While United States and Chinese diplomats are working to forge cooperation between the countries on climate issues, the Chinese government’s huge clean tech investments may help that country pass the U.S. as the worldwide clean technology leader.  Could this “competitiveness crisis,” as one group terms it, have implications for the U.S. economy and the clean tech industry?  The results of this global race for dominance in the cleantech sector could significantly impact not only the national economy, but also the condition of the global environment.

Chinese Energy Investments

The Chinese are investing approximately 3% of their GDP on cleantech and renewable energy, as compared to less than half a percent of GDP in the U.S.  During early summer, the Chinese government floated plans to spend at least $440 billion in another stimulus package-all of that money going toward new cleantech investment.

The Chinese government also set a number of demanding goals for renewable energy and clean tech production and installation, including-

• Increasing renewable energy production from wind to 150GW by 2020, from an earlier goal of 100GW, and solar production from 1.8GW to 20GW by the same year
• Increasing production of plug-in hybrid electric vehicles to 500,000 by the end of 2011, up from 2,100 in 2008
• A raft of transportation spending initiatives and policy reforms, including $1 trillion for increased railway infrastructure, tax programs to incentivize the purchase of fuel-efficient cars and increased fuel economy standards
• Strict energy-efficiency standards in building codes, home appliances and amongst China’s top 1000 energy consuming businesses.

China is also moving full speed ahead in the race to dominate nanotechnology research, a likely source for many of the cleantech industry’s future breakthroughs.  These investments, combined with what some see as a willingness to use border measures and anti-competitive bidding practices to discourage foreign participation in the Chinese cleantech market, position Chinese manufacturers to be a dominant player in the global cleantech market.  Indeed, China’s rise in the cleantech space has prompted some U.S. analysts to question the wisdom of investing in domestic cleantech manufacturing capacity, versus simply ceding manufacturing to China and focusing on domestic installation of less expensive Chinese equipment. 

When Cleantech Doesn’t Mean Cleanup

While China has made significant strides in cleantech investment and implementation, it has continued to resist international calls for binding emissions caps or reductions.  Instead, citing its prerogative as a developing nation, China has focused its pledges on reducing energy intensity-a measure of carbon emissions in relation to GDP.  This poses several challenges for international efforts to stabilize carbon levels.  First, with China becoming the world’s largest net emitter of CO₂, internationals effort to freeze global emissions will be an exercise in futility without China (and other large developing countries) making binding commitments.  Second, even under China’s current emissions-rate based goals, China has yet to meet any of the benchmarks necessary to achieve its efficiency goals of reducing emissions 20% by 2010.

China’s aggressive investment in the cleantech sector, combined with its continued refusal to reduce its net emissions, illustrates a major flaw in the assumption that investment in clean energy infrastructure and manufacturing capacity will automatically lead to both a cleaner environment and more robust national economies.  If, as some critics argue, China has opted for the robust economy while leaving the cleaner environment to others, China could reap disproportionate economic benefits from global cleantech investment, while shifting a disproportionate economic and environmental burden to other counties.  This, in turn, could undermine other countries’ efforts to fund today’s environmental cleanup efforts through long-term economic growth in their domestic cleantech industries. 

American cleantech companies are poised between a radical expansion of their potential markets into China and other cleantech-hungry developing countries and the specter of foreign companies, energized by concerted investment in their home nations, outcompeting them both overseas and at home.  This high-stakes race for cleantech hegemony will be hard fought, with China and the U.S. just two of the countries competing.  The race to be a global leader in actual emissions reductions, however, remains any country’s to win.

For further information about this topic, please contact Akin Gump.

Current Administration and congressional climate proposals depend heavily on geological sequestration to reduce CO2 emissions from coal-fired power plants and other major sources and tend to presume that sources in every state will have access to nearby underground storage capacity.  This is the third post in a three-part series reviewing obstacles to a 50-state sequestration strategy and suggesting the need for a national infrastructure to support medium to long-range transport of CO2.

• Part 1: The Porosity Problem
• Part 2: Not Under My Back Yard (NUMBY)

Part 3: 50 States, 50 Hurdles

A fifty-state sequestration strategy will require not only state-by-state access to geologically-suitable subsurface storage capacity and some minimum level of buy-in from state residents and property owners , but also state and municipal governments to codify, fund and implement the supporting legal, regulatory and oversight infrastructure needed to regulate long-term underground injection and storage as an approved land use.  While many state and local governments are struggling to manage and maintain their existing portfolio of governmental functions (issues like healthcare, education and core environmental programs), some are likely to balk at advancing carbon capture and sequestration (CCS) policy to the front of their legislative and regulatory agendas.  At a May 2009 hearing by the Senate Energy and Natural Resources Committee, a  Wyoming state legislator, reflected some of the issues states face in regulating the carbon capture and sequestration industry.  These comments may be particularly trenchant given that Wyoming is one of the first states to codify a comprehensive CCS legislative framework—

• Ownership of pore space as a distinct property right.  Most states have well-established rules relating to allocation of ownership of surface rights versus mineral rights at a given site, a function of the country’s long history of extractive industry (mining, oil and gas production, etc.).  Geologic sequestration introduces a different and less common subsurface property interest-interest in underground pore space as a storage commodity.
• Dominance of surface, mineral, and pore space estates.  Just as the interests of surface property owners and mineral right owners can sometimes clash, the addition of a third form of property right creates the need for rules of priority- particularly between the interests of mineral right owners and pore-space owners
• Site Permitting and Regulation.  EPA is currently establishing federal regulations for underground injection and sequestration of CO2 under its Safe Drinking Water Act authority.   EPA has acknowledged, however, that it lacks authority to address all issues raised by CCS.  Moreover, even recent legislative proposals that would augment EPA’s authority may not address siting issues subject to state and local jurisdiction. 
• Long-term liability for sequestered carbon.  The issue of financial and legal liability for the site, particularly during the decades or centuries after a CCS project has ceased active operations, is currently unresolved.  EPA has ignored the issue in the context of its federal rulemaking, citing a lack of authority.  Given the long time horizon of sequestration storage (centuries to millennia absent development of new uses for sequestered CO2), the prospect of unlimited liability for future problems is a significant source of uncertainty and risk for project managers and host states. 
• Unitization standards or eminent domain.  Liquid CO2, once injected into subsurface pore space, does not respect legal boundaries and ownership divisions.  To address situations where site developers are unable to negotiate terms with other affected subsurface pore space owners to support a project, governments need to establish procedures for unitizing or pooling groups of properties and the associated property interests to accommodate the subsurface scope of a project-sometimes against the objection of some owners. 

While Wyoming has been a leader in the development of CCS-related legislation, it is not the only state addressing these issues.  Recent studies by the National Conference of State Legislatures and the  Interstate Oil and Gas Commerce Commission  reported that at least 31 states were considering legislation addressing CCS issues.  To date, however, only a handful have put actual legislative or regulatory standards in place, including Kansas, Massachusetts, North Dakota, Oklahoma, Texas, Utah and Washington.  (Illinois, home to the recently reinstated FutureGen project, recently passed new CCS legislation that was sent to the governor for signature on June 26, 2009).

Oil and gas states have lead the effort to develop state sequestration policies.  States with well-developed oil and gas industries have numerous advantages when it comes to crafting state and local CCS policies.  Existing oil and gas laws provide policymakers with a starting point, if not a template, for sorting through complicated issues of property ownership, liability and land-use management raised by CCS.  Oil and gas states are more likely to have encountered and considered some of the unique policy associated with underground CO2 injection in the context of already-occurring enhanced oil or gas recovery activities or natural gas storage within their borders.  This experience and familiarity with subsurface property rights and responsibilities, at both the voter and policymaker level, may reduce the political complexities of introducing a new layer of rights and obligations.  Finally, oil and gas states, as natural homes for future geologic sequestration projects, likely see a greater value in developing the regulatory infrastructure needed to support what may become an important new industry, particularly as their oil and gas reserves dwindle.

The lack of CCS standards or experience with the types of issues faced in the other states shows a flaw in the assumption that each state will be ready to attend to its own geologic sequestration needs any time soon.   State lawmaking and regulatory processes can be time-intensive, especially where the public’s attitude is mixed regarding a potential policy.   Indeed,  states like California and New York may face particular challenges in developing legislation and in promulgating implementing regulations due to the extensive public participation and environmental review requirements established under state law.   

Moving Forward

Ultimately, the challenge in a 50-state sequestration strategy will not be spurring the first 10 to 20 states to action-that is already happening, in part because these states see economic benefits to being early movers.  The challenge will be in making the last10 to 20 states CCS ready.  The natural variability of carbon storage potential from one region to another, and the political and legal practicalities of siting and regulating CCS facilities, suggest that not all states will have local CO2 storage infrastructure, at least at a cost and/or a time-frame needed to meet proposed emissions reduction goals.  If policymakers want to rely on carbon capture and storage mandates as part of a nation-wide strategy to reduce CO2 emissions, medium to long-distance transport of the captured CO2 is certain to be a necessary component.  CO2 transport policy can no longer be ignored in the unfolding energy and climate debate. 

For further information about this topic, please contact Akin Gump.

Current Administration and congressional climate proposals depend heavily on geological sequestration to reduce CO2 emissions from coal-fired power plants and other major sources and tend to presume that sources in every state will have access to nearby underground storage capacity.  This is the second post in a three-part series reviewing obstacles to a 50-state sequestration strategy and suggesting the need for a national infrastructure to support medium to long-range transport of CO2. 

Even if additional research and site characterization could resolve geological uncertainties regarding widespread local CO2 storage, companies also will have to overcome the public and political opposition that locally undesirable land use (LULU) energy projects engender.  While CO2 sequestration provides important global benefits, local communities are likely to balk at hosting a sequestration project injecting millions of tons of liquid CO2 as a waste product under or near their communities.

The saga of Used Nuclear Fuel Storage at Yucca Mountain in Nevada illustrates the challenge of siting even one nationally-important, but locally-opposed, facility.  First identified as the nation’s prospective high-level nuclear waste storage site in 1987 and approved by Congress in 1994, the Yucca Mountain high-level nuclear waste storage facility received over 9 billion dollars in funding through 2008 despite vociferous opposition from local stakeholders and, in some cases, key federal constituencies.  In early 2009, the Obama Administration proposed to defund the project.  While only Congress can cancel the project, Senate Majority Leader Harry Reid (D-NV) has committed to doing just that.  Irrespective of the merits of the decision to defund Yucca, it is a significant setback for the domestic nuclear energy industry, as the reversal leaves the nation twenty years behind in developing a long-term disposal strategy for high-level nuclear waste.

Even relatively innocuous renewable energy projects  face siting difficulties.  Indeed, the U.S. Chamber of Commerce recently initiated a campaign to document the wide variety of energy projects that have been stopped or delayed across the nation by local opposition.  The siting challenge illustrates an important reality check for policymakers and investors:  a prospective site may contain optimal subsurface geologic characteristics, but if developers cannot negotiate the local siting process, the technical feasibility of a location is irrelevant.

Siting CCS facilities on federal lands may be one way to reduce the ability of local opposition to stop a project.  The Department of Interior has estimated that 5.5 percent of the onshore U.S. CO2 storage capacity is beneath potentially leasable Federal lands.  But, federal lands bring limitations of their own.  First, federal lands are not uniformly distributed across regions and states, and many areas of the country (e.g., the northeast, southeast and midwest) lack large swaths of federal lands on which facilities could be sited.  The disconnect is even more significant when major emissions sources are considered.  According to a recent DOE Report, while 65% of emissions come from east of the Mississippi River, 83% to 86% of storage capacity on federal lands lies west of the Mississippi River.   In other words, a siting strategy that relies on federal lands for citing will require investment on CO2 transport to match source generation to sequestration capacity.

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For further information about this topic, please contact Akin Gump.

Current Administration and congressional climate proposals depend heavily on geological sequestration to reduce CO2 emissions from coal-fired power plants and other major sources and tend to presume that sources in every state will have access to nearby underground storage capacity.  While some federal agencies and studies consider widespread localized sequestration to be viable, a nationwide rollout faces significant obstacles.  In areas where local sequestration is impractical, emissions sources will be forced to transport captured CO2, by pipeline, ship or other mode, to a viable sequestration site.  To date, however, federal climate proposals have given limited attention to developing the CO2 transport infrastructure. 

This series reviews three obstacles to a 50-state sequestration strategy and discusses the need for a national infrastructure to support medium to long-range transport of CO2.

Part 1: The Porosity Problem (below)
Part 2: Not Under My Back Yard
Part 3: 50-States, 50 Hurdles

Recognizing these obstacles and honestly confronting them is a critical step to making geological sequestration work.  And, without a successful geologic sequestration program, the United States’ ability to achieve emissions reduction targets is astronomically more difficult.

Part 1: The Porosity Problem

While there are many different factors that determine the suitability of a geological formation to store liquefied carbon, one important threshold consideration is porosity.  An effective sequestration site must contain deep layers of porous rock, capable of absorbing and retaining injected CO2 within its void spaces, much like a sponge that absorbs and holds water.  This porous rock must be covered by an upper layer of dense and highly impermeable cap rock that will prevent upward migration of CO2 toward drinking water aquifers or the surface.  

Citing private and public studies conducted to date, the Environmental Protection Agency (EPA) and the Department of Energy (DOE) have estimated that 95% of all coal-fired plants are within 50 miles of an “ideal” candidate sequestration site.  Other government analyses, however, suggest that not all regions and states are geologically equal when it comes to underground storage capacity.  Indeed, federal researchers have had mixed success in identifying viable sequestration sites with the proper geological characteristics based on theory and scientific testing alone. 

EPA and DOE are working to demonstrate the feasibility of geological sequestration at a wide range of host geological sites nationally, but to date, most successful CCS projects have been sited at current or former oil and gas fields.  For decades, the oil and gas industry has injected liquid CO2 underground to promote enhanced oil recovery.  If CCS storage potential is tied to oil and gas production potential, however, there are likely to be significant disparities in storage potential from one region to another.  DOE’s own website acknowledges that “there is a mismatch between largest [CO2 emission sources] and the largest oil and gas traps.”  A 50-state sequestration strategy will force the CCS industry to diversify its portfolio of storage sites.  Federal studies indicate that unmineable coal seams and deep saline formations offer promising storage potential, but the practicality of such formations remains untested in many parts of the country, despite considerable efforts at regional characterization.

For example, there are large numbers of CO2 emitting sources in the Appalachian Basin, making it an important test area for the viability of DOE’s localized sequestration strategy.  In a recent report on progress at a small-scale sequestration field test in the Appalachian Basin of Ohio, researchers found that “porosity, void space and permeability of the target formations were lower than expected.”  DOE’s difficulty in pinpointing a viable sequestration site location for a small regional pilot project illustrates the uncertainties that remain when it comes to siting at the local level.  

DOE is addressing this nationwide site characterization challenge aggressively, investing department resources and grant funding into projects to improve understanding of sequestration capacity in different geological settings.  Earlier this month, DOE announced its intent to offer an additional $50 million in grants to support site characterization work. 

Missing from both Congress and DOE is a serious Plan B in the event that localized geologic sequestration is not feasible in major portions of the country.  Federal policymakers will need a plan to transport captured CO2 from “pore-locked” emissions sources to areas where high-volume sequestration is practicable. 

The prevailing hope of widespread access to local sequestration capacity could become reality within the timeframes policymakers will need to support U.S. climate mitigation plans.  The U.S. experience with project siting on the basis of geology alone suggests strongly that this hope is a dim one.  Geologic sequestration is critical to U.S. climate policy and Congress and the Administration need to address the available alternatives should the local sequestration strategy prove untenable. 

For further information about this topic, please contact Akin Gump.

The American Clean Energy and Security Act of 2009 (ACES) Carbon Capture and Sequestration (CCS) provisions appear at first blush like a wish list for the coal industry and other CCS proponents.  Between directing the Environmental Protection Agency (EPA) to create an improved regulatory framework for CCS, authorizing billions in new ratepayer-generated funds to support early commercial CCS projects, and authorizing EPA to make direct payments to companies that sequester CO₂, the bill, as developed by Congressmen Henry Waxman and Ed Markey, appears intent on removing regulatory and economic barriers to commercializing CCS technology.  Those incentives come with a lofty condition, however, as the final section in the CCS subtitle lays out the expectation that CCS will reach commercial viability by the middle of the next decade - and become a necessary element of any new coal-fired power plant. Should ACES become law, the expectations for CCS commercialization will high, but the stakes for the coal industry will be even higher.

A Regulatory Framework for CCS

ClimateIntel has reported previously on the legal and regulatory barriers investors and project developers face in moving forward with large-scale CCS projects under the current (or even EPA’s proposed) regulatory framework.  ACES would amend both the Clean Air Act (CAA) and the Safe Drinking Water Act (SDWA) to address some of these key barriers: First, ACES would give EPA’s air program new authority under the CAA to regulate the siting and permitting of these CCS facilities to help prevent atmospheric releases of sequestered CO₂.  Also, EPA’s drinking water regulatory program would gain additional authority necessary to impose financial assurance requirements on owners and operators of CCS facilities, building on EPA’s existing authority to regulate those facilities to protect water resources.

In contrast, on some issues ACES reverts to traditional fact-finding and reporting in lieu of charging forward with rulemaking.  The bill would establish a multidiscliplinary task force to study and report on various legal issues associated with CCS regulation, including options for management of long-term liability at CCS facilities-another issue previously examined on ClimateIntel.  The Bill would also direct the Department of Energy (DOE) and the Federal Energy Regulatory Commission to prepare a Report to Congress on barriers to constructing and operating the extensive web of pipelines that would be needed to transport CO₂ to suitable sequestration or enhanced oil recovery sites.

 A Dedicated Funding Stream for Early Movers

In addition to regulatory certainty, the CCS industry has struggled to generate the capital needed to take CCS from a promising demonstration technology to a proven commercial-scale application.  ACES would establish a quasigovernmental corporation, the Carbon Storage Research Corporation (CSRC), to subsidize early CCS commercial projects using an assessment fee passed through to rate-payers.  The CSRC would operate as a division of the nonprofit Electric Power Research Institute (EPRI), under the direction of a Board of Directors composed of representatives from industry, municipal governments, and nongovernmental organizations.  Absent opposition from 40 percent of state regulators, the CSRC would collect a small assessment fee on each kilowatt-hour of fuel-based electricity delivered directly to retail consumers, tailored to each utility based on their energy mix, providing up to $1 billion per year in funding for CCS projects for the next ten years.

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For further information about this topic, please contact Akin Gump.

In the past week, the ethanol industry received two pieces of positive news.  First, the Congressional Budget Office (CBO) issued a report, entitled “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions,” finding that high energy prices had a much more profound effect on the price of food than increased ethanol production in the period April 2007 through April 2008.  Second, EPA published a notice and solicited comments on a waiver application to increase the amount of ethanol that can be blended into a gallon of gasoline to up to 15 volume percent (E15).

CBO Report

The CBO report concluded that, for the period studied, ethanol production accounted for only 10 to 15 percent of the estimated 5.1 percent increase of food prices.  By comparison, the increase in the consumer price index (CPI) for all urban consumers for energy accounted for 22 percent of the 5.1 percent increase in the price of food.

In analyzing ethanol production’s contribution to the increase in the price of food the CBO assessed how increased ethanol production contributed to increases in the price of corn, animal products and soybeans, and how higher prices for these commodities contributed to the prices of foods that are measured in the CPI-U.  Other contributing factors noted by the CBO include a growing demand for meat that increased the demand for animal feed, dollar exchange rate fluctuations that increased demand for U.S. corn exports and concerns about weather for spring planting that caused corn prices to rise during the spring of 2008.

E15 Waiver Request         

The Clean Air Act authorizes EPA to regulate fuels and fuel additives to reduce the risk to public health from exposure to their emissions.  EPA’s regulations require that each manufacturer or importer of gasoline, diesel fuel or a fuel additive, register its product with EPA before “introducing the product into commerce.”  See generally, 40 CFR Part 79.  Since 1978, EPA has established a limit of ten volume percent ethanol (E10) for conventional (non flex-fuel) vehicles.  Growth Energy and fifty-four ethanol manufacturers submitted their E15 application on March 6, 2009.  After EPA’s Notice has been published in the Federal Register, stakeholders have 30 days to submit comments on the waiver application.  The Clean Air Act requires EPA to rule on the waiver application within 270 days of receipt, December 1, 2009.

There will almost certainly be comments submitted to EPA in opposition to the waiver request.  The National Petrochemical and Refiners Association, the American Lung Association, the Sierra Club, the Engine Manufacturers Association and other groups wrote former EPA Administrator Stephen Johnson on December 18, 2008, to oppose any increase in the 10% limit on ethanol in gasoline.  Among the concerns expressed, with respect to a higher blend, were potential machinery impacts, health and safety issues, emissions and compliance with the Clean Air Act.

EPA’s ruling on the waiver request could give an important signal on the direction the Obama Administration will take with respect to the ethanol industry.

For further information about this topic, please contact Akin Gump.

As noted in last Friday’s post, one of the technological gaps that must be filled to increase the percentage of energy supplied by renewable sources is the need for grid-level energy storage.  The 2007 Energy Independence and Security Act, combined with the 2009 American Reinvestment and Recovery Act (ARRA), makes billions of dollars available for development of new and improved energy storage systems.  This infusion of funding to promote grid reliability provides an important opportunity for the electric power industry to build energy storage into the national grid design.  As utilities, investors, and policymakers assess the best way to do so, however, they will be choosing among a broad suite of potential technologies looking to exploit that opportunity.  In a constantly changing technological environment, making the right choice will be no simple task.  Some of the major types of grid-level energy storage technologies currently in play include:

• Pumped Hydro Storage (PHS): PHS is the most mature and widely utilized energy storage technology in the world, with over 90GW of PHS in use worldwide. PHS generally consists of two reservoirs—an upper and lower—connected by a reversible turbine. During times of low demand, water is pumped from the lower reservoir to the upper; that flow is reversed during times of high demand. Because of the significant capital costs, long construction times, and highly site-specific nature of PHS, little additional construction of these facilities is expected, though using lagoons or other tidal resources to power PHS is an emerging field of research.
• Compressed Air Energy Storage (CAES): In a CAES system, off peak power is used to pump air into an underground storage formation, such as an abandoned mine or a salt cavern. That compressed air is used to turn gas turbines during peak power periods. CAES is the second most commercially mature technology after PHS; two plants—both with over 100MW of capacity—have been constructed, and a number of other projects are planned, including the Iowa Stored Energy Park (ISEP), which will use wind energy in concert with CAES, creating a 268MW/13,000MWh power plant, which will also provide 50 hours of energy storage.
• Thermal Energy Storage: Thermal storage is generally used in concert with concentrated solar power facilities, and involves the circulation of a heat-transfer fluid-generally molten salt, though other advanced fluids are under development-to produce steam during periods when the sun is unavailable to the plant. Examples include the thermal energy storage system storage systems constructed as part of the Solar Two Facility in Southern California, and the massive Andasol solar power plant in Southern Spain.
• Advanced Material Batteries: Advanced material batteries use materials like molten sodium or lithium to store energy. Currently, sodium-sulfur (NaS) and lithium-ion based batteries are the primary designs for these technologies. Currently, sodium-sulfur (NaS) batteries have more fully penetrated the market, as significant numbers have been installed in Japan (where the batteries are produced), including a 34MW battery-currently the largest in the world. Advances in lithium-ion batteries have mostly been directed towards applications in electric cars, but with recent advances in nanotechnology, these batteries are finding use at the utility scale as well.
• Flow batteries: Also known as redox flow-cell batteries or regenerative fuel cells, flow batteries store electricity through a reaction between two different electrolyte solutions. Because the capacity of these batteries is largely dependant on the volume of electrolytic liquid available, these batteries are highly scalable, giving them the potential to compete with bulk storage in terms of charge and capacity. Current battery designs exist around zinc-bromide, sodium-bromide/sodium polysulfide and vanadium solutions. Fewer flow batteries have been installed than the previously mentioned technologies—currently the largest in the U.S. is a 250kW/2MWh plant in Utah.
• Flywheel Energy Storage (FES): FES is another mechanical storage technology, where energy is stored in a rapidly spinning cylinder. When that outside source of energy is unavailable, the rotor for the flywheel acts as a generator. Flywheels are easily moved and have no environmentally reactive components , but have limited storage capacity and a short discharge period, limiting their applicability. The technology is just entering commercial viability: in September 2008, Beacon Power produced the first flywheel storage system for use on a utility scale.
• Superconducting Magnetic Energy Storage (SMES): SMES uses the magnetic field produced by cryogenically cooled superconductors to store energy. By utilizing superconductors, SMES maximizes efficiency (very little energy is lost in the storage process, and there is no conversion between the form the energy is stored in and its usable form—electricity). Like flywheels, however, an SMES system discharges its energy quite quickly, and therefore is useful mostly for short term applications.

The current diversity of storage technologies under active commercial development creates both an opportunity and a dilemma for policymakers and market participants.  The opportunity is that because each technology offers different technical, financial, and political pros and cons, project developers have a broad selection of alternatives to choose from in pinpointing the ideal storage technology to fit the technical, financial, and political constraints facing a project.  The dilemma, in turn, is that given the relative scarcity of long-term performance information for many of these emerging technologies, and the uncertainty regarding whether and when federal policymakers will provide future incentives similar to those provided in the ARRA, policymakers granting funds and the project developers and investors requesting funds will want to get it right the first time.

For further information about this topic, please contact Akin Gump.

EPA released today its annual national greenhouse gas inventory, identifying and quantifying the United States’ primary anthropogenic sources and sinks which finds that overall emissions during 2007 increased by 1.4 percent from 2006.  The report further indicates that overall emissions have grown by 17.2 percent from 1990 to 2007. The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007 is the most recent report the United States has submitted to the Secretariat of the United Nations Framework Convention on Climate Change.

EPA prepares the annual report in collaboration with other federal agencies and after opportunity for public comment.  The inventory tracks annual greenhouse gas emissions at the national level and presents historical emissions from 1990 to 2007.  The inventory also calculates carbon dioxide emissions that are removed from the atmosphere by “sinks,” (e.g., through the uptake of carbon by forests, vegetation and soils).

The carbon dioxide equivalent of the total emissions of the six main greenhouse gases in 2007 was 7,150 million metric tons CO₂ Eq.  EPA concludes that increases in carbon dioxide emissions associated with fuel and electricity consumption were the primary causes of the emissions increase in 2007.  EPA also concluded that the primary contributors to the increase in 2007 were: (1) increased demand for heating fuels and electricity due to cooler winter and warmer summer conditions in 2007 than in 2006; (2) increased consumption of fossil fuels to generate electricity and (3) a significant decrease (14.2 percent) in hydropower generation used to meet this demand.

Together with EPA’s proposed rule for mandatory greenhouse gas reporting, published in the Federal Register last Friday, EPA’s national inventory will help inform the deliberations in Congress over the shape of comprehensive climate change legislation.

For further information about this topic, please contact Akin Gump.

At both the federal and state level, expanding renewable energy generation has become a major focus of domestic energy, climate, and economic policy.  Today, twenty eight states and the District of Columbia have adopted some sort of Renewable Portfolio Standard (RPS).  President Obama has voiced his support for a national standard that would mandate a 25 percent share of renewable power by 2025 (up from 2.5 percent today, not counting hydroelectric generation), and that standard is included in a new energy bill introduced by  Congressman Ed Markey (D-MA) and 29 co-sponsors.  If the US is going to deliver on these pledges to increase renewable energy capacity and infrastructure, investments in generation technology will have to tackle an even greater challenge: electricity storage.

According to a report by the American Institute of Chemical Engineers, absent changes to the current electrical grid, pushing renewable energy’s share of the grid above 15% may be technically impractical.  Traditional sources of base-load power—coal and nuclear—provide continuous power to the grid and constantly adapt to changing power demands during each 24-hour period.  In times of increased demand, additional units can be brought online, or the plants can utilize their “spinning reserve”—literally spinning their turbines faster to produce extra power.  Solar and wind power on the other hand, do not have this capacity.  If the sun is not shining (or the wind is not blowing), there is no power flowing from those sources.

The intermittent nature of wind and solar sources means that increasing renewable power’s share of the power flowing into the grid will also increase the grid’s instability, complicating the moment-to-moment process of matching the supply of electricity to the demand.  Absent a technical fix for resolving momentary discrepancies between grid supply and demand, the resulting overloads can lead to rolling or even involuntary blackouts.

One way to address renewable energy’s intermittency problem is through advanced energy storage technologies that can store electricity and release it at periods of high demand (or inconsistent supply), smoothing the peaks and troughs of the energy equation.  While large-scale energy storage is still an emerging technology, a number of companies have already taken steps to commercialize various storage technologies.  For instance:

• In 2006, American Electric Power installed the first large-scale advanced battery, with a 1.2-MW capacity, in West Virginia;
• In the spring of 2008, Xcel energy installed a 1-MW battery at a wind farm in Minnesota;
• In Fall 2008, Altair nanotechnologies, in partnership with AES Solar, announced that their 1-MW lithium-titanate battery had met standards for commercial use in the PJM Regional Transmission Organization, the first lithium battery to do so; (Both AEP and Xcel Energy have batteries based on Sodium-Sulfur technology.) and,
• In November 2008, AES Storage LLC installed a 2-MW battery at an AES facility in in Southern California.

Federal policymakers have also recognized the importance of developing energy storage solutions.  The 2007 Energy Independence and Security Act included a title on “Energy Storage Competitiveness” which authorized the spending of nearly $300 million in each of the next ten years on advanced energy storage technologies. The 2009 American Recovery and Reinvestment Act also included significant funding for advanced batteries, and appropriated another $4.5 billion for the Department of Energy’s (DOE) Office of Electricity Delivery and Energy Reliability for grid modernization efforts, including energy storage. Energy storage companies are already pursing those funds, and the DOE, through Sandia National Laboratories, has established partnership programs focused on advancing battery technology.

Investing in giant batteries, fuel cells, and other advanced energy storage systems designed for the power grid may not draw the same popular attention as is lavished on developments in advanced electric cars, but if the U.S. is to embrace renewable energy in a meaningful way—and meet the mandates it has set for itself—developing the country’s energy storage infrastructure is a must.

For further information about this topic, please contact Akin Gump.

Broadly speaking, biofuel refers to any solid, liquid or gas fuel that has been derived from biomass. It can be produced from any carbon source that is easy to replenish—such as plants.  One of the main challenges when producing biofuel is to develop energy that can be used specifically in liquid fuels for transportation. The most common strategies used to achieve this are to grow plants that naturally produce oils, grow sugar crops or starch that can be fermented into ethanol, or converting “wood” products. 

Over the past year, significant controversies have developed over biofuels related to the extent to which biofuels actually result in reduced carbon emissions, which led to efforts to make “life cycle analyses” to determine the net carbon footprint of biofuels.  Spot food shortages in 2008 led to calls for analyzing whether increased biofuels production leads to food shortages.  In a multi-installment series, ClimateIntel will analyze several issues related to biofuels and the legal and regulatory challenges biofuels face.

The American Recovery and Reinvestment Act of 2009, the Stimulus Bill, includes significant funding and related incentives for development of second generation biofuels.  Earlier this year, the U.S. Departments of Energy and Agriculture  announced a joint funding opportunity pursuant to which $25 million would be awarded to fund biomass research and development.  The funding is directed to researching second generation biofuels, specifically the three technical areas specified in the Food, Conservation, and Energy Act of 2008:

1. “feedstocks development;”
2. “biofuels and biobased products development;” and
3. “biofuels development analysis.” 

Secretary of Energy Steven Chu noted that the biofuels industry should “focus[] on the next generation of biofuels.”  Despite the attention paid to second generation biofuels, however, first generation biofuels still figure prominently and are the only commercially available form of biofuels. 

Recently, the International Energy Agency produced a report comparing first and second generation biofuels.  First generation biofuels are mainly produced from agricultural crops used for food and animal feed, with the two most common sources being sugar cane and maize (corn).  The first generation biofuels market is relatively mature, particularly in the United States, Brazil, and Europe.  Of the three major forms of fuels currently produced, bioethanol, biodiesel, and biomethane, the market is largest for the liquid fuels bioethanol and biodiesel. 

Currently 80% of the world’s ethanol production is derived from sugar cane and corn, based on well-established conversion technologies.  Starch, the raw material from corn and other feedstocks, must first be converted to glucose through a hydrolysis process before ethanol may be produced.  Once the glucose is formed, it goes through a fermentation process during which it is metabolized by yeast cells.  Ethanol is then produced by distilling the product of the fermentation processes.  Sucrose is the raw material from sugar cane, and undergoes the same fermentation and distillation processes as glucose to form ethanol.  The difference is that pressed sugar cane yields sucrose, so it does not have to undergo the hydrolysis step required of starch. 

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