NYISO asked FERC Thursday to approve Tariff revisions that would make it easier for generators to get a place in the transmission queue “class year” (ER16-1627).
The ISO’s large facility interconnection procedures require generators to complete a three-step study process, starting with a high level feasibility study, which evaluates the configuration and local system impacts, followed by a system reliability impact study (SRIS), which evaluates the project’s impact on transfer capability and system reliability.
Finally, the class year study evaluates the cumulative impact of a group of projects that has completed similar milestones. This study identifies the upgrades needed to interconnect the project and maintain reliability.
In order to preserve its place in the transmission queue and enter the class year study, the project must acquire necessary permits from the state within two years of the NYISO Operating Committee deeming its application complete following an SRIS.
The state permitting process for generators over 25 MW “is a relatively new power plant siting process that ‘front loads’ much of the process,” the ISO explained. “As a result, there are concerns that projects may not be able to reach the ‘completed application’ stage in time to enter a desired class year study, despite having an Operating Committee-approved SRIS.”
NYISO cited a recent example in which a generator needed a FERC waiver to enter the class year study. On April 1, FERC granted the 33-MW Dry Lots Wind project in Herkimer County a waiver allowing it to join the study despite lacking a state siting board permit (ER16-1047). In granting the waiver, the commission cited its expectations of the ISO’s pending Tariff filing.
The proposed Tariff changes would extend the deadline for meeting the regulatory milestone requirement to 90 days after the start of the third class year study following the OC’s SRIS approval.
“This gives additional time for the project to meet the regulatory milestone while not permitting the project to remain in the queue indefinitely,” NYISO said. “This revision will help minimize delays to projects that are close to completing their regulatory milestone when a class year study begins. If a project provisionally enters a class year study, it will be withdrawn from the class if its regulatory milestone is still not met after the 90th day.”
NYISO asked for acceptance of the revision by July 5.
CAISO’s Board of Governors last week approved an ISO plan to temporarily alter market operations in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility.
CAISO is proposing to reserve capacity on the Path 26 transmission line in advance of potential gas restrictions in Southern California. The measure is meant to ensure delivery of energy into the region when constrained fuel supplies threaten to limit output from local gas generators. Source: CAISO
The proposal calls for new market rules to help Southern California’s gas-fired generators better manage their burns to avoid system-balancing penalties expected to go into effect June 1 — just ahead of the state’s peak season for electricity consumption.
Under the new requirements, Southern California Gas customers face penalties as high as 150% of daily gas indices when their daily burn deviates from nominated flows by more than 5%. The region’s gas-fired generators say the costs could make them unprofitable when ISO dispatch instructions require their units to burn more — or less — gas than planned for on a given operating day.
“We want to ensure the generation can get” into Southern California, Cathleen Colbert, CAISO senior market design and regulatory policy developer, told a Market Surveillance Committee meeting last month. “That’s why deliverability was the focus.”
Thus, CAISO’s plan takes a systemwide response to gas restrictions, although provisions for recovery of penalty costs are included in the proposal.
When gas flows are restricted the ISO would enforce a gas availability market constraint for generators in a constrained region. The constraint would use the day-ahead or real-time market to cap the gas burn in the affected area below system limitations set out by SoCalGas. Any additional generation needed would only be dispatched through out-of-market operations coordinated with the pipeline operator.
The ISO would also implement a protocol to reserve capacity on the Path 26 transmission line in advance of potential gas shortages, a measure intended to leave enough of a buffer to ensure delivery of energy and contingency reserves into the Los Angeles basin when local resources face curtailment. CAISO decided against implementing a similar procedure along the interties into California because of the current low volume of real-time transfers on those lines.
Additional operational measures proposed by the ISO include:
Reducing the amount of ancillary services procured from Southern California resources based on expected gas and electric system conditions;
Deeming selected internal transmission constraints uncompetitive when the proposed gas availability constraint is in effect, thereby freeing up resources to serve the affected region; and
Clarifying CAISO’s authority to suspend virtual bidding when it identifies potential market inefficiencies.
The ISO is also proposing to allow an affected generator to recover increased gas costs by adjusting the gas component of its day-ahead commitment cost bid cap to up to 175% of the gas index price, compared with 125% today. Gas cost caps included in default energy bids used in the real-time market would be increased from 125% to 200% of the index.
CAISO must now seek FERC approval for the plan. All proposals are set to sunset Nov. 30.
PJM is prepared to meet the power needs of its 61 million consumers this summer, when demand is expected to peak at 152,131 MW, the RTO said last week.
There is 183,912 MW of installed generating capacity available, plus 8,700 MW of demand response.
“With continued transmission enhancements, reinforced capacity commitments and slowing forecasted load growth, we’re prepared to meet the region’s needs,” said Mike Bryson, vice president of operations.
The Public Utilities Regulatory Authority approved “near historic” low rates starting July 1 for the standard offers from the state’s two electric utilities, thanks to depressed natural gas prices.
The standard rate for Eversource Energy customers will drop from the current 9.555 cents/kWh to 6.606 cents. United Illuminating customers will see their standard rate decrease from 10.7358/kWh to 8.0224 cents.
Dave Thompson, a utilities examiner with the state Office of Consumer Counsel, said utility industry officials “haven’t seen prices like this since 2003-04.”
The developers of what would be the state’s largest solar energy farm won vital support from the city of Sanford, where it will be built on vacant land at the municipal airport.
The Sanford City Council authorized a lease allowing Ranger Solar to build a 50-MW photovoltaic array on 226 acres. Ranger intends to start construction in 2018. The project will include 176,000 solar panels.
Ranger estimates that the project will add $29 million in taxable investment to the city, as well as millions of dollars in rent if the lease is extended to the maximum 40-year term stipulated in the agreement. The project still requires environmental permitting from the state and an interconnection agreement with ISO-NE.
Bill to Mandate Offshore Wind Purchases Coming Soon
Pacheco
Legislators will introduce a bill as soon as this month that will require utilities to purchase energy from offshore wind farms, according to Bloomberg News.
Wind developers are pushing for a mandate for utilities to buy 2,000 MW over 10 years. Proponents have said such a guaranteed market would spark an offshore wind-building boom. Three wind development companies have secured federal offshore leases near Martha’s Vineyard: DONG Energy, Deepwater Wind and Offshore MW.
“We have the opportunity to create an industry,” Sen. Marc R. Pacheco said. “We have the opportunity to create thousands of jobs and create a whole supply chain.”
Gov. Maggie Hassan recently signed a bill setting a new net metering cap in the state, and the available capacity for larger projects is already nearly consumed.
The law allocates about 40 MW to smaller projects for homes and businesses and 10 MW for larger projects. Eversource Energy, which was allocated 7.8 MW, already has a waiting list of 7.2 MW worth of projects and another 7.8 MW still in development.
For the second time, Gov. Chris Christie has vetoed a bill that would have paved the way for Fishermen’s Energy to build a 25-MW offshore wind farm near Atlantic City.
Although the project received a $47 million grant from the U.S. Department of Energy, Christie and the Board of Public Utilities have criticized the project as too costly for customers, who would help fund the project through bill surcharges. Christie also argued that the bill “would usurp BPU’s authority” and strip its discretion for “managing energy matters.”
Christie signed a bill six years ago mandating offshore wind with a goal of developing 1,000 MW by 2020, but the BPU never created a funding mechanism that would make such projects economically feasible.
Trust Fund Would Stimulate Clean Energy Technology
The Senate is considering a proposal that would provide loans and loan guarantees to stimulate the clean energy sector.
The bill, S-684, would finance a trust fund through raising an existing surcharge on customers’ bills, called the “societal benefits charge.” That has raised concerns with the business community and the Division of Rate Counsel.
The fund would target investments in clean energy research, promote manufacturing for new and existing technologies and support the development of a clean energy curriculum at universities.
Duke Energy Progress is asking state regulators to require opponents of a new power plant near Asheville to put up a $50 million bond if they appeal regulatory approvals. The company said that delays would drive up construction costs by as much as $140 million.
Environmental groups say that amount is just to prevent them from taking appeals to court. “We aren’t asking them to delay anything,” said Jim Warren, executive director of NC WARN. The groups said an appropriate bond would only be $250.
Duke called that “absurd,” saying the company’s customers needed adequate protection from potential construction delays for a $1 billion project. Duke wants to start construction in October.
OG&E Admits Including Legal Fees, Lobbying in Rates
Oklahoma Gas & Electric acknowledged that the company’s customers have been paying the legal fees for shareholders of the utility’s parent company for the past 11 years and agreed to reduce its rate-increase request.
As hearings opened before the Corporation Commission on OG&E’s $92.5 million rate case, a company witness acknowledged the utility had improperly included the legal fees for the OG&E Shareholders Association in customer rates. The issue came to light after an audit by the commission’s public utility division and questions by the attorney general’s office, which represents ratepayers in utility cases.
The utility has agreed to lower its rate request by about $275,000 to reflect the incorrect allocation. It also agreed to reduce it another $20,000 for “legislative activities” that should have been paid by parent OGE Energy instead of ratepayers.
Gov. Tom Wolf has nominated senior adviser David Sweet to serve on the Public Utility Commission.
Sweet, a Democrat, was a state representative from 1977 to 1988 and has advised Wolf on energy and economic development matters since April.
He also has served on the Banking and Securities Commission and as a liaison to the Philadelphia Regional Port Authority. Sweet will need to be confirmed by the Senate.
Majority of Residents Want CPP Compliance Plan Developed
State residents believe their leaders should draw up a plan to shift from coal-fired power to natural gas and renewables, even if the state wins a high-profile battle against the federal Clean Power Plan, according to a new poll.
Two Republican pollsters developed and conducted the survey of more than 800 registered voters on behalf of the Texas Clean Energy Coalition, a group that supports natural gas, solar and wind energy. It offers insight into residents’ views on energy policy and a test of how public opinion compares to the rhetoric of politicians on the issue.
Among the findings, 85% (including 81% of Republicans) believe the state should develop its own comprehensive clean energy plan, regardless of the outcome of a lawsuit over the Clean Power Plan, and 69% believe their leaders should construct a proposal to comply in case the state loses its court battle.
The Senate last week approved a modified version of a bill giving towns more say over renewable energy projects, but action by the House of Representatives is uncertain.
Rep. Tony Klein, a Democrat and chairman of the House Natural Resources and Energy Committee, said he wanted the attorney general’s office to weigh in before agreeing with Senate language on regulating sound from wind towers.
The Senate version of the bill calls for the Public Service Board to issue new rules on noise levels by July 1, 2017.
Appalachian Power Developing 100% Renewable Offering
Appalachian Power has informed the State Corporation Commission that it is developing a pure alternative energy rate for its customers. It said it has seen a higher demand for renewable energy from its customers and is seeking a way to offer a 100% renewable product.
The company said it is seeking more sources of renewable energy to be able to provide a rate that will reflect the use of renewables around the clock.
“We do know that it will be set up as an annual review situation where we’ll look at the cost every year and adjust the cost to the customer every year,” said John Shepelwich, a company spokesman.
Citizen Groups Criticize Mon Power, Potomac Edison IRP
Critics are calling an integrated resource plan put forth by FirstEnergy utilities Mon Power and Potomac Edison “a thinly disguised attempt to pave the way” to buy a coal-fired power plant from an affiliated company, Allegheny Energy.
Two citizen groups are urging the Public Service Commission to force the utilities to rewrite the plan, saying the cost of the purchase would fall to customers.
MISO is seeking stakeholder input on how to revise its energy offer cap rule while awaiting guidance from FERC for developing a final rule.
“If we have some of the groundwork laid out for the final rule, we’ll be in better shape,” said Chuck Hansen, a MISO senior engineer.
The RTO has queried market participants about changing the operating reserve demand curve and whether to remove — or increase — the $3,500/MWh LMP cap.
This winter is likely to see a repeat of the “temporary” solution implemented the past two years, in which the RTO used revenue sufficiency guarantees to cover costs exceeding the offer cap. (See MISO: No Change to Energy Offer Cap this Winter.)
In January, FERC issued a Notice of Proposed Rulemaking that would require offers more than $1,000/MWh be verified before being used to calculate LMPs. Offers not verified in time for market clearing would become eligible for a make-whole payment. (See FERC Proposes Uniform Offer Cap Across RTOs.)
Market participants became concerned about the hard cap in 2014 when natural gas demand spiked during extreme cold. Although inefficient generators were called up, offers more than $1,000 never materialized.
“The MISO market is becoming more and more dependent on natural gas,” Hansen explained. “The problem with this is if we actually clear and commit these units,” their costs would be higher than offers allow.
While MISO generally supports FERC’s proposals, it prefers that administrative caps be gradually relaxed to provide incentives for competitive offers so the need for “artificial, administrative caps” would disappear, Hansen said.
“We thought [FERC’s NOPR] was a reasonable compromise between protecting customers and potential exercise of market power, [and it] sets appropriate prices during periods of high fuel cost,” Hansen said. “Eventually we’d like to see the offer caps be relaxed to the point where they’re not getting in the way of valid offers.”
MISO said that over time, new technologies and new demand response will supplant offer caps with more efficient pricing during scarcity situations.
MISO currently uses a $3,500/MWh LMP cap, which reflects the cost of firm load shedding. Hansen said that amount is adequate — for now.
“The $3,500/MWh works with the current experience, but there’s not a lot of room,” Hansen said.
Hansen said MISO must consider the different verifiable costs among external asynchronous resources, hydro, storage, demand response, imports and virtual supply.
‘Modest’ Price Impacts as Extended LMP Enters Phase 2
Extended locational marginal pricing (ELMP) will enter a second phase of implementation despite its limited effect on energy prices a year after its introduction.
ELMP is intended to improve the way the security economic dispatch (SCED) algorithm calculates LMPs and sets market-clearing prices. The practice was designed to reduce uplift charges by allowing certain fast-start resources that are either offline or scheduled at their limits to set clearing prices.
Clearing prices under SCED often fail to compensate fast-start units for their start-up costs, necessitating use of revenue sufficiency guarantees.
According to MISO market design engineer Congcong Wang, stakeholders generally support roll-out of the second phase, which will allow 30-minute fast-start resources into the program. Currently, only real-time scheduled units with 10-minute start times and an hour or less of minimum runtime are eligible to set real-time energy prices under ELMP.
Wang said the inclusion “captures more fast-start schedules.” Including resources with a 60-minute start time would not make as much of a difference on prices, she said.
Wang noted that stakeholders also want offline units included in the price-setting process if those units “appropriately reflect system conditions.”
In the meantime, MISO is studying cases from last winter to evaluate price impacts and determine if offline fast-start resources are “truly available and economic.” Wang also said MISO will create a “recommendation tool” that lists eligible ELMP offline fast-start resources for operators to manage shortages or congestions.
MISO will present its findings at the August Market Subcommittee meeting.
MISO Independent Market Monitor David Patton said ELMP’s impact on prices has been “modest.” (See MISO Monitor: Extended LMP Changes Minimal Thus Far.) The practice only lifted real-time prices by about a penny per megawatt-hour in spring 2015, and reduced them by almost 8 cents in summer and 3 cents in fall. Day-ahead market impacts were even lower.
That minimal effect was a product of the limited number of units eligible to set prices under ELMP, Patton said. Units with a 10-minute start time account for just 2% of total peaking resources.
Patton advocates expansion of ELMP, saying MISO could capture 90% of peaking units in the real-time market if it expanded the practice to include resources with two-hour minimum runtimes and 30-minute startup times, as well as those committed in the day-ahead market.
“There’s no clear reason for day-ahead units not to contribute to price setting,” Patton said. He said no software changes would be required if MISO allowed 30-minute fast-start resources — representing 12% of peakers — to be eligible in the second phase of ELMP.
However, the Monitor recommended suspending offline price-setting in LMP, saying that although the offline units are economic, “analysis indicates that the units setting prices are rarely utilized.”
Sunset on Financial Transmission Rights Working Group
The MSC approved retirement of the Financial Transmission Rights Working Group and will absorb tasks associated with financial transmission rights and auction revenue rights.
Working group Chair Brad Arnold said the group agrees with a MISO proposal last month to sunset the group.
“The only request was stakeholders continue to have access to FTR reports and continued MISO support,” Arnold said.
Zakaria Joundi, MISO liaison to the working group, said a decrease in agenda items and stable FTR funding prompted the move. He added that MISO will continue to post FTR and ARR reports on a monthly basis as needed.
Joundi also noted that MISO subject matter experts will respond to inquiries about the reports, and that the RTO could always create a task team in the future if a specific FTR issue arises.
The developers of an underwater transmission project that would deliver hydroelectric and wind power into New England filed for permits last week for the New York section of the project (16-T-0260).
Anbaric Transmission and National Grid filed for a certificate of environmental compatibility and public need with the New York Public Service Commission for their Vermont Green Line. The project would connect 400 MW of wind generation to be developed in northern New York to Vermont through buried lines under Lake Champlain. The wind power would be supplemented by hydropower from Quebec, to provide firm power to ISO-NE.
The northern New York-Vermont border runs down the middle of the lake. The HVDC system would run from the New York Power Authority’s Plattsburgh substation in Beekmantown, Clinton County, to Vermont Electric Power Co.’s New Haven substation in Addison County. The New York portion of the project includes 6.7 miles of buried HVDC cable from a converter station to the shoreline of Lake Champlain at Point Au Roche State Park and about 4.9 miles underwater on the New York side of Lake Champlain.
The Vermont section of the project will include 35.2 miles of underwater HVDC cable, a converter station and 13.3 miles of buried line to the New Haven substation.
The project will also need approval from the Vermont Public Service Board. Bryan Sanderson, senior vice president of Anbaric Transmission, told RTO Insider on Wednesday that the companies plan to file with Vermont this summer.
Invenergy is developing the Bull Run Wind Energy Center in Clinton County, pending approval from state regulators. The proposed development would have as many as 140 turbines, with an in-service date projected for 2019.
The overall project, with energy also supplied by Hydro-Quebec, has been dubbed the “wind-hydro response” to the request for proposals solicited by three New England states to procure renewable energy for the region. The proposal is one of about 30 submitted to Connecticut, Massachusetts and Rhode Island now under review. (See State-Sponsored Energy Procurement Moves Ahead in NE.)
The hydro generation would flow into New York via a transmission connection between Hydro-Quebec and NYISO at Chateauguay, Quebec, according to Sanderson.
If the project is selected, the developers would then file with FERC for negotiated rate authority, he added.
“We think the Vermont Green project is well timed to provide the region with a reliable, clean energy source of hydro firming wind,” Sanderson said.
While the wind project is aimed at the New England market, developers say it will provide benefits to New York as well, including meeting the state’s goal to procure 50% of its energy from renewable sources by 2030.
“The project will provide an ‘energy bridge’ that will allow additional development of new wind energy in upstate New York that would otherwise be constrained and uneconomic given the existing infrastructure for delivery to load centers in New York,” according to an economic analysis filed with the NYPSC.
When the hydroelectricity from Canada is more than what is needed to firm the wind energy destined for New England, that excess would be available to the New York market, according to the analysis.
Exelon said it will close the Clinton Power Station next summer and the Quad Cities facility the following year if Illinois legislators fail to pass a bill to shore up the money-losing nuclear plants and Quad Cities does not clear PJM’s 2019/20 capacity auction this month.
“Without adequate legislation, we no longer see a path to profitability and can no longer sustain ongoing losses,” CEO Christopher Crane said on Friday’s first-quarter earnings call with analysts.
Together, the plants have lost $800 million in cash flow from 2009 to 2015, he said.
“For reasons outside of our control, we have not seen progress in Illinois policy reform,” Crane said. “In order to reverse course, we would need Illinois to cover our cash costs and operating risk.”
Clinton Nuclear Plant Source: Exelon
The Clinton plant would be shuttered June 1, 2017, and the Quad Cities station would cease operations one year later.
The closures would represent the loss of $1.2 billion in economic activity and 4,200 in direct and indirect jobs, Crane said. Together, the plants employ 1,500 workers.
The company last year deferred a decision on closing the generators pending the outcome of MISO’s 2016/17 Planning Resource Auction, held last month, and PJM’s Base Residual Auction, the results of which will be known May 24. Last year, for the second year in a row, the 1,819-MW Quad Cities plant did not clear the PJM auction. (See Reactor to Participate in 2016 Auction.)
While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price is “insufficient to cover cash operating costs,” Crane said Friday, noting that power prices have fallen to a 15-year low.
“We are not covering our operating costs or our risk, let alone receiving a return on our investment capital,” he said.
Exelon last year backed legislation that would have ensured continued operation of its ailing nuclear power plants with a $300 million annual charge paid by Commonwealth Edison and Ameren customers.
Illinois legislators, however, declined to act on the bill, or on other energy legislation put forward by ComEd, Exelon or the Clean Jobs Coalition, environmental and consumer advocates who sought to boost energy efficiency and wind and solar power.
On Thursday, Exelon and ComEd announced they would be supporting new legislation, the Next Generation Energy Plan, which Exelon said contains parts of their previous legislation and the Clean Jobs bill.
A key new element in the plan, Exelon said, is a shift to a zero-emission standard.
“The zero-emission standard addresses stakeholder concerns by requiring full review of plants’ costs by state regulators and by ensuring that only those plants that can demonstrate that revenues are insufficient to cover their costs and operating risk will be entitled to receive compensation,” the company said in a release. The model is similar to Gov. Andrew Cuomo’s plan to save New York’s struggling nuclear plants, including Exelon’s R.E. Ginna. (See New Lifeline for FitzPatrick Nuclear Plant.)
Exelon Executive Vice President Joe Dominguez said on a call with reporters Thursday that Clinton and Quad Cities are expected to lose “well over $100 million” next year, signaling that that would be the amount of state assistance for the two plants.
The bill also would double energy efficiency programs in Illinois and provide $140 million per year in funding for solar development. The companies estimate the plan would result in a 25-cent monthly increase in the average ComEd residential customer’s bill.
Just as they were last year, legislators continue to debate the state budget, and their session ends this month.
Also Friday, Exelon announced its first quarter earnings following the $6.8 billion acquisition of Pepco Holdings Inc. (See Exelon Closes Pepco Merger Following OK from DC PSC.) Operating revenue dropped 14% to $7.57 billion. The company reported a profit of $173 million (19 cents/share), down from $693 million (80 cents/share).
Dynegy said it will idle at least three coal-fired units in Central and Southern Illinois beginning in the fall, saying the merchant units can’t recover their costs from MISO’s energy and capacity markets.
Baldwin Energy Complex
Dynegy said the three 40-year-old coal units totaling 1,835 MW — Units 1 and 3 at the Baldwin Power Station and Unit 2 at the Newton Power Station — are unable to recoup their operating costs because of current energy and capacity market prices. In MISO’s Planning Resource Auction in April, Zone 4 cleared at $72/MW-day, a 50% drop from a year earlier. (See MISO’s 4th Capacity Auction Results in Disparity.)
The company also said it’s considering closing another 500 MW of coal-fired capacity in Zone 4, though it didn’t name specific plants, with a final decision due later this year.
Including Dynegy’s 465-MW Wood River Power Station — which it previously announced would shut down in June — the planned suspensions would remove 2,800 MW of generation, about 30% of the capacity in Southern Illinois.
At a Thursday meeting of MISO’s Resource Adequacy Subcommittee, Dynegy Director of Regulatory Affairs Mark Volpe clarified the company’s stance on the closures. “I want to be clear that we plan to suspend, not retire. Those units could come out of suspension given the right compensation,” he said.
The company said competitive generators in Zone 4 cannot cover their operating costs under the existing MISO market design because out-of-state generators receiving regulated revenues from their home states are suppressing capacity and energy prices. “If Newton and Baldwin were located in PJM, as Northern Illinois plants are, or Zone 4 was regulated as the other MISO generators outside of Illinois are, no shutdowns would occur,” the company said in its announcement Tuesday.
“This is a losing model that exports Southern and Central Illinois jobs and economic base to the surrounding states, resulting in a catastrophic economic outcome for downstate Illinois,” Dynegy CEO Robert Flexon said. “Central and Southern Illinois competitive units in MISO Zone 4 are wrongly grouped with out-of-state utilities rather than the competitive power producers in Northern Illinois and PJM. This must change.”
Dynegy said it was seeking relief from state policymakers because it wasn’t convinced MISO — whose “membership is overwhelmingly represented by out-of-state utilities that reap the benefits of the existing market design” — would make needed design changes.
Unless MISO determines the units are needed for reliability, Dynegy said, Newton Unit 2 will stop operations in September, with Baldwin Unit 1 following in October and Unit 3 in March 2017. The shutdowns will leave one unit apiece still functioning at the Newton and Baldwin locations. Dynegy purchased the Newton plant from Ameren three years ago along with four other coal plants, as Ameren departed the Illinois market.
“In the limited time left before closures occur, we are ready to work quickly with MISO, the state of Illinois, union leadership and all stakeholders to rectify the situation and preserve the jobs and economic base in downstate Illinois,” Flexon said.
Flexon lamented that Illinois officials’ only response so far has been to file a complaint against the Houston-based utility over its bidding in the 2015 capacity auction. (See FERC Launches Probe into MISO Capacity Auction.)
The Public Utility Commission of Texas agreed Wednesday to wait until no later than June 10 before determining whether to grant a rehearing on its decision to allow Hunt Consolidated’s acquisition of Oncor.
The commission granted the extension partly to allow time for review of the flood of filings that followed the May 1 announcement by Oncor’s debt-laden owner, Energy Future Holdings, that it had filed a new Chapter 11 reorganization plan. (See EFH Files New Chapter 11 Plan; Oncor-Hunt Deal in Doubt.)
The PUC will resume the discussion of whether to grant the Hunt group’s rehearing request at its May 19 open meeting. The intent is to make a decision then, rather than extending the timeline until its next meeting on June 9.
“I think we can make a decision on the 19th whether we can grant a rehearing,” Commissioner Ken Anderson said. “At the very least, we should discuss our position on the issues raised by the parties. I guess we’re probably decided on 80% of those issues now.”
However, the commission’s requirements that the REIT’s tax savings be set aside for customers led to EFH’s investors pulling their support for the deal. That, in turn, led to EFH killing its original bankruptcy exit plan last weekend and filing a new one.
Anderson is widely seen as the swing vote in the three-person commission’s eventual decision. Chair Donna Nelson has often sided with the Hunt group’s position, while Commissioner Brandy Marty Marquez has supported the restrictions placed on the deal.
“Is there even a transaction for us to still approve?” Anderson asked.
Two opposing groups, the Steering Committee of Cities Served by Oncor (comprising about 150 Texas cities) and the Texas Office of Public Utility Counsel, argued the commission should dismiss the rehearing request.
“The [bankruptcy exit] plan is dead, according to the bankruptcy court,” Geoffrey Gay, lead attorney for the cities coalition, told the commission. “If I was in your position, my gut reaction is this case no longer exists. You’re being asked to proceed on a hypothetical basis.”
“We believe the transaction is null and void,” said Laurie Barker, deputy public counsel for the OPUC. “While the Hunts do have an opportunity to negotiate and possibly become the next plan, there are other potential investors and plans out there as well. If we allow one entity to come before you with their preferred plan, you would have to allow all.”
Richard Nolan, an attorney for the Hunt group, said turning Oncor and its assets into a REIT is still a viable option for the bankruptcy process. He said the door has been left open for creditors and the court to approve the structure under the reorganization plan, “and we intend to pursue that.”
“We’ve receive a lot of interest from investors,” Nolan said. “To the extent we can make this work … that offers the opportunity to avoid going through another six months of proceedings. We realize the plan that was selected will have to conform to whatever the final order is.
“We think if that’s done, that would be the quickest way for the debtors to exit the bankruptcy proceeding without going through another six months and delay the process. That also gives the commission an opportunity to shape, to some degree, a plan that would be workable and approved by the [bankruptcy] court.”
Commission staff also requested an extension, saying “new developments in the EFH bankruptcy proceeding raise new issues that may affect this … proceeding.” Staff said they needed sufficient time to “identify and address any new issues.”
“I think you maintain maximum flexibility with your options if you extend time for the rehearing,” PUC attorney Sam Chang said.
EFH, saddled with $42 billion in debt following its leveraged buyout of TXU Corp. in 2007, filed its first bankruptcy exit plan in Delaware two years ago. In December, a U.S. bankruptcy judge approved the company’s plan to split into separate companies — Oncor, Luminant and TXU Energy — wiping out the buyout sponsors’ equity. The Luminant and TXU Energy businesses would go to senior lenders owed about $24 billion.
A merchant transmission developer asked FERC last week for authority to negotiate transmission contracts for a mostly underwater cable to transport 1,000 MW of electricity underneath 260 miles of the Erie Canal and Hudson River to New York City (ER16-1495).
Erie Canal Source: New York State Canal Commission
Empire State Connector filed an application for transmission service on a HVDC line that would deliver renewable energy from upstate New York.
ESC is a joint venture of Toronto-based transmission developer oneGrid and investment firm Forum Equity Partners. The company says it is assuming the entire financial risk of the $1.5 billion project. It asked for FERC approval by June 26 to keep to its preferred permitting and open season schedule.
“Our strategic location and innovative, low-impact route will ‘unlock’ upstate renewable and zero-emission generators, helping New York state achieve its ambitious goal of 50% renewable generation by 2030,” CEO John Douglas said in a statement.
The project would originate at a converter station located near Utica and terminate at a converter station located in either the Bronx or Brooklyn. Underground cables would be connected to a new converter station near the existing Marcy substation near Utica until it enters the canal. Cables would be buried under the locks and dams along the canal route.
The company said a NYISO feasibility study concluded the project is viable and it has secured a spot in the ISO’s interconnection queue.
ESC said it will file its Article VII application for major infrastructure review certification with the New York Public Service Commission by the end of the year. It will also conduct a solicitation later this year seeking subscribers for capacity on the line.
The project will create more than 500 construction jobs and 1,200 indirect jobs during the three-to-four-year construction period, the company said. Each converter station is estimated to cost more than $200 million. The target in-service date is for some time in 2021.
The NYPSC in December declared a public policy need for above-ground transmission to move upstate power from central New York to the New York City area through AC lines that are using existing corridors. (See NYPSC Directs NYISO to Seek Tx Bids.) Douglas told RTO Insider on Monday that he sees ESC and above-ground AC as “complementary.”
“New York state certainly has ambitious goals to develop renewable energy,” Douglas said. “It’s going to need a lot of new transmission, especially if it succeeds in closing Indian Point. So we see … room for both [projects] for both energy and capacity.”
The Public Utilities Regulatory Authority approved “near historic” low rates starting July 1 for the standard offers from the state’s two electric utilities, thanks to depressed natural gas prices.
The developers of what would be the state’s largest solar energy farm won vital support from the city of Sanford, where it will be built on vacant land at the municipal airport.
For the second time, Gov. Chris Christie has vetoed a bill that would have paved the way for Fishermen’s Energy to build a 25-MW offshore wind farm near Atlantic City.
Duke Energy Progress is asking state regulators to require opponents of a new power plant near Asheville to put up a $50 million bond if they appeal regulatory approvals. The company said that delays would drive up construction costs by as much as $140 million.
Oklahoma Gas & Electric acknowledged that the company’s customers have been paying the legal fees for shareholders of the utility’s parent company for the past 11 years and agreed to reduce its rate-increase request.
Appalachian Power has informed the State Corporation Commission that it is developing a pure alternative energy rate for its customers. It said it has seen a higher demand for renewable energy from its customers and is seeking a way to offer a 100% renewable product.
Critics are calling an integrated resource plan put forth by FirstEnergy utilities Mon Power and Potomac Edison “a thinly disguised attempt to pave the way” to buy a coal-fired power plant from an affiliated company, Allegheny Energy.
Anbaric Transmission and National Grid filed for a certificate of environmental compatibility and public need with the New York Public Service Commission for their Vermont Green Line. The project would connect 400 MW of wind generation to be developed in northern New York to Vermont through buried lines under Lake Champlain. The wind power would be supplemented by hydropower from Quebec, to provide firm power to ISO-NE.
