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Saturday, December 31, 2011

Court Delays Enforcement of EPA Cross State Air Pollution Rule

A federal appeals court in Washington ruled Friday that the U.S. Environmental Protection Agency must delay enforcement of a regulation aimed at reducing power plant pollution in 27 states. The rule was to go into effect Monday, January 1, 2012, but the court granted a delay sought by more than a dozen electric power companies, municipal power plant operators and states.

The EPA, in a statement, said it was confident that the rule would ultimately be upheld on its merits. But the agency said it was “disappointing” the regulation’s health benefits would be delayed, even if temporarily.

Republicans in Congress had unsuccessfully attempted to block the rule through legislation, saying it would shutter some older, coal-fired power plants and kill jobs. While the Republican-controlled House passed legislation to block the rules, the Senate — with the help of six Republicans — rejected an attempt to stay the regulation.

And theWhite House had threatened to veto it. The rule, finalized by the Environmental Protection Agency in July, replaces a 2005 Bush administration proposal that was rejected by a federal court.  In the first two years, the EPA estimates that the regulation and some other steps would have slashed sulfur dioxide emissions by 73 percent from 2005 levels and nitrogen oxides bymore than half.

Sulfur dioxide and nitrogen oxide pollution from power plant smokestacks can be carried long distances by the wind and weather. As they drift, the pollutants react with other substances in the atmosphere to form smog and soot, which have been linked to various illnesses.

Six states — Texas, Nebraska, Florida, Kansas, Louisiana and Ohio — had asked the court for the delay. All would have had to reduce pollution from their power plants under the regulation. They were joined by local power plant operators and power generating companies, including Entergy, Luminant Generation and GenOn Energy. (Wash Post, 12/31/2011)

Friday, December 30, 2011

Federal Judge Puts Hold On Portion of California CO2 Reg


Federal Judge Lawrence J. O'Neill, of the U.S. District Court for the Eastern District of California in Fresno, rejected the state's greenhouse-gas emissions regulations, finding that California's effort to control fuel imports infringed on Congress's constitutional authority over interstate commerce. It is a victory for refiners and ethanol producers because the ruling says the regulations would have discriminated against crude oil and ethanol imported into the state. The ruling means that refiners and ethanol producers won't have to buy credits when importing oil and ethanol into California, as the regulations would have required in certain cases.

The decision puts on hold a major portion of California's effort to cut greenhouse-gas emissions, at a time when the most-populous state's stance has taken on extra importance nationwide because of a stalemate in Washington over greenhouse-gas legislation.

Refiners and ethanol producers filed a lawsuit over the issue two years ago, arguing the rules penalize suppliers that use crude oil or ethanol from outside the state and would lead to higher costs for consumers.
Judge O'Neill hasn't issued a final decision on the case, but on Thursday he barred California from enforcing the rules while the lawsuit continues.

In setting out the rules, the California Air Resources Board calculated a "carbon intensity" score for different types of fuel, favoring biofuels over carbon-heavy crude, and also assigning imported fuels a higher "carbon intensity" score. To comply with the rules, companies could in some cases be forced to buy credits for fuel scoring high on the carbon intensity scale.

California said the rules on importing were justified because suppliers burn fuel and emit carbon when they transport fuels into the state.

The California Air Resources Board, which put the rules in place in 2010, said it would appeal the ruling and ask the court to "stay its preliminary injunction order in the shortest time possible."

The low-carbon rules on transportation fuels were approved by the California Air Resources Board as part of a sweeping initiative to limit greenhouse-gas emissions, signed in 2006 by then-Gov. Arnold Schwarzenegger. The Republican governor had allied himself with Democratic lawmakers in Sacramento in seeking to make California a world leader in the fight against carbon emissions.

Under the legislation, the state aims to cut its total emissions by 174 million metric tons by 2020, with most of the reduction intended to come from a cap-and-trade program on carbon credits. About 15 million metric tons, or 9% of the total, would come from the low-carbon fuel requirements such as mandating more use of ethanol and biodiesel in vehicles.

The rules have come under broad attack, legally and politically. A ballot measure in 2010 known as Proposition 23 would have kept provisions of the legislation from going into effect until California's unemployment rate dropped by more than half. That measure was defeated by voters, but Judge O'Neill's order adds new uncertainty. (WSJ, 12/30/2011)

EPA Finalizes 2012 Renewable Fuel Standards

The U.S. Environmental Protection Agency (EPA) today finalized the 2012 percentage standards for four fuel categories that are part of the agency’s Renewable Fuel Standard program (RFS2). EPA continues to support greater use of renewable fuels within the transportation sector every year through the RFS2 program, which encourages innovation, strengthens American energy security, and decreases greenhouse
gas pollution.

The Energy Independence and Security Act of 2007 (EISA) established the RFS2 program and the annual renewable fuel volume targets, which steadily increase to an overall level of 36 billion gallons in 2022. To achieve these volumes, EPA calculates a percentage-based standard for the following year. Based on the standard, each refiner and importer determines the minimum volume of renewable fuel that it must ensure is
used in its transportation fuel.

The final 2012 overall volumes and standards are:

Biomass-based diesel (1.0 billion gallons; 0.91 percent)

Advanced biofuels (2.0 billion gallons; 1.21 percent)

Cellulosic biofuels (8.65 million gallons; 0.006 percent)

Total renewable fuels (15.2 billion gallons; 9.23 percent)

Last spring EPA had proposed a volume requirement of 1.28 billion gallons for biomass-based diesel for 2013. EISA specifies a one billion gallon minimum volume requirement for that category for 2013 and beyond, but enables EPA to increase the volume requirement after consideration of a variety of environmental, market, and energy-related factors. EPA is continuing to evaluate the many comments from stakeholders on the proposed biomass based diesel volume for 2013 and will take final action next year.

Overall, EPA’s RFS2 program encourages greater use of renewable fuels, including advanced biofuels. For 2012, the program is implementing EISA’s requirement to blend more than 1.25 billion gallons of renewable fuels over the amount mandated for 2011. (EPA)

More information on the standards and regulations

More information on renewable fuels

Thursday, December 29, 2011

Oklahoma based Chesapeake Energy Corporation will sell $865 million worth of Pennsylvania pipelines to a spun-off subsidiary as part of the oil and gas explorer's broader push to trim debt and close a projected funding gap. Chesapeake formed Chesapeake Midstream, a master limited partnership, or MLP, with private investment fund Global Infrastructure Partners. Shares were sold publicly last year with Chesapeake retaining about a 35% stake. Chesapeake Midstream Partners LP will gain a 47% interest in about 200 miles of pipelines and other gas-gathering assets in Pennsylvania's Marcellus Shale formation.

Chesapeake, the second largest natural gas producer in the U.S., has become the oil patch's predominant deal maker, relying increasingly on asset sales and partnerships to fund drilling and acquisitions of new production fields. The company says it plans to raise $7 billion in 2012 through joint ventures in oil and gas fields, divesting its stakes in oil producer Chaparral Energy Inc. and oilfield service company FTS International Inc., and selling public shares of its own oilfield service company. By comparison, it expects operating cash flow to amount to $6 billion next year.
 
Wednesday's deal is Chesapeake's second with its spin-off. A year ago it sold its network of Louisiana pipelines for $500 million. Acquiring the Pennsylvania assets, which handle more than a billion cubic feet of gas per day, will make Chesapeake Midstream the largest gathering and processing master limited partnership as measured by throughput volume. (WSJ, 12/29/2011)

Monday, December 26, 2011

James Connaughton Gets It Right With Cap & Trade

James Connaughton
Former White House Council On Environmental Quality (CEQ) Chairman James Connaughton is remaining true to the cap and trade philosophy that was developed by his former boss's father.  Republicans and Democrats have switched sides on emissions trading, but Jim is sticking with an approach that the Center agrees is the best way to mitigate emissions.

Connaughton states:
The more market-based approach [cap-and-trade regulatory system] creates opportunities to optimize your pollution control of both [smog-forming compounds] and air toxics. Performance-based [regulations] set the target, usually based on benefit/cost, and then let the private sector sort out the most cost-effective way to get there. And there’s no better example of that than the acid rain trading program. Its main purpose was to deal with the acidification associated with power plant emissions. And no program has been more successful at lower costs, with lower bureaucracy, with virtually no litigation.

If you have a really effective and stringent market-based approach to air pollution, you’re going to get rid of a lot of your air toxics. Now, are you still left with peaks and valleys from one region to another? Yes. But are the peaks and valleys a lot smaller than they were before you did the market-based regulation? Absolutely. The “hot spot” becomes a less and less applicable concept as we get dramatic pollution reductions. You’re always going to have an unequal distribution of emissions of some sort, but pollution is so low now that, relatively speaking, the highs are just not that far away from the lows. Before, there used to be big differences.
(More-The Center for Public Integrity Interview, 12/22/2011))

China Coal Company Buys Into Australia Coal Mining

Yanzhou Coal Mining Company will become the largest standalone coal miner on the Australian stock exchange after Gloucester Coal Ltd. announced that its largest shareholder, Noble Group Ltd. will accept a $2.2 billion reverse takeover. Gloucester’s directors urged shareholders to accept the offer, which is conditional on the successful completion of due diligence and an independent expert’s report finding that the offer is fair and reasonable. Singapore’s Noble Group owns 64.5% of Gloucester, and confirmed in a statement that it intends to accept the offer in the absence of a superior proposal. Singapore-listed Noble Group said that it expects book a gain of about $200 million from its divestment.

Gloucester said the merged entity will be 23% owned by its shareholders and 77% by Yanzhou, which will contribute about $2.7 billion of debt immediately after the deal is completed.

Diversified mining houses BHP Billiton Ltd. and Rio Tinto Ltd. are the biggest coal miners listed in Australia, the world’s biggest exporter of coal.

Rio Tintoand partner Mitsubishi Corp. recently bought the remaining shares they didn’t hold in Coal & Allied Industries Ltd. in a deal that valued the target at A$10.8 billion.

U.S. coal miner Peabody Energy Corp. in November gained control of Macarthur Coal Ltd. with a A$4.9 billion bid, and Whitehaven Coal Ltd. this month agreed to buy smaller Aston Resources Ltd. for almost A$2.3 billion.

By buying foreign assets outright, China is filling projected supply gaps as well as reducing its exposure to fluctuations in coal prices. (WSJ, 12/23/2011)

Thursday, December 22, 2011

E.U. Emissions Trading System Takes Effect January 1, 2012


The Court of Justice of the European Union in Luxembourg ruled in a lawsuit brought by the Air Transport Association of America, American Airlines and United Continental that aviation can be included in the E.U.'s emissions trading system (ETS). The decision cannot be appealed. The European Court of Justice earlier ruled that the EU could, from next year, include all carriers in a carbon trading system targeting polluters as part of the EU's efforts against climate change. The court said the plan "infringes neither the principles of customary international law at issue nor the Open Skies Agreement" covering transatlantic flights.

The US Department of Transportation said it opposed a court ruling which told US airlines to get ready to obey emissions rules in the same way EU companies do. US and Canadian carriers argued the decision was discriminatory and amounted to a backdoor tax. US Secretary of State Hillary Clinton had warned of reprisals ahead of the ruling.

Airlines landing or taking off in Europe will have to join the ETS on Jan. 1, 2012, getting 85 percent of their emissions certificates for free and buying the rest at auction. Even flights conducted by the U.S. Navy will be included.

U.S. air carriers said they would "comply under protest" when the law takes effect but would also press their argument in British court and in international forums.

Environmental groups welcomed the ruling as a necessary nudge for the U.S.

The aviation sector's burden in the ETS for 2012 is expected to be close to €500 million, based on current price forecasts for 2012, when the sector will face a shortfall of around 60 million tons. The cost rises to €9 billion total by the end of 2020.

The CO2 emissions of aircraft operators will be capped at 97 percent of their average 2004-2006 levels next year and 95 percent from 2013 forward. Airlines that do not use all their allowances can sell the excess, while those that are short will have to buy more. Airlines will need to start counting fuel consumption and emissions in 2012, and bills are expected to go out in early 2013, unless they can stop this measure.

Airlines initially would only be required to pay for 15% of the carbon they emit and would be allocated free allowances to cover the other 85%.  Depending on decisions by airlines on how much to pass on to customers, the European commission has calculated that costs per passenger could rise between €2 and €12, much less than the €100 per allowance penalty it would impose on airlines that do not comply.

Several countries including Canada, the U.S., China and Russia have opposed these rules, and the airlines are hoping the fight moves to the political realm where countries can negotiate new rules through the Montreal-based International Civil Aviation Organization. (AFP, E&E Publishing, 12/21/2011, The Guardian, 12/21/2011)

Coal Plants Without Scrubbers Account for a Majority of U.S. SO2 Emissions

Source: U.S. Energy Information Administration, based on Form EIA-860,
EPA Continuous Emissions Monitoring System, Ventyx Energy Velocity.
Note: Circles denotes plants with capacity greater than 25 megawatts.
 Red circles are unscrubbed coal plants, green circles indicate coal plants
 with scrubbers, and blue circles indicate coal plants that plan to add scrubbers.

Coal-fired electric power plants make up the largest source of national sulfur dioxide (SO2) emissions. The Cross-State Air Pollution Rule (CSAPR) calls for a 53% reduction in SO2 emissions from the electric power sector by 2014. To meet this goal, plant owners can implement one of or a combination of three main strategies: use lower sulfur coal in their boilers, retire plants without emissions controls, or install emissions control equipment—primarily flue gas desulfurization (FGD) scrubbers. Plants with FGD equipment generated 58% of the total electricity generated from coal in 2010, while producing only 27% of total SO2 emissions.

SO2 is formed during the combustion of coal. The amount of SO2 produced depends on the sulfur content of the coal burned in a boiler. FGD scrubbers remove the SO2 from a boiler's post-combustion exhaust (flue gas) by passing it through an alkaline solution. This process is also effective in removing acid gases, such as hydrochloric acid. Acid gases are expected to be regulated under EPA's Air Toxics Rule.

Source: U.S. Energy Information Administration,
based on EPA CEMS 2010 data. Note: Graph includes generation
 and emissions from plants with capacity greater than 25 megawatts.

FGD scrubber SO2 removal rates vary based on characteristics such as the specific equipment type, age, and the sulfur content of the coal. New systems have the potential for removal efficiencies of up to 98% according to EPA estimates.

The sulfur content of coal varies by rank. Generally, bituminous coal and lignite coal have higher sulfur content than subbituminous coal, but this can vary by region. Bituminous coal is concentrated in the eastern half of the U.S, while subbituminous coal can be found in the west. Lignite production is concentrated in Texas, Louisiana, and North Dakota.

Subbituminous coal has the lowest sulfur content of the three main coal types, so plants that burn subbituminous coals have been less likely to add scrubbers. Of the plants without scrubbers, the ones burning subbituminous coal generated 69% of the electricity while only emitting 48% of the associated emissions in 2010 (see chart). Even though lignite-burning plants accounted for 16% of SO2 emissions from scrubbed plants in 2010, they generated only 8% of the electricity from scrubbed plants. (DOE-EIA)

Mercury Utility MACT Rule Closes Old Plants & Creates Jobs

PRESIDENT'S CORNER

By Norris McDonald

President George W. Bush issued the first mercury rules, but they were shot down in court.  Now the Obama administration has issued mercury regulations (including other contanimants) that will probably close the oldest, dirtiest coal-fired power plants.  Some utilities claim this will lead to job losses, but EPA Administrator Lisa P. Jackson counters that scrubber installations will create more jobs than will be lost via plant closure.  I guess we will just have to wait and see.  One thing is sure, scrubbers are now as large and complicated as the power plants they serve.  They can cost just about as much as the power plants too.  So signficant jobs should be created by their installation. 

According to EPA:
It will cost about $9.6 billion annually to implement but will provide substantially more in health benefits each year. The EPA estimates the new regulation’s safeguards — which are slated to fully take effect in three years will prevent as many as 11,000 premature deaths a year by 2016 .

The EPA said some 60% of the 1,400 affected coal- and oil-fired generating units already complied with the rule. Many power companies, including Exelon Corp. and Calpine Corp., support the rules because they rely less on coal-burning generation.

Jackson estimated that only 4.7 gigawatts of the nation’s 1,000 gigawattsof electricity capacity,or less than one-half of 1 percent of the nation’s plants, would have to shut down as a result of the new standards.
Of course, critics complain that some of the health stats have been aggregated with other air laws and claim the numbers are inflated.  Yet one thing is clear, mercury is a neurotoxin that can harm the nervous system.

As usual, the litigation has begun, but this rule should withstand lawsuits.  The entire air regulation area frustrates me because it includes, in my opinion, a merry-go-round of legislation, regulation, litigation and it all starts over again.  However, our standards for visible air pollution are stricter than EPA's standards: if you can see the air, it is not healthy to breathe.  So therer would be many more nonattainment days for criteria pollutants than are designated under the EPA system.

We applaud EPA's rule and believe the utility sector will comply to the maximum extent possible.

Natural Gas Exports Could Raise Price of Domestic Supply

Just a few years ago, the Center was working on the LNG import issue.  Now the script has flipped and America is becoming an exporter of LNG due to the boom in domestic shale gas production via hydraulic fracturing.  Of course, this flipping of the import/export issue is brewing a fight between companies that want to export some of America's fast-growing supply of natural gas and big manufacturers that oppose the exports because they rely on cheap domestic gas. Exporting natural gas could cause U.S. prices to increase and could pit manufacturers such as Dow Chemical Co. against energy producers like ConocoPhillips.

Companies are setting their sights on selling liquefied natural gas (LNG) to markets in Europe and Asia where natural gas sells for three to four times the price in the U.S. According to Platt's, natural gas in Japan and South Korea sells for more than $16 per million British thermal units, compared with a benchmark price of a little more than $3 per million BTUs in the U.S. The companies are looking to spend billions of dollars on new terminals that could ship out about 17% of U.S. daily production, or about 11 billion cubic feet per day, according to the Energy Department. But Dow Chemical and others say allowing exports will crimp the supply available to U.S. users and drive up prices here.

To send natural gas across the oceans, companies must supercool the fuel to minus 260 degrees and convert it to liquid form so it can be loaded onto tankers. Building massive coastal facilities to make liquefied natural gas requires multiple permits from Washington and states.

The Energy Department is looking at whether exports will drain U.S. supplies and inflate domestic prices. The Energy Information Administration, part of the department, is expected to deliver its analysis in a few weeks. If the department finds export terminals will raise the domestic price of natural gas and fail to serve the country's best interests, it could block applicants from exporting to most nations except those with free-trade agreements with the U.S. That could doom the projects.
 
Chemical companies would take a  hti becuase they use natural gas as a raw material in car parts, bottles, cleaners, mattresses and other products. Dow Chemical, one of the most outspoken critics of the export proposals, says the U.S. would be better off using its cheap natural gas for domestic manufacturing instead of exports.

Energy companies say there is plenty of natural gas in the U.S. to meet domestic demand and support exports at the same time. They say building the giant export facilities would create construction jobs and boost long-term employment by encouraging a faster rise in U.S. natural-gas output.

While concern over price increases "gets the most airplay," the Energy Department is also examining potential benefits of exports, such as creating jobs and offsetting the large U.S. trade deficit.

Cheniere, which wants to start construction in 2012 on an export facility in Louisiana, is the only company to have cleared the Energy Department hurdle on exports. It got approval to export to most nations in May, before opponents had fully geared up to resist such plans. Cheniere has already signed long-term contracts to supply natural gas to the U.K.'s BG Group PLC, Spain's Gas Natural Fenosa and GAIL (India) Ltd.

Many companies that are seeking permission to export natural gas had planned to import it just a few years ago. Then U.S. production rose 18% between 2005 and 2010, with the bulk of the increase coming from gas trapped in rock formations known as shale.  Import terminals are now gathering dust. Earlier this year, a terminal owned by Dominion Resources Inc. south of Baltimore had to buy a shipment of natural gas from overseas just to keep its equipment running.

With natural gas prices in the U.S. at multiyear lows, power companies can generate electricity more cheaply and pass the savings to consumers. (WSJ, 12/22/2011)

Justice Department Clears Exelon / Constellation Merger

The Justice Department on Wednesday gave antitrust clearance to the merger of Exelon Corp. and Constellation Energy Group Inc. but said the companies must divest three electricity-generating plants in Maryland in order to proceed with the deal. The department said the transaction as originally proposed would have lessened competition for wholesale electricity and increased prices for consumers in the Mid-Atlantic region. The companies agreed to sell the plants as part of a proposed settlement that was filed in a Washington federal court.

The stock-for-stock transaction, announced in April, has been valued at nearly $8 billion.

The companies still need the approval of the Maryland and New York public-service commissions, as well as the Federal Energy Regulatory Commission and the Nuclear Regulatory Commission.

Constellation Chairman and Chief Executive Mayo Shattuck and Exelon President and Chief Operating Officer Christopher Crane will proceed with the merger proposal in 2012. (WSJ, 12/22/2011)

Maryland Public Service Commission Fines Pepco $1 Million

The Maryland Public Service Commission (PSC) has fined the Potomac Electric Power Company (PEPCO) $1 million for tree-trimming failures that have led to dramatically higher outage durations.  The PSC has also threatened to disallow future rate increases unless it improved its performance.  And just when we were impressed with PEPCO's tree trimming action.  They must have know this was coming because they have been out tree trimming like crazy in Prince George's County, Maryland. 

Although each day of outages costs businesses and consumers tens of millions of dollars, we have felt that PEPCO has done a pretty good job of restoring power.  We have to admit that they have fallen down a bit on the tree trimming though.  Appears they are trying to make up for it now.  But do not forget that the legislator and regulators REALLY BURNED PEPCO WITH BOTCHED DEREGULATION. The order said that tree-trimming failures led to dramatically higher outage durations and frequencies in 2010.

The commission order said:

“Pepco’s history of inconsistent and sometimes contradictory tree trimming practices between 1999 and 2010 imposed more costs and outages on customers than otherwise would have been the case had the company adhered to one coherent strategy. Pepco’s reliability problems were amplified by the utility’s refusal to increase the frequency of its tree trimming from once every four years to every two years. Those lapses contributed to poor performance in national reliability studies and increased the power system’s vulnerability to storms "
The commission also concluded that Pepco failed to conduct periodic inspections of its distribution lines and did not conduct after-storm inspections or patrols. Interestingly, PEPCO is replacing distribution lines along with the more aggressive tree trimming. The commission was especially critical of Pepco’s inability to accurately estimate how long it would take to restore service after major storms.

The order noted that Pepco had already initiated a five-year, $300 million program to improve reliability and planned to pass the cost along along to consumers. The commission cautioned that if the program did not reduce outages, the utility might have to pay those costs itself.

A Washington Post analysis found that the average Pepco customer experienced 70 percent more outages than customers of other big-city utilities and that the lights on average stayed out more than twice as long.  Accoring to The Post, Pepco’s reliability began declining five years ago, but company officials failed to immediately mobilize to counteract the decline. (Wash Post, 12/22/2011)

Tuesday, December 20, 2011

National Academy of Sciences Report on Virginia Uranium

The National Academy of Sciences (NAS) and National Academy of Engineering have completed a 22-month review of the proposed Virginia Uranium proposal to mine element in that state.  The 302-page report says uranium could be mined, but the company would have to protect workers, the public and the environment in Virginia. The report said that “steep hurdles” need to be surmounted before Virginia’s longtime ban on uranium mining could be lifted.

Virginia has a decades old ban on uranium mining and many in Richmond expected the study to provide conclusions supportive of lawmakers seeking to lift the ban.  Instead struck more of a cautionary tone.

The state’s Coal and Energy Commission, which ordered the study, will review the findings and recommend to the General Assembly in the next few weeks whether Virginia should lift the ban. The study did not recommend whether the site should be mined. Critics argue that the study is tainted because the company, Virginia Uranium, paid the $1.42 million cost for the report.  This sort of arrangement is not unusual for such reports and is often the case in the preparation of environmental impact statements.

It is being reported that Virginia Uranium has aggressively lobbied lawmakersand has spoken to 100 of 140 legislators and flew more than a dozen of them to France and Canada to visit uranium mines. It is also being reported that Virginia Uranium has donated more than $150,000 to candidates in Virginia and retained five of Richmond’s most influential lobbying and public relations firms.

The 20-member Coal and Energy Commission asked the National Academy of Sciences in 2008 to conduct the study, despite objections from the General Assembly. Several studies have been released.

Thirty-two governmental organizations in Virginia and North Carolina have passed resolutions to keep the ban.

Uranium would be mined underground. (Wash Post, 12/20/2011)

The NAS Report

"Uranium Mining in Virginia: Scientific, Technical, Environmental, Human Health and Safety, and Regulatory Aspects of Uranium Mining and Processing in Virginia (2011)"

Report in Brief

A range of health and environmental issues and related risks are important considerations as Virginia deliberates on whether to rescind its almost 30-year moratorium on mining uranium. Although there are internationally accepted best practices to mitigate most of these risks, there are still steep hurdles to be surmounted before mining and processing could take place within a regulatory setting that appropriately protects workers, the public, and the environment.

Key Findings

• Of the sites in Virginia explored so far, only the Coles Hill uranium deposit appears to have the potential to be economically viable. Extensive site-specific tests would be required to determine the most appropriate mining and processing methods for each uranium deposit. Geological exploration carried out to date indicates that underground mining or open-pit mining are the probable methods of extraction for uranium deposits in Virginia.

• Protracted exposure of workers in uranium mining and processing facilities to radon decay products generally would be expected to represent the greatest radiation-related health risk. Exposure to radon is associated with lung cancer, a link that has been most clearly established in uranium miners exposed to radon. Cigarette smoking increases the risk.

• Other potential health risks for mine workers apply to any type of hard rock mining or other large-scale industrial or construction activity. The inhalation of silica dust and diesel exhaust, to which miners in general can be exposed, increases the risk of lung cancer and silicosis.

• Off-site releases of radionuclides could present some risk of radiation exposure to the general public, depending on how the release occurred and the density of the nearby population.

• Uranium tailings, the solid or semi-solid waste left after processing, present potential sources of radioactive contamination for thousands of years. Modern tailings management facilities are designed to prevent the release of radioactive contaminants for at least 200 years, but longer-term monitoring results from modern tailings facilities are not yet available.

• Virginia is susceptible to extreme natural events, including heavy precipitation and earthquakes, and any uranium mining and/or processing facility would need to take the possibility of such events into consideration during planning.

• Three over-arching best practices should be guiding principles if uranium mining were to be permitted: the need to plan at the outset of the project for the complete life cycle of mining, processing, and reclamation; the need to engage and retain qualified experts familiar with internationally accepted best practices for all aspects of a project; and the need to encourage meaningful and timely public participation throughout the life cycle of a project, beginning at the earliest stages.

• At a more specific level, there are numerous internationally accepted best practices that would contribute to operational and regulatory planning for uranium mining in Virginia. These cover the health, environmental, and regulatory impacts of uranium mining.


Additional Studies:

TECHNICAL REPORT ON THE COLES HILL URANIUM PROPERTY PITTSYLVANIA COUNTY, VIRGINIA, 2007


Proposed Coles Hill Virginia Uranium Mine and Mill: An Assessment of Possible Socioeconomic Impacts, RTI International, December 2011.

Origin of Uranium Mineralization at Coles Hill Virginia (USA) and its Natural Attenuation within an Oxidizing Rock-Soil-Ground Water System, 2001. 

Monday, December 19, 2011

Fracking Creates Lucractive Market For Gas Liquids

U.S. shale-oil and natural-gas boom opens another lucrative market—gas liquids used to make plastics

The hydraulic fracturing (fracking) method used to unlock vast amounts of crude and natural gas from previously unproductive shale formations across the U.S. is also are reaping large stores of ethane, propane and butane, known as natural-gas liquids. This is resuscitating the U.S. petrochemical industry, which just a few years ago was being strangled by the high costs of the raw materials.

Methane is the main component of natural gas, usually accounting for 70%–90% of the total volume produced. If gas contains more than 95% methane, it is sometimes termed dry or lean gas, and it will produce few, if any, liquids when brought to the surface. Gas containing less than 95% methane and more than 5% of heavier hydrocarbon molecules (ethane, propane, and butane) is sometimes called rich gas or wet gas. This gas usually produces hydrocarbon liquids during production.

Natural gas liquids include propane, butane, pentane, hexane and heptane, but not methane and ethane, since these hydrocarbons need refrigeration to be liquefied. The term is commonly abbreviated as NGL.

Processing ethane into chemicals is 50% cheaper than using crude oil-derived naptha and its availability has made U.S. petrochemical companies the envy of overseas competitors. It also brings the prospect of lower prices for auto parts, Styrofoam and other products.

The boom has turned into a potential profit center for oil-and-gas producers, as well as for the pipeline companies that transport the fuel. Demand for ethane grew to about 933,000 barrels a day during the first half of 2011, up from 812,000 barrels a day in 2009, according to Bentek Energy. But like the other fuels extracted from remote shale deposits, the biggest problem is how to get it to facilities that can process it.

A dearth of pipelines created a bottleneck that drove the price that petrochemical companies pay for ethane to 95 cents per gallon in the third quarter, from 60 cents at the start of the year, according to Dow Chemical Company.  But even with that price spike, chemical companies prefer ethane over other chemicals.  Ethane is still by far the preferred feed here in the United States and is much more cost-competitive than all of its equivalents.

To free up the flow of natural-gas liquids, about 12,000 miles of pipeline needs to be built by 2035, costing $14.5 billion, according to data from the Interstate Natural Gas Association of America, a trade association. Until those pipelines are built, higher production will make the market volatile as short-term fixes such as rail transport are used.

Some pipeline operators are working to expand their reach into oil- and gas-producing shale formations. Enterprise Products Partners LP is spending $7 billion on projects. That includes a 280,000 barrel-a-day pipeline joint venture with Anadarko Petroleum Corp. and Enbridge Energy Partners LP and a wholly owned 125,000-barrel-a-day pipeline, both of which will transport natural-gas liquids from the shale formations in the Northeast and mid-continent areas to the U.S. Gulf Coast, where the bulk of the petrochemical companies are located. DCP Midstream Partners LLC is also expanding its natural-gas liquids business, building two pipelines with a combined capacity of 350,000 barrels a day from the mid-continent and Texas to the Gulf Coast. (WSJ, 12/19/2011, NatgasInfo, Schlumberger)

Asplundh Tree Expert Company

Since 1928 the Asplundh Tree Expert Company has been dedicated to safe, efficient and innovative line clearance services to the utility industry. Reliable, uninterrupted power is an important service provided by the world's electrical utilities and Asplundh has the expertise to help keep the power flowing. Diversification over the years has opened up vegetation management services to other specialized markets such as railroads, pipelines, municipalities and departments of transportation.

Their Mission Statement

At Asplundh, their mission is to be the recognized world leader in providing professional, safe, cost-effective and environmentally sustainable vegetation management and other utility-related services.

Who They Are and What They Do

A family-owned and operated corporation headquartered near Philadelphia, Pennsylvania, Asplundh has grown to employ over 26,000 service professionals throughout the U.S., Canada, New Zealand and Australia.

As a full-service utility contractor Asplundh performs tree pruning and removals, right-of-way clearing and maintenance, vegetation management with herbicides and emergency storm work and logistical support. Asplundh is the parent company of UtiliCon Solutions, Ltd. whose subsidiaries provide overhead and underground line construction, meter reading and installation, infrared inspection, utility pole maintenance, and street lighting/traffic signal services. (Asplundh)

[Note:  PEPCO has contracted with Asplundh for tree trimming services in the Washington, DC region.]

EPA Releases Draft Findings on Pavillion, Wyoming Fracking

Ground Water Investigation for Public Comment and Independent Scientific Review

Rebuttal

The U.S. Environmental Protection Agency (EPA) today (Dec 8) released a draft analysis of data from its Pavillion, Wyoming ground water investigation. At the request of Pavillion residents, EPA began investigating water quality concerns in private drinking water wells three years ago. Since that time, in conjunction with the state of Wyoming, the local community, and the owner of the gas field, Encana, EPA has been working to assess ground water quality and identify potential sources of contamination.

EPA constructed two deep monitoring wells to sample water in the aquifer. The draft report indicates that ground water in the aquifer contains compounds likely associated with gas production practices, including hydraulic fracturing. EPA also re-tested private and public drinking water wells in the community. The samples were consistent with chemicals identified in earlier EPA results released in 2010 and are generally below established health and safety standards. To ensure a transparent and rigorous analysis, EPA is releasing these findings for public comment and will submit them to an independent scientific review panel. The draft findings announced today are specific to Pavillion, where the fracturing is taking place in and below the drinking water aquifer and in close proximity to drinking water wells – production conditions different from those in many other areas of the country.

Natural gas plays a key role in our nation’s clean energy future and the Obama Administration is committed to ensuring that the development of this vital resource occurs safely and responsibly. At the direction of Congress, and separate from this ground water investigation, EPA has begun a national study on the potential impacts of hydraulic fracturing on drinking water resources.

Findings in the Two Deep Water Monitoring Wells:

EPA’s analysis of samples taken from the Agency’s deep monitoring wells in the aquifer indicates detection of synthetic chemicals, like glycols and alcohols consistent with gas production and hydraulic fracturing fluids, benzene concentrations well above Safe Drinking Water Act standards and high methane levels. Given the area’s complex geology and the proximity of drinking water wells to ground water contamination, EPA is concerned about the movement of contaminants within the aquifer and the safety of drinking water wells over time.

Findings in the Private and Public Drinking Water Wells:

EPA also updated its sampling of Pavillion area drinking water wells. Chemicals detected in the most recent samples are consistent with those identified in earlier EPA samples and include methane, other petroleum hydrocarbons and other chemical compounds. The presence of these compounds is consistent with migration from areas of gas production. Detections in drinking water wells are generally below established health and safety standards. In the fall of 2010, the U.S. Department of Health and Human Services’ Agency for Toxic Substances and Disease Registry reviewed EPA’s data and recommended that affected well owners take several precautionary steps, including using alternate sources of water for drinking and cooking, and ventilation when showering. Those recommendations remain in place and Encana has been funding the provision of alternate water supplies.

Before issuing the draft report, EPA shared preliminary data with, and obtained feedback from, Wyoming state officials, Encana, Tribes and Pavillion residents. The draft report is available for a 45 day public comment period and a 30 day peer-review process led by a panel of independent scientists. (EPA)

For more information on EPA's Pavillion groundwater investigation

Saturday, December 17, 2011

Virginia Uraniuim Wants To Mine Uranium In Virginia

Virginia Uranium wants to mine uranium in Southside, Virginia.  A state-ordered study , conducted by RTI International for the Danville Regional Foundation, released last week predicted the creation of jobs (up to 1,000) and an economic boost to the beleaguered Southside economy ($70 million to $220 million). But, it also says, that “even if the mine and mill meet or exceed regulatory standards, detectable concentrations of uranium and other constituents would be released from the facility into the surrounding environment.” Another study by the National Academy of Sciences is expected to be released next week. Environmentalist oppose the project.

Virginia Uranium hopes to persuade the General Assembly to repeal the nearly three-decade moratorium on uranium mining at its session in January.

Two uranium deposits were found three decades ago in Coles Hill, near Chatham, a small town in Pittsylvania. They begin at the ground’s surface, under land used to raise cattle, hay and timber, and run about 1,500 feet deep. Virginia Uranium tests indicate 119 million pounds of uranium - worth as much as $10 billion - are below the surface. That would be enough to supply all the country’s nuclear power plants for about two years or all of Virginia’s demands for 75 years. (Wash Post, 12/16/2011)

EPA Finalizes Mercury & Air Toxics Standards (MATS)

Final MATS to be issued by December 16, 2011

Utility Maximum Achievable Control Technology (MACT) Rule

EPA proposed the Mercury and Air Toxics Standards on March 16, 2011. The EPA issued the final standards on December 16, 2011. Since proposing this rule, EPA updated some of the mercury emissions data used to develop the proposed standards. The rules will prevent 91 percent of the mercury in coal from entering the air and much of the soot as well: According to EPA estimates, they will prevent 11,000 heart attacks and 120,000 asthma attacks annually by 2016.

The new rules will cost utilities $10.6 billion by 2016 for the installation of control equipment known as scrubbers, according to EPA estimates. But the EPA said those costs would be far offset by health benefits. The agency estimates that as of 2016, lowering emissions would save $59 billion to $140 billion in annual health costs, preventing 17,000 premature deaths a year along with illnesses and lost workdays. (EPA, Wash Post, 12/16/2011)

Background:

What is the Utility MACT (National Emissions Standards for Hazardous Air Pollutants [NESHAP] for Coal- and Oil- Fueled Electricity Generating Units)?

The Clean Air Act requires the Environmental Protection Agency (EPA) to regulate hazardous air pollutants, through the National Emissions Standards for Hazardous Air Pollutants program established in Sec. 112 of the Act. EPA must identify sources of the 188 hazardous air pollutants (HAPs) listed in section 112(b), including acid gases, asbestos, dioxin, benzene, chlorine, lead compounds, mercury, phosphorus, various metals and others. Major sources of these pollutants are those that emit 10 tons per year of a single HAP or 25 tons per year or more combined of several HAPs.

EPA promulgates technology-based standards for reducing HAP emissions using maximum achievable control technology (MACT) for both new and existing sources. Determination of the MACT considers a number of factors, including cost, energy requirements, and non-air quality health and environmental impacts.

As with some other Act programs, the Federal government establishes and state air quality programs implement NESHAP programs.

Who are the covered entities?

Starting with the mandate of the Clean Air Act Amendments of 1990 and then revised every eight years, EPA determines a list of categories and subcategories of sources of HAPs. After Congressionally-mandated EPA studies indicated that other rules were not substantially reducing HAP emissions from coal- and oil-fueled power plants, these plants were determined to be source categories of HAPs in 2000. Mercury is the most significant HAP emitted from coal- and oil-fueled power plants. These power plants are also significant emitters of other carcinogenic HAP metals, such as arsenic, nickel, cadmium, and chromium; HAP metals with potentially serious non-cancer health effect such as lead and selenium; and other toxic air pollutants such as the acid gases hydrogen chloride and hydrogen fluoride. There are 1,325 units at 525 power plants around the United States that will need to comply with the recently announced rule. Some of those power plants are more than fifty years old, and complying with the new regulations will be significantly more challenging and expensive than for newer facilities. Some of these older plants may be retired rather than incur the costs of installing new pollution control equipment.

What is the status of regulation?

After coal- and oil-fueled power plants were determined to be a source category in 2000 and therefore subject to regulation, EPA undertook to regulate mercury from these sources. This Bush Administration rule was known as the Clean Air Mercury Rule (CAMR) and would have instituted a cap-and-trade program for mercury emissions. A court ruled that EPA must regulate HAPs under section 112 and not under another section as proposed in CAMR. It vacated the 2005 rulemaking. EPA’s new utility MACT rule was proposed in March 2011, and scheduled to be finalized in November 2011. EPA delayed the final rule for a month, until December 16, 2011.

In September 2011, the House of Representatives passed H.R. 2401, the Transparency in Regulatory Analysis of Impacts on the Nation (TRAIN) Act, that would, among other regulations, delay implementation of the Utility MACT rule pending completion of additional economic studies (other than those EPA and the Office of Management and Budget have already conducted). This bill is unlikely to advance in the Senate. (Center for Climate and Energy Solutions)

Keystone XL Pipeline Legislation Will Not Speed Construction

Legislation Could Inadvertently Force President Obama to Kill The Project

Senate leaders announced Friday evening a deal to extend the payroll tax holiday and unemployment benefits for two months.  The deal includes House-passed language to expedite construction of the Keystone XL oil sands pipeline. But Democratic aides said this concession would have the effect of killing the project because the Obama administration has said it would not grant approval on a truncated timeline. Boehner and Senate Republican Leader Mitch McConnell (Ky.) said they would not accept even a temporary extension of the payroll tax holiday without the Keystone language.

The Obama administration delaying a decision on the pipeline project until 2013.  The pipeline would deliver oil sands crude from Canada to Texas, but Republicans have sought to force the president to make a decision sooner.

President Obama will not accept an attempt by Congress to mandate construction of the pipeline before there is an adequate review of health, safety and environmental regulations. The State Department has already said that if the review was shortened to 60 days as it is in this bill, it won't be able to conduct the necessary review. So the pipeline will almost certainly not be approved, the official said, proving the entire process moot. They killed the Keystone XL pipeline because they forced the president to make a decision before he can make it so he’s not going to move forward with it.

The House-passed Keystone language merely speeds up the decision process but does not determine whether the project would be approved. Officials at the State Department, which has authority over approving the project, said they would not be able to conduct the necessary review if given only 60 days, the timeline set by House Republicans. (The Hill, 12/16/2011, The Hill, 12/16/2011)

Friday, December 16, 2011

TEPCO: Owner of the Fukushima Daiichi Nuclear Power Facility

The Tokyo Electric Power Company (TEPCO) is the Japanese conglomerate at the center of the nuclear radiation emergency at Fukushima, Japan. TEPCO is the fourth largest power company in the world, and the biggest in Asia, operating 17 nuclear reactors and supplying one-third of Japan’s electricity.  TEPCO was established in May 1, 1951.

TEPCO's first nuclear power facility, the Fukushima Daiichi Nuclear Power Station's No. 1 reactor (460 MW) began operation on March 26, 1971. 

TEPCO's headquarters office is located at 1-1-3 Uchisaiwai-cho, Chiyoda-ku, Tokyo, JAPAN.  Its Washington Office is located at Suite 720,1901 L Street, N.W.,Washington, D.C. 20036, U.S.A. Tel: +1-202-457-0790. TEPCO's London Office is located at Wing 7, Fourth Floor, Berkeley Square House,Berkeley Square London W1J 6BR, U.K. Tel: +44-20-7629-5271

TEPCO holds equity capital of 900.9 billion yen ($11.5 billion)

TEPCO has 38, 671 employees and 28.73 million customers.

TEPCO has electricity sales of 293,386 GWh (FY2010)

(TEPCO)

Maryland Governor Offers Deal on Exelon-Constellation Merger

Martin O'Malley
Maryland Governor Martin O’Malley has offered his blessing to the merger of Exelon and Constellation Energy in exchange for commitments for funding of a new gas power plant, a potential doubling of the state’s output of solar energy and seed money to begin developing offshore wind power.  This sounds a bit too good to be true.  But O’Malley believes his deal to support the takeover of Maryland’s largest utility would net the state $1 billion in investment and potentially 6,000 saved or created jobs.
Chicago-based Exelon, which runs utility Commonwealth Edison, would receive final approval next month from state regulators for its proposed $7.9 billion takeover of Constellation Energy and subsidiary Baltimore Gas & Electric.

Under the deal, Maryland’s PSC will retain authority to spin off BGE, mostly in the event of catastrophes, such as a nuclear accident at Constellation-owned Calvert Cliffs or an Exelon bankruptcy,
but also in the event of repeated violationsof state orders. The deal calls for Exelon to build 120 megawatts of naturalgas generation and 125 megawatts of renewable energy generation.  If the latter is done with landbased windmills, the state’s onshore generation of wind power energy would double.

The arrangement also requires 30 megawatts of new solar generation, which would nearly double Maryland’s output. The solar facility is expected to be built near Baltimore, and the power plant will be required to be built east of Frederick, near the state’s greatest area of energy demand. Half of the power must be online by the end of 2015, and the other half within 10 years.  This is wildly optimistic.

Without the deal, Maryland lacked incentives to make significant progress toward its goal of
producing 20 percent of its energy from renewable sources within 10 years. But even with the help, the state will require a major infusion of renewable power from offshore wind or some other means to meet that mark.

Exelon also has promised to provide $30 million for an offshore wind development fund. (Wash Post, 12/16/2011)

Thursday, December 15, 2011

Shenango Inc Coke Plant Upsetting Community Over Emissions

The Allegheny County Pennsylvania Health Department monitors emissions near the Shenango Inc coke plant and has levied more than 150 citations for violations at the plant this year, including about 40 since August. DTE Energy, the Detroit-based company that owns the plant, is appealing 114 violations and $114,000 in fines it received through July.

Dr. George Sloan
Local groups want to discuss the reasons the violations occurred, whether the problem will be fixed, why the company appealed its fine and what it plans to do to improve the region's air quality. DTE, which bought the Shenango plant in 2008, has regularly participated in meetings of the Neville Island Community Advisory Panel.  The health department is working with company officials on an agreement to create control measures to reduce harmful emissions when production increases.

Emissions are released when hot coke -- a fuel used in steelmaking that is produced by baking coal -- is moved from an oven to a quenching station. Shenango has 56 ovens inside its battery.  Smoke from the plant can contain particulates and pollutants that can cause cancer and respiratory problems, according to the health department.

Dr. George Sloan, Chairman of Center Special Projects, intends to assist the community groups in monitoring and mitigating the emissions from the plant. (Pittsburgh Trib Live, 12/15/2011)

South Allegheny School District Needs School Air Filters

The South Allegheny School District, located downwind from U.S. Steel's Clairton Coke Works, has asked the Allegheny County Board of Health to help fund the installation of air filtration systems at two of the district's schools in Liberty. According to documents submitted with the funding request, the district's schoolchildren have asthma rates 300 percent to 400 percent higher than national rates. The facility is located about 20 miles south of Pittsburgh in Clairton, Pennsylvania.

School officials asked the health board to appropriate money from the county's Clean Air Fund, which has a balance of about $10 million that has been collected from companies as a result of air pollution violations. The air filtration systems for 650 students and 200 faculty at the combination high school/middle school and at an Early Childhood Center attended by 80 students in pre-kindergarten through first grade would cost a total of $9.2 million, school district officials said.

In addition to the increased asthma rates among students, recent tests by the U.S. Environmental Protection Agency showed that elevated concentrations of benzene, a known carcinogen, were present in the schools.

South Allegheny is located in the county's hot spot for air pollution. The Health Department's air pollution monitor for the Liberty-Clairton area is located on the roof of South Allegheny High School and regularly registers the highest airborne particle readings in the county.

A $1 billion reconstruction and equipment upgrade at U.S. Steel's Clairton Coke Works is under way and is expected to result in significant air pollution reductions, but not until 2013 or 2014. The school district can't wait and has contacted area foundations, including the Heinz Foundation, for help in funding the new air filtration systems.

A similar air filtration system was installed at the district's elementary school. It cost about $10 million and was funded through a bond issue.

The Health Department has indicated that while there is enough money in the Clean Air Fund to finance the filtration systems, the money also is needed for other projects and programs. (Pittsburgh Post Gazette, 12/14/2011)

FERC Denies, Delays Duke Energy - Progress Energy Merger

The Federal Energy Regulatory Commission (FERC) again rejected the proposed merger between Duke Energy and Progress Energy, assuring the $26 billion deal will not get done this year, and raising questions whether it can get done at all.  FERC said the merger raises serious concerns about giving the companies too much monopoly power in North Carolina. Announced in January, the merger would create the nation's largest electric utility to be based in Charlotte. It would also result in the elimination of 1,860 positions, mostly in North Carolina.

Charlotte-based Duke and Raleigh-based Progress had argued the merger would result in hundreds of millions of dollars in savings for customers, and would hold down rising electricity costs. The deal had won support from the state's consumer advocate, known as the Public Staff, as well as from environmental advocacy groups.

Today's ruling was the second time the FERC said the merger was unacceptable. After the first such ruling in September, Duke and Progress said they'd cap their profit at 10 percent of some wholesale power sales, but the FERC said that wasn't good enough.

The agency said the companies' proposals to address monopoly concerns are vague, lack support, are riddled with flaws, and would not work. The feds said Duke and Progress still have the option of coming up with more alternatives to fix the problem.

The merger also requires approval by the N.C. Utilities Commission, but the commission had been waiting for the federal ruling before signing off on the deal. (News Observer, 12/14/2011)

Wednesday, December 14, 2011

Kenneth W. Cornew New President of Constellation Biz Unit

Kenneth W. Cornew, president of the Exelon Power Team of Kennett Square, Pa., will be president of the Constellation business unit of Exelon Corp. after the $7.9 billion acquisition of Constellation Energy Group by Exelon is approved by federal and state regulators, Chicago-based Exelon said Wednesday.

Other appointments announced are Mark Huston, currently head of retail energy at Baltimore-based Constellation, to senior vice president, retail of the combined company; Joseph Nigro, currently senior vice president of portfolio management and strategy at Exelon, tosenior vice president, portfolio strategy; and Max Duckworth and Edward Quinn, currently co-heads of commodities at Constellation, to senior vice president, proprietary trading and fuels; and senior vice president, wholesale trading and origination, respectively.

All four will report to Cornew. (The Daily Record)

Tuesday, December 13, 2011

American Electricity Map - Electricity Tends To Flow South


The map above shows that electricity tends to flow south in North America. The numbers on the map reflect average net power flows—metered hourly—between electric systems aggregated by regions for the year 2010. Most electric power demand is served by local generators. Net interregional trade accounted for less than 1% of delivered power in 2010. However, excess, low-cost power—primarily from hydroelectric generators in the Pacific Northwest, Manitoba, and Quebec—supplied higher-cost markets to the south.  The numbers next to the arrows represent annual net flows of electricity between regions measured in millions of megawatt-hours.

Electricity tends to flow south in North America. Electricity flows south from the Northwest to California and the Southwest. It flows south from Manitoba to the Midwest and from there to the Central region (the Southwest Power Pool) and the Tennessee Valley Authority (TVA). Electricity also flows south from TVA to the Southern region (Southern Company) and from the Southern region into Florida. It flows south from eastern Canada into New England, New York, and the Midwest.

There is also a circular flow pattern from the Midwest region through the Central, Gulf, TVA, Southern and Carolinas regions into the Mid-Atlantic region (PJM Interconnection) and on to New York (New York ISO). Surprisingly, the data show that, on net, power flows from the Mid-Atlantic region to the Midwest. The flow of low-cost, coal-fired power from the Midwest to the east during on-peak hours may be offset by the flow of nuclear generation from Exelon's Commonwealth Edison service area in and around Chicago (part of the Mid-Atlantic region) to the surrounding Midwest region during off-peak hours.

California is the largest net importer of electricity, consuming power produced in the Northwest and Southwest. These two regions provide about 25% of California's electricity supply.

While the map shows annual data, some flows are distinctly seasonal. For instance, the hydro capacity in the Pacific Northwest generates large amounts of electricity in excess of the region's need (and, therefore, large transfers to other regions) when river flows are typically highest in spring and early summer. (DOE-EIA)

Canada Pulls Out of Kyoto Protocol

Canada pulled out of the Kyoto Protocol on climate change Monday, saying the accord will not help solve the crisis of globalwarming. Canada invoked its legal right to withdraw and noted that Kyoto does not represent the way forward for Canada or the world. Canada, joined by Japan and Russia, said last year that it will not accept new Kyoto commitments.

The United States never ratified the treaty, initially adopted in Kyoto, Japan, in 1997.

Canada’s previous Liberal government signed the accord but did little to implement it. Prime Minister
Stephen Harper’s Conservative government never embraced it.  George W. Bush rejected Kyoto during his presidency and president's Clinton and Obama never sent the treat to the U.S. Senate for a ratification vote.

The Kyoto Protocol does not cover the world’s largest two emitters, United States and China, and
therefore cannot work. (AP, Wash Post, 12/13/2011)

EPA Regulations in 2012


The Environmental Protection Agency will be busy proposing, finalizing, implementing and defending one rule after another in 2012.  Of course, Election Day makes a big difference in the implementation of rules.

• In the remaining weeks of 2011, the agency will finalize rules regulating emissions for boilers and solid waste incinerators and to curb mercury and toxic emissions from power plants. The EPA also will move forward with automakers and the Department of Transportation to set new miles-per-gallon standards for automobiles and lower the amount of sulfur in gasoline.

• On Jan. 1, the agency’s rule governing air pollution that blows across state lines will take effect, amid a flurry of paperwork in a massive lawsuit driven by 45 petitioners. The lawsuit was brought by states beholden to more stringent requirements and utilities that will have to implement them. The EPA is joined in the case by downwind cities and states that will benefit from the new air pollution limits, along with environmentalists and some other utilities.

• April 3, the EPA will finalize air standards for wells that use hydraulic fracturing to access natural gas and for oil and natural gas processing plants.

• The EPA will set greenhouse gas emission standards for fossil-fueled power plants and petroleum refineries.

• Under review at the White House Office of Management and Budget are rules to reconsider air emission standards at chemical manufacturing plants, and a review of risk and technology for emission standards for shipbuilding and ship repair.

• The EPA plans to decide during the summer how to regulate coal ash — the byproduct that is often reused in housing products but has been the subject of national attention after some dangerous spills from huge retention ponds.

• In July, the agency also will finalize a rule for water discharge permits for cooling towers that keep power plants and manufacturing facilities from overheating. Such towers pull water from rivers and streams, posing dangers to fish and fish eggs that become caught in intake screens. The issue prompted a Supreme Court ruling that says the EPA may consider costs and benefits in its regulations because the Clean Water Act does not explicitly forbid it. (More)

• The EPA has agreed to judicially mandated deadlines for acting on plans to cut haze-causing pollution from coal-fired power plants in 45 states. The deadlines run from this December to November 2012.

• Meanwhile, several rules are caught up in an ongoing lawsuit over EPA’s climate “endangerment finding” in which the agency determined that carbon dioxide emissions threaten public health and the environment. The finding became an underpinning of EPA climate regulations. The U.S. Court of Appeals for the District of Columbia Circuit will hear oral arguments for that case Feb. 28-29, and many expect that the case will be decided in the summer.

(Politico, 11/13/2011)

EPA's Cooling Tower Rule: Clean Water Act Section 316(b)


On March 28, 2011, the U.S. Environmental Protection Agency (EPA) signed the proposal for the last of its Clean Water Act Section 316(b) rules for cooling water intake structures – this one for " existing" facilities and new units at existing facilities.  Comments on the proposed rule were due in July 2011 – 90 days after publication in the Federal Register. EPA is required to finalize the rule by July 27, 2012.

Section 316(b) of the Clean Water Act requires that National Pollutant Discharge Elimination System (NPDES) permits for facilities with cooling water intake structures ensure that the location, design, construction, and capacity of the structures reflect the best technology available (BTA) to minimize harmful impacts on the environment.

According to EPA, the rule covers roughly 1,260 existing facilities that each withdraw at least 2 million gallons per day of cooling water. EPA estimates that approximately 590 of these facilities are manufacturers, and the other 670 are power plants, including electric cooperatives.

The proposed rule does not require existing power plants with once-through cooling to retrofit cooling towers where they do not make economic sense when other less-expensive alternatives exist. EPA is not presuming that cooling towers are BTA; however, the proposed rule appears to allow for site-specific analysis and for permitting agencies to consider costs when making BTA determinations. (National Rural Electric Cooperative Association, 4/1/2011)

More information on EPA’s proposed Clean Water Act Section 316(b) rule

Monday, December 12, 2011

Electricity Storage

Edwin F. Feo spoke about energy storage with Jeff Postelwait {Postelwait responses are below}

Storage can assist with renewables by smoothing the effect of variable energy output—typical for wind and solar—providing capacity firming such that a renewable resource can be seen as an almost constant source of energy, and with frequency regulation support for the transmission grid. Without storage, the grid needs to be able to deal with the effects of intermittent energy, and that can be done with other generation sources providing firming services. The issue historically with storage has been the cost.

Traditional generation can benefit from storage to the extent that storage technologies can provide cheaper and or faster-reacting support services. Flywheels and lithium-ion batteries, for example, can respond quickly and are typically used for frequency regulation.

The main technologies are: pumped-hydro storage; compressed-air storage below or above ground; batteries—sodium sulfur, vanadium redox, lead acid, nickel cadmium and lithium ion; molten salt; thermal peak shaving, aka ice storage; and flywheels. Of global installed storage capacity of about 125,000 MW, over 123,000 is pumped hydro. Other technologies lag by comparison: molten salt, 142 MW; compressed air, 440 MW; batteries, 451 MW; and flywheels, 95 MW. The different technologies have different applications. Pumped hydro has been used for centralized, utility-scale projects—being able to handle load with quick response.

Compressed-air projects are also being aimed at large utility applications, but there are also small above-ground, compressed-air assets, which can be teamed with a specific generation asset. Certain batteries—sodium sulfur, vanadium—have long duration and are better oriented to back up applications. Other batteries—e.g., lithium-ion—have faster response and are best used for renewable integration and frequency regulation, typically at the generation project level. Flywheels are used for frequency regulation and are being developed as stand-alone projects.

The more that the electric service model migrates from the central station generation-dumb meter consumer model—where it is today—to more of a distributed generation-smart meter consumer model, the greater the role for storage to play in smoothing of energy delivery, integration and regulation.

Pumped Hydro
The primary issue is cost. Pumped-hydro projects have tended to be large—1,000 MW—and significant civil works projects. The newer technologies are more geared to smaller applications, so the capital cost per unit is less, but the issue is the cost on a kilowatt-hour basis. These costs are headed down as technology improves. A somewhat related issue is reliability. Given the relatively modest and recent deployment of some of the storage technologies, there is an issue as to evidence of long-term reliability. The more that units are deployed, of course, the more there should be evidence of reliability, and the lower the cost, as well.

First Wind is using Xtreme Power batteries in wind farms in Hawaii. Energy storage makes a lot of sense in an island application where the load may not be large and the day and night demand may differ widely. In the case of the wind projects in Hawaii, First Wind would be facing the potential of curtailment at night when the wind still blows, given the reduced demand for energy. So a battery can be charged with off-hours electricity and discharged during peak demand during the day.

AES Energy Storage is developing storage systems using A123 Systems’ lithium-ion batteries to provide ancillary services. Primus Power is proposing to build a 25-MW battery storage project for the Modesto Irrigation District (MID). This is known as the Wind Firming EnergyFarm and is intended to replace a fossil fuel plant as the means of firming energy provided to the MID from wind power sources. Southern California Edison is building an 8-MW lithium-ion battery storage project to improve grid performance and to aid in integration of wind energy resources located in the Tehachapi area. Another example is a 20-MW flywheel project built by Beacon Power in Massachusetts. That project is a stand-alone project that will deliver frequency regulation services to the grid.

The Department of Energy launched a program to support energy storage technology in 2009. DOE is providing about $185 million to support over $775 million of energy storage projects; these aggregate about 537 MW of new storage.

Storage presents an interesting regulatory challenge. Depending on its use and the point of view of a regulatory agency, it may be considered transmission or generation, and as either a wholesale or a retail service. Those characterizations affect by which agency it is regulated—federal or state—and how an investment in storage can be recovered. Choice of a regulatory regime affects planning. Who approves? Ownership: Who can own, and by whom are they regulated, among other issues.

Pumped Hydro
Certain storage projects can be delivering both transmission and generation support services and therefore technically regulated by both regulatory regimes. The regulatory complexities of storage are addressed but not completely resolved by FERC in a Request for Comments Regarding Rates, Accounting and Financial Reporting for New Electric Storage Technologies (Docket No AD 11-7-000) and a Notice of Proposed Rulemaking—Frequency Regulation Compensation in the Organized Wholesale Power Markets (Docket No. RM 11-7-000).

As a broad concept, electric vehicles can be used as energy sinks in the sense that they can charge at night while other electric demand is low. Of course, that doesn’t mean the vehicles are available as storage to be applied during the peak of the next day. I think electric vehicles ultimately will be another variable in the electric supply-demand mix that can’t be controlled other than in the broadest terms and so may present as many problems as they do solutions for grid operations.

A number of utilities are pursuing demonstration projects. The most interest seems to be in areas where there is significant penetration by renewables. Ultimately, the deployment of more storage technologies at the distribution level means that demand management can be more flexible because storage can be used to meet peak demands as opposed to relying on reduction of demand to trim peaks.

The principal benefits will be reliability of the grid, backup power when applied locally and lower costs because high on-peak prices can be mitigated with stored energy.  (Electric Light & Power, Oct 2011)