Former FERC Commissioner Philip Moeller, who helped steer efforts to reform regional transmission system planning that became Order 1000, told an audience last week that it is time to take a look at compliance with the landmark 2010 rule.
Moeller told a TransForum East gathering in D.C. that he was “kind of a lukewarm supporter of Order 1000.” He decried what he called “Order 1000 fatigue,” saying that some compliance filings were on their third or fourth iteration, and he called for FERC to look at what is and isn’t working, and perhaps to make changes.
“I believe we’ve spent way, way, way too much time talking about the cost of transmission and way, way, way too little time talking about the value of transmission,” he said. “The debate really focuses on cost, whereas I think the debate really should focus on value.”
A U.S. District Court judge has dismissed a suit that sought to overturn Virginia’s 1982 moratorium on uranium mining.
Virginia Uranium and three other companies sued Gov. Terry McAuliffe and various other state officials after Virginia denied a permit to mine an estimated 119-million-ton uranium deposit in Pittsylvania County. Judge Jackson L. Kiser said that since the moratorium dates to 1982, long before McAuliffe was in office, current officials couldn’t be named in the suit.
Kiser also dismissed the plaintiffs’ argument that the federal Atomic Energy Act of 1954 gives the federal government sole regulatory authority over safety concerns at the heart of the state’s moratorium. The federal act, the judge said, “institutes no permitting regime respecting nonfederal uranium deposits’ conventional mining and does not otherwise regulate nonfederal uranium deposits or their conventional mining.”
The Department of Energy and Israel’s Ministry of National Infrastructure, Energy and Water Resources chose six joint American and Israeli clean energy projects to receive $5.1 million in funding. Energy Secretary Ernest Moniz said the Binational Industrial Research and Development Energy Program will help both countries develop cleaner energy.
The projects include remote metering and analytic tools for smart grids by Jerusalem-based Ayyeka Technologies and Michigan-based UIS Holdings ($1 million); and the development of software that would assess threats to birds by wind farms, by The Hebrew University of Jerusalem and New York-based Applied Biomathematics ($500,000).
Just three months after admitting that its push into green energy wasn’t producing returns for shareholders, NRG Energy CEO David Crane announced his resignation. Chief Operating Officer Mauricio Gutierrez will assume the role.
Under Crane’s helm, NRG launched a billion-dollar push into rooftop solar, wind energy and car charging stations. But the company in September announced plans to return to its core conventional generation business. NRG stock has plummeted 60% so far this year.
Crane took over as CEO in 2003, when it was a regional power producer in bankruptcy. It became one of the nation’s largest owners and operators of solar facilities.
NRG Energy said it is selling two power plants for $138 million to reduce debt and improve cash flow.
In one of his last official announcements before resigning, NRG CEO David Crane said the plant sales are part of a “reset” process. “By streamlining our fleet, we can create additional value for our shareholders and meet the needs of our customers with reliable, efficient and economic power,” he said.
NRG is selling its 535-MW, waste coal-fired Seward plant in Pennsylvania to Robindale Energy Services and its 352-MW, natural gas-fired plant in Shelby County, Ill., to The Woodlands-based Rockland Capital. NRG said the two plants would need about $17 million in maintenance in the next three years.
Alliant has said it will close its Dubuque Generating Station on Iowa’s eastern border in June 2017. The Mississippi River plant, which used coal as a fuel source before being converted to gas four years ago, only ran occasionally and was not necessary to maintain system reliability.
Alliant this year settled EPA allegations of Clean Air Act violations, agreeing to close the plant in 2019 or face fines. The facility’s 13 employees will be offered positions at other plants.
Alliant has no plans to sell the property, where a power plant has been in operation for more than a century. If it does, the city of Dubuque has first rights to buy it.
Google announced it has signed six deals on three continents to buy 842 MW of clean energy, bringing its worldwide renewable power purchases to more than 2 GW. Google said it now supplies 37% of its power needs with renewable energy, and the company eventually wants to power all 14 of its data centers with green energy.
“We’re going to get renewable energy any way we can, no matter what it takes,” said Michael Terrell, who leads energy policy and market strategy for Google’s global infrastructure team. The new purchase of solar and wind energy is enough, as Wired pointed out, to power two cities the size of San Francisco.
Duke Energy was involved in several deals with the search giant: One in North Carolina for 61 MW of solar from a project in Rutherford County; and two others in Oklahoma for 401 MW of power.
FirstEnergy named Brian A. Farley vice president of sales, where he will be responsible for strategic planning and day-to-day operations. The division includes the governmental aggregation, large commercial and industrial, and residential and municipal channels.
Farley, who joined FirstEnergy in 1989, most recently was director of wholesale and provider-of-last-resort transactions.
He holds a bachelor’s in electrical engineering from Cleveland State University and a master’s in business administration from Baldwin Wallace University.
The law firm of Frost Brown Todd is opening a Pittsburgh office with the addition of 10 attorneys formerly with law firm Burleson. The attorneys will join the firm’s energy industry practice.
The office is the firm’s 12th and expands its presence to eight states. Kevin Colosimo is the member-in-charge of the new office.
Energy Future Holdings won bankruptcy court approval last week to shed about $30 billion in debt and split into two separate companies.
The bifurcated EFH can exit bankruptcy in a few months, provided that Texas regulators bless the reorganization and the company wins an Internal Revenue Service endorsement of the tax structure behind the deal. Luminant, the company’s unregulated generating business, will go to senior lenders, who are owed about $24 billion. Oncor, the regulated transmission unit, will go to a coalition of lower-ranking creditors and Hunt Consolidated, a Dallas-based energy and real estate company.
With lower debt, the two companies should be in a better position to weather the difficult market conditions that caused the $48 billion leveraged buyout to flounder about seven years after it was completed under the leadership of KKR and TPG Capital. The new plan wipes out the buyout sponsors’ equity.
EFH Agrees to $2M Settlement over New Mexico Uranium Mines
Energy Future Holdings has agreed to pay $2 million to help EPA clean up closed uranium mines it owns in northwest New Mexico.
The agreement, filed Dec. 1, settles a dispute with the Justice Department, which objected to the company’s bankruptcy plans, claiming EFH was trying to skirt its environmental responsibilities. According to court papers filed by the government, EPA found uranium contamination was still present decades later after a now shuttered subsidiary extracted uranium from four New Mexico mines in the 1970s and 80s.
The agency estimated the cost of the cleanup at $23 million.
Luminant Acquiring 2 Gas Plants for $1.6B from NextEra Energy
Luminant, the power generation subsidiary of Energy Future Holdings, is buying two Texas gas-fired power plants for $1.6 billion from NextEra Energy Resources. The deal is expected to close in the first quarter of 2016.
Luminant said its purchase of the 1,912-MW Forney Energy Center and the 1,076-MW Lamar Energy Center in Paris have been approved by the U.S. Bankruptcy Court in Delaware, which is overseeing the reorganization of EFH.
Southern Co. Buys 51% Interest in Texas’ Largest Solar Farm
Southern Co. is buying the controlling interest in a 157-MW planned Texas solar farm, its first solar investment in the Lone Star State.
The Atlanta energy giant said it bought a 51% stake for an undisclosed sum in the planned Roserock solar facility in West Texas near Fort Stockton. Canadian Solar Inc., which is developing the project, will retain 49% ownership through its Recurrent Energy subsidiary.
The Roserock solar farm will provide power to the city of Austin and surrounding areas through a 20-year power purchase agreement with municipally owned Austin Energy. Roserock is one of the largest solar facilities planned in Texas.
El Paso Customers Oppose Proposed $71.5M Rate Increase
About 20 people gave El Paso Electric’s proposed $71.5 million rate increase a thumbs down at an El Paso City Council hearing Dec. 2. The utility is seeking a 10.15% rate of return.
Most of those speaking at the hearing were solar advocates. They included homeowners with solar rooftop systems who said their rates would increase more than other residential customers, and solar system installers who said the utility’s proposed new rate class for residential solar customers would discourage consumers from embracing renewable energy.
Representatives of Western Refining’s El Paso refinery, the utility’s largest customer, said the proposed increase has prompted the company to begin exploring the possibility of generating its own electricity.
Aksamit Resource Management announced plans to build three wind farms generating 449 MW in southeastern Nebraska, representing a $725 million investment.
The developer said it has filed with SPP for permission to hook up two of the wind farms to transmission lines owned by the Nebraska Public Power District. The projects include a 150-turbine farm spread over 30,000 acres with a capacity of 300 MW and a 76-MW project with 40 turbines on 8,000 acres.
Aksamit said a third project, a 40-turbine farm in Saline County that can produce 73 MW, will be up and running within the next two years.
CARMEL, Ind. — MISO would reduce the price tag to enter its generator interconnection queue and provide “off ramps” for canceled projects under a final proposal presented Monday to the Planning Advisory Committee.
RTO officials said they reduced a proposed $60,000 refundable deposit for study models based on stakeholder feedback. Instead, interconnection customers would have to pay a non-refundable $5,000 study deposit.
Vikram Godbole, senior manager of MISO’s generator interconnection planning group, said the non-refundable charge facilitates trust between the RTO and interconnection customers. “We need to have a relationship with interconnection customers before providing models because there’s a lot of non-public information in these models,” Godbole explained in a presentation during a special PAC meeting.
Discussions on the proposed reforms will continue at the Dec. 16 PAC meeting, after which the proposal will open to a final round of stakeholder comments. MISO plans to file Tariff changes by the end of the year, Godbole said.
In addition to reducing the study fee, MISO has also cut its proposed M4 milestone by half; the new M4 cap will be set at $5,000/MW instead of $10,000/MW. The proposed $2,000/MW floor remains intact. MISO said it was responding to stakeholder comments that existing milestones are high and act as a barrier to entry.
Additionally, MISO has relaxed some rigidity surrounding its queue, allowing interconnection customers to receive M2, M3 and M4 refunds on projects that withdraw before the first decision point, which doesn’t occur until customers have the results of a system impact study.
Customers can also request provisional interconnection service up until their first decision point. Interconnection customers that request provisional interconnection service can now cancel their request, forgoing money spent on studies up to the cancellation date, and enter the definitive planning phase cycle.
“I think what we’ve done here is made this more flexible. If you want to proceed, that’s fine. If you don’t want to proceed, that’s fine too,” Godbole said. “The fact that we have these off-ramps built in; we expect that some interconnection customers will use them. I’m hoping these off-ramps will really help interconnection customers decide whether to get their M2 back.” MISO’s current queue doesn’t allow for the refund of M2 payment for withdrawing projects.
MISO has also eliminated the potential for restudies after customers execute a generation interconnection agreement.
“If any conditions change, we’re not going to rope you back into a restudy,” Godbole said.
“With the queue reform, one of the main goals was certainty,” MISO Director of Interconnection and Planning Tim Aliff said, explaining that if interconnection customers “have done their homework” on project feasibility and economics before entering the queue, M2, M3 and M4 payments will come back to them.
Aliff added that projects that withdraw and forfeit milestone payments will benefit other projects that complete generation interconnect agreements. “Your costs are offset by what others have left in the bucket,” he said.
Godbole said MISO has explored three transition options to the new queue rules, which are expected to take effect in February. In all three, MISO will grant existing projects priority over projects that have yet to join the queue. Interconnection customers will have the opportunity to request provisional agreements during the transition period to the new queue rules.
Godbole said MISO will produce a study calendar of pertinent dates after a transition plan is finalized.
“It’s in our best interests to do everything as quickly as possible,” Godbole said. He added that MISO plans to file Tariff changes by the end of the year. Discussions on queue reform will continue on Dec. 16’s Planning Advisory Committee where no formal action is anticipated. The queue reform proposal will then move into a stakeholder comment period.
WASHINGTON — Having achieved a settlement with Mayor Muriel Bowser’s administration, Exelon and Pepco Holdings Inc. tried to persuade the D.C. Public Service Commission over the course of three days of hearings last week that their nearly $7 billion merger is now in the public interest.
Carim Khouzami, chief integration officer for Exelon, and David Velazquez, Pepco’s executive vice president for power delivery, were among those whom Chairman Betty Ann Kane and Commissioner Joanne Doddy Fort questioned on the details of the settlement. Commissioner Willie Phillips did not ask any questions.
Regulators unanimously rejected the deal in August, finding that it was not in the public interest. The Bowser administration brokered the settlement, which was filed in October. D.C. is the last jurisdiction needed to close the deal, with New Jersey, Maryland, Virginia, Delaware and FERC all having given their approval. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
“In retrospect, we realize that our failure to present a settlement agreement made it a very difficult task for this commission to find the merger was in the public interest,” Peter Meier, vice president of legal services for Pepco, said in an opening statement. “We’re here today because a settlement was agreed to.”
Rate Impact
The D.C. commissioners questioned the officials about the logistics of the settlement: how rate credits would appear on customers’ bills, what the structure of the new company would look like and whose overdue bills would be forgiven.
DC Commissioners at the hearing, left to right: Commissioner Joanne Doddy Fort, Chairman Betty Ann Kane, Commissioner Willie L Phillips (Source DC PSC)
Kane was interested in how the promised credits would protect against rate shock. Exelon promised $14 million in direct credits to residential customers and $25.6 million in credits to offset future rate increases the company expects to file. Kane estimated that the distribution portion of customers’ bills would jump 20 to 30% in 2019 after the $25.6 million ran out.
“Ultimately the rate cases are the determination of the commission [and] what they see as reasonable and prudent,” Khouzami said. But “with this commitment, $25.6 million worth of rates will never be paid by customers.” Without the merger, Pepco would still seek similar levels of rate increases and “customers would still be subject to that without an offset,” he said.
Fort asked how $5.2 million in contributions to district workforce development programs constituted a “direct and tangible benefit” to ratepayers, required to prove the merger is in the public interest.
In a pre-hearing brief, Velazquez said the contribution will provide training to district residents in “sustainable jobs.”
At the hearing, however, the executives were vague about the types of jobs residents would be trained for in the workforce development programs, and what exactly was meant by “sustainable.”
Residents would get “a skill set needed to get a good-paying, secure, sustainable job in the district that will help benefit them for years to come, so I think there’s a true benefit here,” Khouzami said. The companies have not made a firm commitment to hiring residents who participate in the programs, he said in response to a question from Fort. The funds are “really intended to provide the job training needed so that individuals can actually select the job that they want, whether it’s at Pepco or somewhere else in the district.”
“It is my hope that through this program, we’ll also be working with the district and having a discussion about the type of jobs that Pepco will need as we move forward with the grid of the future,” Velazquez said. “These are jobs that are related to helping drive renewable energy, driving energy efficiency, driving microgrids, driving the smart grid. All those things are going to help create a more sustainable electric grid and a more sustainable use of electric energy.”
District Official also Questioned
The director of the district’s Department of Energy and Environment, Tommy Wells, was the first witness questioned by the commission on Wednesday.
The commissioners peppered Wells with questions about how money in the district’s Renewable Energy Development Fund and the Sustainable Energy Trust Fund has been used to make up for shortfalls in the district’s general fund. Under the settlement, Exelon will contribute $3.5 million to each fund.
DC’s Tommy Wells testifies (Source DC PSC)
Wells admitted that transfers from the energy funds, which must be approved by the D.C. Council, are not prohibited under the settlement. But, Wells said, “it is completely in alignment with the plans and vision for this administration to expend those funds exactly as they’ve been negotiated.
“I can’t speak to the whims of the council, but I believe the council” will respect the intent of the administration, Wells said.
Wells, like Khouzami and Velazquez, was also vague about the workforce development funds. Fort asked what agency would receive them.
“That’s a great question because we’re working on that now,” Wells answered. He mentioned the University of the District of Columbia and the Department of Employment Services as possible candidates, but it’s not clear yet if the money would even go to the government, he said. If it does, City Administrator Rashad Young would ultimately decide which agency receives the funds, he said.
Wells also said “sustainable” jobs was meant to refer to both green and long-lasting jobs.
Wells was questioned first at the request of the D.C. government, as he had to catch an afternoon flight to Paris, where he accepted an award for green energy on behalf of the district from the C40 Cities Climate Leadership Group. The group, comprising 78 cities around the world, honored the district for its 20-year power purchase agreement with Iberdrola Renewables that will supply 30% of the government’s electricity through wind power.
The announcement of the award — which was followed by applause in the room — came during the hearing on Thursday, as Pepco cross examined Bruce Burcat, executive director of the Mid-Atlantic Renewable Energy Coalition. Iberdrola is a member of MAREC, which opposes the merger.
Looking Ahead
With the administration and the district’s public advocate on its side, Exelon’s chances appear to hinge on winning over Kane or Fort.
Phillips had issued a partial dissent in August, saying that he would have supported a merger that would have brought “benefits for ratepayers, the local economy and the environment.”
The settlement brokered by the Bowser administration includes $78 million in customer benefits, up from $14 million in the company’s original offer.
Post-hearing briefs are due Dec. 16, with reply briefs due Dec. 23. The record will then close, starting the countdown to a commission decision.
On Monday, four councilmembers sent an 11-page letter to the PSC urging it to reject the deal, saying it offers “short-term benefits that in the long-term have detrimental costs.”
CARMEL, Ind. — Signaling a newfound sense of urgency, MISO officials last week proposed a switch to a two-season capacity market procurement and appointed a team to consider ways to retain merchant generators in Illinois.
Under a draft proposal outlined to stakeholders last week, MISO would obtain capacity based on a four-month summer season (June-September) and eight-month winter (October-May), with separate seasonal resource accreditations, reserve margins and capacity import/export limits.
“We do see the value in two seasons and providing resource adequacy in both summer and winter. This felt like a place that is justifiable,” Laura Rauch, manager of resource adequacy coordination, told stakeholders at a two-day joint meeting of the Supply Adequacy Working Group and the Loss of Load Expectation Working Group.
Officials said the proposal was driven by concerns over the year-round availability of resources such as demand response and generation imports. The RTO, which sets its reserve margins based on a summer loss-of-load probability of one day in 10 years, was awakened to its winter reliability risk in the 2013–2014 season, when forced generation outages peaked at 22 GW, almost 50% above the expected 15 GW.
The two-season proposal, which retains the current June 1-May 31 planning year, appeared to be a compromise between those who favored a four-season procurement, including the Organization of MISO States and the Independent Market Monitor, others who wanted monthly auctions and those who favored the status quo. (See MISO Seasonal Procurement, Site Auctioning Proposals Face Opposition.)
Task Team
The two-day stakeholder meeting also resulted in the announcement of a SAWG “task team” to recommend ways to accommodate merchant generators in MISO Zone 4 in Illinois, which unlike most of the RTO, allows retail choice.
The move followed an Oct. 20 FERC technical conference and a Nov. 19 policy session of the Illinois Commerce Commission on the problems in Zone 4. (See MISO Stakeholder Process Under Scrutiny.)
The formation of the team came over the opposition of some stakeholders who said the RTO should delay action until after the ICC’s second session on the subject, scheduled for this Thursday.
But Jeff Bladen, MISO’s executive director of market design, told stakeholders Wednesday, “These issues are ripe whether we like it or not.
“If there was agreement on anything [at the Nov. 19 session], it was that Illinois is depending on MISO’s markets as the primary mechanism to ensure resource adequacy,” he said. “The process of asking for a task team was a dynamic one. It was a result of Illinois moving forward and describing that MISO needed to more proactively address the issue.”
Bill Booth, of the Mississippi Public Service Commission, asked if MISO will develop rules that would work for both retail choice states and traditionally regulated states.
“Our goal would be to find solutions that are tailored and meet the needs of the states like Illinois with retail choice, but at the same time, we need to ensure that we … meet the needs of non-retail states,” Bladen said.
He said MISO is not looking to change states’ planning processes. “I think what’s been identified in Illinois is a gap,” he said. “It is a very targeted, surgical matter that needs to be tackled.”
Illinois Senior Assistant Attorney General Susan Satter told stakeholders that the creation of a team could be “somewhat premature.”
“It sounds like Illinois has directed MISO to address this … I think there were several avenues that were being discussed and explored. So I think it needs to be kept within that perspective,” Satter said.
Kevin Murray, chair of MISO’s Advisory Committee, objected to the creation of a task team, arguing that stakeholders should have been given advance notice of a vote to create a group.
Supporters cited SAWG rules, which they said do not require a vote to form a task team. “This is a topic that pretty well suits the business for what a task team does,” said SAWG Chairman Brian Glover, markets compliance and policy analyst for Great River Energy.
Urgency Needed
Glover said he favored “reaching a productive end” instead of inaction and delays.
Marka Shaw, director of wholesale market development for Exelon, also called for urgency. “There are retirements occurring in southern Illinois,” she said. Dynegy cited a poorly designed capacity market in Illinois when it announced last month that it would close its 465-MW Wood River Power Station in 2016.
The task team is expected to have an approximate six-month lifespan and convene in time to deliver preliminary recommendations at the next SAWG meeting in January.
Shoulders Ignored?
Shaw was among several stakeholders who complained that the proposed two-season capacity structure ignores the spring and fall shoulder periods, when peaks are much lower.
Shaw said a planning auction modeled after two seasons isn’t feasible in states with deregulated markets. “What MISO’s doing here just won’t work for what we’re doing in Illinois. We’re going to be requesting something different,” she said.
The draft plan says MISO’s current structure does “not explicitly ensure transparency or sufficiency of resource adequacy throughout the year. In addition, stakeholders expressed an interest in a less-than-annual requirement to account for the seasonal diversity, thus providing additional flexibility to meet load and reserve obligations.”
MISO noted that several other regions also have addressed concern about winter reliability, citing ISO-NE’s Pay-for-Performance and PJM’s Capacity Performance programs.
MISO’s recommendation calls for retaining the system-wide summer reserve margin (0.1 day/year LOLE risk) while setting the winter requirement based on a “negligible” one day in 100 years or 0.01 day/year LOLE.
The same targets would apply for local resource zones “if the zone’s base model indicates zero LOLE risk in the winter season. If a zone’s base model annual LOLE risk results in winter LOLE risk, then the annual LOLE will be driven to 0.1 day/year LOLE risk without deterministically dictating where the LOLE risk is distributed.” The analysis would include seasonal capacity import and export limits.
MISO said it was unaware of other regions using season-specific reserve margin requirements.
The RTO would accredit resources based on continued use of the single real power test but using seasonal interconnection service for capacity accreditation, and with seasonal ratings for load modifying resources and intermittent generation. It also would reflect outages through a total capacity availability rate (“seasonal EORp”).
Stakeholder feedback on the draft proposals is due Dec. 17. Design review of the constructs will begin in February with MISO unveiling proposed Tariff language. Tariff filings with FERC are targeted for March.
[Editor’s Note: A prior version of this article contained an incorrect link to the draft document mentioned in paragraph 2.]
FirstEnergy said Tuesday it has reached a proposed settlement with Public Utilities Commission of Ohio staff that would provide guaranteed income for eight years for two of the company’s merchant generating stations and for the portion the company owns of two other plants.
FirstEnergy has said that it needs the income guarantees, in the form of power purchase agreements for its Davis-Besse Nuclear Power Station, the W.H. Sammis coal-fired plant and its share of Ohio Valley Electric Corp.’s generation output, to keep them profitable. Without the guarantees, it said, it might have to retire the plants, threatening system reliability.
Sixteen parties, including PUCO staff, a low-income advocacy group, Ohio Partners for Affordable Energy and other civic groups, signed on to the proposed settlement filed with the commission Tuesday (14-1297-EL-SSO).
But several other organizations, including the Office of the Ohio Consumers’ Counsel (OCC), have refused to sign on to what they decried as a “bailout” and joined in a motion to reopen the record.
“PUCO’s staff decision to move forward with a backroom deal to bailout FirstEnergy’s aging power plants is insulting to Ohio utility customers,” said Daniel Sawmiller of the Sierra Club of Ohio, which dropped out of the settlement negotiations in protest last week.
FirstEnergy’s first proposal, which PUCO staff rejected earlier this fall, called for income guarantees for 15 years. This proposal seeks income guarantees for eight years.
According to the proposal, ratepayers would pay FirstEnergy if its generators were not profitable based on their capacity and energy sales in the competitive market. The company contends that in the long run, the plants will be able to produce power more cheaply, and any income over cost would be returned to ratepayers.
It estimates that under its new proposal, residential ratepayers would pay an extra $3.25 to $3.50 a month during the first year. Over the eight years of the plan, the company says, it will produce savings of about $560 million.
“The settlement filed by FirstEnergy’s Ohio utilities — Ohio Edison, The Illuminating Company and Toledo Edison — outlines ambitious steps to safeguard customers against retail price increases in future years, deploy new energy efficiency programs, and provide a clear path to a cleaner energy future by reducing carbon emissions,” the company said in a statement.
The proposal also includes a “goal” to reduce carbon dioxide emissions from FirstEnergy’s generating fleet by at least 90% below 2005 levels by 2045 regardless of whether EPA’s Clean Power Plan survives court challenges.
It also promises $102 million in assistance to low-income customers and energy efficiency programs.
Sawmiller blasted the proposed settlement.
“Over months of public hearings, there was no credible evidence presented that this bailout furthers any public interest. The shortened timeline has an even more negative impact, front-loading the handout to FirstEnergy and its shareholders while saddling customers with a cost that could run into billions. This deal provides no path for transitioning to a cleaner, more affordable clean energy economy and should be flatly denied by the PUCO.”
The Consumers’ Counsel and the Northeast Ohio Public Energy Council (NOPEC) also opposed the agreement.
“OCC and NOPEC’s expert preliminarily projects that the new PPA proposal will cost consumers approximately $3.9 billion,” reads a joint statement from the two groups. “And the settlement’s impact on Ohioans’ electric bills does not end with the PPA charges: the settlement contains a virtual holiday wish list of favorable ratemaking for FirstEnergy.”
Chuck Keiper, NOPEC executive director, noted that some of those that signed on to the agreement would receive payments from FirstEnergy in exchange.
“The use of financial inducements to obtain buy-in of some intervenors for pennies on the dollar compared to the billions we project the utility will collect from other customers is, frankly, a terrible way to develop public policy,” he said. “It is our sincere hope that the PUCO commissioners will do the right thing and reject this settlement,” he said.
Consumers’ Counsel Bruce Weston also was critical of the settlement agreement. “Consumers should not be charged a penny more than the cost of power in the market,” Weston said in a statement. “FirstEnergy’s proposal comes at a time when Ohioans already are paying more for electricity, on average, than consumers in 32 other states,” he said.
The PJM Power Providers Group (P3) and the Electric Power Supply Association also criticized the deal, with P3 President Glen Thomas saying PUCO staff’s “about face” represents “corporate welfare at its worst.”
“If FirstEnergy is so sure this is a good deal for consumers, they should make public the information underlying its claims and provide iron clad corporate guarantees that consumers will actually receive the promised net benefits,” said EPSA President John Shelk.
Although PUCO staff approved the settlement, it still needs approval of the commission. FirstEnergy said it expects the commission to hold hearings on the proposed settlement early next year.
But it may face tough going.
Earlier this year PUCO’s new director, Andre Porter, criticized FirstEnergy and American Electric Power, which has a similar proposal before the commission, for raising the threat that reliability will suffer without income guarantees for their generation. “Let’s stop attempting to scare Ohioans,” Porter said at the time. “We’re going to continue to have reliable power” with or without guarantees, he said.
A transmission developer is asking PJM to determine if four projects in the Public Service Electric and Gas territory in North Jersey are still necessary if Consolidated Edison of New York makes good on its threat to terminate the “PSEG wheel” to route power into New York City.
Writing on behalf of Linden VFT, GE Financial Services asked PJM Nov. 16 for a reevaluation of the projects, given the “likely termination” of the wheel in 2017.
“We also request that PJM consider directing PSEG to cease work on the projects until careful reconsideration can be completed,” Linden VFT said.
Con Ed told PJM last month it will end use of the wheel when its current term expires on April 30, 2017, if it doesn’t win relief in a cost allocation dispute. (See Con Ed: Cost Allocation Dispute Could End PSEG Wheel.)
The four projects, part of the Regional Transmission Expansion Plan, include the Sewaren storm-hardening project, two sections of the Bergen-Linden Corridor and the Edison Rebuild.
Linden VFT is the owner of a 315-MW merchant transmission line in northern New Jersey that connects to NYISO on Staten Island. PJM has assigned it $100 million as its share of the project costs. “Linden VFT strongly believes it will not receive benefits from the projects [that] are roughly commensurate with the costs it is being asked to shoulder,” it wrote.
Linden also asked that if PJM determines the projects are still needed without the wheel, it should explore if there are less expensive alternatives.
Salem and Hope Creek Nuclear Reactors on Artificial Island. (Source: Wikimedia Commons)
FERC ruled Tuesday that PJM’s cost allocation schemes for the Artificial Island and Bergen-Linden Corridor transmission projects may be unjust and unreasonable, ordering a technical conference to probe the issue.
The technical conference will “explore both whether there is a definable category of reliability projects within PJM for which the solution-based DFAX [distribution factor] cost allocation method may not be just and reasonable, such as projects addressing reliability violations that are not related to flow on the planned transmission facility, and whether an alternative just and reasonable ex ante cost allocation method could be established for any such category of projects,” FERC said in its order (EL15-95).
Those wishing to participate may submit their requests by Dec. 18.
FERC accepted PJM’s Tariff changes involving the cost allocations but suspended them pending the outcome of the technical conference.
Under PJM’s rules, the cost of lower voltage facilities such as the Artificial Island and Bergen-Linden projects is computed up using the solution-based DFAX method. For regional facilities or “necessary lower voltage facilities,” only half of the cost is allocated by DFAX, with the remaining expense distributed on a region-wide, postage-stamp basis.
In the case of the Bergen-Linden project, Consolidated Edison of New York and Linden VFT had complained to FERC that the DFAX method was inappropriate and assigned a disproportionate percentage of the cost to Linden, which would receive “negligible benefits.” (See Con Ed Rebuffed Again on NJ Cost Allocation Dispute.)
Similarly, state agencies representing consumers in Maryland and Delaware, along with Easton Utilities Commission, Old Dominion Electric Cooperative and Linden VFT, argued that it was unfair to bill those states’ customers for virtually all of the $146 million price tag of the Artificial Island project, designed to fix a stability issue at the Salem and Hope Creek nuclear plants in New Jersey.
The DFAX methodology generally identifies reasonable beneficiaries of reliability projects based on power flows, it said. The Artificial Island project, however, is a stability fix, in which power flow is not the derived benefit.
The $1.2 billion Bergen-Linden project intends to upgrade a short-circuit problem in the Public Service Electric and Gas transmission zone outside New York City. PJM assigned $629 million of the cost to Con Ed and $52 million to PSE&G.
Responding to the ruling, PJM said, “FERC has determined that overall, the current method of allocating the costs of transmission projects is just and reasonable. However, in certain instances, the allocations led to complaints that individual results were unjust and unreasonable.
“Therefore, PJM will be pleased to support the FERC’s process to explore alternative cost allocation methods for projects that may not fit into the current process.”
FERC’s order was welcomed by Delaware Gov. Jack Markell.
“This FERC decision is an important first step to protect Delawareans from a significant electric rate increase,” he said in a statement. “I want to thank the FERC for its review and very sensible conclusion that the costs of a project designed to maximize power production and improve reliability in New Jersey should not fall entirely on Delaware and Maryland consumers.”
Connecticut regulators released a draft decision Tuesday approving Iberdrola USA’s $3 billion acquisition of UIL Holdings, adding a requirement that UIL’s headquarters remain in the state indefinitely.
With its “proposed final decision,” the Connecticut Public Utilities Regulatory Authority appears poised to give final approval next month to the Spain-based conglomerate’s second try to acquire UIL. The companies withdrew their initial application in June when PURA indicated it was likely to deny it.
“The authority concludes that the applicants have met their burden of proof that the proposed transaction, as presently structured, is in the public interest,” PURA wrote in the draft. UIL is comprised of The United Illuminating electric distribution company and two natural gas distribution companies in Connecticut, and two natural gas distribution companies in Massachusetts.
The regulators required Iberdrola to amend its settlement agreement with the state Office of the Consumer Counsel to include a promise to keep UIL’s headquarters in Connecticut for as long as it owns it. The companies had committed to a minimum of seven years.
“The authority sees the applicants’ commitment to maintaining its headquarters in Connecticut as meaningful and an integral aspect of this approval. Having a physical presence in the state enables more effective local management of the day-to-day operations of Connecticut-based utilities,” PURA said.
Otherwise, the draft largely mirrors the settlement agreement, which was filed in September. The companies agreed to “ring-fencing” to protect the Connecticut operations from any financial risks from Iberdrola’s other domestic or international operations — addressing a concern that helped doom the initial filing. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)
PURA also required the companies to provide a more detailed post-merger plan on their commitment to hire 150 people in Connecticut, saying “the details of the hiring plan are weak at this time.”
The settlement provides $40 million in ratepayer credits to existing electric and gas customers; approximately $45.4 million in rate freezes and avoided costs related to pipeline upgrades and system hardening; and approximately $39 million in public benefits from environmental remediation, charitable contributions and customer disaster relief, the draft says.
The companies previously agreed to a consent order with the state’s Department of Energy and Environmental Protection that would allow the contaminated English Station site in New Haven to be cleaned up for reuse. (See Iberdrola, UIL Would Clean Up Site if Connecticut Acquisition Approved.) The draft reiterates that the estimated $30 million in cleanup costs will come from shareholders and not ratepayers.
Parties to the PURA proceeding have until Dec. 1 to submit written comments on the proposed decision. The PURA commissioners are scheduled to hear oral arguments on the case on Dec. 3 and plan to render a final ruling on Dec. 9.
Iberdrola said last week it plans to change its U.S. holding company’s name to Avangrid following the UIL merger, but the names of the local distribution companies, including New Haven-based United Illuminating, would not change.
Ontario’s Independent Electricity System Operator serves a population of 13.8 million, almost 40% of Canada’s total population, making it nearly equivalent in population and peak demand to ISO-NE.
After peaking about a decade ago at almost 160 TWh, Ontario’s annual electricity use has dropped to 140 TWh — equivalent to that in 1990 — as growth has been offset by conservation, distributed generation and a decline in the pulp and paper industry. Loads are not expected to rise until 2028.
Nuclear power, now 60% of the province’s generation output, is expected to drop to 40% by 2025 following the retirement of the 3,252-MW Pickering plant. Two other nuclear plants with a combined 8,400 MW of capacity, Bruce and Darlington, are scheduled to be refurbished from 2016 to 2032.
Because of the lost nuclear output, the province will need to add as much as 3,000 MW of capacity between 2021 and 2032.
Prices
As in New England, prices are relatively high, and that has prompted frequent interventions from government.
Sergio Marchi, president of the Canadian Electricity Association, lamented that Canada’s electric rates are much more politicized than in Europe. “Electric rates, rightly or wrongly, have become a go-to tool to clobber the incumbent government.”
“I’m really surprised that Ontario ratepayers aren’t up in arms with pitchforks and the like,” said Jason Chee-Aloy, a consultant and former director of generation procurement at the Ontario Power Authority. “I think that is going to be an issue in the next election because we’ve baked in a lot of these costs.”
Jasmine Bertovic, vice president and general manager for eastern energy at TransCanada, said opening the market to more imports would provide price discipline.
The province is a net exporter with Michigan (46%) and New York (39%) its biggest export markets. About 85% of its imported power comes from Quebec.
“When you tie yourself to another jurisdiction and now you’re competing beyond Ontario … it is another check on your market. … It can’t be a check valve. It has to be open seams, open import-exports.”
Cap and Trade
Canada’s electricity system is among the cleanest in the world, says Marchi, noting that 80% of its generation does not emit greenhouse gases. That compares, he said, with Germany (41%), the U.S. (31%) and Japan (15%).
In 2017, Ontario plans to begin trading emissions through cap-and-trade auctions. The first auction will be for the province only, but Ontario plans to link its prices to those of California and Quebec, which already trade allowances. The province’s goal is to reduce CO2 to 15% below 1990 levels by 2020.
A U.S. District Court judge has dismissed a suit that sought to overturn Virginia’s 1982 moratorium on uranium mining.
The Department of Energy and Israel’s Ministry of National Infrastructure, Energy and Water Resources chose six joint American and Israeli clean energy projects to receive $5.1 million in funding. Energy Secretary Ernest Moniz said the Binational Industrial Research and Development Energy Program will help both countries develop cleaner energy.
