The Nuclear Regulatory Commission Friday cited nine PJM plants for additional scrutiny in its mid-year gradings of the nation’s nuclear fleet.
The NRC grades each reactor based on data submitted quarterly by plant operators (“performance indicators”) and inspections by resident inspectors and regional staff. Its mid-year assessment places all operating units within one of four levels, with the agency’s scrutiny increasing as plant performance declines. (See sidebar: NRC Plant Rating Methodology.)
Eight PJM reactors were named among 17 nationwide in the second highest category and will undergo additional inspections because of items of low safety significance: FirstEnergy’s Beaver Valley 1 and 2 (Pa.) and Davis Besse (Ohio); PPL’s Susquehanna 2 (Pa.), and Exelon’s Three Mile Island 1 (Pa.), Dresden 2 and 3 (Ill.) and LaSalle 2 (Ill.).
In addition, FirstEnergy’s Perry 1 plant in Ohio was among eight reactors cited for a “degraded level of performance,” the third performance level.
The agency said the Perry plant and the Beaver Valley units resolved their issues after the close of the mid-year review and are now in the highest performing level, which are subject to only “baseline” inspections. The agency gave top grades to 75 reactors in the mid-year assessment for the period ending June 30.
One reactor, Browns Ferry 1 in Alabama, is in the fourth category because of a “high significance” safety finding.
In addition, the NRC has shut down the Fort Calhoun plant in Nebraska due to significant performance issues. It is in a special NRC oversight program and did not receive a mid-cycle assessment.
(Source: NRC)
Two other plants, Crystal River 3 and Kewaunee, entered decommissioning during the first half of the year and are no longer considered operating reactors.
Dominion Virginia Power last week won the rights to develop Virginia’s “Wind Energy Area,” nearly 113,000 acres of Atlantic Ocean with the potential to support 2,000 MW of offshore wind generation. But Virginia’s largest utility is making no promises that it will exploit the resource.
“Offshore wind has the potential to provide the largest, scalable renewable resource for Virginia,” the company said in a statement after the auction, “if it can be achieved at reasonable cost to customers.”
That’s a big “if.” The company’s proposed Integrated Resource Plan, filed Aug. 30 with the Virginia State Corporation Commission, commits it to developing only a 12 MW offshore demonstration project. The base 15-year plan, which commits virtually all of its new generation to natural gas, ranked offshore wind as the most expensive of the non-dispatchable resources the company considered, far more expensive than solar or onshore wind.
Dominion estimated a plan incorporating up to 1,600 MW of offshore wind would cost about 14% more than its base plan. This includes an assumption by Dominion that a carbon tax will be enacted by 2023, increasing the cost of generating power with coal and natural gas.
(Source: Energy Information Administration)
The Energy Information Administration estimates the levelized cost of offshore wind at $221/MWh (2011 dollars), more than twice the $87/MWh cost of onshore wind. By comparison, EIA estimates the cost of power from new natural gas-powered combined cycle plants favored by Dominion at $66/MWh.
No Renewable Incentives
The high costs will be a particular challenge in Virginia. The state does not have a mandatory Renewable Portfolio Standard, and unlike Maryland and New Jersey, is not offering any subsidies to encourage offshore wind developers. It also does not allow retail choice, which could create a niche for a green alternative. (See previous coverage: PJM States Seek ‘First Mover’ Status.)
Dominion outdueled competitor Apex Virginia Offshore Wind, LLC in six rounds of bidding conducted by the Interior Department’s Bureau of Ocean Energy Management (BOEM). Six other companies that were prequalified for the auction chose not to bid. One of them, Iberdrola Renewables, told RTO Insider it decided to focus on bringing its pipeline of “more competitively priced” onshore wind projects to market.
Dominion’s $1.6 million bid won it the rights to 112,799 acres on the Outer Continental Shelf, 23.5 nautical miles off Virginia Beach. Assuming it passes an antitrust review by the Justice Department, the company will have five years to submit a Construction and Operations Plan for BOEM’s approval. Including review by state rate regulators, Dominion said it will be a decade before the first turbine could be installed.
Wind Backers Disappointed
Dominion’s victory was a disappointment to environmentalists. Beth Kemler, Virginia State Director at the Chesapeake Climate Action Network, said the company’s IRP “doesn’t leave us with high hopes for Dominion’s speedy development of this clean energy resource.”
“While Dominion came out on top …that unfortunately doesn’t guarantee that the company will actually erect a single turbine. The company could rent the wind energy area for years without moving forward with any development, preventing a more eager company from doing so,” she said.
Dominion spokesman Dan Genest noted that Dominion cannot add new generation without approval of Virginia regulators, who must judge it “prudent.”
“Anything we present as a generation project has to meet the price test,” he said. “To say we’re going to build wind at any cost — the state corporation commission is not going to allow us to do it.”
Genest said the purpose of the company’s demonstration project is to “find ways to make [offshore wind] affordable.”
Demonstration Project
The project, two six-megawatt turbines, will test the use of “twisted jacket” foundations that offer the strength of traditional structures but use substantially less steel. It was one of seven projects awarded $4 million each in federal matching funds to explore ways to lower costs of offshore wind.
Chesapeake Action’s Kemler said another bidder that is not a cost-of-service utility might be willing to develop the site as a merchant project. Other offshore projects under development in Rhode Island, Massachusetts, New Jersey and Maryland hope to finance them through state subsidies, purchase power agreements and the sale of credits tied to mandatory Renewable Portfolio Standards.
Although Virginia has no mandatory RPS, Dominion says it will meet a voluntary goal to obtain 15% of its power from renewables by 2025. Excluding pump storage, renewables represent 3% of Virginia Power’s capacity.
“The legislative climate in the Northeast is a lot friendlier to renewables,” than Virginia, Kemler acknowledged. “But there are certainly plenty of states in PJM that have mandatory RPSs” that might be buyers of offshore wind.
Integrated Resource Plan
Virginia law requires utilites’ Integrated Resource Plans to “promote reasonable prices, reliable service, energy independence, and environmental responsibility.”
Dominion’s recommended expansion plan predicts annual increases in peak demand of 1.6% through 2028. It’s base “least-cost” plan proposes that the company add up to 7,060 MW of new gas-fired generation and 59 MW of solar and biomass, with 544 MW of demand-side management. Also included are PJM market purchases representing 127 MW of capacity and 12% of energy.
In addition, the company developed a higher-cost, lower-emission “fuel diversity” plan that could be needed to respond to potential federal rules restricting greenhouse gases.
It would eliminate one 1,375-MW combined cycle plant, and add 1,453 MW of nuclear power — a third unit at the company’s North Anna facility. Renewables are limited to 220 MW of solar, 247 MW of onshore wind and the 12 MW offshore wind demonstration project. PJM market purchases would increase to 173 MW of capacity.
The company notes that its onshore wind assets are limited to three mountaintop locations in western Virginia. By contrast, the National Renewable Energy Laboratory estimates Virginia has a “technical potential” of 89 GW of offshore wind capacity.
NREL’s estimates don’t consider economic or market constraints that will reduce actual renewable generation. The 2,000 MW “Wind Energy Area” was mapped out by BOEM to avoid conflicts with other ocean uses such as commercial fishing and shipping traffic.
If Democrats backing a carbon tax agree to use the revenue to reduce personal and corporate income taxes, congressional Republicans could sign on, says Harvard economist N. Gregory Mankiw, who served as chairman of the Council of Economic Advisers under President George W. Bush. Most economists agree a carbon tax is a less expensive way to reduce carbon dioxide emissions than current federal policies, such as the corporate average fuel economy (CAFÉ) standards for automobiles.
The Nuclear Regulatory Commission is seeking public comments on how to spend the remaining $11 million in its budget for licensing a nuclear waste repository at Yucca Mountain. The project has been in limbo since 2011 due to opposition from Congress and the Obama administration. On Aug. 13, however, the U.S. Court of Appeals for the District of Columbia ordered the NRC to continue the work required to issue a decision on licensing the facility.
Environmental groups urged the Supreme Court to revive the Environmental Protection Agency’s Cross-State Air Pollution Rule (CSAPR), saying that a lower court’s nullification would prevent regulators from ever tackling unhealthy power plant emissions that cross state lines. The lower court ruling “would force EPA to follow unworkable judicial algorithms that Congress never enacted,” the Environmental Defense Fund, the American Lung Association and others said in a brief filed Wednesday.
The Supreme Court agreed in June to review the appellate decision vacating the 2011 regulation. The rule would force cuts in smog- and soot-forming power plant emissions in more than two dozen states in the eastern half of the country.
Three years after the Obama administration announced plans to return solar power to the White House, workers have completed the installation. President Jimmy Carter had solar panels installed on the White House roof in the late 1970s for heating water. They were removed during a roofing job in 1986 under President Ronald Reagan.
Air pollution from electric generation is responsible for more than 29,000 premature deaths annually in PJM states, more than any other air pollution source, according to a new study by researchers at the Massachusetts Institute of Technology.
(Source: MIT)
The study found that fine particulates (PM2.5) and ozone pollution from electric generation caused 52,000 deaths in the continental U.S. annually, second only to the 53,000 deaths attributed to tailpipe emissions from autos. Within PJM states, auto pollution was second, responsible for more than 23,000 premature deaths.
All told, including other emission sources, such as industrial smokestacks, commercial and residential heating and cooking and marine and rail transportation, air pollution is responsible for 200,000 deaths annually, the study found.
Coal-burning Kentucky, West Virginia and Ohio had the highest electric generation mortality rates in PJM, with Kentucky’s 40.2 deaths per 100,000 population nearly double the rate for New Jersey (22.2). New Jersey has a higher overall death rate, however due to higher impacts from autos, shipping and commercial and residential emissions.
Among cities, the Baltimore metropolitan area ranked worst, with an annual mortality rate of 130 per 100,000 due to high emissions from power generation, autos and industry.
Persons who die from an air pollution-related cause typically have about a decade cut from their lifespan, according to Steven Barrett, an assistant professor of aeronautics and astronautics who was one of the authors of the study.
The researchers found that the impact of auto emissions was highest in densely populated areas while power plants emissions, which are deposited at a higher altitude, were more dispersed.
(Source: MIT)
The highest electric generation-related death rates were in the east-central U.S. and Midwest, which researchers suggested was due to the burning of coal with higher sulfur content than burned in the west.
The Environmental Protection Agency estimates that 74 million people in the U.S. are exposed to levels of PM
2.5 higher than permitted by the Clean Air Act and that more than 131 million live in regions not compliant with ozone limits. The EPA computed the costs for the implementation of the 1990 Clean Air Act to be about $65 billion from 1990 to 2020, potentially avoiding 230,000 premature deaths in 2020.
The MIT researchers based their study on data from EPA’s National Emissions Inventory. The results were published in the journal Atmospheric Environment.
The NRC grades each reactor based on data submitted quarterly by plant operators (“performance indicators”) and inspections by resident inspectors and regional staff. Its mid-year assessment places each operating unit within one of four levels of regulatory response, with the agency’s scrutiny increasing as plant performance declines:
The top-rated plants, judged to be meeting all of the agency’s objectives, are subject to the “baseline” inspection program.
Plants with no more than two white findings — indicating problems causing minimal reductions in safety margin — fall into the second category, subjecting them to additional inspections and oversight by NRC regional officials.
Reactors with “degraded” performance, for example those receiving a yellow finding indicating a moderate reduction in safety margin are subject to higher scrutiny, including involvement of senior regional officials.
NRC headquarters officials take part in scrutiny of plants with multiple yellow findings or a red finding, indicating a significant reduction in safety margin.
Not Operating: Plants with unacceptable reductions in safety margins are not permitted to operate and may have their licenses revoked.
The Markets and Reliability Committee Thursday reviewed two alternatives to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM. The committee will be asked to approve one of the alternatives at its next meeting.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.
Under Alternative 2, state estimator data would be used to interpolate output for each five-minute period with curtailments. Under Alternative 3, forecast data from PJM operations — which is currently used for lost opportunity cost calculations — would be used for curtailment periods.
(Source: PJM Interconnection, LLC)
Both options would use metered data for all hours without curtailments. Units with no curtailments over peak summer hours would not be affected by either option.
The Planning Committee last month approved Alternative 2 by a 101-23 margin, making it the primary option MRC will consider Sept. 26. The MRC also can select Alternative 3, which was approved more narrowly, 68-40. (See Planning Committee OKs Relief for Wind Generators.)
PJM’s Tom Falin said Alternative 2 may be more accurate for short curtailments while Alternative 3 is more accurate for long curtailments. “The most important curtailments are the long ones,” Falin said. “They’re going to impact the average more than a five-minute interruption.”
An analysis released by PJM showed that Alternative 2 would have increased ratings for 21 wind generators with 12 reduced and two unchanged. Alternative 3 increased ratings for 24 generators and reduced them for 11. (See chart)
Any new procedure approved by would be applied to summer 2013 data when capacity credit calculations are finalized in December 2013.
The following issues generated little or no discussion among members when they were brought before the Markets and Reliability Committee for first readings Thursday. The issues will be brought to a vote at the next MRC meeting Sept. 26.
Below are brief descriptions of the issues along with their agenda numbers and links to prior coverage in RTO Insider.
6. COORDINATED TRANSACTION SCHEDULING
MRC will be asked to approve a new product for scheduling trades between PJM and the New York ISO.
Under the current system, power often flows from PJM into New York even when PJM’s prices are higher. The new product, Coordinated Transaction Scheduling (CTS), is intended to reduce uneconomic power flows between the two regions. Traders would be able to submit “price differential” bids that would clear when the price differences between New York and PJM exceed a threshold set by the bidder.
PJM officials had planned to ask the Market Implementation Committee to endorse the proposal Aug. 7 but postponed a vote to provide answers to members’ questions.
Addressing one of the questions that came up before the MIC, PJM’s Rebecca Carroll told MRC Thursday that PJM does not expect the new product to have any impact on balancing congestion, which results because of a change in transmission system capability between the day-ahead and real-time markets. (Negative balancing congestion occurs when the real-time transmission system cannot accommodate all the transactions scheduled day ahead; positive balancing congestion occurs when the real-time transmission capability increases above what was available day ahead.)
Carroll said the scheduling of external interchange transactions won’t affect transmission capability.
PJM and the Market Monitor will seek a vote on a joint proposal to boost penalties for resources that fall short of their synchronized reserve commitments. The measure, intended to address concerns that the current penalty structure is insufficient to ensure compliance, stalled at the Operating Committee in August as utilities called for more details. (See Bid to Boost Synch Reserve Penalties Stalls at OC.)
9. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS
MRC will be asked to choose among three proposals for streamlining the demand response registration process. Current rules require Curtailment Service Providers to submit customer names to both the Electric Distribution Company and Load Serving Entity. The LSE’s role in the process has been largely eliminated as a result of FERC Order 745. (See PJM Proposes Streamlined DR Registration.)
10. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER
MRC will be asked to vote next month on a charter for the Energy Market Uplift Senior Task Force. The task force was created by MRC May 30 to conduct a broad review of its method of providing operating reserve payments. PJM said changes are needed to reduce growing uplift costs. (See MRC Approvals 5/30/13; PJM Proposes Operating Reserve Changes to Cut Uplift.)
12. PJM MANUALS
A. Manual 12: Energy and Ancillary Market Operations and Manual 27: OATT Accounting.
Reason for changes: The changes conform to new policies developed by the System Restoration Strategy Task Force on black start generation, critical load and restoration plans.
PJM will lose some existing black start capacity as a result of pending coal plant retirements. The changes are intended to increase the pool of potential resources. Tariff changes reflecting the new policies were filed with FERC July 9 (ER13-1911).
Section 7 of Manual 27 allows the cost of cross-zonal black start units to be allocated to multiple zones based on transmission owners’ critical load share.
Section 4.6 of Manual 12 governs the number of critical units in a zone and the ratio of black start generation to critical load in a zone. It also eliminates a restriction on the number of black start units at a station, allows units to provide service outside their zone and changes the time in which a unit must close to a dead bus.
PJM contact: Tom Hauske
B. Manual 01: Control Center and Data Exchange Requirements.
Reason for changes: The changes are necessary to comply with NERC Standard BAL-005-0.2b — Automatic Generation Control.
Impact: Creates a new tie line cut-in process requiring telemetry be in place prior to energization. Includes major changes to Section 5.3.5 (Tie Line Telemetry Specification) to provide more detailed requirements for Tie Line Telemetry and Attachment B to remove redundant text and streamline table. EOP-005-2 and EOP-008-1 requirements are updated.
FirstEnergy Corp.’s nuclear operating company will meet with the Nuclear Regulatory Commission Sept. 5 after security forces at the company’s Beaver Valley nuclear plant apparently failed part of a routine “force-on-force” exercise in April.
An environmental group asked Montana regulators for documents that may indicate whether PPL Montana is in talks to sell several power plants to NorthWestern Energy. PPL Montana, which owns 11 hydroelectric plants and several coal-fired plants, and NorthWestern, Montana’s largest electric utility, have refused to comment on rumors of a possible sale.
NRG Energy Inc., the largest independent U.S. electricity generator, may further expand its clean-energy portfolio after its purchase of Energy Curtailment Specialists Inc., an analyst said. NRG announced the purchase of Energy Curtailment in a statement without giving a price. Energy Curtailment manages more than 2 GW of demand response for at least 5,000 customers.
“We see the transaction as among a series of other potential moves for NRG,” an UBS Securities LLC analyst said. “Other potential ‘alternative energy’ investments to complement NRG’s retail offerings could include distributed solar generation.”
Duke Energy chief executive Lynn Good, who began work July 1, discussed her priorities, the coal ash pollution that has prompted state lawsuits and the future of electric service in an interview with The Charlotte Observer.
In an interview, Brad Davids, vice president of utility solutions with EnerNOC Inc., talked about the company’s evolving business model, big data and renewable energy.
“The future is not always 10 years away,” Energy Secretary Ernest Moniz warned in his first major policy address. Speaking at Columbia University’s Center on Global Energy, Moniz discussed President Obama’s climate action plan and said industry change will be driven by extreme weather, distributed generation, electric vehicles and pollution concerns.
After a wait of nearly two years, the Energy Department proposed energy efficiency rules for new commercial refrigeration equipment and walk-in coolers and freezers. The rules represent one of the Obama administration’s first steps to address climate change through executive authority since the president announced his climate action plan in June.
U.S. solar power capacity will exceed wind power generation in about a decade, outgoing FERC Chairman Jon Wellinghoff told Greentech Media. Wellinghoff predicted rooftop solar prices will drop from more than $4 per watt to $1 or $2. “It is going to be the dominant player,” Wellinghoff said. “Everybody’s roof is out there.”
Some analysts predict the U.S. will double its capacity of distributed solar within three years.
The U.S. Senate Permanent Subcommittee on Investigations asked the Federal Energy Regulatory Commission to turn over “key documents” from FERC’s probe of JPMorgan Chase & Co.
Democrat Carl Levin, who leads the panel, and John McCain, its ranking Republican, asked FERC to include a 70-page document outlining investigators’ findings, which was cited in articles by The New York Times. The regulator kept that document private when announcing a $410 million accord with JPMorgan last month.
Most people find it tough to get excited about regulators. But President Obama’s nomination of Ron Binz to head the Federal Energy Regulatory Commission is reason to sit up and take notice.
Energy companies are manipulating costs and other data to deny private and government landholders billions in oil and natural gas royalties, ProPublica alleges. Thousands of landowners are receiving far less money than they were promised by energy companies, with some receiving virtually nothing.
Federal law requires that royalty payments to landowners be no less than 12.5% of the oil and gas sales from their leases.
Coal boosters who hope carbon capture technology will ensure the fuel’s future will find little support in a new report conducted for planners in the Eastern Interconnection.
EPA’s proposed New Source Performance Standards for greenhouse gases will likely make it impossible to permit new coal-fired generation that doesn’t include Carbon Capture and Storage (CCS) technology.
But the report notes that the Department of Energy’s flagship CCS project, FutureGen in Illinois, “has experienced multiple delays and changes of scope and design [and] its prospects remain uncertain.”
Even if CCS becomes economical, the report concludes, the higher capital costs of coal generators means CCS “may be first deployed on natural gas plants before coal-fired plants, if natural gas prices remain low.”
“… Any state-level incentives to support coal mining and encourage the use of coal face an uphill battle in contending with these challenges.”
(Source: EPA)
The report also predicts the retirement of more than 50 GW of current plants between 2013 and 2016, in addition to the approximately 12 GW retired during 2010 through 2012. Of the 269 GW of coal capacity in the Eastern Interconnection, about one-third is located in five states that fall all or partly within PJM: Ohio, Indiana, Pennsylvania, Illinois and West Virginia. The average age of coal units in these states will be nearly 50 years by 2015.
The study, “Current State and Future Direction of Coal-fired Power in the Eastern Interconnection,” was conducted by ICF International for the Eastern Interconnection States’ Planning Council and the National Association of Regulatory Utility Commissioners (NARUC) with funding from DOE.
