NRC Denies License for Proposed Calvert Cliffs Nuclear Plant

Calvert Cliffs Nuclear Plant

Federal regulators denied a license Thursday to the French-controlled company for a proposed third nuclear reactor at the Calvert Cliffs nuclear power plant in Southern Maryland, giving the company 60 days to find a U.S. partner.  At the end of those 60 days, the three judges of the Atomic Safety and Licensing Board will be forced to terminate the company's application proceedings entirely.

The decision follows warnings from the Nuclear Regulatory Commission in April 2011 that UniStar Nuclear Energy, which is owned by Electricite de France, is not eligible to control the proposed $9.6 billion Calvert Cliffs 3 project under its current ownership structure. Federal law prohibits a foreign entity from completely owning or controlling a U.S. nuclear plant.

Regulators said in April 2011 that they would continue to process EDF's existing application for licensing while the company sought a partner.

The board said Thursday that while "60 days may seem a short period of time in which to obtain a domestic partner," UniStar has already had two years to do so. Until November 2010, UniStar had been owned in "near-equal shares" by Constellation Energy Group and EDF, the judges wrote.

But after Constellation pulled out of negotiations with the Department of Energy over a federal loan guarantee considered critical to the project, EDF acquired Constellation's 50 percent interest in UniStar and decided to push forward with the project on its own. (The Baltimore Sun, 8/30/2012)

New Stormwater Management Rule in Washington, DC

"Making Stormwater Retrofits Pay"

Creating a market for stormwater retrofits to harness self-interest, leverage river protections, and promote sustainable development in the District of Columbia

By Brian Van Wye

In a highly urban area such as Washington, D.C., vast impervious surfaces shed massive volumes of stormwater every time it rains. Stormwater retrofits that retain stormwater onsite have the potential to make D.C. “spongier,” that is, more closely mimicking a natural area where rainfall is captured by vegetation and soaks into the ground. However, getting retrofits installed to serve the 43% of D.C.’s land area that is impervious is a difficult challenge. The majority of this impervious surface achieves little or no retention, is not required to retrofit, and does not have financing available to support a retrofit.

Center Stormwater Credit Exchange

Against this backdrop, the D.C. Department of the Environment (DDOE) drafted revised stormwater management regulations with a new requirement for regulated development projects. DDOE also saw the potential for a win–win between regulated projects and the vast areas of D.C. that need stormwater retrofits and soon embraced two key ideas: allowing regulated projects to achieve a portion of their obligation offsite makes fiscal and environmental sense and a private market that pays dividends to property owners for retrofits may optimize these benefits and yield additional ones. Read full article

Continuous Emissions Monitoring System (CEMS)

Electric utility companies must meet stringent regulatory standards for environmental quality with a continuous emissions monitoring system (CEMS) that provides reliable and accurate data.

Example:

Figure 1: Oswald Generating Station

The Oswald Generating Station is a 510-megawatt (MW), combined-cycle, natural gas combustion turbine plant located in Pulaski County, 0.5 miles south of Wrightsville, Arkansas. The plant (Figure 1) consists of six GE LM6000 aeroderivative combustion turbines, one GE Electric Frame 7EA combustion turbine, seven duct burners and two steam turbines. The plant configuration is commonly known as a 'Seven on Two.' "
This means the seven combustion turbines (CTs), or fewer, provide steam to one or both steam turbines, depending on the current power demand. The plant is not configured for the CTs to operate in simple cycle mode.

The plant is designed to supply approximately 75 MW to 510 MW of power during high electrical demand hours of each day, usually between the hours of 7:00 a.m. and 11:00 p.m., and ramp down to approximately 75 MW during off-peak hours. This daily load cycling results in reduced power production each day during hours when there is less demand for the power.

The six LM combustion turbines are equipped with steam injection for emission control of oxides of nitrogen (NOx). The Title V Air Permit limits the six LMs to a three- hour rolling average of 25 ppm and a yearly average of 22 ppm NOx corrected to 15% oxygen (O₂). The 7EA combustion turbine utilizes dry low NOX (DLN) burners for NOx control. The 7EA is limited to a three-hour rolling average of 9 ppm NOx corrected to 15% O₂.

The facility currently operates and maintains seven Continuous Emissions Monitoring System (CEMS) that are subject to the Acid Rain Program under 40 CFR Part 75 and the Clean Air Interstate Rule (CAIR) for the NOx ozone season trading program. Each system is comprised of an O2 monitor and a NOx monitor. The emissions are monitored every minute, and the data is passed to the existing, common data acquisition handling system (DAHS), which calculates the hourly emissions for each CT. Each calendar quarter the NOx (lbs/mmBtu) and other plant data are electronically reported to the U.S. Environmental Protection Agency (EPA). The CEMS undergo a calibration check each operating day, linearity checks each quality-assured (QA) quarter and an annual relative accuracy test audit (RATA).

Big Coal Faces Steel Slowdown Amid Shale-Gas Pain

Four of the largest U.S. coal producers [Alpha Natural Resources Inc., Peabody Energy Corp., Arch Coal Inc. and Walter Energy Inc.] made $20 billion of acquisitions last year to reduce their dependence on the domestic power industry. They have completed takeovers that boosted sales of metallurgical coal used in steelmaking. The companies bet that the coal, which sells for a higher price than the thermal variety burned to generate electricity, would benefit from booming Asian demand and counter threats from falling natural-gas prices and extra environmental regulation.

That strategy isn’t working out as planned. Prices for metallurgical coal have fallen so far this year amid slowing steel output in China and Europe. U.S. coal producers have been closing mines and firing workers this year as some power plants switch from coal to gas.

    

Thermal Coal

Prices for Central Appalachian thermal coal, the U.S. benchmark, have declined to $58.12 a ton on the New York Mercantile Exchange. Metallurgical-coal prices are down to $192.50 a ton, according to data published weekly by Energy Publishing Inc. China, the second-largest economy and biggest steelmaker, expanded 7.6 percent in the second quarter, the slowest pace in three years.

 

Also adding to the gloom is the recession in Europe, the destination for about half of U.S. metallurgical-coal exports. Luxembourg-based ArcelorMittal, the world’s largest steelmaker, was cut to junk by Standard & Poor’s on Aug. 2. According to some experts, metallurgical coal won’t rebound in 2013 and will average $210 next year, while thermal coal will be $70.

    

Alpha paid $7.5 billion including debt for Massey Energy Company in July 2011. Alpha has plunged 70 percent this year, the worst performer on the Standard and Poor’s 500 Index.

 

Not all producers made similar decisions on metallurgical coal. Consol Energy Inc. opted to expand into gas, paying $3.5 billion for assets of Dominion Resources Inc. Canonsburg, Pennsylvania-based Consol overtook Peabody in May as the biggest U.S. coal miner by market value.

 

Most metallurgical coal that’s 'seaborne' -- the industry term for coal exported by oceangoing ship -- is priced each quarter based on a benchmark established by the largest exporters and users.

                          

U.S. coal producers have been affected by unusually warm winter weather, which helped to curb demand for thermal coal. The industry is also facing regulations from the Environmental Protection Agency restricting the burning of coal to produce power, limiting new mining permits and enacting tighter water- quality limits. The increasing regulatory burden combined with competition from cheaper gas has put U.S. coal producers’ “backs to the wall,” and metallurgical-coal hasn’t helped. (Wash Post, 8/29/2012)

Pennsylvania DEP Amending Fracking Rules

The Pennsylvania State Department of Environmental Protection is proposing to make far-reaching amendments to oil and gas regulations governing Marcellus Shale gas developments.  The more than 100 proposed changes in a 23-page draft "concept paper" indicates stronger rules are needed to protect Pennsylvania's surface and groundwater resources.

The document is the first step in a regulatory rewrite, required by the 2012 Act 13 Amendments to the state's 1984 Oil and Gas Act, and was circulated to the DEP's Oil and Gas Technical Advisory Board earlier this month. The five-member board, appointed by the governor, has scheduled public meetings Sept. 17 and Oct. 15 in Harrisburg to review as-yet-to-be-completed regulatory language based on the proposals.

Among the more notable proposals in the concept paper are:

1) the elimination of the drilling industry's use of in-ground pits for storage of "produced fluids," which are briny liquids that flow back to the surface after a well has been hydraulically fractured,

2) a requirement to locate and map abandoned gas and oil wells near new well sites that could allow methane to migrate into shallow aquifers.

3) require drillers to build secondary containment structures around all new permanent storage tanks (to American Petroleum Institute standards) to protect nearby waterways and regulate on-site wastewater treatment processes and pipelines for the first time.

According to the DEP's concept paper, there are tens of thousands of tanks containing produced fluids that have no adequate secondary containment, which has resulted in numerous spills and releases of produced fluids into the environment over many decades.

While a proposal would eliminate use of storage pits for produced fluids, it doesn't say whether produced fluids are just salty brine flushed from the deep shale formation or also the so-called "flowback fluid" containing fracking chemicals. Critics not that if produced fluids are only brines and they pose an unacceptable risk, wouldn't it stand to reason that flowback fluid does as well?

The DEP in a statement said the proposals are just memorializing existing regulations or industry practices. The DEP's plans call for finalizing the proposed language of the regulatory changes at the technical advisory board meeting Nov. 15 and submitting the final regulatory language for consideration by the state Environmental Quality Board on Dec. 12. (Pittsburg Post-Gazette, 8/28/2012)

Projected Natural Gas Prices Depend On Shale Gas Economics

Considerable uncertainty exists regarding the size of the economically recoverable U.S. shale gas resource base and the cost of producing those resources. Across four shale gas resource scenarios from the Annual Energy Outlook 2012 (AEO2012), natural gas prices vary by about $4 per million British thermal units (MMBtu) in 2035, demonstrating the significant impact that shale gas resource uncertainty has in determining future natural gas prices. This uncertainty exists primarily because shale gas wells exhibit a wide variation in their initial production rate, rate of decline, and estimated ultimate recovery per well (or EUR, which is the expected cumulative production over the life of a well).

If a resource assessment of a shale formation relies on "sweet spot" production rates, where wells produce at rates higher than expected elsewhere in the formation, then the productive and economic potential of the entire formation could be exaggerated. On the other hand, future technological improvements that reduce production costs and/or enhance well productivity, along with closer well spacing, would increase the economic potential and resource recovery of the U.S. shale gas formations.

AEO2012 includes an analysis of varying future shale gas well production estimates and the associated EUR, along with a change in shale gas well spacing, to test the influence of shale gas resource uncertainty on future natural gas prices. In addition to the reference case, the three AEO2012 shale gas resource scenarios are:

• Low well productivity case (green line in chart). The EUR per shale gas well is assumed to be 50% lower than in the Reference case, nearly doubling the per-unit cost of developing the resource. Unproved shale gas resources are reduced to 241 trillion cubic feet (as of January 1, 2010), as compared with 482 trillion cubic feet of unproved shale gas resources in the Reference case.


• High well productivity case (light blue line). The EUR per shale gas well is assumed to be 50% higher than in the Reference case, nearly halving the per-unit cost of developing the resource. Unproved shale gas resources are increased to 723 trillion cubic feet.


• High resources case (orange line). The well spacing for all shale gas plays is assumed to be 8 wells per square mile, which increases the well density in about half the shale gas plays, and the EUR per shale gas well is also assumed to be 50% higher than in the Reference case. Unproved shale gas resources are increased to 1,091 trillion cubic feet, more than twice the unproved shale gas resources in the Reference case.

U.S. natural gas prices are determined by supply and demand conditions in the North American natural gas market, in which the United States constitutes the largest regional submarket. Future natural gas prices reflect the cost of developing incremental production capacity. Because shale gas production is projected to be a large proportion of U.S. and North American gas production, changes in the cost and productivity of U.S. shale gas wells have a significant effect on projected natural gas prices. In the Reference case, for example, shale gas production accounts for 49% of total U.S. natural gas production in 2035.

In 2031, natural gas prices dip in the low EUR case as model results reflect completion of an Alaska gas pipeline, which would transport about 1.6 trillion cubic feet per year of gas from the North Slope to the lower 48 states. Because an Alaska gas pipeline would make up for some of the reduction in lower 48 states' shale gas production, the difference between projected prices in the Reference and Low EUR case is reduced after the pipeline is completed. (EIA)

Obama Administration Finalizes 54.5 MPG Fuel Efficiency Standard

The Obama Administration today finalized groundbreaking standards that will increase fuel economy to the equivalent of 54.5 mpg for cars and light-duty trucks by Model Year 2025. This will nearly double the fuel efficiency of those vehicles compared to new vehicles currently on our roads.

The historic standards issued today by the U.S. Department of Transportation (DOT) and the U.S. Environmental Protection Agency (EPA) build on the success of the Administration’s standards for cars and light trucks for Model Years 2011-2016. Those standards, which raised average fuel efficiency by 2016 to the equivalent of 35.5 mpg, are already saving families money at the pump.
 
The final standards were developed by DOT’s National Highway Traffic Safety Administration (NHTSA) and EPA following extensive engagement with automakers, the United Auto Workers, consumer groups, environmental and energy experts, states, and the public. Last year, 13 major automakers, which together account for more than 90 percent of all vehicles sold in the United States, announced their support for the new standards. By aligning Federal and state requirements and providing manufacturers with long-term regulatory certainty and compliance flexibility, the standards encourage investments in clean, innovative technologies that will benefit families, promote U.S. leadership in the automotive sector, and curb pollution.
 
The Administration’s combined efforts represent the first meaningful update to fuel efficiency standards in decades. Together, they will save American families more than $1.7 trillion dollars in fuel costs, resulting in an average fuel savings of more than $8,000 by 2025 over the lifetime of the vehicle. For families purchasing a model Year 2025 vehicle, the net savings will be comparable to lowering the price of gasoline by approximately $1 per gallon. Additionally, these programs will dramatically reduce our reliance on foreign oil, saving a total of 12 billion barrels of oil and reducing oil consumption by more than 2 million barrels a day by 2025 – as much as half of the oil we import from OPEC each day.

Ray LaHood, Lisa Jackson

The standards also represent historic progress to reduce carbon pollution and address climate change. Combined, the Administration’s standards will cut greenhouse gas emissions from cars and light trucks in half by 2025, reducing emissions by 6 billion metric tons over the life of the program – more than the total amount of carbon dioxide emitted by the United States in 2010.

President Obama announced the proposed standard in July 2011, joined by Ford, GM, Chrysler, BMW, Honda, Hyundai, Jaguar/Land Rover, Kia, Mazda, Mitsubishi, Nissan, Toyota, and Volvo, as well as the United Auto Workers. The State of California and other key stakeholders also supported the announcement and were integral in developing this national program. (The White House)

The White House Forum on Urban Innovation

The Center participated in a forum at The White House yesterday that brought people from all over the country to share information about innovations in their respective areas.  The White House Forum on Urban Innovation is a part of a new set of conversations hosted by The White House to spotlight stories of social innovation on the ground.  The White House wanted to learn from pioneers who are driving change in challenging times and to explore new ways federal policymaking can support their endeavors. 

Today, many of our cities are growing at a faster rate than our suburbs, a phenomenon we have not seen since the 1920s.  Within those cities, many neighborhoods have struggled with concentrated poverty and economic immobility for generations.  These innovations exemplify the goals of the Obama administration and the best of Aemrican ingenuity in creating jobs, improving economic resilience, and strengthening urban communities.

Center President Norris McDonald was given the opportunity to describe our Stormwater Credit Exchange and Section 3 Water Efficiency Entrepreneur Progrm.

Opening remarks were provided by Racquel Russell, Deputy Assistant to the President for Urban Affairs and Economic Mobility and Jonathan Greenblatt, Director, White House Office of Social Innovation and Civil Participation.

Administration perspectives were given by Valerie Jarrrett, Senior Advisor and Assistant to the President and Cecilia Munoz, Director, White House Domestic Policy Council.

Spotlight on Innovators: Session 1 included Angela Blanchard, Neighborhood Centers, Inc., Mayor Pedro Segarra, City of Hartford, Carol Thompson Cole, Venture Philanthropy Partners, and Jennifer Crozier, IBM Corporate Citizenship.

Spotlight on Innovators: Session 2 included Rachel Haot, City of New York, Yusef Freeman, McCormack Baron Salazar, Mayor Luke Ravenstahl, City of Pittsburgh, Jessica Venegas, 100,000 Homes, and Kristine Breese, Jacob Center for Neighborhood Innovation.

Breakout Workshops included Neighborhood Revitalization moderated by Luke Tate, White House Domestic Policy Council, Public Health moderated by Julie Moreno, White House Domestic Policy Council, Education moderated by Jim Shelton, Department of Education and Economic Development moderated by Ari Matusiak, White House Office of Public Engagement.  (The White House)

HUD Innovation of the Day

The U.S. Department of Housing and Urban Development (HUD) has developed a new tool for highlighting innovations.  Innovation of the Day (IOD) was developed as a hub for collecting and disseminating innovative housing, community development, built environment, and urban practices. Its purpose is to crowd-source new models that can be leveraged not only within HUD, but by other agencies, municipalities, philanthropies, non-profits, and citizens. Additional benefits include the ability to identify emerging trends, promising solutions, and successful means of implementation. Share your innovations with us or search our database for emerging practices in your own community or from around the world! (HUD)

Center Partners With Water Management, Inc

Section 3 Water Conservation Jobs Training and Business Creation Program

Center for Environment, Commerce & Energy Water Management, Inc. HUD Outreach Section 3 July 2012 WANTED: SECTION 3  WATER MANAGEMENT ENTREPRENEURS The Center for Environment, Commerce and Energy (Center) and Water Management, Inc (WMI) have partnered to offer water management entrepreneurial services to Public Housing Authorities and their residents.   Section 3 businesses should contact Water Management, Inc. (WMI) today if they are interested in providing water management services . WMI is prepared to work with already certified Section 3 businesses and is also prepared to assist prospective businesses in establishing water services companies.If your housing authority is interested in saving water, please share this notice with residents of public housing or other low income people who you believe would be a good match for this sort of work. ENERGY SERVICE COMPANIES Creating Jobs & Saving Money Energy Services Contracts include water management as a component of saving energy and money. Water Management, Inc. is examing the feasibility of integrating Energy Performance Contracts with Section 3 entrepreneurial actitivities. We can save water, create new businesses, increase cash flows and save on utility bills all at the same time. Let us show you how this can be done. Water Management, Inc About Water Management, Inc. is well established in the field of water efficiency and conservation and has developed a successful track record since its founding in 1980. WMI operates nationwide with offices in Alexandria, VA (Headquarters), Nashville, Atlanta, Boston, Fort Worth and Los Angeles. Experience Testing Lab Over the past 30 years, WMI's water professionals have conserved hundreds of billions of gallons of water for our clients. WMI continually trains its personnel in leading water conservation techniques so our clients can be assured of world class service in the areas of water demand management and conservation. Roughly two-thirds of our employees are involved with hands-on supervision or direct product installation. Water Management Inc. also operates an in-house testing laboratory to advise our clients on which products will best fit the water efficiency needs of their property. Center for Environment, Commerce & Energy About The Center for Environment, Commerce & Energy is an environmental organization dedicated to protecting the environment, promoting the efficient use of natural resources, enhancing human, animal and plant ecologies and increasing participation in the environmental movement. HUD Section 3 Creating Entrepreneurs The HUD Section 3 program requires that recipients of certain HUD financial assistance, to the greatest extent possible, provide job training, employment, and contract opportunities for low- or very-low income residents in connection with projects and activities in their neighborhoods. WMI and the Center support the HUD Section 3 program and are available to provide outreach and support services to public housing entrepreneurs. WMI and the Center will provide water management support services. Contact Me Today WMI and the Center are available to provide training and incubator water management company services to Section 3 companies. Contact: Norris McDonald NorrisMcDonald@cfece.org 1629 K Street, NW., Suite 300 Washington, DC 20006 443-569-5102 Thank you for considering us. We want to save water and create water efficiency entrepreneurs. Sincerely, Norris McDonald, President Center for Environment, Commerce & Energy Russ Horner, President Water Management, Inc.

Exelon and First Solar

In September, 2011, Exelon Corporation acquired Antelope Valley Solar Ranch One, a 230-megawatt (MW) solar photovoltaic (PV) project under development in northern Los Angeles County, Calif., from First Solar, which developed and will build, operate, and maintain the project. Construction has started, with the first portion of the site expected to come online in late 2012 and full operation planned for late 2013.

When fully operational, AV Solar Ranch One will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The project has a 25-year power purchase agreement (PPA), approved by the California Public Utilities Commission, with Pacific Gas & Electric for the full output of the plant.

Exelon expects the total investment of up to $1.36 billion to be accretive to earnings beginning in 2013 and free cash flow accretive starting in 2013. The project is value accretive, and will have stable earnings and cash flow profiles due to the PPA. Exelon expects to invest up to $713 million in equity in the project through 2013.

The Treasury Department approved a $646 million loan, guaranteed by the U.S. Department of Energy's Loan Programs Office to support project financing for AV Solar Ranch One. Advances under the loan are contingent on the satisfaction of various conditions. No regulatory approvals are needed for Exelon's acquisition of AV Solar Ranch One from First Solar.

The project will deliver economic benefits to the local community and the state of California, including the generation of state and local tax revenues and creation of up to a peak of 400 construction jobs and up to 15 ongoing operations and maintenance positions, with an emphasis on hiring workers from the local area.

When fully operational, AV Solar Ranch One will displace approximately 140,000 metric tons of carbon emissions per year - the equivalent of taking approximately 30,000 cars off the road. Plus, it will generate electricity with no water use, no air emissions and no waste production. Exelon's existing solar assets include Exelon City Solar, the nation's largest urban solar power plant, which is located on the South Side of Chicago and was completed in 2010.

The project will be built on 2,100 acres of fallow farmland near Lancaster, Calif., in the Antelope Valley area of the Western Mojave Desert, approximately 80 miles north of Los Angeles. The transaction expands Exelon's geographic presence into California, an attractive solar market with an ambitious renewable energy policy and some of the best PV resources in the world.

AV Solar Ranch One will employ First Solar's FS Series 3 PV Module and deploy its tracking system on a portion of the facility. The technology will increase electricity output by tilting the solar panels to track the daily path of the sun. The project also will feature innovative inverters with voltage regulation and monitoring technologies, which provide more stable and continuous power, increasing the project's efficiency and reliability. (First Solar)

Exelon Corporation is one of the nation's largest electric utilities with more than $18 billion in annual revenues. Exelon distributes electricity to approximately 5.4 million customers in northern Illinois and southeastern Pennsylvania and natural gas to approximately 490,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC. First Solar (Nasdaq: FSLR) manufactures solar modules with an advanced semiconductor technology, and is a premier provider of comprehensive photovoltaic (PV) system solutions. The company is delivering an economically viable alternative to fossil-fuel generation today. From raw material sourcing

Center Seeking Keystone Pipeline Construction Contract

The Center and its pipeline construction partner, S.L. Sibert Management and Construction Company (SLSMC), are pursuing contracting opportunities on the proposed Keystone XL pipeline project.  The Center hopes the pipeline, TransCanada, will select our team to construct a portion of the pipeline.  The Center would assure that appropriate environmental protections are in place and SLSMC has extensive experience in pipeline construction.

The Keystone pipeline already runs from Edmonton, Alberta, Canada to Cushing, Oklahoma.  The southern extension from Cushing, Oklahoma to Port Arthur and Houston, Texas has been approved.  The controversial project is still awaiting State Department approval, which should come early in 2013, if not sooner.  The project needs State Department approval because it crosses an international border.  The Keystone XL Expansion pipeline would provide a shortcut and extension from Cushing, Oklahoma to Port Arthur and Houston.  The Center/SLSMC is prepared to participate in construction along any section of the pipeline.

Keystone XL Pipeline Primer

Mitt Romney Energy Plan

Mitt Romney released his new energy plant in a white paper and it focuses on developing domestic fossil fuels like oil, gas and coal. Romney's plan would make states the custodian of energy production on federal lands within their borders and allow them to implement their own federally-approved leasing practices. Such a move would effectively shift responsibility for permitting, leasing and environmental regulation from the Department of the Interior to states, with the hope of speeding energy development by cutting red tape.

Romney's plan calls for reaching North American energy independence by 2020, primarily through expansion of traditional fossil fuels. The United States is currently the world's third largest oil producer, which Romney would hope to expand. The U.S. also currently imports more than half its oil from countries in the Western Hemisphere, with Canada making up a 29-percent share. According to Romney, those imports could be increased through greater cooperation and by the immediate approval of the Keystone XL pipeline, and similar projects.

The Romney includes greenlighting increased offshore drilling, slowed after 2009's BP oil spill disaster, particularly off the coasts of Virginia and North Carolina.

The GOP challenger's plan pays little attention to renewable fuels like wind and solar power.  Romney's plan includes continued research support for alternative fuels, but would have wind and solar generation succeed or fail on their own, without government subsidies or loan guarantees.
President Obama makes a contrasting argument about continued oil industry tax subsidies, arguing that the highly profitable major oil companies don't need the tax breaks, the extension of which is supported by Romney. (NBC News)

Shipbreaking in Brownsville, Texas

Special Projects

Chairman, Doc Sloan

ESCO Shipbreaking Site

Although most shipbreaking is done overseas, there are a few shipbreaking companies in the United States.  Ship breaking in the United States is booming at the moment, as congressional mandates to reduce the rotting hulks in the three Ghost Fleets of the nation are being implemented. These mothball fleets are composed primarily of US Maritime Administration (MARAD) reserve ships, initially kept in case they needed to be activated again for war. These reserve fleets started after WWII, the biggest ship-building boom in history. In 1950, there were over 2,000 surplus federal ships, tied together in slack water clusters around the nation.

ESCO is a ship breaking site in the USA located in Brownsville, Texas, just a few miles from Mexico. This is where the vast majority of the nation’s federal ships are broken apart. A 15 mile-long channel, made from scratch from 1934-1936, connects the Port of Brownsville to the ocean, at South Padre Island. Built inland to protect the port from hurricanes, not much occurs along the channel’s first ten miles.

ESCO is an active 88 acre yard full of scrap piles, metal processing machinery, cranes, and processing areas where larger chunks of the ship have been removed and are being cut down on shore with torches and other equipment. ESCO has salvaged former offshore rigs as well.

 

Center-Arranged Youth Tour of Avesta Sheffield Plant

Special Projects Chairman Doc Sloan put together a program on behalf of the Center in 1998 that sought to combine shipbreaking on the Patapsco River in Baltimore with a Welfare-To-Work component that included a steel plant in Baltimore County.  Unfortunately, the steel plant closed unexpectedly just as the program was about to launch.

The Center assisted Avesta Sheffiend Steel Company in addressing pollution issues at the site and took Baltimore inner city youth on a tour of the facility.

President Roy Cooke, Avesta Sheffield-East President is in green in the above photo, Joe Duncan, President of the United Steel Workers of America, Local 1245 is in the middle and Center President Norris McDonald is at right at the steel plant near Baltimore.(1998)

Doc Sloan is working with ESCO to explore unique entrepreneurial opportunities.  The Center stands ready to assist ESCO with environmental services and assessments at the site. (The Center For Land Use Interpretation) 

Natural Gas Key To Renewable Energy Use

Combined-Cycle Gas Turbine Plants Solve Intermittency Problem of Wind & Solar 

How do we develop an energy future that copes with the variability of solar and wind energy? Non-renewable natural gas seems destined to play a larger role in ushering in a greater penetration of renewable energy. It's the only practical utility-scale source of energy that can be to help match fluctuations in load.

While gas supply and pricing have historically been subject to significant fluctuations, it appears that for the foreseeable future, gas will continue to be consistently affordable and plentiful in North America. Much of this comes from the growth of technology for pulling gas from "tight" rock formations such as shale.

These supplies are widely distributed geographically, so that many parts of the country can access gas supplies without the risk of power loss due to long-distance electrical transmission, or gas pipelines.

The pricing point for natural gas futures contracts traded on the New York Mercantile Exchange is forecasted to be below $6/mmbtu through 2016, at which price electricity can be produced for about $55/MWh. As of this writing, gas trades below $2/mmbtu, allowing electricity to be produced for around $30/MWh.

To support the intermittent nature of wind and solar power,
gas turbine manufacturers such as Alstom are building
 quick-firing  gas turbines. Alstom's GT24 gas turbine.
 Photo courtesy Alstom

The combined-cycle gas turbine plants (CCGT) uses a gas turbine generator to generate electricity and the heat of its exhaust to make steam, which in turn drives an electricity-generating steam turbine.  Gas turbine manufacturers have invested heavily in fast-start combined cycle plant designs, which have the potential to integrate well with renewable resources. CCGT cycle plants offer significant advantages compared to nuclear and coal, including shorter start-up time, high start reliability, lower start-up costs, daily multi-startup and shutdown, high ramping rates, and extended emission compliance at partial loads, as well as comparatively lower installed cost.

CCGT is the best match with a wind turbine farm because, during a hot summer day a wind farm will generate less power in the afternoon, when power is needed the most and when power prices are highest. A thermal solar energy facility can be used during the day to supplement the steam supply from the turbine's Heat Recovery Steam Generator (HRSG) -- a solution most applicable to hot, sunny areas such as the Southwest.

With CCGT technology, the way is clearer for gas-fired generation to provide the power needed to compensate for the fluctuations in solar and wind power supply, allowing these green energy sources to provide more of the total energy share.

Compared to some power technologies, CCGT plants make few infrastructure demands. They must have a source of water for the boiler and a fuel supply. If operated in tandem with renewable energy, they need a turbine-generator technology and a plant design that can match the fluctuations of the renewable resource.

If located close to the renewable energy source, the CCGT plant can share interconnection facilities and help regulate the output of that wind or solar power installation. If located along the transmission corridor, it can help regulate the supply from several renewable-energy generation sites and electricity users.

The capacity factor for wind power is in the range of 13 percent to 40 percent depending on the location, and is normally higher at night. Many merchant CCGT plants are operating in the range of 40 percent to 60 percent capacity factor, and normally run during the day when demand and prices are higher. Accordingly, wind farm and CCGT plant generation capacity factors can balance each other to create a higher overall capacity factor and revenue stream.

Building CCGT to complement wind and other renewable energy sources is not economically viable without price support and regulatory incentives. Incentives from governments are required to support the higher operating costs of the CCGT, due to lower output. Renewable energy must be sustained with tax incentives, including PTCs, federal Modified Accelerated Cost Recovery Systems (MACRS), state Accelerated Depreciation and other tax exemptions. Incentives could be provided to natural gas suppliers and generators to raise allowable renewable energy penetrations to the grid.

Current trends indicate that if wind and solar grow, the output of these variable resources will need to be stabilized through variable output, baseload power such as gas-fired generation. Renewable energy alone will not be a viable source of energy, but integration of variable output, baseload generation, such as natural gas combined cycle plants will allow renewable energy to grow. (By Ying Ng, Power Engineering, 7/1/2012)

Natural Gas v. Coal

According to data from the Energy Information Administration (EIA), natural gas accounted for 28.7 percent of total generation during the first quarter of 2012, compared with 20.7 percent during the same quarter last year. In contrast, coal's portion of total generation declined from 44.6 percent to 36.0 percent over the same period. Even more drastic numbers can be seen when comparing the amount of gas generation in March 2012 to March of last year. According to the EIA, U.S. power plants increased natural gas use by 40 percent this March compared to a year earlier – from 503.9 billion cubic feet (Bcf) in March 2011 to 703.5 Bcf in March of this year.

As natural gas prices have reached startling lows this year, gas has taken a sizeable amount of U.S. electric power generation from coal. Many utilities being forced to retrofit or retire coal-fired facilities to comply with the Mercury and Air Toxics Standard and Cross State Air Pollution Rule (struck down by court) are finding solutions in revamping their plants as partial gas-burning facilities. Additionally, natural gas facilities constructed in the early 2000s that have been operated as peakers in the past are now being called upon to run at significantly higher rates.

With regulations targeting not only the traditional emissions such as sulfur dioxide and nitrogen oxide, but also new challenges like mercury and carbon capture, coal is not a cheap option for the time being. A number of new facilities that were formerly proposed as coal plants have switched to full natural gas or combined cycle over the last few years. One of the few remaining proposed coal plants, the Taylorville Energy Center, is likely to switch to gas.

The continued development of natural gas shale resources and an exceptionally warm winter have contributed to an overabundance of natural gas. The average spot price for natural gas in April 2012 was less than $2 per mmBtu, and prices may remain relatively low for a while.  Gas prices in the U.S. could double in the next three years due to the gas demand as coal is replaced for gas in electricity.  For the short-term, gas will likely stay far below $5.  (Power Engineering, 7/12/2012)

Court Strikes Down EPA Cross State Air Pollution Rule

The United States Court of Appeals for the District of Columbia, in a 2-1 ruling today, said the Environmental Protection Agency had exceeded its authority in the way it apportioned the cleanup work among 28 upwind states, called the Cross-State Air Pollution Rule.  The rule addressed how to deal with states whose own air was clean enough, but were hosts to power plants, refineries and other industrial plants that emitted sulfur dioxide and nitrogen oxide pollutants that prevented neighboring states from attaining the level of cleanliness required under the Clean Air Act.

The rule was EPA’s attempt to carry out a court-ordered fix on an earlier version, the 2005 Clean Air Interstate Rule.  The court said that the E.P.A. was authorized to set rules that would require upwind states “to bear responsibility for their fair share of the mess in downwind states.”  But the E.P.A. had improperly required states “to reduce their emissions by more than their own significant contribution to a downwind state’s nonattainment,” according to the opinion, written by Judge Brett M. Kavanaugh and joined by Judge Thomas B. Griffith. Judge Judith W. Rogers dissented from the ruling.       

The E.P.A.’s rule also violated the Clean Air Act because it failed to let the states submit their own plans to comply and imposed a federal plan instead, the court said. The statute leaves it to the states to decide how they will meet federal standards. The ruling could also leave the previous Clean Air Interstate Rule in place.    

Several power companies had challenged the E.P.A. rule, and were supported by more than a dozen states, mostly in the South and Midwest. North Carolina supported the rule, along with several mid-Atlantic and New England states.

      

Many big environmental groups, including the Sierra Club, Environmental Defense Fund, Clean Air Task Force, American Lung Association, and the Natural Resources Defense Council, supported the E.P.A.’s position and were joined by downwind states and cities. (NYT, 8/21/2012)

Natural Gas & Renewables Dominate 2012 Capacity Additions

During the first half of 2012, 165 new electric power generators were added in 33 states, for a total of 8,098 megawatts (MW) of new capacity. Of the ten states with the highest levels of capacity additions, most of the new capacity uses natural gas or renewable energy sources. Capacity additions in these ten states total 6,500 MW, or 80% of the new capacity added nationally in the first six months of 2012.

Most of the new generators built over the past 15 years are powered by natural gas or wind. In 2012, the addition of natural gas and renewable generators comes at a time when natural gas and renewable generation are contributing increasing amounts to total generation across much of the United States. In particular, efficient combined-cycle natural gas generators are competitive with coal generators over a large swath of the country. And, in the first half of 2012, these combined-cycle generators were added in states that traditionally burn mostly coal.

Only one coal-fired generator was brought online in the first half of 2012, an 800-MW unit at the Prairie State Energy Campus in Illinois. In its 2011 annual survey of power plant operators, the U.S. Energy Information Administration (EIA) received no new reports of planned coal-fired generators. Of the planned coal generators in EIA databases, 14 are reported in the construction phrase, with an additional 5 reporting a planned status but not yet under construction. However, only one of the 14 advanced from a pre-construction to an under-construction status between the 2010 and 2011 surveys.

More small generators were added than large generators: of the 165 generators added, 105 were under 25 MW. Many of these use renewable energy sources, most commonly solar and landfill gas; wind plants aggregate many individual turbines into one large "generator" for reporting purposes.

Solar has shown significant growth in the electric power sector over the past two years. From the beginning of 2010 to the end of June 2012, 1,308 MW of new utility-scale solar capacity has come online, more than tripling the 619 MW in place at the end of 2009. Despite this significant increase, these additions understate actual solar capacity gains. Unlike other energy sources, significant levels of solar capacity exist in smaller, non-utility-scale applications (e.g., rooftop solar photovoltaics). 

More capacity was added in the first half of 2012 than was retired. A total of 3,092 MW was retired, from 58 generators in 17 states. Over half of this was coal, and another 30% was petroleum-fired generators. (EIA)

Resources For The Future: New Shale Gas Research

"A Review of Shale Gas Regulations by State"

Experts at Resources For The Future (RFF) analyzed regulations in the 31 states that have significant shale gas reserves to identify how 20 important regulatory elements are applied in each state.

The maps in this project show the preliminary results of these efforts for approximately 20 important regulatory elements in each state in the continental United States.  The purpose of these maps is to provide an overview of the regulatory patterns, similarities, and differences among states.  (RFF)

GAO Report on EPA Regulations and Electricity

The General Accounting Office (GAO) recently completed a report (summary) on the effects of Environmental Protection Agency regulations on the electric utility industry ("EPA Regulations and Electricity: Better Monitoring by Agencies Could Strengthen Efforts to Address Potential Challenges"). 

EPA recently proposed or finalized four regulations affecting coal-fueled electricity generating units, which provide almost half of the electricity in the United States:

(1) the Cross-State Air Pollution Rule;

(2) the Mercury and Air Toxics Standards;

(3) the proposed Cooling Water Intake Structures regulation; and

(4) the proposed Disposal of Coal Combustion Residuals regulation.

Power companies may retrofit or retire some units in response to the regulations. EPA estimated two of the regulations would prevent thousands of premature deaths and generate $160-$405 billion in annual benefits. Some stakeholders have expressed concerns that these regulations could increase electricity prices and compromise reliability—the ability to meet consumers' demand. FERC and others have oversight over electricity prices and reliability. DOE can order a generating unit to run in certain emergencies. GAO was asked to examine: (1) actions power companies may take in response to these regulations; (2) their potential electricity market and reliability implications; and (3) the extent to which these implications can be mitigated.

It is uncertain how power companies may respond to four key Environmental Protection Agency (EPA) regulations, but available information suggests companies may retrofit most coal-fueled generating units with controls to reduce pollution, and that 2 to 12 percent of coal-fueled capacity may be retired.  Power companies may also build new generating units, upgrade transmission systems to maintain reliability, and increasingly use natural gas to produce electricity as coal units retire and remaining coal units become somewhat more expensive to operate.

Available information suggests these actions would likely increase electricity prices in some regions. Furthermore, while these actions may not cause widespread reliability concerns, they may contribute to reliability challenges in some regions.

Regarding prices, the studies GAO reviewed estimated that increases could vary across the country, with one study projecting a range of increases from 0.1 percent in the Northwest to an increase of 13.5 percent in parts of the South more dependent on electricity generated from coal. According to EPA officials, the agency’s estimates of price increases would be within the historical range of price fluctuations, and projected future prices may be below historic prices.

Regarding reliability, these actions are not expected to pose widespread concerns but may contribute to challenges in some regions.  Among other things, it may be difficult to schedule and complete all retrofits to install controls and to resolve all potential reliability concerns associated with retirements within compliance deadlines.

Existing tools could help mitigate many, though not all, of the potential adverse implications associated with the four EPA regulations, but the Federal Energy Regulatory Commission (FERC), Department of Energy (DOE), and EPA do not have a joint, formal process to monitor industry’s progress in responding to the regulations. Some tools, such as state regulatory reviews to evaluate the prudence of power company investments, may address some potential price increases. Furthermore, tools available to industry and regulators, as well as certain regulatory provisions, may address many potential reliability challenges.  FERC, DOE, and EPA have not established a formal, documented process for jointly and routinely monitoring industry’s progress and, absent such a process, the complexity and extent of potential reliability challenges may not be clear to these agencies. This may make it more difficult to assess whether existing tools are adequate or whether additional tools are needed. (GAO)

Pipelines

The nation’s network of more than 2.5 million miles of pipeline is largely regulated by the Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) and state entities. Part of this network consists of more than 200,000 miles (estimated) of onshore "gathering" pipelines, which transport hazardous liquid and natural gas products from wells to processing facilities and to larger transmission pipelines. Many of these gathering pipelines, however, have not been subject to PHMSA regulation because they are generally located away from population centers and operate at low pressures.

Pipelines transport roughly two-thirds of domestic energy supplies throughout the United States. These pipelines carry hazardous liquids and natural gas from producing wells to end users (residences and businesses). Within this nationwide system, there are three main types of pipelines.

Gathering pipelines

Gas gathering pipelines collect natural gas from production areas, while hazardous liquid gathering pipelines collect oil and other petroleum products. These pipelines then typically transport the products to processing facilities, which in turn refine and send the products to transmission pipelines. According to PHMSA officials, traditionally, gathering pipelines range in diameter from about 2 to 12 inches and operate at pressures that range from about 5 to 800 pounds per square inch (psi). These pipelines tend to be located in rural areas but can also be located in urban areas. PHMSA estimates there are 200,000 miles of gas gathering pipelines and 30,000 to 40,000 miles of hazardous liquid gathering pipelines.

Transmission pipelines

Transmission pipelines carry hazardous liquid or natural gas, sometimes over hundreds of miles, to communities and large-volume users (e.g., factories). For natural gas transmission pipelines, compression stations located periodically along the pipeline maintain product pressure. Similarly, pumping stations along hazardous liquid transmission pipelines maintain product flow. Transmission pipelines tend to have the largest diameters and pressures of any type of pipeline, generally ranging from 12 inches to 42 inches in diameter and operating at pressures ranging from 400 to 1440 psi.

Distribution pipelines

Gas distribution pipelines continue to transport natural gas to residential, commercial, and industrial customers, splitting off from transmission pipelines. These pipelines tend to be smaller, sometimes less than 1 inch in diameter, and operate at lower pressures—0.25 to 100 psi. PHMSA has estimated there are roughly 2 million miles of distribution pipelines, most of which are intrastate pipelines. There are no hazardous liquid distribution pipelines. For the purposes of this report, we use the term transmission pipeline to refer to both hazardous liquid and natural gas pipelines carrying product over long distances to users.

GAO: "PIPELINE SAFETY, Collecting Data and Sharing Information on Federally Unregulated Gathering Pipelines Could Help Enhance Safety," March 2012