Search
`
November 1, 2024

Posted on

Eversource to Sell New Hampshire Plants

By William Opalka

eversourceEversource Energy will sell its New Hampshire power plants to satisfy regulators’ divestiture demands and resolve a long-standing dispute over how much it should recover from ratepayers for pollution controls on its largest coal-fired generator.

Under an agreement announced Thursday, Eversource’s subsidiary, formerly “Public Service of New Hampshire,” will seek to sell three fossil fuel plants and nine hydroelectric stations, exiting the power generation market in the state. Eversource said it will join the state’s other utilities in purchasing energy on the open market.

Legislation enacted last year directed the state Public Utilities Commission to investigate ways to expedite the company’s sale of its electric generation as a means to develop energy markets and save consumers money.

An April report by the PUC said that the plants had a book value of $660 million but could only expect to bring in $225 million in any sale.

Eversource and state negotiators said the agreement will save consumers $300 million over the next five years due to securitization of those stranded costs. Realizing the savings will require legislation approving low-cost bond financing.

The settlement also resolves the long-standing issue over pollution upgrades made to the 439-MW Merrimack Station in Bow. Eversource agreed to forgo recovery of $25 million of the $422 million it spent on a scrubber on the 55-year-old generator.

The PUC in 2011 authorized a temporary charge of $0.98/kWh while the case remained on its docket, but the charge was insufficient to cover the entire cost of the scrubber. The PUC late last year was prepared to enter an order determining how the costs would finally be split when legislators and the company requested a delay to continue negotiations. The PUC agreed to the delay but denied a PSNH request to stay the divestiture proceeding.

“This agreement represents an opportunity to create real savings for PSNH customers, avoids protracted litigation with uncertain outcomes for all parties and moves the operation of PSNH generating plants to competitive markets rather than remaining an ongoing ratepayer obligation,” said Senate Majority Leader Jeb Bradley, who led the negotiations with the company.

In addition to Merrimack, the sale includes the 400-MW oil-gas Newington Station, built in 1974, and the 63-year-old 150-MW Schiller Station in Portsmouth, which burns coal, oil and biomass. The nine hydroelectric plants total 69 MW.

The agreement also includes a freeze on distribution rates through July 2017, and requires the plant buyers to honor current collective bargaining agreements and to keep the plants in operation for 18 months.

The agreement also calls for three years of property tax stabilization payments if a plant sells for less than its assessed value.

Eversource shareholders will also provide $5 million to capitalize a clean energy fund, which will target investments in energy efficiency and distributed generation projects.

The deal disappointed the New Hampshire Sierra Club, which sought the closure of Merrimack. Marc Brown, president of the New England Ratepayers Association, said he feared savings from the plants’ sale would be short-lived and that prices will rise as the state becomes more reliant on natural gas-fired generation.

Posted on

Michigan Leaders at Odds over Deregulation

By Chris O’Malley

michigan
Snyder

A week after a Michigan lawmaker introduced a bill that would end electric deregulation, fellow Republican and Gov. Rick Snyder unveiled an energy plan of his own that would continue the state’s limited customer choice.

Michigan’s current plan allows up to 10% of an electric utility’s retail load to purchase power from alternative suppliers. Last year, 13 alternative suppliers provided 2,354 MW statewide.

DTE Energy and Consumers Energy have complained that the choice plan makes capacity planning difficult, especially as they retire coal-fired plants and try to gauge how much replacement they’ll need.

On March 5, state Rep. Aric Nesbitt, chairman of the House Committee on Energy Policy, introduced a package of bills that included elimination of electric choice.

“Retail customers currently purchasing electric generation service from an alternative electric supplier must return to receiving electric service from the incumbent electric utility when the primary term of their existing agreement with the alternative electric supplier expires,” reads Nesbitt’s House Bill 4298.

On Friday, Snyder proposed a plan that would retain the 10% customer choice cap and increase the state’s renewable energy goal to 19% by 2025, up from the current 9%. The governor’s plan also calls for reducing energy waste to meet another 21% of Michigan’s energy needs, up from 6%.

Capacity Concerns

Snyder would require that alternative electricity suppliers submit plans to the state Public Service Commission on a rolling, five-year basis that demonstrate that they have adequate capacity and reliability.

michigan
(Source: Governor Rick Snyder)

 

“If you want to play, you have to carry your weight as far as being an alternative provider,” Snyder said, speaking at the Detroit Electric Industry Training Center in Warren.

A lack of adequate capacity has been a concern for Michigan regulators as well as MISO. The RTO forecasts that its Zone 7, which includes most of Michigan’s Lower Peninsula, will be 3,000 MW short of its reserve margin in 2016.

Michigan’s commission said that “there appears to be a gap in the planning and procurement of adequate resources for the long-term for customers served under the customer choice program.”

That’s the result of “ambiguity” in responsibility among Michigan’s utilities and alternative suppliers for providing long-term planning reserves and associated cost allocation issues, the commission said.

Utilities say these are trying times for fleet planning, due to the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS), which take effect this year, and its proposed carbon emission rule.

“We’re expecting the retirements of about 60% of the state’s coal-fired plants in the next 10 to 15 years,” DTE spokesman Scott Simons said. “With the shortfall, we’re planning capacity without that 10%” of customers who buy power from alternative suppliers.

Consumers Energy said it supports Nesbitt’s proposal to return to a fully regulated environment.

“The evidence and historical record is clear that customers benefit the most from the fairness, stability, affordability and investment provided by full state regulation,” the company said in a statement.

Less Choice, Higher Prices

Energy Choice Now, a group pushing for additional deregulation, expressed its appreciation for Snyder’s stance but would have liked the governor to expand customer choice further. “Since 2008, Michigan lawmakers have imposed a system of winners and losers in this state, with 90% of us being the losers,” Executive Director Wayne Kuipers said in a statement shortly after Snyder rolled out his proposal.

Michigan once had “a very successful electricity choice program,” Theodore Bolema, senior policy editor at the Mercatus Center at George Mason University, wrote in a report two years ago for the Michigan-based Mackinac Center for Public Policy.

According to the report, before competition began in the state, in 2002, Michigan’s rates were well above the national and Great Lakes state average. Two years after competition was introduced, rates fell below the national average. But after the 10% cap and other changes in 2008, rates increased rapidly. By the end of 2012, rates were 18% above the national average.

Michigan electric customers have paid $10.5 billion above market rates since 2009, claims Energy Choice Now.

Kuipers noted that there’s a backlog of electric customers who want to join the choice program but cannot because of the 10% cap.

Almost 6,500 customers participated in the electric choice program as of last December, with about 11,000 customers waiting in the queue, according to the PSC.

That doesn’t count other customers who are interested in joining the program but haven’t applied because of the waiting line, Energy Choice Now spokeswoman Maureen McNulty Saxton said.

The choice program is dominated by commercial and industrial customers and public institutions such as school districts. There are virtually no residential customers participating.

MISO Flexible

All MISO states excluding Michigan and Illinois operate under traditional regulated monopolies.

“MISO’s view is that we can work with either regulatory framework,” MISO spokesman Andy Schonert said. “Through the stakeholder process we try to develop an approach that accounts for differences on a state-by-state basis. The resource adequacy requirement and OMS Survey are ways to help give that region-wide view for the regulators and load-serving entities responsible for ensuring resource adequacy.”

Posted on

Debate over Cost, Impact of EPA Clean Power Plan in Southeast

By Rich Heidorn Jr.

epaWASHINGTON — Witnesses from the Southeast generally expressed far more concern than their counterparts in the Northeast during the Federal Energy Regulatory Commission’s technical conference on the Environmental Protection Agency’s Clean Power Plan on Wednesday.

Mary Salmon Walker, chief operating officer for the Georgia Environmental Protection Division, said the proposed rule fails to give her state credit for previous CO2 emission reductions or for Georgia Power’s Vogtle nuclear units 3 and 4, now under construction.

She also said EPA’s assumption that the state can obtain 10% of its energy from renewables by 2030 is unrealistic and should be reduced to 7.5%.

Georgia also opposes an alternative method for calculating state goals that EPA included in its Notice of Data Availability in October. The state says it would force an 83% reduction in fossil fuel generation from 2012 levels. (See EPA Signals Flexibility on Interim Carbon Targets, Coal-Gas Shift.)

Too Much, Too Soon

Paul Newton, North Carolina president of Duke Energy, said the EPA proposal is “too much too soon” and that the proposed interim targets would require North Carolina and Florida to meet more than three-quarters of their 2030 emission reduction requirements by 2020, resulting in billions in stranded assets.

The company said it has invested more than $7 billion on SO2 scrubbers and selective catalytic reduction technology that controls NOx emissions to bring its coal-fired generators into compliance with EPA regulations. “The EPA modeling of its proposed ‘preferred option’ shows a number of Duke Energy coal units shutting down by 2020. Duke Energy currently has no plan to retire the units the EPA modeling shows retiring,” Newton said.

Duke said EPA should eliminate the interim compliance period targets and allow states to develop their own “glide paths” to meet the 2030 targets. The North American Electric Reliability Corp. or its delegates should evaluate state implementation plans to help identify possible reliability problems before submitting them to EPA, the company said.

John Trawick, Southern Co.’s senior vice president for commercial operations and planning, said the company will have to negotiate four sets of state regulators, legislatures and environmental departments as Georgia, Alabama, Mississippi and Florida develop their implementation plans. “It’s a very challenging thing to deal with,” he said.

Sky is Not Falling

John D. Wilson, research director of the Southern Alliance for Clean Energy, offered a much sunnier picture. “I’m ‘the sky is not falling’ person here today,” he told the commission.

Wilson said the size of Duke, Southern and the Tennessee Valley Authority means they can meet the EPA requirements with “relatively modest” steps — increasing solar and wind power and improving planning and operational tools the utilities already use.

“EPA’s proposed Clean Power Plan will be flexible and, frankly, not challenging enough to merit alarm,” Wilson said.

The alliance cited studies that it says concluded an 18% renewable energy portfolio and state energy efficiency targets of at least 15% — rather than the roughly 10% savings assumed by EPA — are feasible.

“Wind- and solar-power market-development opportunities in the Southeast are at least 15 to 20% of total generation, several times greater than the 0 to 10% considered by EPA,” Wilson said. “Wind resources are available in-region; proposed HVDC transmission provides access to on-peak wind resources that will complement solar.”

Wilson conceded that compliance will be more difficult for smaller utilities with limited generation diversity. To help them comply, state regulators should support the establishment of credit or allowance markets, he said.

One of those smaller utilities is the Seminole Electric Coop., which supplies nine distribution cooperatives in 42 Florida counties.

James Frauen, vice president of technical services and development for Seminole, said the 38% carbon reduction EPA set for Florida would require retirement of more than 90% of the state’s coal-fired generation — including the 1,300-MW Seminole Generating Station, which generates 50% of the co-op’s power — most of them by 2020.

The co-op has invested more than $500 million on the plant, funded by long-term loans that represent more than three-quarters of its outstanding debt. It says it planned to run the plant, which it calls “one of the cleanest in the nation,” until at least 2045.

“None of the options are particularly good. It’s going to cost more,” said Frauen, who noted that the co-op’s rates are already higher than average because of its low population density. “We can get there, but certainly not by 2020.”

Florida’s Challenges

Florida has firm transmission to import only 2,800 MW of generation to serve its 52,000 MW of load. It also has no natural gas reserves, nor the geological formations to economically store gas underground.

“A substantial amount of coal-fired electric generation must remain in Florida to ensure some level of fuel diversity and the resulting reliability benefits,” Frauen said. “To remove more than 90% of coal capacity from Florida would obligate Florida to rely solely on ‘just in time’ inventory for nearly all of its fuel supply, with reliability consequences for any disruptions in the supply chain.”

(See related stories, FERC Seeking Its Role on Carbon Rule ‘Safety Valve’.)

Posted on

Inhofe Decries EPA ‘Power Grab’

By Ted Caddell

inhofe
Sen. Jim Inhofe (R-Okla.) opened a hearing last week by displaying a map identifying the 32 states he said are opposing EPA’s proposed carbon emission rule, which he called a “selfish power grab.” The Natural Resources Defense Council said Inhofe’s map “radically overstates state opposition.”

There’s no mistaking where Sen. Jim Inhofe (R-Okla.) stands on global warming and the Environmental Protection Agency’s plans for addressing it.

In February, the chairman of the U.S. Senate Environment and Public Works Committee brought a snowball onto the Senate floor to underscore his skepticism of climate science. Last week, he kicked off a committee hearing by displaying a map identifying the 32 states he said are opposing EPA’s proposed carbon emission rule, which he called a “selfish power grab.”

“The proposal undermines the longstanding concept of cooperative federalism and the Clean Air Act, where the federal government is meant to work in partnership with the states to achieve the underlying goals,” Inhofe said. “Instead, the rule forces states to redesign the way they generate, manage and use electricity in a manner that satisfies President Obama’s extreme climate agenda.”

In a two-hour hearing, the committee heard from officials from Wyoming, Wisconsin and Indiana, who said the rule would harm their states’ economies, and representatives from California and New York, who insisted it is necessary and achievable.

“You can significantly reduce these emissions in a way that grows your economy,” said Michael J. Myers, chair of the litigation section of New York’s Environmental Protection Bureau. “The time is now for state leadership. So take the wheel.”

Todd Parfitt, director of the Wyoming Department of Environmental Quality, said EPA’s “timelines are problematic if not unrealistic.” A major problem for his state and others in the Midwest, he said, is that EPA would give credit for wind power to consuming states rather than producers. He said that 85% of wind energy generated in Wyoming is consumed outside the state.

Under the Clean Power Plan, states will first be asked to come up with their own ways to implement the emissions reductions rules, but the federal government would step in and impose rules if they don’t.

The Natural Resources Defense Council said after the hearing that Inhofe’s map “radically overstates state opposition” by including any state where a state official or agency has raised concerns.

Indiana is among the 12 states that are challenging EPA’s authority to issue and enforce the carbon rule. Oral arguments in the case are scheduled for next month before the D.C. Circuit Court of Appeals.

Posted on

PJM MIC Briefs

VALLEY FORGE, Pa. — PJM will delay action on manual changes on generator notification and start-up times until the Federal Energy Regulatory Commission rules on the RTO’s Capacity Performance proposal (ER15-623, EL15-29).

The issue stems from a four-year-old problem statement drafted to address reliability and market implications of de-staffing little-used generator units during the spring and fall shoulder months. At the time, some manual changes were endorsed, but others were overlooked, and the issue was mistakenly closed.

Chantal Hendrzak, PJM general manager of applied solutions, told the Market Implementation Committee on Wednesday that many stakeholders had provided feedback since the issue was resurrected in February. (See Members Dispute PJM, IMM on Unfinished Changes to Notification, Start-Up Times.)

Some wanted to re-open the issue because they had not been involved in the original talks; others questioned whether years-old solutions were still appropriate.

“A lot’s changed … and we’ve got this thing called [Capacity Performance] coming that talks specifically to this,” she said. “Let’s get that feedback first and then decide how best to handle the remaining scope.”

PJM asked FERC to rule on the Capacity Performance proposal by April 1.

CTS on Track Despite PJM-MISO Interface Pricing Dispute

The dispute between MISO and PJM over interface pricing is not expected to derail the Coordinated Transaction Scheduling product intended to reduce uneconomic power flows between the RTOs, PJM officials told the MIC. In presenting the interregional coordination update, Stan Williams told the committee that MISO believes its Independent Market Monitor’s pricing proposal is superior to PJM’s. (See Patton Asks FERC to Set Deadline on PJM-MISO Interface Pricing Dispute.)

Meanwhile, PJM believes that proposal “will misrepresent the impact of interchange on internal PJM constraints,” he said. PJM staff also believes the impact of the modeling issue has been “significantly overstated,” Williams said.

Regardless, the RTOs plan a joint FERC filing outlining the CTS proposal in May, with hopes of launching it by November 2016.

PJM Drafting Proposal on External Capacity Transfer Rights

PJM staff will draft a detailed proposal for allocating capacity transfer rights to historical external resources and present it to stakeholders in April, MIC members were told Wednesday.

In December, PJM stakeholders agreed to review modeling practices that the RTO said might be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market. (See PJM MIC OKs Capacity Transfer Rights Inquiry.)

The issue involves only a few players, said Stu Bresler, vice president of market operations, who presented the MIC with a “conceptual” proposal. Among them is the Illinois Municipal Electric Agency, which uses capacity resources outside of the Commonwealth Edison locational deliverability area to meet its internal resource requirements.

CO2 Emission Rates Steady

pjmDespite retirements of numerous coal-fired generators, PJM has reduced its carbon emissions only modestly in the last five years.

Between 2009 and 2014, PJM’s system average emissions dropped 3% to 1,108 lb/MWh. Marginal on-peak units saw a bigger, 10% drop to 1,646 lb/MWh while off-peak dropped 7% to 1,707 lb/MWh.

The Environmental Protection Agency’s proposed Clean Power Plan would require an overall 30% reduction in power plant carbon dioxide emissions from 2005 levels by 2030.

The burdens will fall unevenly on PJM states, with Kentucky, West Virginia and Indiana — the top-ranked PJM states in 2012 carbon emissions per megawatt-hour — having to cut their emissions by only 20%, while New Jersey, already the least carbon-intensive state in the RTO, having to cut its emissions the most in percentage terms (43%).

PJM’s 2014 system-wide average puts it well above EPA’s proposed targets for New Jersey and four other states but below the targets for eight states. (See Carbon Rule Falls Unevenly on PJM States.)

PJM Releases More Details on Carbon Plan Impact Study

PJM this month released more details on its scenario analyses of the Clean Power Plan with a 129-page study of the economic impacts of adhering to the new carbon rule. The RTO released preliminary results of the study, which was requested by the Organization of PJM States (OPSI), in November.

The study concludes that individual state compliance would be more costly than a regional approach and would increase the capacity at risk for retirement. PJM expanded on the key findings with an appendix providing state-by-state impact.

PJM will use the results of the economic analysis as the foundation for reliability analyses to determine transmission needs resulting from potential generator retirements. (See related item in PJM TEAC Briefs.)

(Prior coverage PJM: EE, Renewables Could Save Some Coal Plants under Carbon Rule.)

— Suzanne Herel

Posted on

PJM Transmission Expansion Advisory Committee Briefs

VALLEY FORGE, Pa. — PJM received 118 transmission proposals during the competitive window that closed in February, including 92 market efficiency projects and 26 to address reliability problems.

pjmNineteen transmission owners and non-incumbent developers submitted proposals, led by ITC Holdings, FirstEnergy, Commonwealth Edison and American Electric Power with at least 10 each.

The market efficiency proposals are intended to relieve congestion in 12 locations, nearly half of the proposals targeting the AP SOUTH and AEP-DOM regional facilities. In addition to 34 transmission owner upgrades ranging from $100,000 to $81 million, there were 58 greenfield proposals projected to cost from $9 million to $433 million. (See PJM TEAC IDs 20 Market Efficiency Candidates.)

PJM’s Tim Horger suggested that the Federal Energy Regulatory Commission’s ruling last month rejecting the RTO’s proposed $30,000 fee on greenfield proposals was a factor in the unexpectedly high number of market efficiency proposals. (See FERC Rejects Fee on Greenfield Transmission Projects.)

Initial analysis of the proposals will require more than 15,000 hours of computing time, assuming 160 hours of base runs for each proposal, Horger told members of the Transmission Expansion Advisory Committee on Thursday. Sensitivity analyses on projects that pass the initial screening will require additional time.

“This will be a challenge, at the least,” Horger said. “I’m confident our guys will get it done.”

Particularly demanding will be the projects proposed for AP SOUTH, he said, as they can impact other interfaces. Those proposals likely will take until the end of the year to review.

The reliability proposals consist of 15 transmission owner upgrades with a cost range of $300,000 to $62 million and 11 greenfield projects estimated from $18 million to $101 million.

PJM Studying Tx Upgrades Needed Under EPA Carbon Rule

PJM is conducting studies to determine transmission upgrades that may be needed to respond to plant retirements resulting from the Environmental Protection Agency’s proposed carbon emission rule.

Preliminary results of a scenario assuming 16 GW of at-risk generation identified voltage and thermal violations. The plant retirements were assumed to be evenly distributed between 2020 and 2029.

The voltage issues affected the PJM West, Southwest MAAC and Dominion locational deliverability areas (LDAs).

Thermal violations prevented five LDAs from importing their capacity emergency transfer objective (CETO) values in the load deliverability test. The generation deliverability test found multiple 230-kV violations, mostly in Southwest MAAC.

Planners will continue the analysis with scenarios assuming 6 GW and 32 GW of generation at risk.

— Suzanne Herel

Posted on

Company Briefs: March 17, 2015

NRG Yield is buying majority stakes in two Colorado wind farms with a combined capacity of 63 MW. The company also announced it is buying a 1.4-MW fuel cell project in Connecticut.

NRG is buying the wind farm interests from Invenergy. Spring Canyon II and Spring Canyon III, consisting of 35 GE turbines, began operations last year and sell their output to Platte River Power through a 25-year power purchase agreement. NRG is buying the University of Bridgeport Fuel Cell project from Fuel Cell Energy.

The two transactions are valued at about $41 million.

More: SeeNews Renewables

Xcel Asks Minnesota PSC to Limit Large-Scale Solar

Xcel Energy has asked the Minnesota Public Service Commission to limit the aggregation of smaller solar “gardens” that qualify as large-scale projects.

The request is in response to the popularity of the state’s Solar Rewards Community program, which already has attracted proposals totaling 431 MW. Minnesota law restricts smaller, community “garden” solar projects to 1 MW, but allows projects to band together to form larger facilities in order to take advantage of location and transmission connections. Xcel cited one proposal for 50 MW of 1 MW gardens in a suburb near Minneapolis.

Among Xcel’s suggestions: limit co-located applications to 1 MW or less; allow co-located applications from single developers as long as they don’t exceed 1 MW; and limit applications from multiple developers at co-located sites to 1 MW. Xcel said community solar projects are expensive and add 1.5 to 1.8% to ratepayer bills.

More: Midwest Energy News

Arkansas Electric Co-op Looking at More Hydro

Arkansas Electric Cooperative Corp. this month filed preliminary permit applications with the Federal Energy Regulatory Commission for three new hydroelectric generating stations on the Arkansas River with a total capacity of 123.6 MW.

AECC surrendered previous licenses it held for hydro projects at several locks and dams on the river, saying they were uneconomic to develop at the time. But AECC said it has revived interest in the hydro potential of lock and dam Nos. 3, 5 and 6. The licenses for those facilities, held by another entity, expired at the end of February. An Entergy Arkansas transmission line runs close to the proposed stations.

AECC built three other hydropower plants on the river between the late-1980s and 2000 with a total capacity of 167.4 MW.

More: P-14663-000; P-14664-000; P-14665-000

NRG Plant Likely Customer of Controversial PennEast Pipeline

NRG Energy said it would likely switch its Gilbert Station in New Jersey from burning ultra-low sulfur diesel to natural gas if the controversial PennEast pipeline is built to deliver gas from Pennsylvania’s Marcellus Shale region.

The pipeline is owned by a consortium of companies, including affiliates of four New Jersey utilities serving most of the state’s natural gas customers. Pipeline opponents say that no customers directly on the pipeline route would benefit. The comments from NRG are the first public acknowledgement that a local industrial customer might tap into the PennEast line.

More: NJ.com

FP&L Buying, then Closing Jax Coal Plant to Get CO2 Credits

Florida Power & Light is paying $520 million for a modern 250-MW coal-fired power plant near Jacksonville, Fla., that it plans to shut down within two to three years.

FP&L has been paying $120 million a year to buy power from the Cedar Bay Generating Plant under a long-term power purchase contract. The utility says it will be able to cut $70 million in annual costs and reduce carbon emissions by a million tons per year if it buys the plant and shuts it down.

FP&L, a subsidiary of Juno, Fla.-based NextEra, filed a request for the acquisition and proposed shuttering of the plant with the state Public Service Commission.

More: Jacksonville Business Journal

Madison Gas & Electric Bows to Shareholders to Increase Renewables

Madison Electric & Gas agreed to expand its renewables development in response to pressure from shareholders.

The company agreed to work with the shareholder group and a designated consultant to “study adding substantial and measureable amounts of renewable energy” to its supply mix.

A group of MGE Energy shareholders were pushing a proxy proposal calling for the utility to obtain 25 percent of its energy from renewable sources by 2025. The shareholders agreed to drop their proposal after the company made its commitment.

More: Journal Sentinel

SunEdison Buys into Storage Market, Acquires Solar Grid Storage

SunEdison, a major developer of renewable power projects, announced it has purchased a four-year-old solar generation and storage startup.

With the purchase of Solar Grid Storage, SunEdison is venturing into the energy storage business. Solar Grid Storage specializes in linking solar installations with lithium-ion battery systems. It has completed four such projects and is in the planning stage with three more.

Terms of the purchase were not disclosed.

More: Clean Technica

Exelon Seeks Permits for LNG Facility in Brownsville, Texas

Annova LNG, majority owned by Exelon Generation, filed a request with the Federal Energy Regulatory Commission to build a natural gas liquefaction plant and export terminal on 650 acres at the Port of Brownsville, Texas.

For Exelon Generation, best known for operating the nation’s largest nuclear fleet, this will be the first foray into the LNG export business. “The project represents a potential opportunity to diversify Exelon’s role in the energy business in an area that shows strong growth potential: natural gas exports,” Exelon Generation President and CEO Ken Cornew said.

The U.S. Department of Energy recently authorized Annova to export up to 342 billion cubic feet of gas per year to free-trade agreement countries. The company said construction of the $3 billion “mid-scale” terminal would take four years. It will require 26 separate federal, state and local permits and licenses.

More: Exelon; San Antonio Business Journal

Exelon’s Limerick Nuclear Station Gets Additional NRC Inspection

The Nuclear Regulatory Commission has ordered an extra inspection at Exelon’s Limerick Generating Station in Pennsylvania after identifying an unspecified security issue during an inspection last June.

Limerick was notified of the inspection as part of its annual assessment. Post-9/11 security procedures prohibit the agency and the company from providing details about security lapses, but a company spokeswoman said the issue has been fixed.

“We promptly corrected a technical security concern identified last year, and at no time was the security of the facility, our workers or local residents compromised,” Dana Melia said.

More: Mainline Media News

Anti-Nuclear Group Calls on NRC to Withhold Watts Bar 2 License

An anti-nuclear group called on the Nuclear Regulatory Commission to hold off on licensing the Tennessee Valley Authority’s new Watts Bar 2 nuclear station until the TVA reviews earthquake and flood risks at the plant. Watts Bar 2 is currently scheduled to go into operation by the end of this year.

The Southern Alliance for Clean Energy said the earthquake and tsunami that destroyed the Fukushima plant in Japan in 2011 underscores risks not currently planned for at Watts Bar 2. The reactor will be the first new commercial unit to come online in 20 years.

“It shocks the conscience that the NRC is preparing to issue an operating license for Watts Bar Unit 2 potentially this June without completing its post-Fukushima review of seismic and flooding risk,” an alliance spokeswoman said. TVA said it made several changes to the plant’s original design, which were approved by the NRC’s Advisory Committee on Reactor Safeguards.

More: Chattanooga Times Free Press

Westar Files for $125 Million Rate Increase in Kansas

Westar Energy requested a $125 million rate increase to pay for environmental upgrades at its coal-fired power plants and for service life extension work at the Wolf Creek nuclear station near Burlington, Kan.

In a filing with the Kansas Corporation Commission, Westar said nearly half of the increase would pay for coal-plant upgrades to meet federal Clean Air Act standards. One-third would go toward improvements at the Wolf Creek nuclear plant, of which Westar owns 47%. The rate increase would boost a residential customer’s bill about $13 a month.

A state consumer advocate agency indicated it would challenge the request.

More: Wichita Eagle

PPL Issues RFP for 370,000 MWh of Alternative Energy Credits

PPL Electric Utilities is looking to buy more than 370,000 MWh of alternative energy – wind, biomass, solar – in order to meet its Alternative Energy Portfolio Standard requirement in Pennsylvania.

It has hired NERA Economic Consulting to act as RFP manager. The delivery period would start June 1 and run for six years. The bid date for the RFP is April 1.

More: North American Wind Power

FirstEnergy Invests $748M in Infrastructure Projects

FirstEnergy’s three Ohio utilities, which last year spent more than $1 billion on “Energizing the Future” upgrades, want to spend $784 million this year to improve the overall efficiency and reliability of its electric system.

Toledo Edison plans to put $120 million toward upgrading infrastructure. Ohio Edison and The Illuminating Company expect to spend $383 million and $281 million, respectively, for reliability programs. The expenditures include more than $475 million for transmission projects owned by FirstEnergy’s American Transmission Systems Inc.

More: Zacks

Compiled by Ted Caddell

Posted on

Monitor: Winter Prices Boosted PJM Prices, Raise Withholding Concerns

By Rich Heidorn Jr.

PJM’s markets were generally competitive in 2014, but last winter’s cold resulted in a 37% increase in LMPs and raised concerns about economic withholding, the Independent Market Monitor said in its annual State of the Market report, released Thursday.

pjm

Market Monitor Joe Bowring said weather-related demand and higher fuel costs in the first quarter boosted energy prices for 2014 despite lower prices the rest of the year.

Real-time LMPs rose from $38.66/MWh in 2013 to $53.14/MWh last year. Congestion costs increased by $1.2 billion (186%), and uplift jumped 11% to a record $965 million.

As a result, total billings increased by 62% to a record $50 billion, beating the previous record of $35.6 billion set in 2011.

The Monitor said the results show energy prices were generally competitive, meaning they were set by generators offering at, or close to, their marginal costs. The exception was the high demand hours in January 2014, when the behavior of some participants raised concerns about “economic withholding.”

“In particular, there are issues related to the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage,” the report said. “One of the symptoms of these issues was an unprecedented increase in uplift charges in January.”

The adjusted markup component of LMP doubled from $1.16/MWh (3%) to $3.32/MWh (6.2%).

pjm
(Click to zoom.)

“There are currently no market power mitigation rules in place that limit the ability to exercise market power when aggregate market conditions are extremely tight,” the Monitor said. “If market-based offer caps are raised, aggregate market power mitigation rules need to be developed.”

The report includes 11 new recommendations (see table above). Only four of the Monitor’s 83 previous recommendations between 2009 and 2014 have been adopted in full, with another seven adopted in part. The remainder (87%) have not been acted on.

Generator Revenues

Thanks to the high prices last winter, average net revenues — a measure of the incentive to invest in new generation — rose sharply for many generators, with an increase of 74% for combustion turbines, 30% percent for combined-cycle plants, 113% for coal, 43% for nuclear, 24% for wind and 7% for solar.

“The impact of a relatively short period of high loads on net revenues illustrates how scarcity pricing can work to address the missing money issue in wholesale power markets,” the report said.

A new combined-cycle plant would have been profitable in 12 of 19 zones in 2014, while a new CT would have been profitable in 10 eastern zones. Despite the increases, however, new coal and nuclear plants would not have been profitable anywhere in PJM last year.

“Coal is still not remotely close to a signal to invest,” Bowring said during a press briefing last week.

The report identified 22 generators totaling almost 7,000 MW as at risk of retirement, 70% of the capacity from coal units with an average age of 46 years. One-quarter of the at-risk capacity are oil- or gas-fired steam units with an average vintage of 35 years.

Falling into this category were units that did not recover avoidable costs from total market revenues or did not clear the 2016/17 or 2017/18 base residual auctions but cleared in previous capacity auctions.

This is in addition to almost 27,000 MW of retirements that occurred or are expected between 2011 and 2019.

Capacity Market

Bowring also continued his campaign against the inclusion of limited demand response in the capacity market. DR and the 2.5% “holdback” to demand reduced capacity revenues by $3.4 billion (31%), Bowring said.

Total payments for DR rose almost 44% to $676 million in 2014 thanks largely to a $195 million increase in capacity revenues.

The Monitor said DR should be used to offset demand rather than treated as supply.

“A successful redesign of the PJM capacity market to address its identified flaws is the most critical initiative currently being considered by PJM stakeholders,” the report said. PJM’s Capacity Performance proposal, which would address some of the Monitor’s concerns, is pending before the Federal Energy Regulatory Commission.

Auction Revenue Rights & Financial Transmission Rights

Auction revenue rights and financial transmission rights revenues offset almost 91% of total congestion costs in the day-ahead energy market and the balancing energy market for the first seven months of the 2014/15 planning period, nearing full funding “for the first time in quite some time,” Bowring said.

The improvement resulted from a reduction in ARR allocations. “We don’t think it should have been done that way,” Bowring said. “And we think the underlying problems with FTR funding remain.”

The report cites a market design that it said “incorporates widespread cross subsidies.”

Uplift

Uplift rose $96 million to almost $965 million, although uplift as a share of total billings fell to 1.9% from 2.6%. Balancing charges increased $407 million, partially offset by a $282 million reduction in reactive services.

The recipients of uplift payments remained “remarkably concentrated,” Bowring said, with 10 units responsible for more than one-third of the total.

Bowring repeated his call for a change in confidentiality rules that would allow him to identify the units so that competitors could propose new generation or transmission to address the need for the out-of-market payments.

The lack of transparency “means there’s no competitive pressure on them,” Bowring said. “It’s not possible to compete that away.”

Posted on

New York Industrials Want Ginna Deal Tossed

By William Opalka

ginnaA group of large electric customers asked federal regulators to reject an agreement to keep a nuclear power plant in western New York operating.

The group said the Federal Energy Regulatory Commission should reject a reliability support services agreement ordered by the New York Public Services Commission to keep the 580-MW R.E. Ginna plant financially viable to serve customers of Rochester Gas & Electric (ER15-1047).

The utility and NYISO said the plant is needed to maintain system reliability until a transmission project that would bring additional energy into the Rochester area is completed in late 2018. An agreement filed with the PSC on Feb. 13 guarantees annual payments of about $210 million, minus some adjustments for support services. (See Ginna Nuclear Plant Wins Contract to Keep Operating).

The interveners — 60 large industrial, commercial and institutional energy consumers — say the out-of-market payments would distort NYISO’s wholesale electricity markets and result in “potentially staggering rate impacts to RG&E’s retail electric customers.”

RG&E estimated an average residential customer would see bills rise about 4.2% while costs for large primary customers would increase 6%. The exact amount will depend on the monthly output of the plant and changes in wholesale energy and capacity market prices.

The group says RG&E’s estimates understate the impact of the increases because they are averaged over the life of the 3.5-year agreement and are based on the total bill, including commodity costs unaffected by the deal. Primary customers would see increases of 9.05% in 2015. “On a delivery-rate-only basis, the RSSA apparently would result in increases of over 20% to retail customers,” the protest says.

Exelon unit Constellation Energy Nuclear Group said it has lost $100 million over the last three years operating the plant. It said it would mothball the plant without an agreement.

However, opponents to the deal have previously said no formal proceeding to shutter the plant has been started, and the move by CENG is an attempt to sidestep the lengthy and costly process to formally retire a nuclear plant. The interveners say reliability-must-run contracts should only be allowed when there is concrete evidence the plant would otherwise retire.

Posted on

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM generators performed much better during this winter’s cold than a year ago, with forced outage rates limited to 12.3% on Feb. 20, when PJM set a new record winter peak load of 143,826 MW. About 22,800 MW of generation was unavailable due to forced outages.

Cold Sends PJM to New Winter Record.)

Compared with last year, this winter saw some areas with colder temperatures, and they extended farther south, dispatch manager Chris Pilong told the Operating Committee last week.

About 22% of the outages Feb. 20 were due to gas issues. PJM lost 17,500 MW to forced outages the night before the record was set, of which one-third were gas-related.

No emergency procedures were required, and no demand response was dispatched, during the cold snap. There were no major transmission constraints.

SynchroPhasor Error Rates Greatly Improved

SynchroPhasor error rates have been trending downward in the past few months. In January, five of the 12 companies met the 0.2% error goal, and four others were below 1%.

The phasor measurement unit (PMU) technology is not currently considered a “critical” cyber asset but could become so in about a year. Critical assets are defined as those whose failure would, within 15 minutes, adversely impact systems in a way that would affect the reliable operation of the bulk electric system.

PJM expects the technology to become critical once it is used in solutions by the state estimator or becomes crucial to interconnection reliability operating limit (IROL) determinations.

Emergency Tool Refresh Underway

A revamped emergency procedures tool, which has been in testing since Feb. 19, is expected to go live March 30. Phase 2 enhancements are expected to be rolled out in June.

Fuel Type Posting Rule Takes Effect April 1

Generation operators will be required to enter fields for energy fuel type (and sub type) and start-up fuel (and sub type) in eMKT beginning April 1. Offers lacking the information will be rejected.

The rule change follows the Feb. 23 introduction of new functionality allowing generators to make intraday cost schedule changes in eMKT. The manual process for such changes is no longer being used.

— Suzanne Herel