Wisconsin Power & Light Offers Emission-Saving Goodies to Make New Coal Plant Proposal Palatable

In an effort to counter opponents of its proposal to expand an existing coal-fired generating station by 300 MW, Wisconsin Power & Light (WP&L) has offered to take several steps to offset the increased greenhouse-gas emissions that would result from the expanded plant's operation.  In a draft environmental impact statement, the Wisconsin Public Service Commission criticized WP&L's proposed use of a circulating, fluidized bed (CFB) boiler, which results in higher CO₂ emission.  In response, rather than abandon CFB, WP&L has offered to retire the oldest coal-fired plant in its fleet, develop an additional 200 MW of wind power above the 300 MW it has already pledged to develop in the next several years, increase the amount of biomass co-firing planned for the new unit, and increase energy efficiency and conservation efforts.  WP&L's estimated cost for these proposed efforts are $500-$550 million. 

Michigan Legislators Consider State RPS, Rolling Back Electric Choice

The Michigan Legislature currently is considering legislation that would enact a renewable portfolio standard (RPS) and that would limit electric choice in the state.  At issue are three bills that have been passed by the state's House of Representatives and are now under Senate consideration. 

House Bills 5548 and 5549 would require the state's utilities to obtain at least 10% of their power from renewable energy resources by 2015.  These bills, however, do not currently propose to allow competitive bidding for renewable resources.  Senate Republicans have indicated they will seek to amend the legislation to require competitive bidding when the Senate takes up the measures. 

H.B. 5524 proposes to impose a 10% hard cap on participation in electric choice programs.  Opponents of the measure say it would effectively end electric choice in the state.  The state's largest utilities, Detroit Edison and Consumers Energy, have supported the bill, asserting that electric choice has limited their ability to secure financing for new power plants and to implement energy efficiency and renewable energy programs.

The Senate Energy Policy and Public Utilities Committee passed all three bills last week, by identical votes of 5-3.  The bills will now come before the full Senate, although it is unclear when they are slated to do so.

San Francisco to Fund Nation's Largest Municipal Solar Program

The City and County of San Francisco Board of Supervisors on June 10, 2008, approved a program that will create a fund to provide rebates for residents and businesses that install solar power systems. Under the Solar Energy Incentive Program, the nation's largest municipal solar program, residents could receive between $3,000 and $6,000 for photovoltaic systems. Businesses could receive $1,500 per kilowatt installed, with a cap of $10,000 per building. The 10-year program will use up to $50 million from the city's energy-conservation account. The Board of Supervisors also voted to approve a complimentary one-year pilot program that would budget $1.5 million to buildings owned and operated by low-income residents and non-profit organizations.

The Solar Energy Incentive Program would supplement incentives from the federal investment tax credit and the California Solar Initiative. Creation of the program is propitious since the federal investment tax credit is set to expire at the end of this year.

Supervisor Dufty, a co-sponsor of the measure, believes that the program will provide an important opportunity to encourage the development of the solar industry in San Francisco. The incentives provided by the program will help with installation costs, which are more expensive in San Francisco than in surrounding counties. The program also seeks to help San Francisco increase its amount of solar generation. Currently, the city ranks last in the Bay Area in terms of the solar energy installed per capita, according to data compiled by the California Energy Commission and the California Public Utilities Commission.

Bonneville Holding Transmission Open Season to Speed Interconnections

Transmission providers and customers alike are increasingly complaining about the lengthy queues for interconnecting to the transmission grid.  Scores of generator projects sign up for interconnection service, which is then delayed for years while the transmission provider conducts an array of studies.  To clear backlog on its transmission network, the Bonneville Power Administration is conducting a Network Open Season for transmission service that asks customers to commit to the transmission service they are seeking. 

At present BPA’s transmission queue includes requests by 25 customers for approximately 180 applications for transmission service totaling about 8,500 MW of new capacity, but BPA states that many of these service requests are speculative.  Under its new procedure, BPA will give all customers applying for transmission service by May 15, 2008, a precedent service agreement.  If a customer signs the binding agreement and remits the required financial security by June 16, 2008, BPA commits to providing the service, so long as it can provide the service at its rolled-in rate and complete its environmental study obligations.  BPA also will assume the study costs itself and arrange financing for any required transmission facilities, instead of requiring customers to front these costs.  However, if a customer declines the offer, BPA will withdraw its service requests from the transmission request queue, while allowing the customer to participate in future Network Open Seasons.

In December 2007, the Federal Energy Regulatory Commission held a technical conference focusing on transmission queue logjams.  The interconnection queue process is governed by Order No. 2003, which standardized the agreements and procedures related to the interconnection of large generating facilities based on a first-come, first-served process.  However, the surge of new generation projects, including many based on wind and other forms of renewable energy, have led to long interconnection queues that transmission providers are now debating how to expedite. 

ERCOT blames inaccurate wind predictions for February emergency event

The Electric Reliability Council of Texas (ERCOT) recently released its Operations Report to explain why it was forced to cut electric supply to interruptible customers on February 26, 2008. The emergency event was caused largely by the convergence of the normal rapid load growth that occurs around 6:00 p.m. and a simultaneous unexpected and sudden drop in wind that decreased the power output from windfarms.

ERCOT was primarily relying on day-ahead schedules to judge wind capacity, which predicted 1294 MW. However, only 335 MW were actually available during the relevant hour. To address this problem, ERCOT stated it would try to adopt in the near term the generation forecasting model it will use when the market transfers to a nodal operating system in 2009, since that model creates more accurate short term planning values for wind generation.

Managing reliable integration of wind generation is a high priority for ERCOT, since Texas is now the state with the largest wind energy production in the United States and has almost 3000 MW of additional wind development with signed interconnection agreements waiting to come online.

Maryland Energy Administration Calls for Efficiency and More Local Generation

The Maryland Energy Administration (MEA) released its Strategic Electricity Plan on January 14 in an effort to help customers lower their energy bills.  The plan, focused on conservation, efficiency and local new generation, also came in response to Maryland Governor Martin O'Malley's recent warning that the state could face serious power shortages in the near future.

The plan aims to reduce both electricity consumption and peak demand by 15% by the year 2015 and require the state's utilities to implement performance-based programs to help meet these goals.  The MEA predicts that if these goals are met, electricity consumption in the state would fall by 25 billion kilowatt-hours and consumer charges fall by over $2 billion in 2015 and by over $4 billion in 2020.

The plan comprises four central elements.  First, financing would come from a Strategic Energy Investment Fund of revenues earned from the state's sale of carbon allowances as part of Maryland's participation in the Regional Greenhouse Gas Initiative (RGGI), a 10-state initiative that aims to reduce greenhouse gases.  Second, the plan would implement energy efficiency programs, including incentives and rebates for consumers to purchase efficient appliances and have home energy audits, as well as installing interruptible load (cycling) devices on their air conditioners.  Third, the plan calls for increased investment in new generation within the state, particularly investment in sources of renewable energy, including by improving grant programs for the development of solar and geothermal energy, encouraging long-term contracts for new generation, and evaluating the need to require utilities to build or purchase new generating capacity to meet peak summertime demand.  Finally, the MEA asks for additional resources to help it produce biennial state energy plans, encourage regional transmission planning, and stimulate clean energy within Maryland.

Maryland retail customers have in recent years faced significant increases in their electric bills, following the expiration of retail rate freezes on the state's utilities.  Moreover, Governor O'Malley has predicted that by 2011 the state will face electricity shortages during peak periods.

Federal Trade Commission Examines Green Marketing and Carbon Offset Markets

With increased concern about climate change, but limited government action, voluntary carbon markets have bloomed in recent years.  The Federal Trade Commission (FTC), which regulates advertising claims, is now taking a closer look at these new carbon offset markets to gauge how the money they attract is being invested.  The FTC held a workshop in early January and is considering revising its environmental marketing guides to address sales of carbon offsets markets as well as renewable energy credits (RECs). 

Carbon offsets are credits that correlate to quantifiable reductions in greenhouse gas credits.  Purchasers of carbon offsets can claim that their carbon-emitting activity, such as travel, is offset by unrelated beneficial measures.  Common examples include tree planting or forest preservation, as well as investment in generation of energy from low-carbon-emissions sources.  Carbon offsets are typically measured in volumes of carbon.  RECs are quantifications of energy produced with renewable means, and are measured in megawatt-hours.  Voluntary REC markets allow buyers to purchase RECs to support renewable energy development.  State renewable portfolio standards also rely on RECs to quantify utilities’ mandatory procurement of renewable energy. 

The concern related to carbon offsets and RECs is whether the funds from voluntary sales are being used in legitimate or constructive ways.  Concerns have been voiced over issues such as whether eligible projects might oversell credits, or, even if not, whether the money paid goes to existing projects or projects that would have happened anyway.  For example, if an existing, operating windfarm that was built without any sales of RECs or carbon offsets subsequently obtains additional funds from such sales, there is arguably no additional environmental benefit obtained from these REC or carbon offset sales.

The FTC is inviting comments on carbon offset guidelines until January 25 and on environmental marketing guidelines until February 11, and will subsequently decide how and if to revise the marketing guides. 

Incentive Rates to Support Transmission from Midwest Wind Projects

The Federal Energy Regulatory Commission (FERC) granted Xcel Energy Services, Inc.’s request for incentive transmission rates as part of Xcel’s plan for a $1 billion upgrade of its transmission grid inside the territory of the Midwest Independent Transmission System Operator (Midwest ISO).  The upgrades will help Xcel’s utilities meet state renewable electricity standards and serve increased power demand in the Upper Midwest.

Reflecting concerns that the Nation's transmission grid was not being adequately maintained and expanded, the Energy Policy Act of 2005 directed FERC to develop incentive-based rate provisions for transmission projects.  FERC did so in a later rulemaking, establishing numerous rates incentives comprising cost recovery, accelerated depreciation, and higher rates of return on equity for assets operated by ISOs/RTOs.  Utilities can establish eligibility for these incentives by demonstrating a relationship between the incentive sought and the transmission investments being made.   

Xcel proposed changes to its transmission rate formula under the Midwest ISO tariff to avail itself of two of the incentive rates.  FERC approved the proposal, which will grant Xcel (1) recovery of return on 100% of prudently incurred construction work in progress and (2) recovery of prudently incurred costs of transmission facilities that are canceled or abandoned for reasons beyond the control of Excel and its parent, the NSP companies.  FERC stated that the transmission upgrades will help bring renewable energy projects on-line, in compliance with various state renewable energy procurement requirements.  Xcel Energy has stated that it is seeking to build transmission to accommodate between 300 and 700 MWs of wind power.

First Hydrokinetic Energy Project Conditionally Approved

On December 21, the Finavera Renewables Ocean Energy, Ltd conditionally secured a FERC license for its hydrokinetic power project located 1.9 nautical miles offshore Washington State.  The 5-year license to the Makah Bay Offshore Wave Pilot Project is designed "to demonstrate the economic and environmental benefits of wave energy conversion power plants near coastal communities."   The project will generate an average of 1,500 MWh annually.

The innovative technology is powered by a closed-loop hydraulic system inside four (4) 19.5 feet x 16.4 feet buoys filled with 1,850 gallons of fresh water.  An acceleration tube converts a wave's kinetic energy into pressurized water through a piston system that lowers and stretches with each wave motion, thereby pressurizing water to the nozzles of a turbine housed near the top of a buoy.  A 3.7 mile submarine transmission cable anchored to the ocean floor will lead to an onshore connection to the utility grid.  

FERC Commissioner Moeller lauded the license since “[c]onsumers are demanding more renewable energy options, especially those sources that are domestic, renewable, and carbon-free."  Commission Moeller added that "it demonstrates this Commission’s proactive approach to enable the development of this and other sources of hydropower.” 

The license is conditioned on, among other things, Finavera's written notification to FERC that all other authorizations have been obtained as required under federal law.  This condition is consistent with the agency’s November 2007 Policy Statement on Conditioned Licenses for Hydrokinetic Projects in which FERC enumerated its policy of conditioning licenses to hydrokinetic projects “on the licensee being precluded from commencing construction until the necessary authorizations are received."

Finavera filed its application on November 8, 2006, and construction must be completed within three years from the effective date of the license.

EPA Rulemaking Will Provide Guidelines for Underground CO2 Storage

The Environmental Protection Agency has announced it is preparing a rulemaking to develop guidelines for permanent underground storage of carbon dioxide.  Underground sequestration of carbon may be a valuable tool for combating climate change, as it complements usage of fossil fuels such as coal that are widely available but also relatively high in carbon content.  The potential success of carbon sequestration and storage, however, depends on resolution of numerous technological challenges, including means for separating out the carbon from fossil fuels and transporting it to and storing it in secure underground locations.

The EPA will evaluate the potential impact of underground carbon storage on health, safety and the environment, including underground sources of drinking water.  The agency stated that rules are needed to determine what parties have responsibility and liability for storage of carbon dioxide.  The EPA’s timeline is unlikely to provide much near-term guidance, as its proposed rules would appear in mid-2008 and final rules not until 2010 or later.  The proposed rules will not address the high-profile issue of who would get credit for any reductions in carbon emissions related to reduced emissions or underground storage of CO2. 

Energy Expands Loan Guarantee Program, Picks 16 Pre-Applications for Further Analysis

Initiatives Provide Transmission for Renewable Power

The California Energy Commission has initiated a Renewable Energy Transmission Initiative (RETI) to identify transmission projects needed to help the state meet its renewable energy development goals.  In a process similar to that already adopted in Texas, the RETI process entails identifying Competitive Renewable Energy Zones (CREZs) from which renewable energy could be brought to California consumers.  Not surprisingly for the power-importing state, CREZs could be outside as well as inside California, although designation of external CREZs to serve California may not be well received in neighboring states.

The RETI process should complement the California Independent System Operator’s (CAISO) development of transmission financing rules.  The CAISO’s FERC-approved trunkline proposal provides for sharing of costs between interconnecting renewable generators, together with subsidies from other transmission customers.  The CAISO is now working on a tariff proposal for the inelegantly named “Location Constrained Resource Interconnection” rules, and is expected to submit the proposal to FERC by the end of October. 

On the national stage, Senator Harry Reid, the Majority Leader from Nevada, has introduced a bill to promote renewable energy development.  The bill, S.2076, would require establishment of renewable energy zones and direct federal power administrations to identify the transmission needed to access renewable energy in the zones.  The prospects of the bill becoming law are uncertain.  At minimum, however, the bill signals increased awareness by senior policymakers of the need to foster transmission development to connect the nation’s vast renewable energy potential with the load centers in need of energy. 

North Carolina Brings Southeast to RPS Table; Illinois & Delaware Expand RPS Laws

Various states around the country have recently created or expanded their renewable portfolio standard (RPS) requirements.  The combination of traditional RPS requirements with complimentary initiatives, including cost recovery incentives, energy efficiency directives and voluntary green power programs, characterize these recent additions to the nation's RPS goals.

With its recent enactment of a Renewable Energy and Energy Efficiency Portfolio Standard (REPS), North Carolina has become the first southeastern state to join the ranks of RPS states.  The REPS will be phased in beginning in 2012; it requires that by 2021 all investor-owned utilities within the state meet 12.5% of their 2020 energy needs from renewable energy resources or energy efficiency measures.  A reduced requirement of 10% applies to rural electric cooperatives and municipal electric suppliers.  Until 2018, up to 25% of the requirement may be met through energy efficiency efforts, including combined heat-and-power systems powered by non-renewable fuels.  After 2018, 40% of the standard may be met by energy efficiency strategies.  Other noteworthy facets of the new law are its provisions (1) permitting utilities to recover certain incremental costs incurred to comply with the REPS, to fund renewable energy or energy efficiency research, or comply with any future federal RPS mandate, (2) requiring electric power suppliers to implement demand-side management and energy efficiency measures and providing for cover recovery for those measures, and (3) extending rate recovery to construct costs associated with out-of-state generating facilities.   

Building on its previous voluntary renewable portfolio goal of 8% by 2013, Illinois recently enacted a new law that creates the Illinois Power Agency (IPA) and charges it with developing electricity procurement plans for state utilities serving over 100,000 customers and then competitively procuring energy according to those plans.  The IPA's procurement activities must also meet an expanded and now-mandatory RPS of 25% by 2025, beginning in 2008 with a 2% requirement.  A minimum of 75% of the renewable energy must be produced from wind.  The new law also requires that utilities establish annual energy savings goals in order to meet a percentage of their energy delivery requirements through efficiency efforts. 

CPUC to Consider Innovative Energy Efficiency Incentives for State's IOUs

The California Public Utilities Commission (CPUC) will soon consider an innovative incentive program to encourage the state's investor-owned utilities (IOU) to meet energy savings goals.  Based on an August 9 proposed decision by CPUC Commissioner Dian Gruenich and Administrative Law Judge Meg Gottstein, the proposal would pay the IOUs -- include Pacific Gas & Electric Co., San Diego Gas & Electric Co., Southern California Edison Co., and Southern California Gas Co. -- up to $323 million over three years if they exceed the base targets.  If utilities satisfy these goals, the plan would purportedly save California ratepayers $2.4 billion and cut about 3.4 million tons of carbon dioxide emissions in 2008.  Conversely, if the utilities fail to meet the base targets, the plan would impose monetary penalties on them.  The proposal caps both potential earnings and losses for shareholders at $500 million.

Commissioner Gruenich, the plan's chief proponent, argued that the proposal would provide "both a meaningful level of shareholder earnings and an estimated return of over 100 percent on ratepayers' investments in energy efficiency as the utilities reach toward and exceed our 2006-2008 energy savings goals."  The proposed decision is on the CPUC's agenda for its September 20 meeting.

Western Climate Initiative Seeks 15 Percent Reduction in Greenhouse Gas Emissions

Achieving one of the goals set for itself at its inception, the Western Climate Initiative (WCI) has pledged to reduce aggregate regional greenhouse gas emissions to 15 percent below 2005 levels by 2020.   

Initially composed of Washington, Oregon, Arizona, New Mexico and California, the WCI was established in February 2007 with the goal of collaborating on climate action initiatives across the Western U.S., Canada and Mexico.  Since that time, Utah and the Canadian provinces of British Columbia and Manitoba have joined.  Several other states and provinces have signed on as "observers" to the WCI, including Sonora, Mexico; Wyoming; Colorado; Kansas; Nevada; and Ontario and Quebec, Canada. 

According to the Statement of Regional Goal that WCI issued last week, the regional 15 percent goal reflects the cumulative emission reduction goals of the "partner" states and provinces, and does not replace those partners' existing reduction goals, some of which — such as California's — are more aggressive than the WCI goal.   

House Passes Energy Bill with 15% RPS Requirement, Other Clean Energy Initiatives; House and Senate Must Now Reconcile Vastly Different Legislation

On the heels of a Senate bill passed in June, the House of Representatives on August 4 passed a comprehensive energy bill by a vote of 241 to 172.  The House bill is drastically different from the Senate's energy legislation, and it appears the House and Senate face an arduous conference to reconcile the two versions, which contain drastically different approaches to energy policy.

In summary, the House bill:

• Incorporates a 15% renewable portfolio standard (RPS), requiring utilities to produce at least 15% of their electricity through the use of renewable energy resources (e.g., wind or solar power) by 2020;
• Sets a goal of eliminating greenhouse gas emissions by federal agencies by 2050;
• Establishes new efficiency standards for appliances, lighting and buildings, while promoting new technologies for transmitting and delivering energy to create a "smart grid;"
• Authorizes billions of dollars for research into sustainable energy sources and alternative fuels, including research into carbon dioxide sequestration efforts;
• Resolves the sticky issue of numerous "faulty" leases in the Gulf of Mexico that arose when the Department of the Interior erroneously executed leases with several oil and gas companies that provided the companies with excessive royalties, by requiring the oil and gas companies to either renegotiate the leases or pay a conservation fee before bidding on future leases; and
• Promotes international energy-efficiency standards and U.S. involvement in other international partnerships to address energy issues and climate change.

The House also passed a companion package of changes to the tax code, by a vote of 221-189.  The tax bill offers various incentives to encourage the use and production of renewable energy and energy conservation, including new tax credit bonds to encourage energy efficiency in residential property and more production of clean energy, and $3.6 billion in bonds for state and local governments to fund energy conservation efforts.  The bill pays for these tax incentives by repealing approximately $16 billion worth of tax breaks for oil and gas companies.

There are several notable absences in the House's bill.  For instance, the bill does not revoke or condition the backup transmission siting authority given to FERC in 2005's Energy Policy Act in so-called "national interest electric transmission corridors," a provision that has raised significant concern in states with controversial transmission projects, like New York and Virginia. Similarly, the House bill does not set new corporate average fuel economy (CAFE) standards for cars and trucks, nor does it provide any support for coal-to-liquid production, both of which were contained in the Senate's energy bill.

It may prove a substantial battle to reconcile the House's and Senate's legislation.  While both bills included some of the same provisions, including requirements for research and development of carbon sequestration, biomass resources, and cellulosic ethanol and biodiesel, the two versions appear to be quite far apart on several major policy issues.  Key differences include:

• the House's inclusion of an RPS, which the Senate bill did not contain;
• the House bill's expanded energy efficiency provisions, which are more expansive than the Senate's version, which only included new standards for appliances and lighting;
• the House tax bill's rescission of approximately $16 billion in tax breaks for oil and gas companies, which the Senate bill does not contain;
• the Senate's inclusion of increased CAFE standards, requiring 35 mpg by 2020 for cars, SUVs, and small trucks, which the House bill omitted;
• the Senate bill's ethanol mandates, which require that the use of ethanol increase by sevenfold by 2022 and that 85% of cars manufactured by 2015 be capable of running on E-85 fuel (a blend of 85% ethanol and 15% gasoline); the House's bill did not contain such ethanol provisions; and
• the Senate bill's provision making it unlawful to charge an "unconscionably excessive price for oil products, including gasoline, which the House bill does not include.

The House and Senate will likely convene a conference committee this fall to attempt to iron out these differences.  Even if able to come to a compromise, White House approval is not assured.  Shortly after the passage of the House bill, the White House indicated its opposition to many of the bill's major provisions, stating that it would not "deliver American consumers or businesses more energy security, but rather would lead to less domestic oil and gas production, higher energy costs, and higher taxes." 

States Pursue Cleaner, Sustainable Energy, but not Too Quickly

While climate change legislative proposals and potential energy legislation continue  to muddle in the halls of Congress, individual states keep on creating their own requirements for checking green-house gas emissions and requiring greater use of renewable energy within their borders.  Whether this will lead to a mosaic of disparate standards and obligations or eventual standardization across state lines remains to be seen.

Despite relatively limited renewable energy production potential and a sharply growing population in Florida, Governor Charlie Crist (R) recently issued several executive orders intended to reduce greenhouse gas emissions and increase renewable energy use.  The orders direct the state’s public service commission to initiate a rulemaking intended to achieve a renewable portfolio standard (RPS) of 20%; call for capping utility greenhouse gas emissions at their 2000 level by 2017, reducing them to their 1990 level by 2025, and to 20% of their 1990 level by 2050; and implement other measures such as new interconnection standards, net metering, and requiring state agencies to take additional energy efficiency measures.

Hawaii already has an RPS, and its legislature recently added climate change legislation.  Its objective is to reduce the level of greenhouse gas emissions in the state to 1990 levels by 2020.  New Jersey – a densely populous state with limited renewable energy production – also added climate change legislation to its existing RPS requirements.  Under the new law, greenhouse gas emissions would be reduced approximately 15% below 1990 levels by 2020 and 80 percent by 2050. 

California and Washington already have both an RPS and climate change legislation.  While the mandates of all these states vary, they all push far into the future – 2050 – the most severe level of cuts, a move that may be reflect the technological challenges, but also resonates like a promise to start a diet tomorrow, or later. 

DOE's Loan Guarantee Proposal Penny-Wise and Pound-Foolish, Say Commentators

On May 16, the Department of Energy (DOE) published its Notice of Proposed Rulemaking (NOPR) regarding loan guarantees for projects that would employ renewable energy systems, advanced nuclear facilities, and carbon sequestration units, among other innovative technologies.  In comments on the NOPR, lending and rating institutions slammed the proposal.

The Energy Policy Act of 2005 (EPAct 2005) authorizes DOE to guarantee loans "not to exceed an amount equal to 80 percent of the project cost of the facility."  In the  NOPR, however, DOE proposed to guarantee up to only 90 percent of a particular loan rather than 100% of a loan covering 80% of project cost.  DOE's proposal also prohibited selling off or "stripping" the guaranteed portion of the debt instrument because DOE wishes (1) to preclude the guaranteed portion of the loan from being sold and (2) to ensure that the lender and later debt holders maintain the same level of financial risk in the project as when the debt was issued in order to spur continued due diligence.

Credit Suisse, Lehman Brothers, Goldman Sachs, Merrill Lynch, Morgan Stanley, and Citigroup expressed concern that the proposed rule "is not workable" because it relegates 10 percent of project debt to an un-guaranteed, deeply subordinated tranche, and, by barring stripping, prevents marketability of the debt instrument.  The "hybrid instrument" created by the NOPR, they explained, has no natural market, and "the higher costs associated with financing [it] would deter sponsors from moving forward . . . [or] increase the risk of default."  Goldman Sachs also submitted very similar comments separately.

Standard & Poor's echoed concerns over the 90 percent guarantee limit and prohibition against stripping.  S&P cautioned that the "rating associated with a partially guaranteed obligation will be substantially lower than the 'AAA' rating of a fully guaranteed instrument" and will result in "a significantly higher cost of debt for the project than if it was fully guaranteed."  A 100 percent debt guarantee and/or removal of the no stripping requirement would lower the cost of debt and is likely essential to "the early commercial use of innovative technologies."

Banc of America Securities, LLC concluded that EPAct itself made clear that 100 percent of the loan is to be backed by the full faith and credit of the United States and the NOPR's proposal is consequently inconsistent with the statute.   The Electric Power Supply Association echoed this congressional intent argument when it urged DOE to guarantee 80 percent of the total project cost and up to 100 percent of the amount borrowed.  The Public Service Commission of Florida agreed, adding that the loan guarantee program "was intended to support the deployment of new technologies that reduce, avoid or sequester greenhouse gas emissions by providing a [100 percent] guarantee for up to 80 percent of project costs," not 90 percent of 80 percent of project costs.

Missouri Legislature Dips Toe into Renewable Standards Pond

In late June the Governor of Missouri signed S.B. 54 that calls upon utilities to supply 11% of their retail load from renewable energy sources by 2020.  While Missouri's standards are a far cry from the ambitious efforts of states such as California (requiring 20% by 2010), New Mexico and Hawaii (requiring 20% by 2020), and Minnesota (requiring 25% by 2025), Missouri is well ahead of many others in the nation by establishing any goals at all for using renewables.

Missouri state lawmakers elected to set benchmark targets for public utilities to meet (4% by 2012; 8% by 2015; and 11% by 2020) and directed the Public Service Commission to develop standards for measuring electric companies' progress in meeting the targets.  The bill credits utilities for such diverse renewable technologies as yard waste in municipal landfills converted to methane gas, plasma arc technology, and other more traditional renewables such as wind and solar generation.  In addition, the bill requires retail electric suppliers to make net metering available to customers who have their own electric generation units powered by renewable energy resources.

While Missouri should be commended for recognizing the potential for renewables development in the region, the bill's benchmarks are modest.  Other states' renewable portfolio standards typically credit primarily new generation, but Missouri's new law credits all pre-existing renewable generation that remains in use.  In addition, the bill takes into consideration a utility's "good faith efforts" to meet the goals and will take into account that the utility is not financially harmed by those efforts.

Transmission Needed to Connect Burgeoning Renewable Generation

According to the Outlook of Renewable Energy in America report of the American Council on Renewable Energy, the United States by 2025 could have 248 GW of wind power and 100 GW of geothermal energy, in addition to 287 GW of other renewable energy, power and fuels.  "Renewable energy will not be a 'niche' source of America's energy in 2025," according to Robert Detchon, executive director of the Energy Future Coalition.  States such as Texas, Wyoming, New Mexico, and Colorado, where much of the increased wind generation is anticipated, and Nevada, California and Oregon, where much of the increased geothermal generation is anticipated, will likely require more transmission to deliver the renewable power to markets where it is needed. 

Utilities and governments in Europe, China and the United States could spend up to $150 billion on wind projects over the next five years, and the United States alone could invest $67.5 billion by 2015 to produce an anticipated total of 45,000 MW of wind capacity by that year.  According to a May survey conducted by the Geothermal Energy Association, up to 2,455 MW of new geothermal power plant capacity is currently under development in the United States, with 251 MW of capacity currently under construction.  Investment giant Merrill Lynch Commodity Partners recently closed on a $35 million deal with geothermal power developer Vulcan Power in order to finance the development of properties in California, Nevada and Oregon.  Calpine recently announced its intention to boost output at its Geysers geothermal facility in California to approximately 800 MW, and Nevada Power signed a 20-year power purchase agreement with Ormat Technologies for up to 30 MW from Ormat's proposed geothermal project development in northern Nevada. 

The world’s largest wind farm, located south of Abilene, Texas (population 115,000) already enjoyed access to sufficient transmission infrastructure necessary to bring the generation to a nearby market.  But for much future renewable energy development new transmission will be needed since renewable energy resources tend to be remote from load centers.

Several states, including Texas, California, Minnesota and Colorado are using a "zone" approach to transmission planning in order to incorporate renewable energy.  Driven by renewable portfolio standards in many states, the zone approach requires utilities to identify areas of renewable resources, plan the transmission capacity needed to reach those areas, and lobby state regulators to allow recovery of the investment in the required transmission.  Some believe that a federal initiative of this ilk would be necessary in order to tap the nation's vast renewable resources across the country.

D.C. Circuit Strikes Down Rule Favorable to Waste-to-Energy Facilities

Dealing a blow to the waste-to-energy industry, a U.S. Appeals Court recently vacated a rule promulgated in 2004 by the Environmental Protection Agency (EPA) that implemented limits on emissions of hazardous air pollutants (HAP) from certain commercial and industrial boilers (the CISWI Rule). 

In 2005, a number of environmental organizations challenged the rule.  At particular issue was EPA's regulatory definition of "commercial and or industrial waste."  In short, EPA's definition limited solid waste incinerators, as a class, to those facilities (1) that operated without energy recovery or (2) whose design did not provide for energy recovery.  This interpretation effectively exempted waste-to-energy facilities from the HAP limitations contained within Section 129 of the Clean Air Act and allowed waste-to-energy facilities to be regulated by Section 112 of the Clean Air Act.  This distinction is significant because, among other things, the standards in Section 112 only apply to "major" sources of HAP emissions whereas Section 129 applies to all sources of HAP emissions. 

Oregon's RPS Will Apply Broadly but with Large Gaps

Oregon became the last state along the west coast of the continental U.S. to enact a renewable portfolio standard (RPS) law.  It will require all retail providers in the state to obtain a certain percentage of their energy from renewable sources – up to 25% for the largest utilities – but the law also has numerous exceptions for cost and other factors. 

Under the RPS, utilities with at least 3% of Oregon's total retail electric sales must procure 5% of their energy from renewable resources by 2011, followed by 15% by 2015, 20% by 2020, and 25% by 2025.  Smaller utilities (1½ to 3% of all sales) must achieve 10% renewable energy procurement by 2025, with no interim targets.  The smallest utilities (less than 1½% of all sales) would need to procure only 5% of their power from renewables by 2025, with no interim targets.  Retail marketers would abide by the procurement levels of the utilities in the ESS' individual customer areas.  The law does not make clear whether existing renewable energy purchases count towards RPS compliance.

For sales under the RPS, generators that became operational on or after January 1, 1995 are eligible if they use hydropower (outside certain protected areas), wind, solar, wave, tidal, ocean thermal, geothermal, or a wide range of biomass except for trash or wood that is treated with chemical preservatives.  Older generators are eligible to the extent of capacity or efficiency upgrades or if they have been certified as low-impact hydro facilities.  Any renewable energy sold by the Bonneville Power Administration also qualifies under the law.  Eligible generators must be located in the U.S. portion of the Western Electricity Coordinating Council (WECC), but generators in the Canadian or Mexican portion of WECC can sell unbundled renewable energy credits (REC).

There are a number of exceptions in the law.  A utility is excused from the RPS to the extent that its compliance would cause it to:  spend more than 4% of its revenue requirement, as determined by the Oregon PUC on complying with the RPS; displace a consumer-owned utility's purchases of firm Federal Base System preference power rights from BPA; force a utility to purchase power beyond its needs in a given year; cause displacement of a utility's use of a non-fossil fueled resource; displace low-price hydropower from power contracts with Mid-Columbia River dams until those contracts could not be renewed or replaced.  In addition, a utility can make alternative compliance payments instead of procuring renewable energy.

The relative complexity, delayed implementation and numerous exceptions in the Oregon law may support arguments in favor of a national RPS with uniform standards rather than a patchwork of state laws that may fragment the renewable energy market.

UPDATE: Senator Harry Reid Proposes Consolidated Energy Package, Energy Efficiency Promotion Act Incorporated

Senate Committees Take Up Energy Efficiency Standards and Clean Energy Investment Incentives

Two bipartisan energy efficiency bills are wending their ways through the US Congress.  In late April the Senate Energy and Natural Resources Committee held hearing on the Energy Efficiency Promotion Act of 2007, sponsored by Committee Chair Jeff Bingaman (D-NM) and Ranking Member Pete Domenici (R-NM).  And in the Senate Finance Committee, Senator Maria Cantwell (D-WA) introduced the Clean Energy Investment Assurance Act of 2007 on May 11.

Energy Efficiency Promotion Act of 2007

This bill rewards efficient use of oil, natural gas, and electricity, reduce oil consumption, and heighten energy efficiency standards for consumer products and industrial equipment.  The bill contains provisions to: (1) assist state and local governments in energy efficiency; (2) promote federal leadership in energy efficiency and renewable energy; (3) expand use of advanced lighting technologies; (4) implement new energy efficiency standards; (5) develop and market high efficiency vehicles, advanced batteries, and energy storage; and (6) otherwise establish energy efficiency goals.  As an example of the detailed proposals in the current version of the bill, the advanced lighting technologies section would set incandescent reflector lamp efficiency standards, offer Bright Tomorrow lighting prizes, and accelerate procurement of energy efficient lighting. 

Douglas Johnson, Senior Director of Technology Policy and International Affairs at the Consumer Electronics Association (“CEA”), has raised questions regarding design mandates in the bill that unwittingly could stymie innovation and conflict with successful existing federal programs such as Energy Star.  In addition, CEA is concerned that the bill redefines “energy conservation standard” in a way that mandates specific technologies and product components in addition to the energy efficiency products themselves.

While CEA has expressed its commitment to working with legislators to develop federal solutions, it fears that legislating over Energy Star could be “a step backwards.”

Clean Energy Investment Assurance Act of 2007

The bill proposes to amend portions of the Internal Revenue Code of 1986 to encourage investment in clean energy technologies using enhanced and predictable tax credits.  If enacted, the bill would (1) extend until 2013 the renewable electricity production credit; (2) extend and expand the Clean Renewable Energy Bond program that provides public power systems with interest-free borrowing for renewable energy projects; (3) extend two provisions until 2017, namely the 30-percent tax credit for the purchase of residential solar power, solar water heating, fuel cell equipment, and qualified energy storage air conditioner property and the 30-percent business tax credit for investments in solar energy equipment, fuel cell power plants, and qualified energy storage air conditioner property; and (4) extend three provisions until 2013, namely the tax credit for the construction of new energy-efficient homes, the deduction for investments in energy efficient commercial buildings, and the 10 percent investment tax credit for the cost of energy efficient materials used in the construction of buildings.

"Encouraging private investment in renewable energy is an indispensable part of reducing emissions and curbing our overdependence on fossil fuels," explained Senator Cantwell  "To get consumers better technology and cleaner, more renewable, more efficient energy options," she continued, "we need predictable federal incentives to encourage investment."

New Hampshire Commits to a Renewable Portfolio Standard of 25% by 2025

The New Hampshire Senate passed unanimously and will send to Governor Lynch House Bill 873, a renewable portfolio standard intended to promote fuel diversity, lower regional dependence on fossil fuels, reduce and stabilize energy costs, keep energy investment in the state, reduce greenhouse gases, improve air quality, and stimulate investment in renewable technologies.  Governor Lynch expressed his commitment for the RPS' ability to "help create jobs right here in New Hampshire by expanding uses for our wood products, in building clean power plants, and in research and development."

The legislature established four classes of renewable energy in its RPS.  Class I includes new (after January 1, 2006) electricity production from wind, geothermal, biomass and methane fuels, ocean thermal, wave, current or tidal energy, and energy displacement by end-users.  Class II includes new (after January 1, 2006) production of electricity from solar technologies.  Class III includes electricity production from existing (prior to January 1, 2006) small biomass and methane gas operations.  Class IV includes the production of electricity from existing (prior to January 1, 2006) hydroelectric energy.

Those utilities without renewable energy generation can purchase certificates in order to meet the requirements of the RPS.  Although certificates are to be purchased on the open market, they may be subject to price caps that vary according to the energy source.  In addition to setting target percentages by 2025, the legislature also established benchmark percentages for each classification in each year between implementation and 2025.

The PUC is charged with adopting rules to administer the RPS program, monitoring compliance with the rules, administering and making expenditures from the fund, and establishing procedures for classifying existing and proposed generation facilities.

Department of Energy Proposes $9 Billion in Clean Energy Loans

Nine billion dollars could flow to guarantee loans to clean energy projects under a May 10 Department of Energy (DOE) Notice of Proposed Rulemaking (NOPR) under the Energy Policy Act of 2005. Each approved project could receive guarantees covering up to 80% of total project costs.  To be considered by the agency, written comments must be submitted within 45 days from notice in the Federal Register — likely late June or early July.

DOE proposes loan guarantees for ten categories of projects and technologies, including:  renewable energy systems; advanced fossil energy technology, including qualifying coal gasification systems; residential, industrial or transportation hydrogen fuel cell applications; advanced nuclear facilities, carbon capture and sequestration practices; efficiency in electrical generation, transmission and distribution; end-use efficiency technologies; production facilities for fuel efficient vehicles; pollution control equipment; and certain crude oil refineries.

Allocation of the $9 billion in loans will not be equally distributed among the ten categories; rather, $4 billion is reserved for central power stations, $4 billion for biofuels and clean transportation fuels, and only $1 billion for projects involving new technologies for electric transmission or renewable power generation systems.  According to DOE, precise allocation of the guarantees will depend upon the merits and benefits of a particular proposal and the accompanying statutory and regulatory requirements.

While the program is a positive development for the energy industry as a whole, efficient and fair implementation by DOE is critical, and that implementation is the specific subject-matter of the May 10 NOPR.  Provisions of particular interest to potential loan applicants include payment of the Credit Subsidy Cost, assessment of fees to loan recipients, rules on financial structure and eligibility of lenders, regulatory review, and default and audit rules.

Those industries now participating in eligible technologies and those planning expansion into clean energy projects can find public comment and public meeting procedures at Section III of the NOPR.

Washington State Enacts Climate Change Legislation

Washington State has enacted a climate change law half a year after a ballot initiative approved a renewable portfolio standard (RPS).   The new law applies to long-term power-purchase agreements signed by utilities after July 1, 2008 and all new power projects built in the state after that time.   It requires that baseload generation comply with an emissions performance standard of 1,100 pounds of greenhouse gases  per MWh.  This is compatible with the emissions from state-of-art gas-fired generators, but would preclude long-term contracts with or development of coal-fired generation unless the greenhouse gases are sequestered or mitigated.  The law also establishes long-term greenhouse gas emissions reductions goals for the entire state.

The new law recites the state's vulnerability from climate change, including the potential impact on the snow pack that supplies summer stream flows and the effect of rising sea levels on coastal communities.  Under the existing RPS laws, affected utilities must procure 3% of their energy from renewables by 2012, 9% by 2015, and 15% by 2020, subject to different standards for utilities without load growth.  Most forms of renewable energy qualify as eligible sources, although hydropower is mostly excluded. 

How the greenhouse gas and RPS laws will work in tandem remains to be seen.  One impact is that new hydropower facilities could be used for compliance with the climate change law, but not with the renewable portfolio standard.  Washington State isn't the only state to have enacted both types of laws, as California has already gone down this path, and several other states with or without RPSs are working on various types of climate change proposals. 

In general, the two sets of legal requirements have some overlap, but also pursue different objectives.  A renewable portfolio standard doesn't by itself necessarily reduce overall carbon emissions, as it doesn't affect the type of generation that is not required to be renewable, i.e., the remaining 80% in an RPS that requires 20% renewable energy.  For example, if an RPS that requires 20% procurement of energy from renewable resources leads to wind and geothermal development that avoids CO2 emissions, the emissions of CO2 could still increase overall if the remaining 80% of generation includes emissions from sources such as coal-fired plants.  Conversely, setting CO2 limits without an RPS could lead to development of natural gas-fired generators with relatively low CO2 emissions, but would not necessarily promote renewable energy development.

FERC Tailors Transmission to Connect Renewables

In response to a carefully crafted petition from the California Independent System Operator, the Federal Energy Regulatory Commission took a large step toward facilitating development of the transmission needed to harness wind and other renewable energy sources that are remote from load centers.  With its order granting the CAISO’s petition for declaratory order, FERC approved a financing mechanism that is intended to solve the "chicken or egg" sequencing problem of development of transmission lines and renewable energy generators in areas such as the Tehachapi region of California.

The problem vexing renewable energy advocates is that wind, geothermal and other renewable generators must be built where natural conditions allow.  But wind and geothermal hot spots are often far from the energy-thirsty urban centers, and little transmission is available at these remote locations.  Since most renewable energy projects are much smaller than large hydro or fossil-fuel plants, individual generators can’t afford to develop major new transmission projects.  Nor have transmission owners been keen on building lines to locations where the development of generation is either marginal or uncertain. 

To break this transmission logjam, some states have created transmission development agencies.  But California entities have focused more on creating cost recovery mechanisms that would allow the state's transmission-owning utilities to develop the transmission themselves.  In 2005, Southern California Edison initally proposed a "trunk line" model, but FERC objected  because ratepayers would pay for the entire facility, and because the utility would retain control of it.  FERC solicited an alternative, and the CAISO responded with a program having the following key terms:

• The project must provide access to an area with significant potential for development of remote energy resources.
• Initial costs of qualifying interconnection facilities would be rolled into the transmission revenue requirement of the transmission owner that constructs the facility, subject to a cost cap to protect ratepayers. 
• Later costs would be paid pro rata by generators who interconnect with the line.
• The project would have to be approved through the CAISO transmission planning process.
• A minimum level of generators must commit to the line before it can proceed, and another batch must have shown interest in joining. 

FERC earlier had resisted advantaging renewable energy through favorable transmission rules.  But with its approval of the CAISO program, FERC acknowledges that location-constrained resources are unique and warrant different access rules. 

Virginia General Assembly Accedes to Governor-Amended Re-Regulation Bill; Executive Order to Cut Commonwealth’s Energy Demand

On April 4, the Virginia General Assembly voted overwhelmingly to approve amendments to a measure that would "re-regulate" the state's (never de-regulated) retail electric industry, ending the prospect of customer choice for all but very large customers and lifting existing retail price caps two years earlier than scheduled.   The re-regulation bill originated in the General Assembly, but was later amended by Governor Tim Kaine (D), who revised the legislation's rate-setting provisions and doubled the state's voluntary renewable energy use and demand reduction (below 2006 consumption) objectives from 5% to 10% by the year 2022.  The legislation will take effect automatically, without Governor Kaine's signature, on July 1, 2007.

Under the version of the legislation adopted, the Virginia State Corporation Commission will review utility rates every two years and will set a utility's basic rate of return at levels equal to the average rates of return for similar utilities in the Southeast, irrespective of the relative risks it confronts or the quality of electric service the utility provides.  On top of that, the utilities will still be permitted to earn a bonus rate-of-return for developing new baseload generating capacity, but in an attempt to placate environmentalists who had decried the original legislation as not doing enough to encourage the development of renewable resources, the law will give priority to nuclear, "clean coal" plants (i.e., those with carbon capture technology), and renewable projects.  In addition, the existing retail price caps, set to expire on December 31, 2010, will now expire at the end of 2008.  The bill has been called a "hybrid" form of rate regulation, because it allows a few of the largest industrial customers to retain the "choice" option, but would end that opportunity for the majority of retail customers.

With the passage of this legislation, Virginia became the first state to re-regulate its electric industry before any real de-regulation was implemented.  Debate has been ongoing in several other states, with critics calling for the rejection of competition in electric markets.  Illinois, Maryland, and Michigan, to name a few, have also faced growing dissatisfaction in their states with the results of competitive electric markets.

In contrast to the legislation’s weak provision asking utilities to volunteer 10% demand reductions, Governor Kaine more recently issued Executive Order 48 that directs the Commonwealth’s executive branch to reduce the annual cost of energy purchases from non-renewable sources by at least 20% by fiscal year 2010.  Given that Virginia utilities have among the nation’s least developed demand reduction programs and funding, this directive could engender considerable business opportunities for independent vendors of demand-reduction programs and technologies.

States Seek to Increase Renewable Energy Development

State governments have been busy of late seeking to increase renewable energy development and sales within their borders, mostly through the increasingly popular renewable portfolio standards that require utilities to include a certain percentage of renewable energy in the electric power sold to consumers.

Most recently, the Oregon State Senate approved SB 838 that would introduce a renewable portfolio standard to the state.  Oregon is today the most populous Western state without a renewable portfolio standard.   If enacted into law, the bill would require utilities to gradually increase their procurement of renewable energy up to the level of 25 percent of the energy they provide to consumers by the year 2025.  To stimulate development of other resources, the bill would limit the amount of the requirement that can be satisfied by hydroelectric generation, on which the Pacific Northwest already heavily relies.  To reduce the cost of the standard, the bill would cap the added cost of renewables at 4 percent on a utility’s annual revenue requirement.  The bill now goes to the Oregon House of Representatives for hearings.

In Colorado, Governor Bill Ritter signed a bill doubling the state’s renewable energy standard, which had been adopted through a voter ballot in 2004.  The new law increases the renewable energy procurement for utilities from 10% to 20% by the year 2020 and also establishes a 10% procurement requirement by 2020 for municipal utilities serving more than 40,000 customers and electric cooperatives.  The Governor also signed legislation compelling the state’s utilities to identify high-potential wind-energy locations by undertaking biennial reviews to designate “Energy Resource Zones” where transmission constraints hinder the delivery of electricity.  This requirement is intended to spur subsequent development of the transmission needed to bring renewable energy to load centers.

Wisconsin likewise moved to increase renewable energy development as Governor Jim Doyle signed several executive orders intended to boost renewable energy development and fight global warming.  The Governor previously announced a goal of Wisconsin obtaining 25 percent of its electricity and 25 percent of its transportation fuel from renewable fuels by 2025, although the state’s renewable portfolio standard calls for a more modest 10% procurement of renewable energy by 2015.  The executive orders create a new Office of Energy Independence whose objectives will include working with the state’s Public Service Commission on a potential multi-utility effort to build a integrated gasification combined cycle “clean coal” generator.  Another executive order created a Task Force on Global Warming to include a wide range of business, industry, government, energy and environment leaders to examine the effects of, and solutions to, global warming in Wisconsin. 

Supreme Court Rules that Carbon Emissions Are a Pollutant under the Clean Air Act

In a decision with potentially broad implications for the electric power industry, the Supreme Court ruled on April 2 that the Environmental Protection Agency was wrong when it declined to promulgate regulations to limit car and truck emissions of carbon as a greenhouse gas that contributes to global warming.  The case before the high court was confined to US automobile emissions; it did not directly address the far greater domestic carbon emissions from stationary, coal-fired power plants.   But the precedent established will surely fuel efforts to reduce power plant emissions either through a tax on carbon or an emissions cap-and-trade program.

In Massachusetts v. EPA (Case No. 05-1120), a harshly divided U.S. Supreme Court overturned EPA’s 2003 refusal to undertake a rulemaking to regulate carbon emissions from new motor vehicles under §202(a)(1) of the Clean Air Act.  Court patriarch, Justice Stevens (joined by Justices Kennedy, Souter, Ginsburg and Breyer) held that EPA’s denial of the petition should go back to Agency for reconsideration because EPA’s reasoning was not based on the requirements of the Clean Air Act.  The majority also rejected the government’s contention that the State of Massachusetts lacked sufficient interest (standing) to challenge EPA’s decision.  In dissent, Chief Justice Roberts (joined by Justices Scalia, Thomas and Alito), opposed what he called the majority’s  “special solicitude” to the State of Massachusetts, cautioning that the climate change grievances were tailored for redress by the Congress and the Chief Executive, not the federal courts.  Justice Scalia (joined by Chief Justice Roberts and Justices Thomas and Alito) separately dissented on the merits decision, arguing that EPA’s judgment on the petition to regulate carbon emissions was based on permissible reasons that warranted deference from the Court.

Nineteen private organizations petitioned EPA in 1999 for a rulemaking to regulate greenhouse gas emissions from new motor vehicles under §202 of the Clean Air Act.  (A dozen states (CA, CT, IL, ME, MA, NJ, NM, NY, OR, RI, VT and WA), local governments and others later joined in the petition.)  Section 202(a)(1) of the CAA requires EPA to prescribe by regulation “standards applicable to the emission of any air pollutant from . . . any class of new motor vehicles . . . which in the [EPA Administrator’s] judgment cause[s], or contribute[s] to, air pollution . . . reasonably . . . anticipated to endanger public heath or welfare.”  The CAA defines “air pollutant” to include “any air pollution agent . . . , including any physical, chemical . . . substance . . . emitted into . . . the ambient air.”

EPA denied the petition four years later because, in its view (1) the C