A Massachusetts state legislator whose district includes the soon-to-be shuttered Brayton Point generating plant has filed legislation that would revamp the state’s energy landscape.
The bill was proposed by Rep. Patricia Haddad, a Democrat and an ally of Massachusetts Speaker Robert DeLeo.
The sweeping bill would require the state’s utilities to enter into long-term contracts with offshore wind developers. It also seeks to clear obstacles to gas pipeline and electric transmission construction by, among other methods, creating a siting board to more easily locate energy infrastructure.
It proposes a tax that would fund natural gas infrastructure, attempting to revive a proposal last year by the six New England governors that failed to gain traction. Environmental groups toldThe Boston Globe last week they object to the use of public subsidies for pipeline expansions and would like to see incentives for energy efficiency and storage.
It also encourages utilities to submit proposals for competitively bid transmission lines to deliver Canadian hydropower. Another proposal for that purpose bogged down in the legislature last year.
It would make conversion from coal-fired power plants to natural gas easier as well, which could aid efforts to repower the 1,517-MW Brayton Point plant. Brayton Point, the largest taxpayer in Haddad’s hometown of Somerset, is scheduled to close in mid-2017.
Massachusetts has the eighth-highest residential electric rates of any state, according to the U.S. Department of Energy. Each of the other New England states also ranks in the top 10.
Former Gov. Deval Patrick released a study last month that said the state needed significant investment in natural gas pipeline capacity to preserve electric system reliability. (See Gas Price Spikes Likely Through 2019, Study Says.)
ISO-NE also chimed in recently saying that grid reliability is threatened by the region’s inadequate pipeline capacity, which is unable to fully supply heating and power generation during the winter. (See ISO-NE CEO: Despite Mild Winter, Region Still Needs Infrastructure.)
Consumers Energy plans to retire the 328-MW J.R. Whiting coal-fired plant next year in response to the EPA’s Mercury and Air Toxics Standards.
MISO is proposing to modify its Tariff so that generation owners retiring coal plants to meet looming environmental rules can avoid capacity deficiency penalties.
The Tariff revision (ER15-918) filed with the Federal Energy Regulatory Commission on Jan. 28 would apply to generation operating during the Planning Resources Auction offer window that will retire or suspend operations between the March 31 end of the window and the end of the 2015-2016 planning year on May 31, 2016.
Last year, several generators asked the Federal Energy Regulatory Commission for a waiver from MISO’s Tariff. They complained there was no clear mechanism within the MISO Tariff that would permit them to buy replacement capacity through the auction to cover the six-and-a-half-week period between the planned retirement of the coal units and the end of MISO’s planning year.
Only Where SSR is not Necessary
The proposed Tariff revisions would allow generators the option of not making offers into the PRA without facing liability for physical withholding.
It would apply only to the 2015-2016 planning year and only to generators for which MISO has determined a system support reliability agreement (SSR) is not necessary.
In testimony included with its filing, MISO said the proposal will not cause reliability concerns, explaining that a “critical condition” of the proposed change includes a determination by MISO that the retiring or suspending unit is not needed for reliability.
Also, the Tariff change will not relieve load-serving entities from obligations to meet the planning reserve margin requirements for a full year.
The proposed change “will allow market participants greater certainty and flexibility by providing a clear option to avoid risk by not being forced to make the difficult choice between making [zonal resource credit] offers for generation resources that MISO has determined may retire or suspend during the 2015-2016 planning year or being faced with the potential of physical withholding mitigation,” MISO said.
MISO’s Independent Market Monitor had expressed concerns that the change would “limit retrospective physical withholding mitigation” for generation resources.
MISO said the change is appropriate to provide certainty to market participants regarding generating units for which the RTO has determined that retirement or suspension does not present reliability issues.
Different Fates
One utility that was successful in obtaining a waiver was Indianapolis Power & Light. FERC approved its request last October after MISO said its analysis showed that Zone 6, in which IPL is located, has sufficient planning reserve margins even after accounting for the planned retirement of the company’s Eagle Valley coal-fired units.
FERC denied a similar request from Consumers Energy, however. The company plans to retire its “Classic Seven” coal units on April 15, 2016, due to the Environmental Protection Agency’s Mercury and Air Toxics Standards.
Consumers told FERC that purchasing replacement capacity for the entire year could cost up to $84.8 million. MISO opposed Consumers’ waiver request, saying it could cause MISO’s north and central regions to fall below the planning reserve margin. FERC denied Consumers’ request in November.
The Federal Energy Regulatory Commission last week dismissed challenges to three ISO-NE market rules that generators had wanted tossed in advance of this week’s Forward Capacity Auction.
The commission upheld ISO-NE’s pricing rule for new generation, its administrative pricing provisions and its Peak Energy Rent Adjustment.
New Entry Pricing Rule
Artist’s conception of Footprint Power’s planned 674-MW natural gas plant (R), which will be built on the site of the coal- and oil-fired Salem Harbor Station (L) on Massachusetts’ North Shore.
The New Entry Pricing Rule allows new resources to lock in the price at which the resource clears in its first FCA for up to six subsequent delivery years.
A Nov. 28 complaint by Exelon and Calpine alleged the rule suppresses prices for other capacity providers because it results in new resources entering the equivalent of zero-price offers in the six additional years. The companies noted that the commission had rejected zero-price offers in PJM.
ISO-NE opposed the complaint, saying that the price stability provided by the lock-in allows a new resource to be offered with a smaller risk premium, making it closer to its true competitive cost of entry.
In a Jan. 30 order, the commission sided with the RTO (EL15-23). “Complainants have not demonstrated why it is unjust and unreasonable for a new resource electing the price lock-in to be treated as a price-taker in the ISO-NE market for the remainder of the lock-in period,” the commission said.
“ISO-NE’s treatment of those resources simply reflects the design and efficiency advantages that a resource that recently cleared an FCA as a new resource would be expected to have over the rest of the New England fleet. In fact, even if such a resource does not have a price lock-in, it would typically submit a zero-price offer in the ISO-NE market, consistent with its low going-forward costs and in order to ensure that it is taken in the auction.”
PJM Rules
The generators had asked FERC to address the price suppression by allowing a lock-in option for existing resources or implementing corrective rules used in PJM.
Under PJM’s New Entry Price Adjustment rule, a new resource may lock-in the clearing price for two additional years. PJM addresses the price suppression effect of the rule by requiring a price-locked resource to offer its capacity into the second- and third-year auctions at the lesser of either its first-year price or 90% of the net cost of new entry for that year.
The commission acknowledged the companies’ contention that “under certain limited circumstances, PJM’s NEPA rules may result in higher prices than those under ISO-NE’s zero-price offer requirement.” That, however, does not make ISO-NE’s zero-price offer requirement unjust and unreasonable, the commission said.
Administrative Pricing
In a related ruling last week, FERC denied a request for rehearing by the New England Power Generators Association, which had asked the commission to reconsider its 2013 challenge to administrative pricing provisions in ISO-NE’s Tariff (EL14-7).
NEPGA challenged provisions governing the prices paid to existing capacity resources when there is inadequate supply or insufficient competition in an FCA or when capacity that clears in one FCA is carried forward into a subsequent FCA.
The commission’s initial ruling in January 2014 found that the Tariff was unjust and unreasonable because it could result in prices that were not reflective of supply conditions. But the commission rejected NEPGA’s proposed Tariff revisions, saying they would leave consumers vulnerable.
In its rehearing request, NEPGA reiterated its call for a change in the pricing rules, saying the current administrative prices were at least 40% too low.
In its Jan. 30 ruling, the commission again rejected the generators’ request.
“Absent sufficient evidence that a rate increase of such significant magnitude is necessary to incent new entry and retain existing capacity resources … NEPGA’s proposal does not appropriately protect consumers and the market from sudden, significant price increases.”
Peak Energy Rent Adjustment
FERC also dismissed a NEPGA complaint that sought to roll back the Peak Energy Rent Adjustment, which it said would threaten reliability (EL15-25).
FERC said the trade group had failed to show the PER Adjustment was unjust and unreasonable, so it did not address alternatives sought by NEPGA, including raising the PER strike price by $250/MWh.
NEPGA sought to have ISO-NE modify the PER for Capacity Commitment Periods 5 through 8 — from now until early 2018 — and then eliminate it altogether for FCA 9. The auction covers delivery year 2018/19, when the ISO will implement its Pay-for-Performance program, which will tie capacity revenues to real-time performance.
“A supplier still has the obligation and the incentive to operate its resource, and therefore not changing the PER strike price will not create a disincentive for suppliers to provide energy, as NEPGA suggests, and is thus unlikely to cause reliability problems of insufficient resources to meet load demand,” FERC said.
Moeller, Clark See ‘Valid Concerns’
However, Commissioners Philip Moeller and Tony Clark, while denying the complaint, were unsatisfied with the end result.
“NEPGA and other parties have raised valid concerns regarding the continued application of the existing PER Adjustment in light of the increases in the reserve constraint penalty factors in ISO-NE’s energy market put in place in 2014,” they wrote in a separate statement.
FERC’s order noted that the stakeholders will continue to discuss the issue and it suggested further review would be done in advance of FCA 10 a year from now.
A Virginia Senate subcommittee has passed a bill that would freeze Dominion Virginia Power customers’ base rates and bar state regulators from reviewing the utility’s revenue until after 2020.
The bill, SB1349, is among the most controversial in a group of bills introduced by Virginia lawmakers in reaction to the U.S. Environmental Protection Agency’s proposed rule on carbon emissions from existing power plants.
The bill’s sponsor, Republican Sen. Frank Wagner, says it is designed to protect Dominion customers from rate increases that they would incur as a result of coal plant retirements due to compliance with the EPA’s Clean Power Plan.
But critics, such as state Attorney General Mark Herring, aren’t so sure. They point to a projected $280 million earnings surplus in the utility’s Integrated Resource Plan. If the State Corporation Commission finds through its biennial review that the company earned too much money for the past two years, it can order the utility to lower its rates or issue refunds to customers.
Under the bill, Dominion would be able to keep any earnings surpluses. Although base rates would be frozen, the utility would be able to seek surcharges for new technology and infrastructure, subject to SCC approval.
“We’re pretty confused as to why Dominion is introducing this bill,” said Dawone Robinson, Virginia policy director for the Chesapeake Climate Action Network. “This indicates to me that Dominion believes that rates would actually go down under the Clean Power Plan.”
Wagner has said the bill is a work in progress, according to The Daily Press. The original version of the bill, which Wagner said that Dominion helped him write, would have prevented the SCC from conducting its reviews beginning this year. The version of the bill that passed the subcommittee Thursday will allow this year’s review of Dominion’s revenue in 2013 and 2014 to go forward as scheduled.
“I will vote to move it along, but I would just say this has a long way to go,” Senate Minority Leader Richard L. Saslaw (D-Fairfax) said, according to The Washington Post. “I’m somewhat concerned about not having this biennial review.”
The bill was scheduled to go before the full Senate Commerce and Labor Committee yesterday.
“The reason we support the proposed legislation is simple,” Robert M. Blue, president of Dominion, said in a statement. “We want to be able to continue that record of low rates, high reliability and environmental stewardship. We believe it is in the best interest of both our customers and Dominion.”
No Fans of EPA
Wagner isn’t the only Virginia legislator who is not a fan of the Clean Power Plan.
On Jan. 20, Republican Sen. John Watkins introduced SB1365, which would require the state’s Department of Environmental Quality to submit its compliance plan for approval from the General Assembly before sending it to the EPA. Another Wagner-sponsored bill, SB1202, would prohibit the DEQ from submitting a plan until the SCC essentially approved the Clean Power Plan. The commission’s staff gave the plan a scathing review in October. (See Va. SCC Staff Blast EPA Carbon Rule.)
On Friday, the House Committee on Rules passed HJ608, introduced by Republican Del. Terry Kilgore. Under the resolution, the state would voice its opposition to the EPA’s emission rules because they “infringe on the commonwealth’s sovereign powers to regulate electricity for the benefit and welfare of its citizens.” The resolution passed the committee by a 12-3 vote.
Public Service Electric and Gas last week accused PJM of breaking its own rules in refereeing the competition for the Artificial Island stability fix, suggesting the RTO should scrap the process and start again.
PJM did not follow its process in two respects, PSE&G said in a Jan. 29 complaint with the Federal Energy Regulatory Commission (EL15-40).
Unilateral Modifications
“First, PJM unilaterally modified each proposal, rather than, as required, evaluating them and selecting the best proposal or, if none qualified as such, reposting the solicitation. Second, PJM allowed LS Power to modify its proposal more than one year after the proposal window closed and after PJM staff had recommended another proposal,” PSE&G said.
PJM staff had selected PSE&G as the winning bidder after eliminating two 500-kV lines from its proposal. The change reduced the project’s cost by more than three-quarters to a range of $211 million to $257 million, making it equal to a 230-kV proposal from LS Power that was the cheapest among the finalists.
PJM’s selection was criticized by environmentalists and spurned bidders, including LS Power, which offered to cap its project cost at $171 million — at least $40 million less than the PSE&G project.
In response, the PJM Board of Managers delayed action on planners’ recommendation and offered PSE&G and finalists Transource Energy and Dominion Resources to “supplement” their proposals in response to LS Power’s reduction. (See PJM Puts the Brakes on Artificial Island Selection.)
Artificial Island, home to the Salem and Hope Creek nuclear reactors, is the second largest nuclear complex in the country. Historically, according to PSE&G, special operating procedures have been employed to maintain stability in the area.
PJM issued a solicitation for a stability fix — its first competitive transmission project under FERC Order 1000 — in April 2013.
Independent Evaluator
In its filing last week, PSE&G noted that PJM has stressed its role in the process as an independent evaluator and the importance of not allowing bidders to modify their proposals after the window for entries has closed.
“PJM said this would ‘chill’ the competitive process and give one bidder an ‘unfair advantage’ over the others,” PSE&G said. “If PJM believes that none of the proposals submitted in 2013 represents the more efficient or cost-effective solution, PJM can re-post the Artificial Island solicitation and provide any additional guidance to prospective sponsors that PJM deems appropriate based on the experience it has gained over the last two years.
“PSE&G understands that granting this relief will delay the process somewhat, but the process has already languished for nearly two years, there is no other Tariff-based remedy for the violations that have occurred and the remedy is nondiscriminatory because it does not favor one bidder over another.”
More Delays
PJM planners intended to have a recommendation ready for the Board of Managers’ meeting in February after the four finalists squared off at a meeting of the Transmission Expansion Advisory Committee in December. But at the Jan. 7 TEAC meeting, officials said consultants were still studying various aspects of the plans, including sub-synchronous resonance issues involved in Dominion Resources’ proposal. (See Further Study Delays PJM’s Artificial Island Decision.)
Critics, including PSEG Nuclear, the operator of the nuclear plants, have said Dominion is employing untested technology that could damage turbine shafts and cause widespread outages.
Steve Herling, PJM vice president for planning, said that a recommendation should be ready to present to the committee this month, and that plans were underway to call a special Board of Managers meeting in March to review it.
The SPP Board of Directors elected Mike Ross as senior vice president of government affairs and public relations and Malinda See as vice president of corporate services.
CEO Nick Brown said the two “bring unique perspectives and leadership experiences” to the RTO’s executive leadership.
Ross, a former six-term congressman who served on the House Energy and Commerce Committee, oversees the RTO’s external affairs, media relations and corporate communications. Ross (D-Ark.) was defeated by former Rep. Asa Hutchinson (R-Ark.) in Arkansas’ gubernatorial race in November.
See, SPP’s longest serving employee, is responsible for human resources, payroll, facilities and administrative services.
A federal court in California will hear arguments Feb. 26 in a case pitting the Federal Energy Regulatory Commission against Barclays that could result in the British bank having to pay penalties and disgorge profits of up to $470 million.
FERC alleged that Barclays and four of its traders engaged in so-called swap trades between several western energy hubs from 2006 to 2008. FERC cited the bank in 2012. Barclays had the option of defending itself before a FERC administrative law judge or to have the case heard in U.S. District Court.
Obama Administration Working to Open Up East Coast to Offshore Drilling
The Department of the Interior last week said it was working on a plan to open up vast offshore tracks to oil and gas exploration in the Atlantic Ocean off Virginia, North Carolina, South Carolina and Georgia, while declaring 9.8 million acres in Alaskan waters off limits indefinitely.
The plan, which would open the Atlantic to offshore drilling for the first time, drew protests from New Jersey Democrats. “Opening up the Atlantic coast to drill for fossil fuel is unnecessary, poses a serious threat to coastal communities throughout the region and is the wrong approach to energy development in this country,” Sen. Cory Booker, Sen. Robert Menendez and Rep. Frank Pallone of New Jersey said in a joint statement. The Atlantic leases are for areas more than 50 miles offshore.
Republican Sen. Lisa Murkowski said the withdrawal of the Alaskan offshore tracts amounted to a war against her home state. The Obama Administration said the environmentally sensitive areas in the Beaufort and Chukchi seas, as well as a shallow 30-mile shelf in northwestern Alaska, were important to Alaska natives.
NRC Board Denies Vermont’s Request to Force Entergy to Maintain Emergency Monitoring
The Nuclear Regulatory Commission’s Atomic Safety and Licensing Board rejected Vermont’s request to order Vermont Yankee owner Entergy to maintain various emergency monitoring systems on the shut-down nuclear plant. The board said Vermont’s petition challenged an NRC regulation and was therefore inadmissible.
Entergy closed the plant last year, and asked to reduce on-shift and Emergency Response Organization staff due to the decreased risk. The board said the plant’s Emergency Response Data System requirement was put in place after the 1979 Three Mile Island incident but that plants being decommissioned were exempt.
“Expressly excluded from the proposed rule were those nuclear power reactor facilities that are permanently or indefinitely shut down,” the board’s ruling stated.
Department of Energy to Pay $44K Fine on Hanford Violations
The Department of Energy signed a consent agreement agreeing to pay $44,772 in fines assessed by the Environmental Protection Agency for hazardous waste storage violations at the Hanford Nuclear Reservation in Washington.
The EPA cited the Energy Department for two incidents in 2013 when the department moved 136 drums of waste to an unapproved site and when it submitted a plan to close eight storage sites without required information.
Energy Information Admin’s Short-Term Outlooks Already Out of Date Due to Oil Slowdown
The Energy Information Administration’s short-term energy outlook was out of date less than two weeks after it was released, thanks to the volatile energy markets.
The administration, part of the Department of Energy, is having trouble keeping up with fast-changing energy markets. Its recent forecasts of rig counts and oil and gas operations failed to predict the decline in new drilling operations because of the rapid plunge in energy prices.
DOE Releases $59 Million for Solar Energy Innovation Projects
Moniz
The Department of Energy last week announced it was releasing $45 million in funding for solar manufacturing and putting up $14 million more for 15 new community solar deployment projects.
“As President Obama noted in his State of the Union address, the U.S. brings as much solar power online every three weeks as we did in all of 2008,” Energy Secretary Ernest Moniz said. “As the price of solar continues to drop, the Energy Department is committed to supporting a robust domestic solar manufacturing sector that will help American business meet growing demand and help American families and businesses save money by making solar a cheaper and more accessible source of clean electricity.”
The department said the new round of funding is aimed at helping the country reach the administration’s goal of doubling renewable energy by 2020.
Lawrence Livermore Lab Signs 20-Year Solar Deal with juwi
In what is billed as the Department of Energy’s largest solar purchase from an on-site facility, the department’s National Nuclear Security Administration signed an agreement with a solar developer to provide 6,300 MWh per year for the Lawrence Livermore National Laboratory in Livermore, Calif.
The facility, to be developed by juwi solar subsidiary Whitethorn Solar, will be a 3-MW ground-mounted photovoltaic system. The Whitethorn facility will sell into the Western Area Power Administration through a 20-year power purchase agreement with the department.
The Illinois Commerce Commission and PJM’s Independent Market Monitor said last week they oppose the Illinois Municipal Electric Agency’s request for a waiver from the rules for May’s Base Residual Auction.
IMEA asked the Federal Energy Regulatory Commission last month for a waiver that would allow it to use capacity resources outside of the Commonwealth Edison Locational Deliverability Area to meet its internal resource requirement in serving its Naperville, Ill., load (ER15-834).
Last May, FERC granted IMEA such a waiver for the 2017/18 delivery year (ER14-1681). Neither the ICC nor the IMM weighed in on last year’s waiver request.
“Despite the small size of IMEA’s [fixed resource requirement] load relative to total load in the ComEd LDA, the financial impact of granting IMEA’s requested waiver could be significant for the other [load-serving entities] if PJM models the ComEd LDA separately in the May 2015 Base Residual Auction and the ComEd LDA subsequently binds on the [Capacity Emergency Transfer Limit],” the ICC said.
“Moreover, as the commission noted in its Jan. 22 Order, IMEA has had sufficient time to address any consequence of its decision to take the FRR option for the 2018/2019 delivery year.”
The ICC offered two alternatives.
The first — also suggested in the Jan. 22 order — was for IMEA to request to be excused from the five-year stay-in provision for FRR participants so that it could participate in the capacity auction.
Alternatively, the ICC said, FERC could order PJM not to model the ComEd LDA separately.
“If the commission does choose to grant the waiver requested by IMEA, then the ICC requests that the commission also direct PJM to adjust the LDA reliability requirements upon which a separately stated [variable resource requirement] curve for the ComEd LDA would be calculated downward by the amount of internal reliability requirements that IMEA is excused from providing,” it said.
The Market Monitor also said IMEA’s waiver request could have adverse effects on other entities.
“IMEA made certain investments in external units to meet its capacity needs. IMEA made a voluntary election to submit an FRR plan,” the Monitor said. “IMEA made these decisions based on expectations that were not realized. IMEA’s unrealized expectations do not justify waiving the rules.”
PJM Not Opposed
PJM filed comments last week saying it does not oppose IMEA’s current waiver request. It noted that stakeholders have begun a review of the underlying issue regarding historical transfer rights. (See PJM MIC OKs Capacity Transfer Rights Query.)
“PJM cannot predict with certainty if and when a resolution will be reached through the stakeholder process,” the RTO said. “However, PJM anticipates that the stakeholder process will not have run its course in time to culminate in a filing with the commission to resolve the identified issue prior to the 2015 BRA.”
The Nuclear Regulatory Commission is investigating the failure of two transmission lines at Entergy’s Pilgrim nuclear station in Massachusetts, which forced the plant to shut down during last week’s blizzard.
The lines leading out of the plant failed at about 4 a.m. Tuesday, and service was restored two days later. The Plymouth power station remains shut down for maintenance work, an Entergy spokesman said. Entergy officials said there was no threat to public safety and that it is continuing to investigate.
Scram at Entergy’s River Bend Plant Prompts Special NRC Inspection
An emergency shutdown and a series of subsequent pump failures at Entergy’s River Bend nuclear station near Baton Rouge, La., on Christmas morning has resulted in a special inspection by Nuclear Regulatory Commission officials.
The NRC said it was sending a team of inspectors to oversee Entergy’s analysis of a series of failures that required plant workers to manually align valves to restore normal water levels in the reactor vessel.
River Bend’s woes began when an electrical failure in a turbine valve triggered an automatic shutdown. A series of failures in feed-pump controls caused overly high water levels in the reactor vessel, and another pump failure and monitor failures led workers to use backup equipment to restore coolant to the proper height.
Duke Ash Ponds Still Leaking Up to 3 Million Gallons a Day
Duke Energy, still cleaning up a disastrous discharge of coal ash from its Dan River plant, reported that its coal ash ponds across North Carolina may be leaking up to 3 million gallons a day.
According to filings with state regulators, Duke has identified 200 seeps at 14 of its coal-fired plants. Two of those plants — Asheville and Lee — leak up to 1 million gallons of ash-contaminated water daily.
Those leaks appear to be illegal under new state laws enacted after the Dan River disaster. That leaves Duke with two options: repair the leaks or include them in updated wastewater discharge permits. “Our objective is to include seeps in the permits so we can follow the appropriate monitoring protocol or next steps regulators prescribe,” Duke spokeswoman Erin Culbert said.
Duke Energy Spending on Lee Nuclear Station Approaches $45 Million
Duke Energy’s investment in its proposed W.S. Lee Nuclear Generating Station near Gaffney, S.C., continues to climb.
Duke said it spent nearly $45 million on the plant last year. Since Duke applied for a license in 2007 for the 2,234-MW plant, the company has spent $426.6 million, according to company filings. Duke expects to get a construction and operating license from the Nuclear Regulatory Commission next year.
The company could file to recover the costs whether or not the plant is ultimately built, if regulators determine the costs are reasonable.
Duke Exploring Storage Battery Technology, More Projects Coming
Duke Energy sees a future in utility-scale battery storage and said it already has six battery projects in operation.
Duke Energy Technology Development Manager Thomas Golden said in an interview with Smart Grid Today that the company is experimenting with various technologies, from chemical makeup to interconnection systems, to adapt battery storage for large utility systems.
“We believe the batteries are here to stay,” he said. One project is to install a storage battery to smooth out peaks from its growing solar generation fleet.
France’s UniStar Asks for Delay in Preparing Report for New Calvert Cliffs Reactor
Electricite de France’s UniStar Nuclear Energy, which has proposed building a third reactor at Exelon Nuclear’s Calvert Cliffs plant in Lusby, Md., has asked the Nuclear Regulatory Commission for more time to submit a Facility Safety Report.
The plans for a third Calvert Cliffs reactor go back to 2008, when then-partners Constellation Energy Group and EDF announced plans to build a new 1,600-MW reactor. Constellation has since merged with Exelon, and EDF purchased UniStar. EDF now owns the plans for the new reactor outright.
Its request for an extension to file the safety report indicates that the project is still alive.
NextEra Promises $60 Million in Savings for Hawaiian Electric Customers
NextEra told regulators that customers of Hawaiian Electric Companies will save $60 million if its acquisition of the company is approved.
NextEra said it will not seek a base-rate increase for at least four years after the acquisition. The company also vowed that it will not seek to recover any costs associated with the acquisition. It said it hopes to finalize the deal, pending regulatory approval, by the end of this year.
ALLETE Pays $168 Million for Majority Stake in US Water Services
ALLETE is spending $168 million to gain a majority stake in U.S. Water Services, an industrial water management company based in St. Michael, Minn., with operations throughout the U.S.
The company said it will gain an 87% ownership and plans to buy the remaining shares later.
ALLETE also owns Minnesota Power; Superior Water, Light and Power of Wisconsin; ALLETE Clean Energy in Duluth; and BNI Coal in Center, N.D.
Synch and Primary reserve changes (Source: PJM Interconnection LLC)
The Federal Energy Regulatory Commission issued a deficiency letter last week asking PJM to justify its proposal for pricing reserves in emergencies (ER15-643).
The Jan. 27 letter from FERC’s Office of Energy Market Regulation gave PJM 15 days to respond to a series of questions about the RTO’s effort to reduce uplift and ensure that energy prices better reflect operator actions. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)
The letter questioned PJM’s rationale in valuing extended reserves — reserves procured in addition to primary and synchronized reserves — up to $300/MWh. It also asked PJM how it plans to calculate additional reserve requirements for the day-ahead and real-time markets.
The changes outlined in PJM’s Dec. 17 filing were unanimously approved by the Members Committee on Nov. 21.
“PJM’s proposal merely ensures that the additional reserves already scheduled by PJM’s system operators are included in the updated reserve requirement used by PJM’s market clearing engines,” PJM said. “In this way, PJM will be better able to align market clearing prices with its system operators’ actions, while the total production cost of providing reserves will remain the same.”
“PJM’s changes will reduce uplift, decrease price suppression and allow for reserves to be priced consistent with market conditions,” P3 said.
The group added, “The broad support for the proposal is an indication of the importance of getting reserve pricing correct and, perhaps more importantly, recognition of the need to procure additional reserves during times of system stress.”
Public Service Electric and Gas and two sister companies offered limited support.
“While a step in the right direction in improving the Tariff provisions concerning shortage pricing, the PJM filing is not a complete solution to achieve PJM’s stated objective — ‘to enhance PJM’s market rules to better capture actions into energy and reserve pricing.’”
PSE&G also said it disagreed “with PJM’s claim that the reliability contribution of primary reserves is necessarily greater than reliability value of ‘extended reserves’ deemed necessary by PJM’s own operators during times of system stress.”
A Massachusetts state legislator whose district includes the soon-to-be shuttered Brayton Point generating plant has filed legislation that would revamp the state’s energy landscape.
