Still hoping to win approval for its proposed revamp of capacity market rules, PJM asked the Federal Energy Regulatory Commission Tuesday to delay the May 11-15 Base Residual Auction.
PJM’s filing Tuesday asked for permission to delay the BRA until 30 to 75 days after a commission order on the merits of the proposal, but no later than the week of Aug. 10-14 (ER15-1470).
The RTO requested that the commission act on its request by April 24, with comments due by April 14.
Andy Ott, executive vice president for markets, will brief the Market Implementation Committee at about 10:30 a.m. Wednesday on the RTO’s plans for responding to the deficiency order.
Five transmission projects intended to serve New York City and respond to a potential nuclear plant closure suffered setbacks last week as a divided Federal Energy Regulatory Commission rejected the developers’ cost allocation proposals and reduced their requested returns on equity (ROE).
The commission granted some of the developers’ requests for ROE incentives but ordered settlement and hearing proceedings on proposed formula rates, protocols and the base ROE (ER15-572).
On Dec. 4, NYISO proposed a cost-of-service formula rate template and formula rate implementation protocols on behalf of New York Transco, comprised of affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric.
The companies submitted five projects in response to competitive solicitations issued by the New York Public Service Commission.
Two AC projects, the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to alleviate congestion on transmission lines serving the New York metropolitan area. (See Tx Plan to Open NY Choke Points Without New ROWs.)
The other three “Transmission Owner Transmission Solutions (TOTS)” projects were designed to address reliability concerns expected if the Indian Point nuclear plant closes. NYISO and the transmission owners sought an April 3 effective date on their proposed formula rate, protocols, cost allocations and 10.6% base return on equity.
The commission:
Granted requests for construction work in progress, abandonment and pre-commercial cost recovery incentives, and a 50-basis-point ROE adder for membership in an RTO, subject to a cap within the “zone of reasonableness,” to be established through the hearing procedures.
Approved an ROE adder for risks and challenges for the Edic-Pleasant Valley 345-kV line while rejecting it for the Oakdale-Fraser 345-kV line and the TOTS projects.
Ordered the applicants to revise sections 3(e)(ix) and 4(b) of the formula rate protocols, as requested by the New York Association of Public Power, to provide more transparency. The commission said it was concerned with the allocations of shared plant or expense items between members of NY Transco and their parent companies.
Rejected the cost allocation for all five projects.
Denied applicants’ request for an ROE adder for being a transmission company. The commission said NY Transco’s members were not “sufficiently independent” to merit incentives, noting that they serve 84% of the state’s load and own 64% of its high voltage transmission and 4% of its generation capacity.
Ordered hearing and settlement procedures on NY Transco’s proposed formula rates, protocols and base ROE, including components of the formula rate and the allocation of various expenses between the TOs and NY Transco. The commission ordered appointment of a settlement judge within 15 days and a report on the status of negotiations by May 4.
Dissents on Capital Structure
The majority also rejected applicants’ request for a “hypothetical” capital structure incentive of 60% equity and 40% debt for all five projects, instead approving a 50/50 structure.
NY Transco said it would use its actual capital structure in the formula rate after the projects are placed into service but that the hypothetical capital structure would improve its credit rating, reducing financing costs by $168 million compared with a 50/50 structure.
The majority said it agreed with protests by the PSC and others that the 60/40 capital ratio is “excessive for an entity such as NY Transco, whose affiliates … will construct the projects and perform the maintenance and physical operation of the NY Transco assets.”
That sparked a partial dissent by FERC Chairman Cheryl LaFleur and Commissioner Philip Moeller. “Today’s order does not merely apply an overly rigid approach to evaluating these capital structures; the majority has failed to provide any criteria or guidance as to how the commission will evaluate these capital structures going forward,” they wrote. “We believe the applicants demonstrated the required nexus between the need for the requested hypothetical capital structure and the facts of this particular case, and we would have granted the requested transmission incentive.”
LaFleur and Moeller also said the additional proceeding adds “needless uncertainty” to efforts to expeditiously build transmission infrastructure.
Cost Allocation
The commission rejected the cost allocation method for the AC and TOTS projects because it imposed costs on the New York Power Authority and the Long Island Power Authority, both public entities that have not been allowed to join NY Transco.
The PSC said the cost allocation proposal it initially supported included the voluntary participation of LIPA and NYPA, and covered 18 transmission projects throughout the state. NY Transco was originally planned as a six-party Transco, which included NYPA and LIPA, but the New York state legislature refused to allow NYPA permission to participate.
NYPA serves municipal systems throughout the state, but NY Transco’s cost allocation proposal would have assessed its municipals located upstate at the same rate as downstate municipals. “Grossly inequitable situations would arise where a NYPA customer located in the Rochester region would be allocated 16.9% of the costs while another [Rochester Gas & Electric] customer located across the street … would be allocated only 8.9% of the costs,” the commission said.
Because NYPA and LIPA have not accepted the cost allocation method, it cannot be considered a “participant funding method,” the commission said.
The applicants had proposed to allocate the costs of the three TOTS projects using an adjusted load ratio share approach, with 75% of the costs allocated to transmission districts southeast of the UPNY/SENY constraint and 25% allocated to upstate districts, a departure from the default ratio for public policy projects (60% downstate, 40% upstate). The PSC adopted a 90% downstate/10% upstate cost allocation for the AC projects.
The commission said the AC projects could qualify for regional cost allocation if the PSC decides they should be evaluated under NYISO’s Order 1000 public policy transmission planning process and the ISO selects the projects in the regional transmission plan.
Because the TOTS projects were evaluated by the PSC before NYISO’s Order 1000 transmission planning process, the ISO must reevaluate and select them to be eligible for regional cost allocation, the commission said.
Alternatively, the commission said the applicants may submit a revised allocation shared only by entities that agree to pay, “either by renegotiating the cost allocation with LIPA and NYPA or by allocating the costs solely among those transmission developers participating in the NY Transco.”
AC Projects
The commission said the 153-mile, Edic-Pleasant Valley 345-kV line deserved a risk-reducing incentive because it would relieve transmission congestion on existing lines by 41% in 2022.
The project would connect National Grid’s Edic substation in Oneida County to Con Edison’s Pleasant Valley substation in Dutchess County, entirely within existing rights-of-way. The project, including three new substations, would move an additional 1,000 MW from central New York to the southeast region. The line is expected to reduce transmission congestion costs, line losses and installed capacity costs by a net present value of almost $1.3 billion to $4.5 billion over 10 years.
The commission rejected such a bonus for the Oakdale-Fraser 345-kV project, saying it was not convinced it relieved “chronic and severe congestion.” The project would add a second, 57-mile 345-kV line between the Oakdale and Fraser 345-kV substations.
Indian Point Contingency
The three TOTS projects were approved by the PSC as a contingency plan for the loss of Entergy’s Indian Point nuclear plant. Entergy told investors last year it would consider shutting down the plant’s two units if it can reach a “constructive” settlement with state officials.
The transmission projects, which have an in-service deadline of June 1, 2016, are the:
Fraser-Coopers Corner project, estimated at $66 million, which will increase power transfer by reducing series impedance over the existing 345-kV Marcy South transmission lines;
Ramapo-Rock Tavern project ($121 million), which will add a second 345-kV line from Con Edison’s Ramapo 345-kV substation to Central Hudson’s Rock Tavern 345-kV substation; and
Staten Island Unbottling Project ($262 million), which involves transmission upgrades to Con Edison’s interconnecting 345-kV transmission line with Cogeneration Technologies Linden Venture, to allow generating facilities located on Staten Island to export power to the rest of New York.
PJM has asked the Federal Energy Regulatory Commission to untangle the question of how profits from trades that are determined to be illegal get calculated and refunded (IN15-5).
In a filing Wednesday, PJM Associate General Counsel Jacqulynn Hugee referenced a March 6 Order to Show Cause and Notice of Proposed Penalty requiring City Power Marketing and trader K. Stephen Tsingas to explain why they shouldn’t be sanctioned for up-to-congestion (UTC) trades investigators contend violate the Federal Power Act. Hugee filed a similar request in the case of hedge fund twins Rich and Kevin Gates and Houlian “Alan” Chen (IN15-3).
FERC Office of Enforcement staff alleges that the City Power trades resulted in profits of $1,278,358 and recommended that the profits be refunded. The staff also recommended that City Power be fined $14 million and Tsingas $1 million. The refunds and penalties are pending a final ruling by the commission. Tsingas and City Power have until April 6 to answer the charges.
PJM, in anticipation of a determination against Tsingas and City Power, wants to know just who gets the refunds and how they are to be calculated.
Handling the refunds, Hugee noted, could be complicated. She noted that although the March 6 orders don’t say so, usually it is the RTO involved that is tasked with refunding any profits to market participants.
If PJM is ordered to do so, Hugee wrote, the calculations necessary to complete the refunds through the usual month-end billing adjustments “can be very time consuming, taking weeks or months to complete.” She asked that the commission order the refunds be made based on Tsingas’ and City Power’s activity “on an hourly basis, per operating day,” rather than a lump sum that would have to be split up on a pro-rata basis. She asked FERC to do those calculations.
Hugee also sought direction on how refunds should be made to parties who are no longer PJM members and asked that if any former members are due refunds but still owe money to PJM, the refunds be used to clear that debt first.
She noted that there were six entities also alleged to have engaged in sham trades, who would also be considered victims of the City Power/Tsingas trades. “PJM asks that the commission indicate in its order whether these six entities are entitled to receive the portion of the disgorged funds that are due to be refunded to them or whether they should be excluded from any such refunds,” she wrote.
CEO Christopher Crane outlined Exelon’s position on distributed generation, shared his vision for the distribution company of the future and provided insight into the financial struggles faced by the firm’s nuclear power plants during two days of testimony before the D.C. Public Service Commission this week on the proposed $6.8 billion acquisition of Pepco Holdings Inc.
CEO Chris Crane (Source: DC PSC)
“There has to be an equity conversation not only about the microgrid, but the cost of the infrastructure,” Crane said. “We support distributed generation. But the other side of getting in on all this new, neat technology is that we keep people whole. We need to be mindful of the load profile that the generation is going to serve. You can get to a position where you’ve overbuilt and inequities come out of that.
“Who’s going to bear the expense? Is the solar power provider going to contribute to that, or is it going to be on the back of other customers?”
Asked by Commissioner Joanne Doddy Fort to describe the role of the distribution company going forward, Crane — who earlier said the industry’s technology has advanced more in the past few years than in his entire career — replied that it was about adapting.
“We’re trying to define the approach that we’re taking with the utilities,” he said. “To deny it and stay in the old utility ways reduces the relevance that the company can have.”
To that end, Exelon has directed research teams to work with such groups as the Edison Electric Institute and the U.S. Energy Department’s National Labs to identify emerging technologies.
“I do believe in 10% penetration in distributed generation,” he said. “That could be a great opportunity to redesign the operating model to support those microgrids going on.”
In addition, he said, Exelon is investing in storage companies.
Before facing questions from the three commissioners, Crane was grilled by two staunch critics of the planned acquisition: the D.C. Office of People’s Counsel and the D.C. government, both of whom delivered stinging opening statements. (See CEO Crane to DC PSC: Committed to Jobs, Ratepayers.)
Both cautioned the commissioners that the sale of Pepco would have far-reaching consequences.
“While this is not a ‘rate case,’ any decision emanating from this case will largely predetermine the parameters of the next filed rate case,” OPC said. “Second, public participation and concern over the proposed acquisition has been unprecedented.”
An approval, OPC said, “will not only impact every proceeding involving Pepco, it will potentially impact the legislative initiatives that currently exist concerning renewables and distributed generation. The order approving this merger will not be static document. It will serve as a guidebook that will be referred to for decades to come.”
Perhaps the most important question, it said, “is this: If the takeover is approved and it becomes apparent thereafter that Exelon’s priorities are not aligned with the city’s priorities, what ability will this commission have to address the conflict?”
Attorney John Coyle, representing the city government, said “If you approve this proposed merger, it is likely to be the last, as approval would place the retail supply of electricity between the Schuylkill and the Potomac under a single company — albeit one run from Chicago and having merchant generating interests that span the country.
“Sixteen years after this commission approved Pepco’s divestiture of its generation, which divestiture contributed to the development of a reasonably robust market for wholesale electric power, you now find yourselves asked to approve a reconsolidation that brings generation back to the same corporate ‘family’ that runs the District’s transmission and distribution infrastructure.”
Coyle questioned the timing of the deal, which comes as Exelon is struggling to maintain three money-losing nuclear reactors in its home state of Illinois, where it is pushing legislation that would impose a surcharge on electricity customers. [Editor’s Note: An earlier version of this article mistakenly put the number of money-losing reactors at six.]
“No business pays a $1.6 billion premium over market price (in a $6.8 billion stock purchase transaction) for the privilege of generating 2.1% of the $1.6 billion in savings over 10 years, and then giving the claimed savings away.
“Any analyst who has looked at this transaction has expressed the understanding that its point is to acquire a great deal of reliable, regulated cash flow to ease the costs of Exelon’s generating fleet — and particularly its nuclear assets — over the shoal of wholesale power market prices depressed for the time being by the availability of shale gas and oil in unprecedented quantities and at unusually low prices.”
Under questioning, Crane said that Exelon last year lost $100 million alone on its Clinton reactor.
Under the current market design, Crane said, revenue is not sufficient to maintain its six underperforming nuclear plants.
“The quick business decision would be to shut the units down,” he said.
“But, we have the responsibility also of what that would mean to the community,” he said, noting that the Clinton generator significantly supports the tax base of DeWitt County. “We have a commitment not to act too quickly but to work with stakeholders to come up with a market-based fix.”
Regardless, he said, Exelon’s motive in acquiring Pepco is not to shore up its nuclear fleet.
“The generation company overall is profitable,” he said. “It maintains a strong balance sheet. We’re not limping along on the generation company — we have assets that are under-earning or losing money.
“Just so we have the characterization right, this is not a broken car. This is an entity with assets that are losing money, and you find out how to fix it or shut them down. We do not need the regulated revenue to fund or make up for any of that challenge.”
D.C. and Maryland are the last holdouts to the transaction. The acquisition has been approved by the New Jersey Board of Public Utilities, the Federal Energy Regulatory Commission, the Virginia State Corporation Commission and the staff of the Delaware Public Service Commission.
The evidentiary hearings, which are being webcast, continue through April 8 in D.C. and are scheduled for April 15-17 in Maryland.
A Federal Energy Regulatory Commission settlement judge on March 27 certified an uncontested proceeding to reduce transmission owner Niagara Mohawk Power’s return on equity to 10.03% from the current 11.5% (EL12-101, EL13-16, EL14-29).
Niagara Mohawk, a unit of National Grid, reached the agreement with the Municipal Electric Utilities Association of New York, the New York Association of Public Power and the Allegheny Electric Coop. (See FERC Staff Endorses Niagara Mohawk ROE Settlement.) As a result of the settlement, the hearing ordered by the commission last year will not be necessary.
New England power generators asked a federal appeals court to overturn Federal Energy Regulatory Commission orders that accepted ISO-NE’s change to a sloped demand curve in advance of this year’s Forward Capacity Auction.
NextEra Energy Resources, NRG Energy and Public Service Enterprise Group filed a petition for review Monday in the D.C. Circuit Court of Appeals.
A year ago, ISO-NE and the New England Power Pool Participants Committee jointly filed revisions to the RTO’s Tariff to establish a system-wide sloped demand curve for the Forward Capacity Market, which were accepted by FERC (ER14-1369). A rehearing request of what became known as the Demand Curve Order was denied by FERC on Jan. 30.
ISO-NE formerly used a vertical demand curve, which produces a single clearing price for all cleared resources at the point where the demand and supply curves intersect. Before the eighth Forward Capacity Auction in February 2014, ISO-NE determined a potential for a capacity shortage, which would invoke administrative pricing provisions in the Tariff. Capacity prices in FCA 8 tripled to about $3 billion.
In response to a FERC order just prior to FCA 8, ISO-NE posited that a sloped demand curve would be a long-term solution, eliminating the need for administrative pricing rules.
In filings last year, PSEG asserted that the sloped curve failed to meet the one-day-in-10-years loss-of-load expectation.
Judge Hears Arguments on Gas System Expansion Lawsuit
A Superior Court judge this week heard arguments as to why he shouldn’t allow a lawsuit against the state Department of Energy and Environmental Protection (DEEP) to go forward. The Connecticut Energy Marketers Association, which represents the fuel oil industry, sued DEEP last fall, saying the agency failed to do a full environmental assessment of a plan that allows natural gas companies to expand their networks.
That plan would allow 300,000 homes to switch to natural gas for heating, as opposed to fuel oil. The state Attorney General’s office filed a motion to have the suit thrown out, saying the proper target should be the utilities, not the state. The gas expansion program was approved by the Public Utilities Regulatory Agency in 2013.
DEMA Distributing Potassium Iodide Pills to Residents near Artificial Island
The state Emergency Management Agency next week will distribute potassium iodide tablets to residents who live within 10 miles of the nuclear stations on Artificial Island, across the Delaware River in New Jersey. The tablets are an in case of an emergency to limit radiation absorption in the event of an incident at the Salem or Hope Creek generating stations.
Duke Gives $1 million for Battery Storage Research Center
Spurred by a settlement reached on cost overruns at its Edwardsport gasified coal plant, Duke Energy is contributing $1 million to fund research at the Battery Innovation Center, which is developing ways to incorporate battery storage into small solar and wind facilities. Part of the money will go toward installing battery storage systems at two schools.
Battery storage is seen as one part of the answer to a problem experienced by solar and wind facilities: what to do with extra electricity generated by the facilities in times of low demand? If a workable way is found to store the energy for use when demand is higher, it would make renewable energy that much more valuable.
“Technology that can store energy is a way to advance renewable energy sources such as wind and solar, which are clean, but not always available when power is needed,” Duke Energy Indiana President Doug Esamann said.
Outgoing IUB Member Criticizes Gov. for Pushing Her Out
Tipton
Utilities Board member Sheila Tipton criticized Gov. Terry Branstad for removing her, saying he was pandering to utilities and making the move to “appease MidAmerican Energy.” Tipton recently voted to require MidAmerican to use some of its $280 million wind energy proceeds to offset customer rates. Tipton, who used to represent MidAmerican in her private legal practice, said the governor’s decision to remove her from the board and demote the chair, Elizabeth Jacobs, was a “disservice to the citizens of this state.”
“Administrative agencies, including the Iowa Utilities Board, are intended to be independent and not subject to political pressures or threats of retaliation,” she wrote in a letter to Branstad, hand-delivered on March 18. “Yet, in replacing me and demoting Chair Jacobs, the message being sent to the board and its staff is to get in line and approve anything that the utilities, particularly MidAmerican, bring to it.” Before his election to governor, Branstad was a MidAmerican board member.
Higgs’ PSC Nomination Stalls as Session Ends with no Action
Michael L. Higgs Jr. (Source: Shulman Rogers)
The state Senate Executive Nominations Committee ended its final meeting of the legislative session without acting on the nomination of Republican Michael Higgs to the Public Service Commission. A spokesman for Gov. Larry Hogan said the governor had asked that action on the nomination be delayed until the commission had decided on Exelon’s proposed acquisition of Pepco Holdings Inc. But some senators have raised concerns about several off-color messages Higgs posted on a since-deleted Twitter account about Hillary Clinton and “illegal alien immigrants.” Higgs told the Washington Post that the old messages didn’t undermine his ability to serve on the commission.
PSE&G, BPU Staff, Rate Counsel Reach Settlement on Efficiency Plan
Public Service Electric and Gas has reached a settlement with the staff of the Board of Public Utilities and the Division of Rate Counsel to spend $95 million on energy efficiency programs. The utility’s program allows for institutions, non-profits and multifamily housing units to apply for grants and no-interest loans to install energy efficiency devices to allow for savings on their bills.
The settlement allows PSE&G to recover the $95 million, along with $12 million in associated administrative and technology costs, from ratepayers through an adder on electric and gas bills. The typical residential customer would see electric bills increase by about 40 cents a year and gas bills by about 64 cents a year. The utility originally asked for approval for $109.8 million but reached the lower number through the settlement. The agreement still needs the approval of the full board.
“It’s a reasonable price for the services they will deliver,’’ Rate Counsel Director Stefanie Brand said.
XTO Energy is asking that 140 of its oil wells be exempted from rules prohibiting gas flaring because it can’t deliver the gas to a processing facility. It says the company that was to process the gas, a byproduct of drilling, was unable to secure an easement necessary to build a 20-mile pipeline to collect and deliver the gas to its processing plant.
The Industrial Commission’s Oil and Gas Division received the request last week and forwarded it to the full commission for a ruling. OneOK, the gas processing company, said the pipeline would have moved 40 million cubic feet per day. XTO is asking for the gas-flare exemption until 2016, when a different processing facility will be ready to accept the gas.
Kasich swears in Johnson as chairman of PUCO, one year ago this month.
Public Utilities Commission Chairman Tom Johnson announced this week that he would step down as head, but he will serve the rest of his term as commissioner, until 2019. Johnson sent a letter to Gov. John Kasich, citing personal reasons for stepping down. While he only headed the PUCO for a year, he oversaw a controversial decision denying American Electric Power’s request to receive ratepayer-guaranteed profits for one of its Ohio coal-fired plants. That was seen as a crucial ruling, as it was the first of a salvo of similar requests from AEP and FirstEnergy before the commission.
Johnson will remain as chair until a replacement is found. State energy watchers suspect the likely candidate is Andre Porter, the state Director of Commerce who returned to PUCO last month.
DEP Schedules Hearing for Shell Petro Project in Beaver County
A petrochemical project proposed for Beaver County by Shell Chemical took a step forward this week when the state Department of Environmental Protection scheduled a public hearing for May. Shell wants to build a facility to crack ethane and make polyethylene pellets for the plastics industry on the site of a former zinc smelter near Pittsburgh.
The project includes a 250-MW natural gas-fired power plant primarily for on-site use, but about 100 MW of the plant’s output would be available for PJM capacity through a Duquesne Light interconnection.
PPL Electric Utilities is asking the Public Utility Commission to allow it to increase its electric rates 6.9%, for a total of about $167.5 million. The PUC granted PPL a 3% hike two years ago, allowing an increase of $71 million in revenue.
The rate hike covers distribution, not supply charges, which went up 8.5% beginning March 1 in a separate rate increase. The average customer’s monthly bill would increase by $10, to about $157.60. PPL Electric President Greg Dudkin said the majority of the hike would go toward system reliability improvements. The PUC has not yet scheduled public hearings on the request.
The CEO of Enbridge Energy last week said the slump in oil prices won’t affect the company’s ambitious pipeline construction plans, especially those in Minnesota. The company is upgrading two oil pipelines and has proposed the 600-mile Sandpiper project. They are all part of the company’s five-year, $44 billion building program.
“The amount of production that is coming on to our system and the amount of production we forecast from the oil sands or the Bakken is actually well in excess of the capacity we have on our system,” said CEO Al Monaco, whose company operates the world’s longest crude oil pipeline system and has major operations in Minnesota and Wisconsin.
Duke Energy CEO Lynn Good earned about $600,000 less than she could have last year, primarily because the Dan River coal ash spill cut her short-term incentive payment from $1.7 million to $1.1 million. But Good had a good year anyway as, according to securities filings, her total compensation worked out to $8.4 million. She earned $6.4 million the year before, when she was the company’s chief financial officer. Good was named CEO in the middle of 2013.
Dominion Sells Carolina Gas to its Own Midstream Partners Subsidiary
Dominion Resources sold its ownership of Carolina Gas Transmission to its Dominion Midstream Partners subsidiary for $495 million, the company announced last week. Dominion bought Carolina Gas, which owns and operates about 1,500 miles of natural gas pipelines in South Carolina and Georgia, for $493 million in December.
Dominion Midstream is the corporation’s holding company for its natural gas transmission, storage and export business, which includes the under-construction Cove Point liquefied natural gas export facility on the Chesapeake Bay in Maryland.
FERC Approves NextEra’s Acquisition of Hawaiian Electric
The Federal Energy Regulatory Commission has approved NextEra Energy’s proposed $4.3 billion acquisition of Hawaiian Electric, but the Juno, Fla.-based company still needs several more approvals to close the deal. The Hawaii Public Service Commission has set a deadline of Aug. 31 to finish hearings and issue a ruling. Several interveners, including the state’s Consumer Advocate, SunEdison and the International Brotherhood of Electrical Workers, have asked that the deadline be extended to Oct. 30. If granted, the extension could push back complete approval of the acquisition into next year.
NuScale Power Unveils Mock-Up of Small Modular Reactor
NuScale Power has finished constructing the full-scale mock-up of it modular reactor design, one of the final steps before it submits the entire design to the Nuclear Regulatory Commission for approval next year. The Portland, Ore.-based firm said it will be submitting its 12,000-page design application to the NRC in 2016, starting a three-year design review process. NuScale’s design is for small, 50-MW modules that could be joined in as many as 12 units to produce a 600-MW plant. Instead of being constructed on-site, the modules would be built in a factory and shipped to the plant site. NuScale is backed by Fluor Corp. and the Department of Energy.
The Nuclear Regulatory Commission has granted an exemption to Duke Energy Florida’s Crystal River Unit 3, allowing the company to skip its 10-mile emergency planning zone responsibilities in light of the plant’s decommissioning. Duke announced last year that the unit was being permanently shut down. All fuel has been removed from the unit and placed in spent fuel pools. The NRC granted the exemption after determining that the probability of an accident is lower because of the unit’s cold status. All on-site responsibilities for the unit remain in effect.
Survey Shows 86% of Americans Favor Developing Spent Fuel Repository
A new poll shows an 86% majority of those asked favor the development of a federal facility for the storage of spent nuclear fuel in the country. The poll, commissioned by the Nuclear Energy Institute and performed by Bisconti Research, had a margin of error of plus/minus 3%.
Poll results show a less clear picture of who should be in charge of such a repository. Fifty-four percent indicated they thought a hybrid structure of a federal authority steered by a corporate-style board should oversee such a site, with 39% holding to a federal agency-type governance. The poll was conducted just before the introduction in the Senate of legislation that establishing an independent entity to oversee nuclear waste management.
“The public may express changing views about who should manage the storage facilities, but support for consolidating used nuclear fuel has been constant for a long time,” Bisconti Research President Ann Bisconti said.
Interior Secretary Reaffirms 2008 Arctic Drilling Site Auction
In a move that opens the Chukchi Sea to exploratory drilling again, Interior Secretary Sally Jewell this week reaffirmed the government’s auction of drilling rights in the Arctic, saying the region “is an important component of the administration’s national energy strategy.”
Drilling in the Arctic region was halted during a challenge by environmentalists, who argued in federal court that the department’s environmental impact statement was flawed. The results of a new court-ordered study were filed as part of the department’s decision.
Jewell’s affirmation of the auction keeps the door open for Shell Oil to restart its exploratory work in the Chukchi Sea, about 70 miles off the Alaskan coast, this summer. The company must still receive several permits from other agencies, but it is already moving equipment north in anticipation of restarting work.
Former DOE Secretary’s Move to Private Sector Under Investigation
Poneman
Former Deputy Energy Secretary Daniel Poneman’s recent hiring as Centrus Energy’s new CEO is being examined by the House Oversight and Government Reform Committee. Poneman, in his role with the Department of Energy, worked with the uranium enrichment company when it was known as USEC. During that time, USEC received hundreds of millions of dollars in federal funds, according to Politico. House investigators have requested five years’ worth of documents from his time with the department, with an emphasis on any communication between USEC, Centrus and Poneman, who could make up to $1.7 million a year in his new job.
“Given Mr. Poneman’s involvement in the numerous dealings between DOE and USEC since 2009, we are concerned that he may have violated post-employment laws for federal personnel,” Committee Chairman Jason Chaffetz (R-Utah) and Interior subcommittee Chairwoman Cynthia Lummis (R-Wyo.) wrote in a letter to Energy Secretary Ernest Moniz.
A Centrus spokesman said there was nothing improper about Poneman’s activities. “At no time during his employment with the Department of Energy did anyone affiliated with Centrus contact Mr. Poneman to discuss future employment opportunities,” the spokesman said.
NRC Increases Oversight at Vogtle After Waste-Shipping Mistake
The Nuclear Regulatory Commission is increasing its oversight at the operating units of Southern Co.’s Vogtle nuclear generating station near Augusta, Ga., after employees used a wrong container to store and ship radioactive waste. The incident occurred last June, when employees shipped a cask of spent resin radioactive waste to a processing facility in South Carolina. The cask was only approved for storage of a lower class of radioactive waste, according to the agency. Employees at the processing facility noticed the mistake. Vogtle was fined $8,000. Southern said it has instituted increased training and improved procedures.
NRC Finds 3 of Entergy’s Nukes Have Enough Decommission Funds
In response to a petition filed in 2013 by four anti-nuclear groups to order the closing of Entergy’s FitzPatrick and Vermont Yankee plants because of inadequate decommissioning funds, the Nuclear Regulatory Commission found that the plants’ funds are in order. In a preliminary decision released last week, the NRC found that the now-closed Vermont Yankee plant, the FitzPatrick plant in New York and the Pilgrim plant in Massachusetts were all “operating safely and addition actions were not required.” The agency also reviewed financial records relating to the Pilgrim plant and issued a similar finding that there was enough money in Vermont Yankee’s decommission fund.
LaFleur Questioned on Pipeline Review Policies by Va. Officials
Cheryl LaFleur
Federal Energy Regulatory Commission Chairman Cheryl LaFleur is getting a lot of mail from Virginia officials lately. On March 23, Democratic Sen. Mark Warner shot her a missive asking her about the rules surrounding public meetings in response to concerns about a controversial Dominion Resources-led pipeline proposal, the Atlantic Coast Pipeline.
On Friday, the Nelson County Board of Supervisors sent two letters to LaFleur, one asking to extend the scoping period for the proposed line by an additional 30 days, and a second asking her to schedule another scoping meeting. Pipeline opponents have complained that the public hearing process is rigged, after they arrived to find most of the speaking slots taken by the line’s supporters.
A FERC spokeswoman said that scoping meetings are not required as part of the FERC review and wouldn’t comment on the letters.
NY Underground Pumped Storage Project Application Filed with FERC
A $264.1 million plan to develop a 260-MW pumped storage project in an abandoned mine complex in New York is under review by the Federal Energy Regulatory Commission. Albany Engineering filed applications on behalf of its subsidiary Moriah Hydro to construct the facility at three interconnected mines near the town of Moriah. It would use the flow of underground water through the mines to drive five reversible pump turbines. Electricity would be sent underground about a mile to an existing National Grid 115-kV transmission line.
ST. LOUIS — Cap-and-trade, a pollution-control concept rejected by Congress five years ago, appears to be coming back to life in the Midwest.
Stakeholders from MISO and SPP said Tuesday they are developing the framework for an interstate trading platform to comply with the Environmental Protection Agency’s pending limits on power sector carbon emissions.
The comments came in the Federal Energy Regulatory Commission’s fourth and final technical conference on the reliability and market implications of EPA’s Clean Power Plan, which seeks to reduce carbon emissions from existing generators by 30% from 2005 levels.
More than 100 regulators, utility officials and other stakeholders from MISO, SPP and ERCOT attended the conference at a hotel on Lambert-St. Louis International Airport. The session featured a repeat of the near-universal complaints about EPA’s interim 2020 goals and EPA’s Janet McCabe, who promised the agency was “looking very, very closely” at the issue.
Virtually absent, however, was any talk of fighting the EPA rule, which is due to be finalized this summer.
Instead, speakers said they were seeking ways to meet EPA’s ultimate 2030 goals through a mechanism that would allow utilities to trade emission allowances within and across state lines. It would effectively set a price on carbon, similar to the cap-and-trade program credited with reducing the cost of complying with acid rain regulations in the 1990s.
Even a representative from coal giant Peabody Energy conceded: “There is going to be a value on carbon.”
MSEER
“SPP, MISO and the ERCOT regions have the best wind resources in the world and we have harvested only a small part of the potential,” said Steve Gaw, representing The Wind Coalition, a trade group. “Much can be done now, and certainly once the rule is finalized this summer, to start the [transmission] planning processes. Waiting until the [state implementation plans] are developed will be too late. An understanding of what infrastructure is likely to be available should be an input to the states’ SIP development process.”
On Monday in St. Louis, the Midcontinent States Environmental and Energy Regulators (MSEER) held their fifth meeting to continue their work on a regional solution. Fourteen states, including most of those in MISO and SPP, are participating.
“I think there is broad recognition that a regional response will most likely be more cost-effective and operationally beneficial,” said Minnesota Public Utilities Commissioner Nancy Lange, one of those who attended.
The plans are also taking shape in a larger group, the Midwest Power Sector Collaborative, which also includes utilities and environmental organizations.
Former Illinois Commerce Commissioner Doug Scott, now vice president for strategic initiatives at the Great Plains Institute, said he was encouraged by states’ efforts to find regional solutions. The Minneapolis-based institute and the Washington-based Bipartisan Policy Center are providing staffing support to MSEER and the Collaborative.
“By our estimation, 41 of the 50 states are currently taking part in some discussion or another with other states trying to figure out the potential for multistate collaboration,” Scott said. His count is in contrast with that of EPA critics such as Sen. Jim Inhofe (R-Okla.), who opened a committee hearing last month by displaying a map identifying 32 states he said are opposing the EPA plan. (See Inhofe Decries EPA ‘Power Grab’.)
Rate- vs. Mass-Based Standards
Ameren’s integrated resource plan for Missouri would allow it to meet EPA’s carbon emission targets by 2034 by retiring one-third of its coal generation, adding natural gas and renewables, extending the life of its nuclear power plant and implementing energy efficiency programs, CEO Warner Baxter said. Meeting EPA’s 2020 interim goals would increase Ameren’s compliance costs by $4 billion, he said.
EPA’s initial proposal last June set rate-based goals for each state, measured in pounds of CO2 per megawatt-hour. In response to state requests, EPA in November released a technical support document explaining how to translate rate-based goals to mass-based equivalents, measuring total CO2 emissions in metric tons.
The platform being discussed by MSEER would differ from the Regional Greenhouse Gas Initiative, in which nine Mid-Atlantic and Northeastern states set an overall cap on power sector carbon emissions (91 million short tons for 2014, declining by 2.5% annually from 2015 to 2020).
Instead, states would submit for EPA approval implementation plans using their individual mass-based targets. Once the plans are approved, the states would use trading to reduce the cost of meeting their goals.
“That would be a form of regional coordination that doesn’t require the grand bargain of … all the states trying to” reallocate emissions using the rate-based approach, said Michael Schnitzer, director of the Northbridge Group, and a consultant to Entergy.
RGGI’s approach, “nine states agreeing on a target and what their respective responsibilities are — I think that one is much less likely to come to fruition than this other approach,” Schnitzer added.
McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, said agency officials have a similar perception of how a regional compliance plan could emerge. “We’ve … heard from many states that they would very much like the final plan to allow for interstate or regional arrangements that are less formal, perhaps, than some of the ones that already exist,” she said.
Winners and Losers
Recounting a recent conversation with an energy trader about the West Coast energy crisis in 2000-2001, FERC Commissioner Philip Moeller said he has concerns about traders exploiting regional compliance disparities under the Clean Power Plan. The West Coast crisis “was essentially caused by seams. California had a market program that was flawed and then those seams issues spilled over into the entire west,” Moeller said. “I hate to be sounding too dark here, but I certainly hope that will be in the minds of our friends at EPA as they put these rules together. When a trader is telling me that there’s going to be a lot of opportunity here … he’s putting out a pretty good warning.”
EPA’s proposed rate-based approach resulted in dramatically different emission rates from one state to another, which state and utility officials said would be an impediment to regional cooperation.
North Dakota, for example, has the nation’s highest target rate at 1,783 lbs/MWh, more than double South Dakota’s 741 lbs/MWh. EPA said the discrepancies reflected its attempt to determine what was “practical and affordable” for individual states, taking into account factors such as their current generation mixes and the availability of natural gas. (See Carbon Rule Falls Unevenly on PJM States.)
Creating a “blended” regional rate could result in some states with low rates having to reduce their emissions more than if they went it alone.
“There’s no question that the rule as proposed creates winners and losers. But the mass-based approach … can provide every state an opportunity to do better through trading,” Schnitzer said. “If it makes sense for [Iowa] to over-comply to reduce their tons even further so that they can sell them to Minnesota, which is cheaper for Minnesota than doing the next most onerous thing … that’s how it’s going to work. It’s self-interest for both states.”
Trading Between Rate- and Mass-Based States
Lanny Nickell, SPP’s vice president of engineering, said the RTO is rich in wind and solar power but that it is mostly located in the western portion of its footprint. “To get it where it needs to go to help states comply with the Clean Power Plan … it’s got to go through the eastern side of our system and into other states that aren’t in SPP. And we haven’t traditionally planned for that.”
The MSEER group hasn’t been able to find a way to accommodate trading between states using the rate-based standard and others using the mass-based limits, said Thomas Easterly, commissioner of the Indiana Department of Environmental Management.
While the mass-based approach would ease trading, it “sets a cap that basically limits growth over time forever,” Easterly said. “The rate-based plan allows you to have really unlimited growth if you can do it in a clean way. That’s why some different states have different views — one of the reasons not the only reason. That’s what making it so difficult to come to a common understanding.”
Mike Peters, CEO of Wisconsin Public Power, said his company did an analysis assuming trading between mass- and rate-based states.
“If you take a state that has a rate-based approach and another state that has a mass-based approach, identical generating units in both states, [with an] identical cost of fuel, you could have a $20[/MWH]-plus differential in the adders on those plants, and that’s going to result in shifting generation in ways that we can’t even anticipate right now,” he said.
Preserving Economic Dispatch
Richard Doying, MISO’s executive vice president of operations, said a “transparent, liquid market” is essential to ensuring MISO doesn’t lose the $1.5 billion in annual savings resulting from the RTO’s least-cost generation dispatch. “How do you avoid that? It’s really pretty simple: You monetize the cost of compliance [through tradeable allowances]. Those tradeable allowances are easily reflected in generation offers, they’re reflected then in the dispatch of that energy, the clearing of the market and they’re reflected in prices. … It allows you to trade those allowances based on market-derived value across the seam just as you would with energy.”
MISO MVP Example Cited
Clair Moeller, MISO’s executive vice president of transmission and technology, said the RTO needs to reconsider “several layers of conservatism” in its planning assumptions, such as the 20-year assumed economic life for assets that last far longer. He said cost allocation will be MISO’s biggest challenge in expanding transmission to deliver renewable energy. “It always is the hardest thing to solve.”
Former Wisconsin Public Service Commissioner Lauren Azar said MISO’s states demonstrated their ability to collaborate through their development of the Multi-Value Project, a transmission concept designed to help them meet individual renewable portfolio standards.
Azar said state officials met every other week for 18 months to develop the MVP plan. The entire stakeholder process, including drafting tariff changes and cost allocation formulas, took about six years, said Clair Moeller, MISO executive vice president of transmission and technology.
“Transmission owners coalesced around the product because the state commissions were leading the process. So they had some certainty with respect to whether their costs were going to be approved later on,” Azar said.
Referring to MSEER’s five meetings since EPA released its carbon proposal last summer, Azar said: “Let me tell you guys, you’re going to have to meet a heck of a lot more, and I recommend you begin as soon as possible.”
Lone Star State
A measure of how far discussions have progressed is the position of Entergy.
“Entergy does not support the proposed rule,” Schnitzer noted. “But the company recognized that if the rule does go forward, it should be designed to be efficient and to minimize reliability impacts. And the mass-based compliance recommendations we offer are to further that objective.”
But while most of the speakers Tuesday indicated a willingness to embrace trading, Donna Nelson, chairman of the Public Utility Commission of Texas, said her state — which is split between MISO, SPP, ERCOT and the Western Electric Coordinating Council — is unlikely to be among them.
“We’re probably … not going to roll over on the issue of a carbon tax,” she said.
