. He said the correct procedural step would be to amend the problem statement to include all RTO seams.
Dan Griffiths, of the Consumer Advocates of the PJM States, agreed. “I’m kind of indifferent to the outcome, but I’d like to see this addressed properly,” he said.
PJM’s Mike Bryson cautioned against the global approach, saying it would create operational problems. “The all-borders issue causes me great concern,” he said.
Wadsworth agreed, saying he preferred to limit the scope of the deadline change to just the NYISO seam. “I think we need to think through all the consequences,” he said.
Other stakeholders, however, wanted to get to the bottom of NYISO’s concerns. “I’d like a better explanation of the mechanics of what it is that NYISO thinks is increasing the costs,” said Roy Shanker of H.Q. Energy Services. “This summary just doesn’t make sense to me. … You may or may not want to pick a fight, but I feel like everybody on both sides should know what’s going on.”
“In these preliminary stages, we’re beholden to New York’s stance,” Pacella said. He later acknowledged, however, that there is precedent for a market-based solution with the cross-seam transmission agreement in place between NYISO and ISO-NE.
An MIC vote on amending the problem statement, which was motioned by Bob O’Connell of PPGI Fund A/B Development and seconded by Jung Suh of Noble Americas, was tabled until the committee’s next meeting on Dec. 14. However, it likely won’t receive much discussion there because of the MIC special session on Dec. 21. It is scheduled from 1 to 3 p.m. at PJM’s Conference & Training Center in Valley Forge.
FERC last week granted Rochester, Minn., a waiver of its Standards of Conduct, finding that the city qualifies as a small public utility.
The commission’s Nov. 17 ruling said the waiver will remain in effect “unless and until the commission takes action on a complaint by an entity that Rochester has unfairly used its access to information to unfairly benefit itself or its affiliates” (TS15-3).
Zumbro Hydro Dam | Rochester Public Utilities
The southeastern Minnesota city sought the waiver in September 2015, claiming it met the definition of a non-jurisdictional utility. Jurisdictional transmission providers are subject to the Standards of Conduct, which require transmission function and marketing function employees to operate independently of each other and prohibit sharing nonpublic transmission information with marketing employees.
Without a waiver, Rochester said it would indirectly be subjected to the standards based on the commission’s reciprocity rules, which ensure nonpublic utilities’ access to transmission service from public utilities. The city pointed out it transferred operational control of its transmission to MISO in late 2014; the waiver requires that utilities own, operate or control “only limited and discrete transmission facilities.”
Rochester’s municipal utility serves about 50,000 customers, mostly with power purchased from the Southern Minnesota Municipal Power Agency. It owns and operates about 86 MW of generation, 42 miles of transmission and 793 miles of distribution. Early this year, Rochester officials announced that the public utility would begin building a new 47-MW natural gas plant in 2017. The utility has proposed a 3.7% rate increase in 2017.
Baltimore Gas and Electric will pay $170,530 to MISO members to end a dispute over cross-system congestion costs under a settlement approved by FERC last week.
FERC’s Nov. 17 order settles a dispute between BGE and almost 30 MISO utilities relating to the cross-system congestion costs known as Seams Elimination Charge/Cost Adjustments/Assignments (SECA). FERC said the uncontested agreement represents “a final settlement of all SECA obligations.”
| Baltimore Gas & Electric
The settlement directs BGE to pay members of the RTO $344,665 and for the RTO to collect $174,135 from its members for BGE, for a net payment by BGE of $170,530. The approval closes out dockets ER05-6-124, EL04-135-126, EL02-111-145 and EL03-212-140.
The SECA cases originated from a 2002 FERC decision allowing American Electric Power, Commonwealth Edison and Dayton Power and Light to move from MISO to PJM. The move created areas in the RTO that were cut off from the rest of the footprint and led to rate pancaking and the eventual elimination of regional through-and-out rates.
FERC approved the 16-month SECA transitional payment mechanism for 2004-2006 and upheld SECA use in 2010, but it said SECA rates recovered from MISO and PJM transmission customers were subject to refund by MISO and PJM transmission owners. The 2010 decision imposed additional SECA liabilities on BGE. MISO laid out SECA amounts in 2013, charging BGE and about 15 other PJM load-serving entities a combined $4 million in SECA charges.
LITTLE ROCK, Ark. — SPP gathered a half-dozen vendors to show off some of the latest transmission technologies before an audience of stakeholders and staff last week. A first for SPP, the Technology Expo was following a trend set by other RTOs.
“Doing these things is necessary because technology is evolving,” said Todd Ryan, director of regulatory affairs for Smart Wires. “It’s good for us because it helps us understand where our product fits in.”
Ryan was on hand to push his company’s PowerLine Guardian, a modular transmission power-flow control that the company says “will change how power grids are designed and operated.” Combined with the company’s Power Router, the Guardian addresses congestion through local control or central dispatch through devices hung on conductors and towers or deployed in substations.
“You ever hear of the Whac-a-Mole problem?” Ryan asked. “When you solve a problem in one place, it just to moves to another. Every grid has this problem, but [with Smart Wires], you have a tool to more finely tune your investment to your needs and whack more moles.”
Other speakers shared the latest on advanced conductors, topology optimization, dynamic line rating, energy storage and HVDC transmission lines. Almost three dozen members of SPP’s staff and stakeholders attended the expo, with others listening on the phone.
“All technologies are about two things: bringing new capacity to the market and integrating renewables,” said Joe Coffey of General Cable. He motioned to the screen behind him, where a slide showed higher-capacity conductors. “Hey look, a new technology!”
Jay Caspary, SPP’s director of research, development and Tariff studies, said the expo was designed to educate staff and stakeholders “of opportunities that exist today to improve grid operations and planning.”
“We look forward to continued dialogue with interested stakeholders, and we will work with members on efforts which could lead to pilot programs in the near future,” Caspary said.
FERC said last week it is considering changing the way it establishes license terms at nonfederal hydropower projects.
| FERC
The Federal Power Act allows the commission to issue original licenses for up to 50 years and renewals for between 30 and 50 years.
The commission’s current policy on renewals is to set a 30-year term when there is little or no new construction, or environmental mitigation required; a 40-year term for projects with a “moderate” amount of such activities; and a 50-year term for projects requiring “an extensive” amount of such activity.
“The purpose of this policy is to ease the economic impact of new costs and promote balanced and comprehensive development,” FERC staffer Carolyn Clarkin said in a presentation at Thursday’s open meeting. “Determining whether the measures required under a license are minimal, moderate or extensive is highly case-sensitive and largely based on a qualitative analysis of the record before the commission.”
The commission’s policy is a forward-looking approach, “such that measures adopted under a previous license term are not considered,” Clarkin added.
In a draft Notice of Inquiry (RM17-4), FERC sought comment on five potential options:
Retaining the existing license-term policy
Considering measures implemented during a prior license term
Establishing a 50-year default license term
Including a “more quantitative cost-based analysis”; and
Establishing the license term based on negotiated settlement agreements when appropriate.
The open meeting also featured a staff presentation on the commission’s dam safety program and a description of the recently opened Meldahl Project, four sets of hydropower turbines at locks and dams on the Ohio River. A joint venture between American Municipal Power and the City of Hamilton, Ohio, the 300 MW project was the first major hydropower project constructed in several decades in the U.S.
Meldahl Projet | AMP Public Power Partners
FERC regulates more than 2,500 dams with 55,800 MW of capacity, more than half of all hydroelectric capacity in the U.S. Almost 1,000 of the dams are classified as posing high or significant hazards and subject to annual inspections. The remaining, low-hazard, dams are inspected every three years.
LA QUINTA, Calif. — State commissions have a significant part to play in shaping RTO rules, but they must actively seek a place at the table when key decisions are being made, regulators and RTO representatives said during a panel discussion at the National Association of Regulatory Utility Commissioners annual conference last week.
Another takeaway: States will exercise more influence in the process when they cooperate with each other and strive to speak with a common voice.
Vermont Public Service Board Member Sarah Hoffman, the panel moderator, kicked off the discussion with a close-to-home example of the often-complicated relationship between states and RTOs.
Hoffman cited the challenges facing New England’s Integrating Markets and Public Policy (IMAPP) stakeholder process, which seeks to identify changes needed to align the region’s wholesale market with individual state energy policies, particularly those related to renewable energy. The goal of the process is to translate state policies into market rules that ISO-NE can adopt.
“It is a process that is ongoing and that has really put the states into the center of the discussion about how we are going to integrate these public policies” into the market, Hoffman said.
But it hasn’t been seamless.
“Generators and suppliers want to tear their hair out because the six states don’t all want the same thing,” Hoffman said. “Where Massachusetts wants 1,600 MW of offshore wind, Vermont has different requirements. Market participants would prefer that all the states share the same requirements.
“Based on the fact that we all have legislators, that’s never going to happen,” she added.
State Discord in PJM
“If all of the PJM states can be on the same page, that is very effective advocacy,” said Asim Haque, chairman of the Public Utilities Commission of Ohio.
That kind of unity is desirable whether the states are dealing with a “ground-up” state-initiated policy or a “top-down” PJM initiative, he said.
“The intrigue lies in when states do not agree,” Haque said.
Haque noted that the Organization of PJM States Inc. requires a 51% vote to take a policy position.
“If you’re not able to get that 51% and the states start going it alone on an issue, I think it creates a little friction between the states,” Haque said.
Indiana Utility Regulatory Commissioner Angela Weber emphasized the need for regulators to be engaged with their RTOs.
“There are a lot of commissioners who just aren’t engaged, and I think the idea is that [state commissions] don’t have jurisdiction over the RTO, so it doesn’t matter,” she said.
Weber said her work on the Organization for MISO States can seem like a distraction from state-related work, but she considers her involvement to be vital for her state’s residents.
She pointed out that MISO has approved more than $25 billion in transmission spending since 2003.
“All these costs flow through to our ratepayers,” Weber said. “If regulators in MISO want to have influence on these costs, they are better off doing so at the MISO level before the costs get passed on.”
Weber also pointed to an essential connection between state commissions and RTOs.
“There’s an intersection between the RTO’s responsibility to maintain reliability and the state regulator’s responsibility for ensuring resource adequacy,” Weber said. Through their resource planning processes, “the states effectively determine the tools that MISO has at its disposal to maintain reliability,” she said.
SPP General Counsel Paul Suskie said states wield significant influence within his RTO through the Regional State Committee. The committee has governing authority over transmission access charges, financial transmission rights, planning for remote resources and resource adequacy, while also providing input into market developments, strategy and transmission planning.
“Our CEO will tell you that when he said we were going to give state regulators this authority, some of his counterparts thought he was crazy, that it’s not going to work,” Suskie said.
The SPP model works because of the time and effort state commissions dedicate to working through market issues, Suskie said.
“Other states ask me about our governance model and I tell them, ‘From the state commissioner perspective, the good thing is you have the authority. The bad thing is you have the authority,’” Suskie said.
Stacey Crowley, vice president of regional and federal affairs at CAISO, said that a change in governance is key for enabling the ISO to expand into other parts of the West. The ISO was created in 1998 as a single-state body under California statute, with board members appointed by the governor.
That structure “will not satisfy a regional ISO,” Crowley said.
Crowley noted that regional discussions about a Western RTO have focused on the fact that each state has different policy structures, goals and procurement strategies.
“Those are all important and need to be respected in a regional ISO,” Crowley said.
While California represents a large population in the West, “its policies need to be seen as equal amongst all the states” in an RTO, she added.
CAISO has developed a model for state involvement with its Energy Imbalance Market, which features a regionally representative governing body and an advisory body of regulators that provides states with a forum to discuss market issues.
“It’s been a good way to develop a relationship and a way to communicate amongst the states,” Crowley said.
