InfraStructure White Papers FINAL - New England Energy Alliance

SITING CRITICAL ENERGY INFRASTRUCTUREAN OVERVIEW OF NEEDS AND CHALLENGES

A WHITE PAPER PREPARED BY THE STAFF OF THE

NATIONAL COMMISSION ON ENERGY POLICY

JUNE 2006

National Commission on Energy Policy

www.energycommission.org

This white paper was prepared by the staff of the National Commission on Energy Policy as an overview of keyU.S. energy infrastructure siting needs and challenges. It is intended to lay the groundwork for a series offorums on siting challenges sponsored by the Commission and others later in 2006. The views expressed heredo not necessarily reflect those of the Commissioners of the National Commission on Energy Policy.

Acknowledgements

The National Commission on Energy Policy is funded by the William and Flora Hewlett Foundation and its partners.

The Commission thanks Shalini Vajjhala of Resources for the Future as a contributing author for her work on—Section C of the paper: “A Review of Infrastructure Siting Practices in the United States.”

The Commission also thanks OnLocation, Inc. for technical and analytic assistance in preparing this white paper.

Design and Production: Williams Production GroupPrinted and Bound by Lake Litho Printing & Marketing ServicesCopyright © 2006 National Commission on Energy Policy. All rights reserved.Reproduction of the whole or any part of the contents without written permission is prohibited.

NCEP Staff

Jason S. Grumet, Executive Director

Jeremy Bayer, Director of Operations

Paul W. Bledsoe, Director of Communications and Strategy

David Conover, Counsel

Mike DiConti, Chief Operating Officer

Emily Hawkes, Administrative Assistant

Joe Kruger, Policy Director

Lisel Loy, Senior Advisor

Sasha Mackler, Senior Analyst

Karrie S. Pitzer, Director of Special Projects

Billy Pizer, Senior Economist

Vito Stagliano, Research Director

Marika Tatsutani, Senior Analyst

Tracy Terry, Technical Director

Noah Wolfe, Program Analyst

Eric Washburn, Counsel

ii National Commission on Energy Policy

TABLE OF CONTENTS

NCEP Commissioners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

Letter from NCEP Co-Chairs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vKey Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .vi

A. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

B. Energy Infrastructure: An Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

C. A Review of Infrastructure Siting Practices in the United States . . . . . . . . . . . . . . . . . . . . . . . . . . 8

D. The Infrastructure Challenge Going Forward: An Update on Current Projections . . . . . . . . . 12

E. Sector-Specific Infrastructure Siting Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161. Electricity Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162. Wind Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223. Nuclear Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254. Coal Technology, Integrated Combined Cycle Gasification & Carbon Capture and Storage . . . 285. Liquefied Natural Gas (LNG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 326. Alaska Natural Gas Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 367. Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

F. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

National Commission on Energy Policy iii

NCEP COMMISSIONERS

JOHN P. HOLDRENCo-ChairTeresa and John Heinz Professor of EnvironmentalPolicy, Harvard University; Director of the Woods HoleResearch Center

WILLIAM K. REILLYCo-ChairFounding Partner, Aqua International Partners; formerAdministrator, U.S. Environmental Protection Agency

JOHN W. ROWECo-ChairChairman and CEO, Exelon Corporation

PHILIP R. SHARPCongressional ChairPresident, Resources For the Future; former U.S. Representative, IN

MARILYN BROWNInterim Director, Oak Ridge National Laboratory’sEngineering Science and Technology Division

RALPH CAVANAGHSenior Attorney and Co-Director, Energy ProgramNatural Resources Defense Council

LEO W. GERARDInternational PresidentUnited Steelworkers of America

ROBERT E. GRADY Managing Partner, Carlyle Venture Partners, The CarlyleGroup; former Executive Associate Director of the OMB

F. HENRY HABICHTCEO, Global Environment & Technology Foundation;former Deputy Administrator of the U.S. EnvironmentalProtection Agency

FRANK KEATING CEO of the American Council of Life Insurers; formerGovernor of Oklahoma

RICHARD A. MESERVE President of the Carnegie Institution; former Chairmanof the U.S. Nuclear Regulatory Commission (NRC)

MARIO MOLINAProfessor, University of California, San Diego

SHARON L. NELSONChief, Consumer Protection Division, WashingtonAttorney General’s Office; Chair, Board of Directors,Consumers Union

RICHARD L. SCHMALENSEE Professor of Economics and MIT and the John C. HeadIII Dean, MIT Sloan School of Management

SUSAN TIERNEYManaging Principal, the Analysis Group; formerAssistant Secretary of Energy

R. JAMES WOOLSEYVice President, Booz Allen Hamilton; former Director ofCentral Intelligence

MARTIN B. ZIMMERMANClinical Professor of Business, Ross School of Business,University of Michigan; Group Vice President, CorporateAffairs, Ford Motor Company (2001 - 2004)

iv National Commission on Energy Policy

National Commission on Energy Policy v

LETTER FROM NCEP CO-CHAIRS

Dear Colleagues,

In our 2004 report, “Ending the Energy Stalemate: A Bipartisan Strategy to Meet America’s Energy Challenges,” theNational Commission on Energy Policy concluded that: “it will not be possible to ensure adequate and reliablesupplies of energy, achieve desired reductions in greenhouse gas emissions, or diversify transportation fuels withoutsimultaneously reducing the barriers that now hamper the siting of new energy infrastructure.”

This Staff Paper explores the infrastructure challenges and opportunities that will affect ongoing efforts toimprove upon and modernize our nation’s energy systems. Like all contentious energy policy issues, the debate overinfrastructure siting suffers from oversimplifications and unexamined assumptions: that it has become impossible tosite major energy facilities in the United States, that environmentalists will find ways to oppose just about everything,or that energy companies want to build without regard to the burdens they impose on communities, or even that wecan meet our nation’s energy challenges without adding diverse new infrastructure in someone’s backyard. To developa more nuanced understanding of infrastructure siting issues and begin to elucidate realities on all sides of the debate,the Commission is sponsoring a series of workshops for later in 2006 and 2007. Initial workshops will focus on someof the resources and technologies that figure most prominently in current energy policy discussions: liquefied naturalgas or LNG, electricity transmission, renewable energy (primarily wind and biofuels), nuclear power, and advancedcoal technologies and carbon sequestration.

In addition, we hope to explore the broader dynamics that will influence energy-resource decisions in thecoming years. During our internal discussions, some members of our Commission expressed optimism that theadvent of new, more efficient, and environmentally superior technologies will transform current siting paradigms andusher in a new era of local, state, and federal cooperation. According to this view, the primary challenge is to developplanning and siting processes that are inclusive, rigorous, and comprehensive enough to give stakeholders confidencethat all options—including solutions that rely on efficiency and demand management—have been considered. OtherCommission members, by contrast, voiced concern about a growing mismatch between the energy systems the publicwants—or is at least willing to accept—and the energy systems we need to continue delivering reliable and affordableenergy. According to this view, public officials at various levels of government are likely to continue to confrontdifficult siting choices and will increasingly need to weigh regional or national interests against the often vocalopposition of local communities to new energy infrastructure of any kind.

By promoting a broader, shared understanding of these critical issues the Commission aims to advance the policyprocess and engage a wide variety of stakeholders in a substantive dialogue on infrastructure siting and related issues.We ask you to join us in this exploration. Information and materials relating to upcoming forums can be found atwww.energycommission.org. We look forward to working with you.

Sincerely,

John W. Rowe John P. Holdren William K. Reilly

vi National Commission on Energy Policy

KEY QUESTIONS

Recognizing that important infrastructure issues exist in all major energy sectors, the Commission has initiallyidentified the following areas where current or anticipated siting challenges will most directly affect the evolutionof future energy systems. To explore current challenges, describe lessons learned from recent siting successes andfailures, identify best practices for overcoming siting hurdles, and develop related policy recommendations, theCommission proposes a series of workshops to be held later in 2006 and early 2007. The following key questionsattempt to identify issues that could usefully be explored in the workshops.

Transmission• How should “national interest corridors” be designated and how will these designations facilitate the review

and approval of specific facilities?

• How should the Federal Energy Regulatory Commission (FERC) use its backstop siting authority to implementspecific projects?

• How effective have regional planning processes been in streamlining siting processes and what lessons havebeen learned from these processes to date?

• What is the outlook for interstate transmission planning and siting compacts? How should they be constitutedand should they be given special standing in FERC proceedings?

• What new approaches are being used and are there generally accepted “best practices” in transmission planningand siting?

• Do alternative financing models affect siting decisions and are DC lines treated differently than AC lines?

• How can cost/benefit analyses for transmission projects be improved to fully account for impacts on interstateand regional power markets?

Wind• What are the primary siting concerns for onshore wind projects; how problematic are they; and are they more

critical than regulatory, economic, or technology concerns?

• How effectively has the wind industry addressed siting concerns? Do these concerns require regulatoryintervention and if so by whom?

• Are impacts on birds and bats sufficiently well understood and is there consensus on a research agenda tosupport improved performance?

National Commission on Energy Policy vii

• What are the infrastructure implications of substantial renewable energy development in remote areas? Aretransmission constraints likely to be a major impediment and if so what aspects of this issue are mostchallenging?

• Are opportunities for synergistic land uses on agricultural and forest lands well understood? How can the rightparties be brought together to identify and exploit these opportunities?

• What are the unique siting and licensing challenges for offshore wind projects and how are differentstakeholders addressing these challenges?

Nuclear• What has been learned thus far from the Early Site Permit process? Are the major siting issues for new plants

essentially the same as those encountered in the 1970s?

• What siting challenges might arise from continued delay in licensing a permanent waste repository and canthese challenges be mitigated by on-site storage technology (casks)?

• What lessons, if any, can be learned from the experience of other countries that are siting and in some casesbuilding new nuclear reactors?

• Will “site banking” or “advanced siting” options provide opportunities for a project to move to development iffinancial and other factors warrant?

• What role will currently high natural gas prices and projections of future prices play in the regulatorydeliberations concerning siting and cost-recovery for new nuclear plants?

• Will climate change considerations facilitate the siting process for new nuclear power plants?

• Is it financially and otherwise possible to develop new nuclear plants without securing advance long-termfinancial commitments from utilities or their regulators?

• Should the Nuclear Regulatory Commission seek to establish a joint licensing-siting process with states inwhich utilities are considering nuclear plant projects?

• Will new reactor designs facilitate siting decisions?

KEY QUESTIONS

viii National Commission on Energy Policy

Coal• Should climate considerations be incorporated more explicitly into siting and permitting decisions for new coal

facilities and if so, how?

• Will the smaller “environmental footprint” of integrated gasification combined-cycle (IGCC) plants make themeasier to site than conventional coal plants?

• How will public perceptions of carbon capture and sequestration (CCS) affect the ability to site power plantswith carbon storage?

• How should “sequestration readiness” be incorporated into siting reviews of IGCC projects, in light ofexpectations that IGCC will be commercially ready ahead of sequestration options?

• Are there optimal and sub-optimal regions or localities for the siting of IGGC plants?

• Can considerations related to siting IGCC and CCS facilities, and associated transmission requirements, beintegrated into state and regional planning processes?

• What lessons from the siting of other energy technologies are most relevant to CCS?

• How will the developing regulatory regime for CCS shape future siting decisions?

LNG• Are current government forecasts consistent with industry plans for new LNG infrastructure?

• What are the implications of further concentrating natural gas facilities in the Gulf region and what, if any,steps should be taken to geographically diversify LNG infrastructure?

• What are the primary concerns that arise in siting LNG facilities and are these concerns substantially differentthan those encountered by other large industrial facilities?

• How has the Energy Policy Act of 2005 changed the outlook for siting LNG facilities?

• What are the best ways to balance local, regional, and national interests and what best practices would promotethe “cooperative federalism” the Commission has advocated?

• Can regional analyses of the need for additional natural gas supplies substantially aid the siting process forLNG facilities?

• Will new re-gasification technology reduce the requirements (and footprint) of on-shore facilities and facilitatefuture siting decisions?

KEY QUESTIONS

National Commission on Energy Policy ix

Alaska Natural Gas Pipeline• What remaining barriers need to be resolved before the pipeline can move forward?

• Are current siting and permitting requirements manageable and can more be done to responsibly speed thisprocess?

• How have the economics changed since the last pipeline feasibility study five years ago?

• Would pre-construction contract commitments for Alaska gas facilitate pipeline construction?

• Are the markets for Alaska gas likely to be centered in the West or Midwest and how will this influence finalsiting decisions?

• Should LNG options be considered as a complement to the pipeline and if so, what are the siting implicationsof these options?

Biofuels• To what extent will the siting of future ethanol plants depend upon proximity to existing energy infrastructure?

• To what extent will transportation costs force plants to be located near feedstock sources?

• Will communities that are not used to living near large agri-business facilities be willing to tolerate new biorefineries?

• Should the rules governing the Conservation Reserve Program be changed to allow the cultivation of energy crops on some of these lands and if so, how can habitat preservation and other important goals be effectively addressed?

KEY QUESTIONS

Early in its multi-year effort to developcomprehensive recommendations for U.S. energypolicy, the National Commission on Energy Policy

concluded that strengthening the nation’s energyinfrastructure was critical to ensuring a secure,sustainable, reliable, and affordable energy future. Eventssince the December 2004 publication of the Commission’sreport Ending the Energy Stalemate: A Bipartisan Strategy toMeet America’s Energy Challenges—most notably, ofcourse, the widespread havoc wrought on the Gulf Coastin 2005 by a series of hurricanes—have highlightedvulnerabilities in parts of the existing energyinfrastructure, while underscoring the importance ofrobust and resilient energy delivery systems.

The Commission recognizes that it will not bepossible to meet the nation’s energy and economic needs,achieve desired reductions in greenhouse gas emissions,or diversify its transportation fuels without enhancing,expanding, and diversifying America’s energyinfrastructure. The Commission’s fundamental optimismabout that enormous—and enormously important—endeavor draws in part on an ever-strengthening case foraction, on both economic and environmental grounds.To be sure, energy-facility siting and permitting remainsa major cross-cutting challenge for U.S. energy policy. Asthe Commission noted in its 2004 report, while much-needed energy production and distribution capacity hasbeen added in many regions of the country over the lastdecade, other projects face critical siting and permittingconstraints. Many of these constraints result fromprocesses in which local concerns trump broaderregional or national objectives. Environmental concerns,federal-state regulatory conflicts, aesthetic preferences,highly localized planning processes, investment risksand preferences, and regional policy differences have allplayed varying roles in driving current patterns ofinfrastructure development and in making it difficult topermit and build major energy facilities in many parts ofthe United States.

As a result, energy infrastructure has not always beenproposed or built where it is needed most, or mosturgently; extraordinary efforts have often been required toget facilities permitted in a timely fashion; and regulatory

uncertainty and resulting delays have raised the cost offacilities themselves, along with delivered energy prices.In some cases, stakeholders have discounted the fact thatnew technologies can be environmentally andoperationally superior to the technologies they replace.Permitting problems have also narrowed fuel andtechnology options in some regions, exposing consumersto higher price volatility, reduced fuel diversity, increasedrisk of supply interruptions, and diminished operationalreliability. Such hurdles—even when they represent anappropriate, or merely accepted cost of development—have implications for the market’s ability to finance energyinfrastructure; can result in the undesirable geographicconcentration of certain types of facilities (as witness thecurrent concentration of much of the nation’s oil and gasinfrastructure in the storm-prone Gulf Coast region); mayhave negative impacts on the economic competitiveness ofsome regions; and may slow the retirement of morepolluting and less efficient facilities.

Continued advances in energy technology providesome grounds for confidence that these difficulties canbe overcome. In general, new energy technologies andfacilities that are more efficient and environmentallyattractive should be easier to site. The Commissionbelieves that a broader recognition of how newtechnologies advance important national policy goalscan help change the posture of interest groups and thetone of debate with respect to future siting andpermitting processes. And while any significantinfrastructure project is likely to draw opposition fromsome quarters, recent experiences (several of which arehighlighted in this report) point to several factors thatcan contribute to successfully permitted projects. Theseinclude: a determination that a project has importantmerits, particularly when compared to existingtechnologies; the ability to demonstrate, and clearlycommunicate, a project’s broader public benefits; the useof planning or siting processes that provide for anobjective evaluation of a project’s full merits while alsoeffectively addressing local concerns; and restraint onthe part of political leaders in terms of avoidingcategorical declarations of opposition to projects beforethe evidence on the merits unfolds. Where theseconditions are met, it is much likelier that stakeholders

National Commission on Energy Policy 1

A. INTRODUCTION

can come together in support of new projects andsuccessfully defuse the potential for local opposition.

But new technology alone will not alleviate sitingproblems. The headlines are replete with examples ofnew, supposedly advanced facilities that continue to runinto local opposition. Prominent examples include theCape Wind project off the Massachusetts coast nearNantucket Island, a proposed cross-channel transmissionline from Connecticut to Long Island, and attempts tosite liquefied natural gas (LNG) terminals in Maine andNew Jersey. As the Commission has repeatedlyemphasized, the Unites States now operates in a globalenergy market and consumers want access to energysupplies from world markets, even as they balk atsupporting the infrastructure necessary to enable suchtrade. Thus, while policymakers must be mindful of thenation’s federal traditions, they must also seek out newand innovative siting procedures that will enable theUnited States to succeed in world markets and ensure itscontinued energy security.

Moreover, many new energy technologies are costlyand operationally unproven. Consistent with the goal ofensuring a low-carbon future that does not undulyburden the economy, or impose dramatic price increaseson consumers, the Commission recognizes thatvariations on more traditional technologies, includingnot only domestic natural gas development andtransportation, but new cleaner coal technologies andnext-generation nuclear facilities—in addition toadvanced renewable and energy-efficiencytechnologies—are likely to play an important role in thenation’s energy future and will have to be sited, oftenover local objections.

Of course, the challenges involved in successfullypermitting new energy projects will vary by region, byindustry, by technology, by project design, and dependingon the fit between the project and the proposed site. Inparts of the country where regional planning processesare employed, there is a better chance that energyinfrastructure siting decisions will be made—if notexpeditiously—then at least in a manner that advancesthe larger public interest. In the electric sector, regionalplanning is often accomplished directly or indirectly byregional transmission organizations or traditionallyregulated multi-state electric utilities. And for sometechnologies, such as next-generation integrated

gasification combined-cycle (IGCC) coal plants or newnuclear plants, the redevelopment of industrialbrownfields may provide substantial opportunities.Indeed, further study may reveal that a significantproportion of the new capacity needed to satisfy futurebaseload electricity demand can be sited where powerplants or other industrial facilities already exist.

An innovative approach to the planning and siting ofnew infrastructure is already working for the BonnevillePower Administration (BPA), which—notwithstandingthe notorious difficulty of constructing new power lines—has recently completed significant enhancements to itshigh-voltage electricity transmission system, including thesiting of new lines in the vicinity of Seattle. Publicacceptance of the need for these additions reflects, in part,extensive work by BPA’s “Non-Wires SolutionsRoundtable” (discussed at greater length in Section E–1),which is exploring new strategies for transmissionplanning that include comprehensive assessments of abroad range of options to resolve capacity or operationalconstraints, including efficiency and renewableinvestments; upgrades to, or expansion of, existinginfrastructure; and market means. Another recentexample of progress is California’s successful expansion ofits critically important “Path 15” line.

Recent infrastructure success stories are not, ofcourse, limited to electricity transmission. Overall, wind-power generating capacity has increased substantially inrecent years, driven largely by federal subsidies and statemandates. Numerous wind-power projects have beensited in the Northeast, Texas, and throughout the West.The late 1990s also saw a substantial expansion ofnatural gas combined-cycle generating capacity in manyregions of the country, driven by such developments astechnology efficiency gains, enactment of the EnergyPolicy Act of 1992, and then record low gas prices. And,since 2000, several thousand miles of new natural gaspipeline have been added around the country. Thesedevelopments, together with several examples ofsuccessfully permitted projects, point to promisingopportunities for transforming current siting paradigmsand re-framing long-standing infrastructure debates. Thechallenge will be to transfer lessons learned from thesuccesses of the last decade to the broader range ofinfrastructure investments that will be needed to meetthe energy demand growth that is expected to occureven with aggressive efforts to improve efficiency.

2 National Commission on Energy Policy

In sum, siting and permitting processes can directlyaffect the deployment and market penetration of newtechnology, the diversity of fuel and technology availableto serve local needs, the achievement of importantenvironmental objectives, and the integration ofinfrastructure decisions in efforts to promote broadernational goals. Recognizing that important infrastructureissues exist in all major energy sectors, the Commissionhas initially identified five areas where current oranticipated siting challenges will most directly affect theevolution of future energy systems.† They include:

• intra- and interstate electricity transmission;

• renewable energy systems, notably wind and biofuels;

• new nuclear power plants and spent fuel storage;

• natural gas facilities, including pipelines, storage,gathering systems, and processing facilities, as well asLNG re-gasification and storage facilities; and

• new coal-based integrated gasification combined cyclepower plants with technology to capture andsequester carbon.

To explore current challenges, describe lessonslearned from recent siting successes and failures, identify

best practices for overcoming siting hurdles, and developrelated policy recommendations, the Commissionproposes a series of workshops to be held later in 2006and early 2007. Each workshop will be co-sponsored byone or more additional organizations with specialexpertise and interest in the relevant topic area. TheCommission hopes that information and insightsgenerated by the workshops will bring siting concernsinto clearer focus and generate concrete ideas forresolving them.

The remainder of this paper is organized as follows:Section B reviews siting issues in the context of theCommission’s interest in infrastructure issues generally.By way of providing background, Section C reviews thehistory of energy-infrastructure siting in the UnitedStates over the last few decades. Turning to thechallenges that lie ahead, Section D sketches themagnitude of the energy-infrastructure expansion that isexpected to be required to satisfy U.S. energy demandover the next two decades according to the most recent(2006) energy supply and demand forecasts of thefederal Energy Information Administration (EIA).Finally, Section E provides more detailed information oncurrent or anticipated infrastructure challenges in eachof the workshop topic areas noted above. In eachinstance, the paper attempts to identify key questionsthat could be usefully explored in the workshops.


† The Commission is aware of, and shares, the intense concern that is currently being focused on matters ofpetroleum price and supply. The drivers behind the recent run-up in oil prices, however, and the broader issues thatneed to be addressed in any discussion of options for reducing the economic, national security, or environmentalrisks related to oil go far beyond the narrower infrastructure and siting challenges that are the subject of this paper.The Commission is working to explore oil-related issues and policy options in other forums; accordingly, petroleuminfrastructure was not included in this initial list.


As noted in the Commission’s December 2004report, the nation’s existing energy infrastructure isvast, complex, and vital to virtually every facet of

modern life and to the functioning of the U.S. economy. Atmore than 20 million barrels per day, the nation’s demandfor oil—chiefly to fuel the 220 million cars and trucks nowon U.S. roadways—requires 17 million barrels per day ofrefining capacity and 200,000 miles of oil pipeline. Thenation’s infrastructure for extracting and transportingnatural gas encompasses some 1,300 drilling rigs and over300,000 miles of pipeline. In addition, thousands of powerplants linked by some 200,000 miles of interconnectedtransmission lines and countless transformer substationsmust operate synchronously to deliver power for lights,computers, household appliances, and essential equipmentto millions of homes and businesses. The total capitalinvestment embodied in the nation’s existing energyinfrastructure is enormous, as are the financial andinstitutional resources that will be required to continuemaintaining and expanding this infrastructure.

As the Commission developed its initial report,several unexpected events exposed vulnerabilities in thenation’s energy infrastructure and prompted urgentquestions, not only about the reliability and security ofexisting energy systems, but also about the futureadequacy of those systems for meeting the economy’sneeds while responding to new environmentalimperatives. Attention focused, for example, on theelectric transmission system after a widespread powersystem blackout in August 2003 shut down large swathsof the Midwest and Northeast, and much of theCanadian province of Ontario. Although it was notconvincingly linked to any lack of transmission orgeneration capacity, the blackout revealed weaknesses inthe hardware, telecommunications, and protocols thatgovern the operation of all regional electric transmissiongrids. At the same time, a sharp escalation in natural gasprices was drawing attention to the diminishing ability

of domestic gas resources to keep up with demand, andto the fact that existing capacity for processing andtransporting natural gas from domestic and internationalsources to gas-consuming regions was insufficient.Similarly, concerns about high gasoline prices, reflectingexceptionally tight supplies in some parts of the country,were beginning to prompt questions about the adequacyof the nation’s crude oil refining capacity. Thosequestions took on new urgency after the catastrophichurricane season of 2005, which revealed not only thetightness of current oil and gas supply and processingcapacity, but the liabilities of having so much of thatcapacity concentrated in one region of the country.

In the energy sector, local siting decisionsfrequently have national implications. In the case of oiland gas, the entire nation is heavily dependent oninfrastructure that is not only concentrated in a storm-prone region of the country, but on a system that isexpected to operate perfectly at near-peak capacity.Similarly, coal-based electric generating capacity isheavily concentrated in the Midwest, Mountain Westand South, while California and the Northeast aredisproportionately dependent on natural gas and nuclearpower. Also, the nation’s regional transmission systemshave increasingly obvious gaps and weaknesses.

Moreover, recent trends seem to indicate that existingpatterns of infrastructure development are unlikely tochange. For example, EIA’s latest forecasts assume that allnew LNG terminals needed over the next decade will besited and built in the Gulf Coast region (see furtherdiscussion in Section E–4). There are numerous reasonsfor these siting patterns, but allowing them to continuemay not provide optimal results from a public policyperspective. Indeed, it may increasingly be necessary toconsider the energy security, environmental, andoperational risks associated with perpetuating—or evenaccentuating—current patterns of energy development.

B. ENERGY INFRASTRUCTURE: AN OVERVIEW


Figure 1

U.S. Oil and Natural Gas Infrastructure

Our nation’s oil and natural gas infrastructure is heavily concentrated in the Gulf of Mexico region (both onshore

and offshore). Over half of domestic crude oil production and nearly one-third of natural gas production is

located in the Gulf. Texas and Louisiana together provide nearly 50 percent of total U.S. petroleum refining

capacity, while a third of all natural gas consumed in the United States passes through pipeline and processing

facilities in Louisiana. The catastrophic hurricane season of 2005 clearly revealed the liabilities of having so much

of the nation’s oil and gas supply and processing capacity concentrated in the Gulf.


The Commission’s 2004 report cited several specificinstances of existing or looming infrastructurechallenges, many of which remain relevant in 2006.They include:

• Failure to advance projects—at all, or only afterlengthy, extremely contentious siting battles—thatwould relieve electricity transmission bottlenecks inthe Northeast, Southeast, and Northwest, despite thewell-documented benefits that reduced gridcongestion would bring in terms of cost,environmental impact, and the improved reliability ofregional electricity systems.

• Problems siting facilities for importing LNG despite thebenefits that increased U.S. access to overseas sourcesof natural gas would afford in terms of mitigating highprices and compensating for virtually certainreductions in domestic conventional gas production.

• Impediments to the siting of some large wind powerprojects, especially offshore projects, despite clearcarbon-reduction and other environmental benefitsand the need to promote renewable power andelectricity-supply diversification.

• Continued delay in resolving the nuclear waste issue,either through the licensing of a permanent repositoryor through the development of monitorable,retrievable interim storage options, despite the factthat this lack of resolution not only creates risksassociated with the dispersal of large amounts ofnuclear waste around the country, but stands in theway of any future expansion of nuclear capacity in theUnited States.

In each of these examples, failure to resolveregulatory and siting difficulties—in addition to having anumber of measurable near-term economic andoperational consequences—is likely to have importantlonger-term implications for the options available to meetfuture energy demand. A reliable grid with a robustcapacity to support interstate electricity commerce, forexample, is the necessary foundation for a diverse,competitive, and environmentally acceptable mix of thefuels and technologies that supply the nation’s electricpower needs. Difficulty in siting offshore wind projectscould limit access to a potentially vast non-carbonresource base. The further deployment and use of efficient

technologies that use natural gas, a fuel that remainsessential to balancing national energy and environmentalobjectives, could be increasingly constrained if LNGimport capacity cannot be expanded to bridge the gapbetween domestic consumption and North Americanproduction. Resolution of the nuclear waste issue is alsocritical, not only to manage the quantities of waste that arecurrently stored at reactor sites, but to ensure that nucleartechnology is among the options that remain available tomeet future electric-power requirements.

Congress recognized, and attempted to address,some of these challenges in the Energy Policy Act of2005 (EPAct05). That legislation included a number ofincentives and provisions aimed at reducing financialand regulatory impediments to the expansion of variousaspects of the nation’s energy infrastructure, notablydomestic oil production and refining capacity andnatural gas systems. It also contained a number ofprovisions to support the development and deploymentof low- and non-carbon energy technologies. In addition,EPAct05 created new siting authority for federal agenciesinvolved in permitting offshore alternative energyprojects (such as wind, wave, or solar energy facilities)and interstate electricity transmission lines; it alsoclarified existing federal authority for siting LNGterminals. These provisions are discussed at greaterlength elsewhere in this report. How far they will go inmeeting the nation’s short- and medium-terminfrastructure requirements remains to be seen.

What is certain is that the infrastructure needs ofthe future will be substantial, judging by the most recentenergy supply and demand forecasts released by federalenergy experts. Overall, forecasts from EIA’s AnnualEnergy Outlook 2006 (AEO 2006) show that continuedgrowth in energy demand will require an expansion ofU.S. capacity to generate and transmit electricity, refinepetroleum, and deliver natural gas from non-domesticsources, even with significant continued improvement inend-use energy efficiency. At the same time, governmentprojections anticipate rapid growth in renewable fuelsand new technologies—such as biofuels—that comewith their own, sometimes unfamiliar, set ofinfrastructure challenges.

In sum, the critical issues identified by theCommission in 2004 concerning the scope andconsequences of energy infrastructure siting remain


compelling today. Can the multiple energy systems thatare essential to the U.S. economy be better protectedfrom both natural and manmade threats and can they beexpanded and enhanced in a manner deemed acceptableon economic, environmental, security, operational, andpublic interest grounds? Some of these challenges seemlikely to become more rather than less complicated in

the decades ahead, given new concerns related to climatechange and national security. Before turning to a moredetailed discussion of the specific infrastructurechallenges that lie ahead, however, it is useful to beginby reviewing the history of the last several decades withrespect to the siting and permitting of major energyfacilities in the United States.

Figure 2

U.S. High Voltage Electric Transmission System

Over the last fifty years, the siting of major energyfacilities in the United States has evolved into anincreasingly complex, multi-jurisdictional, and

multi-dimensional process. Several factors come intoplay, including features of the local environment;permitting processes and requirements; federal, state,and local laws and regulations as they pertain to energyproduction and use; requisite demonstrations of “publicneed” and of the attractiveness of a particular proposalover its alternatives; public and stakeholderinvolvement; project development and designrequirements; and project financing. Recent mediaattention to siting issues has generally focused onspecific facilities and local concerns, but at differenttimes in the last half century different combinations ofthese constraints have risen to prominence and shiftedthe context of the debate for siting energy projects. Thissection provides a brief historical overview of energyfacility siting in the United States and discusses some ofthe landmark events that have influenced siting policiesand practices over the last five decades.

Serious attention to the processes used to site majorenergy facilities first emerged in the 1950s with thecommercialization of nuclear power.1 Up to that point,siting decisions for most energy facilities were basedprimarily on engineering and economic considerations.The march of power lines across the Midwest in the1930s, for example, was greeted as a sign of progress bylocal communities and the general public.2 Governmentprograms, such as the Rural Electrification Act of 1936,paved the way for new construction and built significantreserve capacity into critical systems like thetransmission grid. Siting-related regulation was limited,risk assessments were rudimentary, and public supportfor new energy infrastructure as a means of advancingeconomic development was generally strong.3

Growing awareness of environmental and publichealth risks began to add new complexity to sitingprocesses in the 1970s. These concerns found expressionat the federal level in the establishment of theEnvironmental Protection Agency (EPA), under theregulatory provisions of the National Environmental

Policy Act of 1969, and in subsequent legislation such asthe Endangered Species Act of 1973. As a result, greaterattention was focused on the environmental effects ofpolluting facilities and their by-products. The SolidWaste Disposal Act of 1965, which was updated by theResource Conservation and Recovery Act (RCRA) of1976, broadened the scope of issues considered in sitingprocesses to include life-cycle impacts such as the long-term management of hazardous waste.

In general, new facilities began to face morestringent environmental and public health standards andmulti-agency reviews, from justifying the need for newfacilities to conducting detailed environmental impactassessments.4 Most states adopted pollution-control lawsand quite a few states also enacted laws to regulate thepermitting and siting of energy facilities. Meanwhile, thefirst Arab oil embargo focused new attention on energysupply and national security concerns during the 1970s,prompting major federal legislation to promote bothsupply- and demand-side energy investments (in theform of the National Energy Act of 1978, which includedthe Public Utility Regulatory Policies Act or “PURPA”)and inspiring a host of government reports and academicstudies on the siting of various types of energy facilities,including LNG terminals, power plants, natural gaspipelines, transmission lines, and renewable resources.5

Despite the introduction of increasingly stringenthealth and environmental regulations, public trust in bothgovernment and industry eroded in the wake of well-publicized disasters such as Love Canal (1978) and ThreeMile Island (1979). Not surprisingly, opposition to majorenergy facilities intensified throughout the next decade.6

Increasingly, development conflicts—such as growingpopulation densities in areas where new facilities mightneed to be located—also created challenges. The mostcommon reasons for local opposition to new energyinfrastructure included (and still include): negativeimpacts on property values; adverse aesthetic impacts andloss of scenic view sheds; concerns about environmentalimpacts (related to air and/or water pollution and, in somecases, waste issues) as well as health and safety risks, andother externalities; insufficient compensation for


C. A REVIEW OF INFRASTRUCTURE SITINGPRACTICES IN THE UNITED STATES

easements and related tax implications; equity and fairnessissues; and skepticism concerning the need for a particularfacility7 By the 1980s, local opposition to the siting, notonly of new energy facilities but also of many other typesof major infrastructure, was so common and in many casesso intense that a new acronym had been coined to describeit: “NIMBYism” for “not in my backyard.”8 Meanwhile,growing sensitivity to environmental justice issues—theconcern that low-income and minority neighborhoods beara disproportionate share, as compared to suburban or moreaffluent neighborhoods, of the burden imposed by energyfacilities and other industrial infrastructure—began to adda new and difficult dimension to many local siting debates.

Overall, traditional “decide-announce-defend” sitingpractices began to meet with such stiff opposition by theearly-1990’s, and protests against a wide variety offacilities were so effective, that the conventional sitingprocess began to be characterized as “decide-announce-defend-abandon.”9 Once a largely linear process (fromplanning to permitting to construction), siting becamethe dynamic, iterative, and sometimes even circularprocess it is today—a process that typically requiresmultiple stages of public meetings, environmentalreviews, project redesigns, permit applications, and likelylegal proceedings. In response, strategies for publicparticipation have become the focus of most new sitingefforts, and anticipated public opposition hastransformed both the traditional engineering andeconomic considerations of siting practitioners.10

Researchers, planners, regulators, and utilityprofessionals have developed a variety of methods andguides, such as The Facilities Siting Credo, for overcomingsiting difficulties—specifically public opposition—byfacilitating public participation, implementing newauction and compensation strategies, and testing detaileddecision analysis frameworks, among other solutions.11

Siting difficulties have also prompted efforts tostreamline permitting processes, reduce regulatoryredundancy, and shift decision-making authoritywhenever possible from the local and state level to thefederal level. The Federal Energy RegulatoryCommission (FERC) has long held authority for thepermitting of interstate gas pipelines and the licensing ofhydroelectric facilities, while the federal NuclearRegulatory Commission (NRC) has always had exclusiveauthority to site nuclear power plants. Primary authorityto review and approve proposals for most other types ofenergy infrastructure—including power plants, electric

transmission lines, oil refineries, and other facilities—has, however, generally resided with a variety of stateagencies. Pressure to shift more siting authority tofederal agencies began to grow in the 1990s.

The 1992 Energy Policy Act, for example, gaveFERC greater jurisdiction over energy infrastructuredecisions and placed a new emphasis on interstate andregional planning approaches to identify futureinfrastructure needs for both natural gas pipelines andelectricity transmission systems. In the past, federalagency involvement in siting projects occurred onlyafter state and local permitting had begun, if at all. Therevision of federal energy priorities to focus oninterstate and regional issues, however, promptedsignificant shifts in jurisdiction. Further provisions tostreamline siting processes and clarify federal sitingauthority were included in EPAct05 and are discussed inmore detail elsewhere in this report. Among them,EPAct05 provides for the creation of national energycorridors on federal lands in the West that wouldalleviate the need to obtain redundant right-of-ways andreduce regulatory hurdles to the siting of different typesof facilities within those corridors. How the designationof such corridors will facilitate the approval of facilitiessited in particular locations, however, remains uncertainat present.

Recent developments notwithstanding, most newenergy projects are still regulated primarily at the statelevel and public opposition remains inextricablyintertwined with local concerns, includingenvironmental and ecosystem impacts as well as, insome cases, complex issues of property rights andcompeting land uses.12 Appropriately, future sitingdecisions may be further complicated by new attentionto life-cycle considerations, such as the need for long-term hazardous waste management and climate changemitigation. In some cases, upstream or downstreaminfrastructure requirements—such as the need for long-term disposal of nuclear waste or, in the future, the needfor underground carbon sequestration sites, or for largetracts of land to cultivate feedstocks in the case ofbiofuels—may generate as much if not more oppositionthan the energy facilities they support. At the sametime—and despite recent moves toward consolidatedoversight by FERC or other regulatory authorities—fragmented permitting processes, nonstandardpermitting requirements, and interagency redundancyoften still compound siting challenges.13



Despite these difficulties, major energy projects doget sited in the United States. The challenges involvedvary enormously depending on the type, size, and locationof the facility being proposed. In the case of the electricpower industry, for example, an unprecedented boom innew power plant construction took place over the periodfrom 1999 to 2004, spurred on in major part by industryrestructuring and low natural gas prices. More than200,000 megawatts of new capacity were addednationwide, nearly all of which involved new natural gas-fired combustion turbines and combined cycle plants. InCalifornia, where few new plants had been constructedduring the 1990s, a 600-megawatt natural gas combined-cycle plant, the Metcalf Energy Center, was recently builtin an upscale area of San Jose. Recent dramatic increasesin natural gas prices may, however, slow further expansionof natural gas capacity in the near future.

In sum, it seems probable that the siting of criticalinfrastructure will continue to present a major challengefor policymakers. The challenge is heightened by the factthat energy markets operate in an interstate environmentwhere production and transmission systems aredispersed at a sometimes considerable distance fromend-use consumers. Those facilities may be associatedwith a set of adverse impacts that are viewed asoutweighing any real or perceived benefits to thecommunities where they are located. This produces anunderstandable but difficult friction betweencommunities that question why a particular facilityneeds to be located where it is proposed on the onehand, and growing demand for new infrastructure toeconomically and reliably meet the energy needs of amuch broader (and geographically more dispersed)group of consumers on the other.

Recognizing that large infrastructure projects canimpose significant changes and burdens on thecommunities in which they are located, the Commission

has recommended that local impacts becomprehensively reviewed and objectively addressedthrough processes that also recognize the importance ofcertain infrastructure projects to regional and nationalreliability, and for achieving economic, environmentaland security goals. The Commission is aware thatfundamental changes in public understanding aboutworld energy markets, global climate issues, andtechnological advances may help with the siting offacilities. For example, technological advances are onthe horizon that will make it possible to use coal togenerate power with less pollution, while new nuclearplants will be a far less controversial proposition if theyare proposed on sites of existing plants with broadcommunity support. Many stakeholders in regions thatare highly dependent upon natural gas for powergeneration are beginning to support the need for nearbysiting of LNG re-gasification and storage facilities. Suchdevelopments may ultimately help in reconciling sitingdisputes over new facilities.

The Commission’s 2004 report also identified anumber of broad reforms that would ease the siting ofneeded energy infrastructure in the future. Theserecommendations are reprinted here in full (see text boxon page 11)—briefly, they cover the need for clear andaccessible siting rules and processes; up-front, pre-filingefforts by developers to identify and address concernswhile reaching out to local communities; care indistinguishing between the processes used to site specificprojects and broader planning efforts, such as utilityresource proceedings, which should include acomprehensive review of alternatives, including effortsto reduce demand through energy-efficiency programs;and increased resources for state and federal sitingagencies. Ultimately, as the Commission concluded in2004, “it is necessary to promote a better understandingof the energy infrastructure issue as one of ‘commoninterests and equal burdens.’”14


POLICY RECOMMENDATIONS FROM ENDING THE ENERGYSTALEMATE: A BIPARTISAN STRATEGY TO MEET AMERICA’SENERGY CHALLENGES

To achieve the Commission’s objectives of assuring an adequate, reliable, and reasonably-priced supply of energy;reducing greenhouse gas emissions; diversifying fuels available for transportation-related energy use; andsatisfying the nation’s other energy security objectives, it is essential to reduce the barriers that now hamper thesiting of new, needed energy infrastructure. Recommended siting reforms include implementing, across thenation, the best practices which currently exist in some states’ siting processes, including:

• Providing clear and accessible agency rules, timelines, siting criteria, other policies, and case precedents tofacilitate the filing and administration of complete and viable siting proposals.

• Requiring up-front, pre-filing efforts by developers in the local affected communities, including contact withpolitical and public interest groups, community education and flagging of key issues, to identify fatal flaws aswell as information and education needs, and to reduce the time and cost of regulatory and administrativesiting procedures.

• Focusing the siting approval process on the question of whether a specific infrastructure proposal at aparticular place is acceptable. Applicants should provide information demonstrating not only environmentalimpacts, but also the process used to identify and consider other sites, as well as project configurations andtechnology choices that satisfy similar needs. These siting-related processes should be distinguished frombroader utility resource planning proceedings, in which there is a review of the various technology and fueloptions available to satisfy the utility’s needs. The siting of electricity transmission infrastructure, in particular,should include a comprehensive system-wide review of alternatives, although once that review process hasvalidated the need for new transmission lines, the siting process for a specific line segment should not allow fora re-opening of broader system planning issues. The Commission’s support for a comprehensive review ofalternatives in the context of transmission proposals is specific to the electricity sector and is not intended toapply to other types of energy infrastructure, such as LNG facilities.

• Providing state and federal siting agencies with sufficient resources (personnel, expertise, and funding) toefficiently guide proposals through the siting process, including educating developers on rules and potentialpitfalls; assisting and educating the public and political representatives within host communities; facilitatingmeetings with relevant groups and officials and hosting public meetings; and posting complete and timelyproject and process information on agency websites.


Again, while end-use efficiency improvements couldsignificantly reduce need for additional electric facilities,new plants will nonetheless be needed to replace older,less efficient generating capacity that is expected to retire.

To put these numbers in perspective, new coalplants are likely to average 1,000 megawatts and newcombined-cycle natural gas plants are likely to rangefrom 300 to 600 megawatts. New nuclear reactors would be 1000 megawatts or larger, while new biomassfacilities would be considerably smaller (on the order of80 megawatts). It is also worth noting that addingcapacity need not always involve breaking ground onnew facilities. Some capacity expansion, perhaps asubstantial amount, will undoubtedly be achieved byadding generating units at existing power plants.

Within its overall forecast of future electricitydemand and generating capacity, EIA simulates the mixof generating technologies expected to be used to meetfuture capacity needs. In doing so, EIA bases itsassumptions on the features of existing law and policy,along with its forecasts of future prices for basic fuels,such as coal, natural gas, and oil. According to theseprojections, EIA anticipates that roughly 85 percent ofnew capacity additions through 2020 will be either coal-or natural gas-fired plants. Continuing recent trends,EIA projects that most capacity additions in the nearerterm will be natural-gas-fired. Later in the forecastperiod, however, EIA expects that continued highnatural gas prices combined with rising demand forbaseload capacity will result in a growing number ofnew coal-fired power plants. Specifically, EIAprojections show 83,000 megawatts of new natural gas-fired capacity by 2020, compared to 42,000 megawattsof new coal capacity. By 2030, however, new coalcapacity is expected to reach a total of 154,000megawatts, compared to 124,000 megawatts of naturalgas capacity.17 In addition to new coal and gas capacity,EIA projections point to a substantial increase inrenewable generating capacity, mostly wind power,along with 6,000 megawatts of new nuclear capacity,(i.e., six new nuclear reactors).

New reference case forecasts issued by EIA sincethe Commission’s report was published at theend of 2004 indicate that the overall energy

needs of the U.S. economy will grow at an average rate of1.1 percent per year over the next quarter century,resulting in an increase in overall energy consumptionfrom about 100 quadrillion Btu (quads) in 2005 to 121 quads in 2020 and 134 quads in 2030. In EIA’sIntegrated High Technology Case, which incorporatesmore aggressive assumptions about continued efficiencyimprovements across all energy end-use sectors, overallenergy demand is forecast to grow to 115 quads in 2020and 126 quads in 2030.15 In either case, supplying thisanticipated demand growth will require, according toEIA, a substantial increase in the quantities of coal, oil,natural gas, and electricity that will need to be produced,imported, or generated and then delivered to end-usecustomers. Moreover, even if the nation pursues morecost-effective energy efficiency opportunities than nowanticipated in the EIA forecasts, the case for new energyinfrastructure will still be driven in part by the need toreplace aging, obsolete, and relatively dirty equipmentthroughout the system. Finally, EIA anticipates asubstantially expanded role for relatively new resources(such as wind and biofuels) and for energy technologiesthat have not seen large new facilities built for some time(such as nuclear power plants and LNG terminals).

Because of the variety of resource and infrastructureissues germane to the electric power sector, it is useful tobegin by considering the latest projections for future U.S.electricity consumption and generating capacity. EIA’sAEO 2006 predicts that sales of electricity will rise by 22 percent over the next 15 years (that is, by 2020) andby 35 percent over the next 25 years (by 2030) comparedto current (2005) levels. To supply this increase inconsumption, EIA estimates in its base or “reference”case that 148,000 megawatts of new electric generatingcapacity will be needed by 2020 and a further 164,000megawatts of new capacity will be needed by 2030.Nationwide, roughly 50,000 megawatts of new capacityare currently in the planning phase, about one-third ofthe total new capacity estimated to be needed by 2020.16

D. THE INFRASTRUCTURE CHALLENGE GOINGFORWARD: AN UPDATE ON CURRENT PROJECTIONS


Lake Ontario

Lake Erie

Lake Huron

Lake

Michigan

Lake

Superior

0

5

10

0

5

10

15

20

25

0

5

10

0

50

5

0

5

10

15

20

25

30

0

5

10

15

0

5

10

0

5

10

0

5

10

15

0

5

10

0

5

10

15

20

25

0

5

10

Figure 3

Projected Electric Generating Capacity Additions by

North American Electric Reliability Council Region

While EIA projections indicate that new plants will be needed in every part of the country, demand for new

capacity is likely to grow more strongly in some regions than in others. In particular, California,Texas, the

Southwest and Rocky Mountain area, and the South (including Florida) are projected to see the largest increase

in new generation capacity by 2020, both in absolute and percentage terms.This result is driven largely by

current population trends: the U.S. Census Bureau projects population growth in the South and West of

43 percent and 46 percent respectively by 2030, while in the Northeast and Midwest population is projected to

grow by only 8 percent and 10 percent respectively. In addition, both New England and New York have added

considerable amounts of new capacity in recent years—over 11,000 megawatts in New England, and over

3,000 megawatts in New York—while the Midwest currently has excess capacity. Even so, it is expected that

new capacity will be needed in these regions also within a few years.

Source: Energy Information Administration, Annual Energy Outlook 2006.

Thousands of Megawatts

1,00

0 m

egaw

atts

0

50

100

150

200

250

300

350

2005 2010 2015 2020 2025 2030

Nuclear

Renewables Coal

Natural Gas

Cumulative Capacity Additions by Fuel

2010 2015 2020 2025 2030 2005

Delivered Fossil-Fuel Prices(to the electric sector)

2004

$ p

er m

illio

n B

tu

Petroleum

Natural Gas

Coal

0

2

4

6

8

10


Of course, future infrastructure needs in the electricpower sector will not be limited to generating capacityalone. EIA does not publish projections concerningfuture transmission needs, but it is clear that further gridenhancements will be necessary to support the increasein electric power generation and consumption anticipatedin current forecasts, and to ensure a competitivewholesale market for power (see Section E–1 for a moredetailed discussion of transmission needs).

Along with increased electricity consumption, EIAforecasts substantial growth in demand for primary fuelslike coal, natural gas, petroleum, and biofuels over thenext quarter century. Overall, EIA projects that coalconsumption will rise 18 and 48 percent by 2020 and2030, respectively, while natural gas consumption willrise 21 percent by 2020 (to nearly 27 trillion cubic feet,or tcf) and then level off over the next decade, withcommensurate new demands being placed on thenation’s rail and pipeline infrastructure. With respect to

coal, production in Wyoming’s Powder River Basin isprojected to increase 27 percent by 2020 and over 60percent by 2030, which suggests the need for asubstantial increase in rail capacity. Indeed, industryexperts are already expressing concerns over constraintsin the nation’s rail system;18 while from anenvironmental perspective there is clearly concern aboutthe climate-related implications of a large-scale increasein conventional coal-based electricity production.

In the case of natural gas, needed pipelineexpansions are not projected to be large in the contextof the nation as a whole, but may be significant inparticular regions that either (1) need expandedpipeline systems to meet high demand growth or (2) that expect to expand production and will needadditional capacity to deliver new supplies to market.Overall, EIA forecasts that natural gas pipeline capacityinto New England and the Pacific region must increaseby over 60 percent and 45 percent respectively between

According to EIA forecasts, roughly 85 percent of new capacity additions through 2020 will be either coal- or

natural gas-fired plants.While most capacity additions in the nearer term will be natural-gas-fired, continued

high natural gas prices combined with rising demand for baseload capacity will result in a growing number of

new coal-fired power plants through 2030.


Figure 4

Electric Sector Forecast


now and 2020. Pipeline capacity going out of theproducing areas in the Mountain West will also need toincrease on the order of 60 percent in the sametimeframe. Implementing capacity expansions of thismagnitude will require numerous pipeline projects,each of which will involve regulatory processes ofvarying complexity depending on the affected locality.Given flat or declining natural gas production in thelower 48 states, moreover, EIA forecasts that imports ofLNG from overseas sources will need to increase, alongwith domestic capacity to handle re-gasification,storage, and distribution.

The energy needs of the transportation sector arealso expected to grow significantly over the next twodecades, resulting in increased demand for petroleumand alternative transportation fuels like ethanol,biofuels, and electricity. Specifically, the AEO 2006forecasts a 20 percent increase in oil consumption (forall sectors and uses) and a tripling in biofuels productionby 2020, while crude oil imports are expected to increaseby 10 percent by 2020. Refinery capacity is expected toincrease 6 percent by 2020 through expansion at existingrefineries, along with slight improvements in capacityutilization. Absent the construction of new refineries,capacity expansions at existing facilities are notprojected to keep pace with demand for refinedproducts. As a result, EIA estimates that imports ofrefined petroleum products will increase by 40 percent.EIA also forecasts a significant increase in the productionof coal-based synthetic liquid fuels (“coal-to-liquids” orCTL). By 2030, CTL production is expected to grow to760,000 barrels per day and account for 13 percent ofdistillate fuel supplies.

More detail about these forecasts is provided in therelevant sections that follow. The main point here—giventhat all the major energy resources available today requirecomplex infrastructure to be extracted, processed, andtransported from the point of production to the point ofend use—is that current government projections (basedon forecasts that assume current laws and regulations)point to a major challenge in ensuring that the facilitiesand systems needed to reliably, safely, and affordably meetthe nation’s future energy needs can be sited and built.And even if, as some contend, those projections areoverstated, such facilities and systems are needed in manycases to replace a huge and aging supply and deliveryinventory that in many cases relies on half-century oldtechnology with high environmental costs and risks.

Infrastructure challenges have, of course, alwaysexisted, and by and large they have always been met. Theissue for policymakers today is whether the currentenvironment engenders greater regulatory uncertaintyand cost—and more complex trade-offs—than was thecase in the past. Siting difficulties vary considerably fromproject to project. In some regions of the country, sitingdebates are driven by both cost and aestheticconsiderations. In other regions they are driven byunresolved conflicts about the relative priority thatshould be accorded to supply vs. demand options. In stillother cases, the siting of certain types of infrastructuresuch as transmission lines may be complicated by long-standing divisions of federal and state authority. In sum,while forecasts provide useful information concerning thepotential magnitude of future energy requirements, theydo not help to resolve the jurisdictional and policy issuesthat will ultimately determine how those needs are met.


1. Electricity Transmission

Transmission facilities serve reliability andeconomic purposes, providing the means to supplypower to keep the lights on as well as a path betweenbuyers and sellers of power. Insufficient transmissioncapacity significantly constrains interstate commerce forpower, with direct impacts on the relativecompetitiveness of wholesale electricity markets and,consequently, on the price that consumers pay for electricservice. Transmission constraints and grid congestion notonly raise costs by reducing access to lower-cost powersupplies, but also limit access to a potentially morediverse mix of resources. A May 2002 study by the DOEconcluded that declining transmission systeminvestments and deteriorating infrastructure, combinedwith growing electricity demand, were creating regionalbottlenecks in the transmission system and jeopardizingthe reliability of the nation’s power grid.

It is difficult to determine exactly how much newinvestment is needed to address these problems, in partbecause different utility systems, states, and regions havevariable requirements, and in part because newgeneration, demand-side investments, or bettercongestion management offer alternatives totransmission expansion in some cases. Moreover,transmission issues and system solutions are oftenlocation specific: in some subsystems a certain amountof congestion on the transmission system may be lesscostly than the investments needed to relieve it; in othercases inadequate transmission capacity may createhigher service costs for all users, including native-loadcustomers. The consensus among transmission systemusers appears to be that substantial investments in newtransmission lines and related equipment are needed tomaintain the reliability and operational requirements ofthe system, meet growth in demand and in transactions,and to ensure a robust wholesale market for power.

Recent data indicate that congestion has grownmore severe over the last decade, consistent with arapid increase in wholesale, interstate transactions. The

need for additional investment has been widelydocumented by private analysts and by the regionalorganizations that operate the grid in many regions ofthe country.19 For example, the North AmericanElectric Reliability Council’s “transmission loadingrelief” procedures, or TLRs, determine which requestsfor transmission will be denied in order to prevent linesfrom becoming overloaded. Since 2000, the averagenumber of monthly TLR calls has more than doubled.20

In the PJM Interconnection, which operates thetransmission grid in the Mid-Atlantic region and partsof the Midwest, transmission congestion is handledthrough market prices rather than TLRs. There,congestion charges have risen steadily—from $132million in 2000 to $499 million in 2003.21 Similarly,FERC data indicate that transmission congestioncharges in the state of New York alone have oftenreached over $1.0 billion per year, while charges of upto $500 million per year have been reached in NewEngland.

In addition, significant reliability concerns haveemerged in various parts of the country, notably in theMidwest. In 1998, a severe disturbance on thetransmission grid came perilously close to causing alarge-scale regional blackout that would have affectedMinnesota, Wisconsin, North and South Dakota, as wellas parts of Canada. The severity of the incidentprompted several utilities in the region to form the firstinvestor-owned transmission-only utilities in thecountry—the American Transmission Company (ATC)in Wisconsin and the International TransmissionCompany in Michigan—as a means of more effectivelyaddressing reliability considerations and thetransmission-expansion needs of the states involved.While a number of steps have been taken to improvereliability and a major new transmission line is currentlyunder construction in the region, the ATC estimates that$3.4 billion in investment will be needed over the nextten years to ensure reliable operation of its portion of thegrid, while much higher investments are estimated to be

E. SECTOR-SPECIFIC INFRASTRUCTURESITING CHALLENGES


needed for the broader region served by the MidwestIndependent System Operator (MISO).22

Although investment in the nation’s transmissionsystem has declined in real terms over the last two decades,it appears this trend may have begun to change. A recentstudy commissioned by the Edison Electric Institute (EEI)documents a large portfolio of transmission projectscurrently under consideration by its member utilities.23

Planned transmission projects are not always realized, ofcourse, but transmission investment has risen fromroughly $3 billion in 1997, a recent low, to just over $5billion in 2002. These trends are significant after a decadeof negative transmission capacity growth that has beencharacterized as amounting to “disinvestment.” Still,current levels of investment are modest considering thesize of the grid and the need for substantial expansion to

concurrently address growth in demand and to reducecongestion. Even at projected levels of $7–$10 billion peryear by 2010, transmission investments are expected tolag, in proportionate terms, behind investments ingeneration capacity.

Several factors have been identified as drivingrenewed interest in transmission investment. First,additional transmission lines are needed to connect newgenerating capacity to the grid and to ensure that powerfrom these facilities can flow to areas where it is needed.Second, in conjunction with the restructuring ofwholesale power markets, regulators at the federal leveland in some states are encouraging new investment inthe transmission system not only to increase overallsystem reliability, but to expand trade and reduce inter-and intra-regional congestion as well.

Monthly Logs 12-Month Rolling Average

0

50

100

150

200

250

300

350

Jan-0

6

Oct-05

Jul-0

5

Apr-05

Jan-0

5

Oct-04

Jul-0

4

Apr-04

Jan-0

4

Oct-03

Jul-0

3

Apr-03

Jan-0

3

Oct-02

Jul-0

2

Apr-02

Jan-0

2

Oct-01

Jul-0

1

Apr-01

Jan-0

1

Oct-00

Jul-0

0

Apr-00

Jan-0

0

Oct-99

Jul-9

9

Apr-99

Jan-9

9

Oct-98

Jul-9

8

Apr-98

Jan-9

8

Oct-97

Jul-9

7

nu

mb

er o

f in

cid

ents

Figure 5

Monthly Transmission Loading Relief Logs(Level 2 and higher)

“Transmission loading relief” procedures, or TLRs, determine which requests for transmission will be denied in order

to prevent lines from becoming overloaded.The number of TLRs has grown substantially in recent years, indicating

that transmission congestion is growing on the nation’s power grid.


A third and quite important factor has been the riseof regional transmission organizations (RTOs) andindependent system operators (ISOs). RTOs and ISOsnow exist in approximately half of the country. This hasresulted in an increased emphasis on regionaltransmission planning over large regions covering manystates and many utility systems’ territories. As noted inthe EEI study, “[r]egional transmission expansionplanning by ISOs and RTOs has put into play a processthat compels the building-out of their transmissionsystems to maintain reliability across larger and largermarket footprints.”24 Regional transmission planningprocesses can provide state regulators responsible forsiting new transmission lines with relatively transparentinformation on both the local and regional benefits ofindividual projects within their state.

Grid expansion constraints—especially involvingconnections between electric systems—remain significantin regions with and without ISOs/RTOs, among otherreasons because those who plan the expansion oftransmission do not necessarily have the means orauthority to execute what they propose. This is truewhether or not the planning occurs at the utility, state, orregional level because siting authority for transmissionlines resides, exclusively and unequivocally, with stateregulatory agencies.

Other factors that are likely to affect the pace andscale of future transmission investments include FERC’songoing efforts to clarify policies on transmission costand financing, structural models to ensure open accessto the grid, and an array of provisions in EPAct05 thatare intended to create new incentives for siting andinvesting in electric transmission lines.25

While investment conditions may improve,however, the process of siting and permitting major newtransmission lines is likely to remain difficult and, basedon past experience, fraught with a number of well-known problems. While smaller projects are oftenapproved in a reasonable period, larger projects that spanlong distances and affect multiple communities caneasily become bogged down and, in some cases, takeyears to obtain final approval. Utilities mustconvincingly demonstrate that a new transmission line isnot only the best option for addressing a particularproblem on the grid, but is also the most economic

infrastructure option for its customers. Environmentalimpacts, competing land uses, and concerns aboutprivate property rights and property values are just a fewof the issues that must be addressed when siting newtransmission lines. Accordingly, high-capacity interstatetransmission projects should be designed to providelocal benefits that can help justify their value to localconstituencies, even though the most significant—butmore difficult to measure—economic impacts of the lineare likely to be on the wholesale side of the market.Finally, experience indicates that utilities operatingoutside structured regional markets have little incentiveto propose and defend investments that primarily fosterinterstate commerce.

This does not imply that transmission projects havenot been successfully completed, in some cases evenagainst heavy historical odds. BPA, for example, has notonly expanded its transmission capacity (as discussed inthe text box included in this section), but has also in theprocess facilitated the interconnection of wind energyprojects to its grid. Similarly, a long-overdue expansionto the Path 15 transmission corridor in California wascompleted in 2005 under a highly innovative model thatcombined the project management expertise of thefederal Western Area Power Administration (WAPA)with equity financing provided by the privately-heldcompany TransElect and the participation of Pacific Gas& Electric (PG&E); PG&E did not take ownership ofthe wires, but enabled the capacity expansion byallowing open access rights to all market participants.

In general, transmission siting processes wouldbenefit from more sophisticated analysis of the costs andbenefits of a given project, with appropriate accountingfor impacts on the wholesale market’s competitivenessand enhanced interstate commerce. States are especiallylikely to subject projects that are designed primarily forthe benefit of consumers in other states to rigorousreview. Regional state “compacts” for transmission systemplanning and expansion are emerging in the Midwest,Southwest, New England, and in the Pacific Northwest,but they are not always successful in overcomingparochial interests. In addition, major transmissionprojects usually require a substantial financial investmentand must often compete internally with other utilityinvestments. Finally, significant uncertainty or delays inthe siting and permitting of new lines act as a further


THE BONNEVILLE POWER ADMINISTRATION’S NON-WIRESSOLUTIONS ROUND TABLE

The Bonneville Power Administration (BPA), a federal agency of the U.S. Department of Energy, servesapproximately half of the electricity needs of the Pacific Northwest (Washington, Oregon, Idaho, and westernMontana). BPA also owns and operates roughly three-fourths of the region’s high-voltage transmission grid.Throughout the late 1980s and 1990s, BPA added no new major transmission lines to its system and instead reliedon equipment upgrades and improved communications and control procedures to maintain reliability whileaccommodating demand growth. By 1999, however, the transmission system was routinely operating at nearcapacity and BPA began seeking ways to reinforce the existing grid while also expanding capacity in constrainedand congested areas. As part of this process, BPA began to pursue a broader approach to transmission planning,one that included consideration of “non-wires” alternatives to new line construction, such as targeted demandresponse, distributed generation, conservation measures, and generation siting strategies.

One of the first major projects proposed by BPA under its transmission expansion program was the Kangley-Echo Lake project, a nine-mile, 500-kilovolt line in central King County, Washington intended to provide reliable,high-voltage transmission to the Puget Sound area. The proposed route crossed five miles of the Cedar RiverMunicipal Watershed, which provides water for, and is owned by, the City of Seattle. The project was announcedin March 2000; a draft environmental impact statement (EIS) was released by BPA in June 2001.

Responding to stakeholder concerns about potential impacts on the Cedar River watershed, BPA prepared amore detailed assessment of alternative routes, along with an analysis of the potential to cost-effectively defer theproject using non-wires solutions, including demand-side management, demand response and direct load control,distributed generation, and large-scale generation. The study concluded that, because the magnitude of demand-reduction or additional generation needed to maintain reliability was so large, construction of the proposedtransmission line was the most cost-effective and feasible solution. It also identified system-wide efficiencyimprovements associated with the line, which would reduce the environmental impacts of power generation. InJuly 2003, BPA and the City of Seattle, by unanimous consent of the city council, reached agreement onconstruction of the line and BPA approved the project shortly thereafter.

While a number of issues were addressed in siting this project, BPA’s analysis of non-transmissionalternatives and the transparency of the broader planning process were key factors in overcoming stakeholderobjections. The Kangley-Echo Lake project moved through the full siting and permitting process—fromannouncement to final approval—in just 28 months.

This success led BPA to formalize its commitment to new transmission-planning approaches by launchingthe Non-Wires Solutions Round Table—a 17-member group that includes representatives from public and privateutilities, environmental groups, regulators, large energy users, Indian tribes, renewable resource advocates, andindependent power producers. First convened in January 2003, the Round Table helps BPA identify non-construction alternatives to new transmission projects and ensures that insights from a variety of stakeholders areconsidered as part of a comprehensive, balanced transmission-planning process.


THE BONNEVILLE POWER ADMINISTRATION’S NON-WIRESSOLUTIONS ROUND TABLE (CONTINUED)

In its first year, the Round Table developed screening criteria to determine whether a proposed transmissionproject is a candidate for non-wires solutions; helped to identify institutional barriers within BPA to non-wiresalternatives; and provided detailed studies for particular problem areas on BPA’s transmission system. Using theKangley-Echo Lake study as a template, BPA prepared similar assessments for the Olympic Peninsula and LowerValley in Wyoming. In both cases, the Round Table recommended that non-wires solutions be further pursued.Most recently, the Round Table has begun exploring non-wires alternatives in the southern Oregon coast region.An initial study, released in January 2006, identified a range of cost-effective measures that, if deployed, couldresult in significant peak load reductions that should allow deferral of additional line construction.

BPA has stated its commitment to full integration of non-wires solutions into transmission planning andinvestment and intends to demonstrate to the region that this is the best model for evaluating all transmission anddistribution projects. The Round Table will continue to assist BPA in fine-tuning its planning process andresolving finance issues related to non-wires solutions; the Round Table will also review and critique pilot projectsto ensure that institutional barriers and other uncertainties are addressed. The success of this program couldprovide a model for innovative approaches to transmission planning in other regions.

disincentive to transmission investments by both utilitiesand the financial community.

Recognition of the need for substantialtransmission upgrades, and of the many obstacles thatcurrently hamper the siting of new transmission lines,has prompted an earnest debate among utilities,stakeholders, and state and federal regulators over thepast few years. As a result, several new transmissionsiting provisions were adopted as part of EPAct05:

• Backstop authority — provides FERC with “backstopauthority” to site interstate electricity transmissionlines. The Secretary of Energy is given authority todesignate “any geographic area experiencing electricenergy transmission capacity constraints or congestionthat adversely affects consumers as a national interestelectric transmission corridor.” FERC can then issuepermits for new transmission lines within thesecorridors if states fail to act on an application withinone year or if states condition their approval to adegree that the project will not ease congestion or is nolonger economically viable.

• Energy Corridors — directs the Secretaries ofAgriculture, Commerce, Defense, Energy, and the

Interior to identify and designate “energy corridors”on federal lands in the West. These energy corridorswould be the preferred locations for utility rights-of-way and energy infrastructure projects, includingtransmission lines, oil and gas pipelines, and relatedinfrastructure.

• Lead Agency — designates DOE to act as the leadagency in coordinating all necessary federalauthorizations, permits and approvals for interstatetransmission projects.

• Interstate Compacts — allows states to forminterstate compacts to establish regional transmissionsiting agencies with the authority to issue sitingpermits and to avoid moving ‘backstop’ jurisdiction tothe FERC.

DOE and FERC have begun implementing theselegislative provisions. In January, DOE issued a FederalRegister notice seeking comment on issues related to anew congestion study it is required to undertake and onthe designation of National Interest ElectricTransmission Corridors (NIETC).26 The NIETCdesignation proceeding has drawn widespread attentionfrom industry stakeholders, with nearly 1,000 pages of


comments now on file. In November 2005, four federalagencies issued a joint report to Congress on existingdesignated transmission and distribution corridors onfederal lands.27 Subsequently, DOE and the Bureau ofLand Management initiated a programmaticenvironmental review on the impacts of designatingenergy corridors on these lands in the West. Although a

consensus has not been achieved on ways and means toimplement these legislative initiatives, taken together,the siting provisions in EPAct05, along with theinstitutionalization of regional approaches totransmission planning, have the potential tosubstantially improve processes for siting newtransmission infrastructure.

KEY QUESTIONS:

• What criteria should be used to designate “national interest electric transmission corridors,” and who shouldhave principal responsibility for such designations? How will these designation lead to the review and approvalof specific facilities proposed to be located within the corridors? What is the appropriate role of states in thedesignation of such corridors given the inherently interstate nature of the likely corridors?

• How should FERC use its backstop siting authority to implement utility-specific or RTO/ISO-wide plannedprojects?

• Should “national interest corridor” projects be planned independently of established utility or RTO/ISOprocesses, or be integrated within them?

• How effective have regional planning processes been in streamlining siting processes for new transmissionfacilities? Has regional transmission planning actually resulted in increased transmission capacity? Whatlessons have been learned thus far from regional planning, and how can these processes be improved?

• What is the outlook for interstate transmission planning and siting compacts? Should the National Associationof Regulatory Utility Commissioners (NARUC) and its regional associations actively promote and foster suchcompacts? Should they be formally chartered or informally constituted? Should regional compacts be givenspecial standing in FERC proceedings?

• Are there generally accepted “best practices” in transmission planning and siting, and if not, should there be?What new planning approaches are being used in RTOs? By electric transmission companies in regions withoutRTOs? Is the BPA “Non-Wires Solutions” model broadly replicable across transmission companies?

• Do alternative transmission project financing models affect siting decisions? Are DC lines treated differentlythan AC lines with regard to siting?

• How can cost/benefit analyses for transmission projects be improved to fully account for impacts on interstateand regional power markets?

2. Wind Energy

As noted in foregoing sections, EIA forecasts asubstantial increase in U.S. wind capacity over the nexttwo decades. Several factors have helped makeinvestment in new wind capacity attractive. First, thecost-performance of the technology has improveddramatically. In fact, over the past 30 years, the cost ofgenerating electricity from wind resources has declinedover 80 percent—it now ranges from 4 cents perkilowatt-hour to 6 cents per kilowatt-hour. In addition,wind benefits from a federal production tax credit and avariety of state-based initiatives to promote thedevelopment of new renewable resources, such as“renewable portfolio standards” and other policies. Forexample, EPAct05 extends the renewable energyproduction credit through 2007 for wind, biomass,geothermal, landfill gas, and small irrigation powerfacilities and municipal solid waste, and provides for anew category of tax credit bonds (Clean, RenewableEnergy Bonds or CREBs) for governmental entities andmutual or cooperative electric companies.

As a result, EIA predicts that 16,000 megawatts ofnew renewable capacity will be built by 2020 with thetotal growing to over 20,000 megawatts by 2030. Otheranalysts and the industry itself foresee still more rapidexpansion. The American Wind Energy Association(AWEA) expects 3,000 megawatts of new wind capacity tobe added in 2006 alone.28 Wind energy is expected todominate renewable capacity additions over the next 15years: it accounts for all of the new renewable energycapacity added by 2020, according to EIA forecasts. Stronggrowth in the wind industry has, of course, already beenunderway for some years. Specifically, U.S. wind capacityincreased from roughly 2,250 megawatts in 1999 to justover 6,000 megawatts in 2004.29 In addition, AWEAestimates that nearly 2,500 megawatts of additionalcapacity was installed in the United States in 2005 alone.30

Wind energy projects generally face some of thesame siting challenges that confront more traditionalenergy plants. Although wind power produces no airemissions, concerns are often raised regarding noise andvisual impacts, land requirements, or effects on wildlife—especially in scenic or exurban residential areas. Moreover,renewable technologies in general, including wind, oftenface additional siting and infrastructure challenges that areunique to the resources involved. First, while proximity or

access to fuel supplies is an important consideration formany types of energy projects, siting constraints areespecially important in the case of wind projects becausethere is no option but to place the turbines in locationswhere adequate wind resources exist. In fact, wind speedscan vary dramatically even across small areas, meaningnot only that proposed projects cannot readily be moved,but that careful mapping and analysis is needed to identifyand maximize the resource base.

Second, the site-specific nature of wind energy givesrise to sometimes demanding ancillary infrastructurerequirements. Because many of the best wind resources(and therefore best potential sites for wind projects) arenot located near population centers, transmissioninterconnection lines or system upgrades may benecessary to transport power where it is needed. Thisissue arises for other types of remotely sited powerprojects as well, but the intermittent and non-dispatchable nature of wind-based electricity generationcreates additional technical challenges related tointegrating wind resources in the dispatch regime of gridoperators with due regard for reliability. Transmissioncost hurdles are likely to be easier to overcome in caseswhere enhanced transmission capacity is needed for otherpurposes as well, or where new lines can concurrentlyserve wind and other energy supply projects.

Over the past several years, as wind energydevelopment has grown rapidly, developers andproponents have taken a number of steps to improve thesiting process, such as pursuing best practices, buildingcommunity support through outreach andcommunications, and devising new mitigation strategiesfor addressing wildlife and aesthetic concerns. States havealso taken steps to articulate clear siting guidelines andrequirements for wind facilities. Future siting challengesmay be further mitigated by the fact that much of thewind resource base on land is located in rural areas withlow population density and minimal competing uses forthe land. In fact, though the land requirements associatedwith substantial wind development can be significant, theturbines themselves occupy only a relatively small areaon the ground, leaving most of the land available forother productive uses. As a result, wind development inmany rural areas where turbines can be sited on existingagricultural and pasture land represents an opportunity



MAPLE RIDGE WIND FARM

The successful siting of Maple Ridge Wind Farm, a large wind project in rural New York, provides a recentexample of the potential for renewable energy development to coexist with traditional land uses while generatingbenefits that can help win the active support of local communities. With 120 turbines in operation as of early2006, Maple Ridge is already the largest wind development east of the Mississippi; when a second phase ofconstruction is complete, the project will encompass some 195 wind turbines and will be capable of generating320 megawatts of electricity, enough to supply the average power needs of as many as 300,000 homes.

Maple Ridge Wind Farm is located on Tug Hill Plateau, east of Lake Ontario, on roughly 33 square miles ofprivately held and mostly active agricultural land that is swept by powerful lake-effect winds. The turbines arelarge—each 320 feet tall—but they occupy only a small area on the ground. Thus, dairy farming and otherexisting land uses can continue even as power production generates new income for local landowners.*Landowners will receive lease payments ranging from $5,000 to $10,000 per year for each turbine on theirproperty; residents who live within 1,000 feet of turbines that are not on their property will receive somewhatsmaller payments (ranging from a few hundred dollars to more than $1,000 annually).

These economic benefits, together with the millions of dollars of new tax revenue the project will generatefor schools and towns, help account for the overwhelming support that Maple Ridge has received from locallandowners, the broader community, and nearby town governments. Because New York is a home-rule state,primary siting and permitting authority for the project rested with the adjacent towns of Martinsburg, Harrisburg,and Lowville. To go forward, the project also required permits from several county and state agencies, as well asfrom the U.S. Army Corps of Engineers.

In addition to the project’s immediate economic benefits, part of the support for Maple Ridge can beattributed to careful planning and a proactive approach to community outreach on the part of its developers,Oregon-based PPM Energy and Texas-based Horizon Wind Energy. Horizon and PPM met frequently withresidents and town boards in the four years leading up to project approval and construction and took steps toaddress a range of concerns, from the project’s impacts on bird and bat mortality to problems with local televisionreception. These and other issues—including concerns related to impacts on views, animal habitat, and noise andto the need for new or expanded roads to access the construction site and for other support infrastructure—werealso addressed in a comprehensive environmental review and impact analysis, which included specific post-construction monitoring and mitigation commitments on the part of project developers.

All of the conditions that have contributed to the success of Maple Ridge Wind Farm may not, of course,exist at every potential site. Elsewhere, the broader community has sometimes objected to project proposals evenwhere these proposals have the support of individual landowners and town governments. Some of the concernsthat motivate these objections are likely to abate with time as wind facilities become a more familiar feature of thelocal landscape. Meanwhile, the Maple Ridge experience stands as a striking example of how good project designand receptive communities can transform traditionally contentious siting and permitting processes to advance anew generation of energy technologies.

* For example, though the turbines are spread over approximately 21,000 acres, project construction was expected to disturb

only 700 acres of vegetation, most of it active agricultural land, according to the environmental impact statement (EIS).

Nearly all of the electrical cables required to connect the turbines were buried underground. Further land impacts,

according to the EIS, included the conversion of 140 acres to built facilities and approximately 73 acres of forest land to

successional shrubland. Project construction and operation was not expected to result in any adverse impacts on rare plants

or unique plant communities.


to complement rather than displace traditional land uses;the Maple Ridge Wind Farm discussed in a text box inthis section provides a potentially promising example inthis regard. In more congested areas or in areas where ahigh premium is placed on the visual features of ridgetops, however, the sheer amount of real estate needed forwind development, along with its location, can present asignificant hurdle, even though emission-free energysources will be in increasing demand.

The issues likely to come up in connection withoffshore wind development, on the other hand, aredifferent and—as recent, well-publicized difficulties witha proposal to build a wind farm off the coast ofMassachusetts would seem to indicate—could be moredifficult to navigate. Cape Wind is the first offshore windproject proposed in the United States: it would include130 turbines (for a total capacity of 420 megawatts),along with two underground 115-kilovolt transmissionlines, and would be located in federal watersapproximately five miles from Nantucket Island.

Although the project has supporters both inside andoutside of Massachusetts and although it was developedin response to the state’s renewable portfolio standard, apolicy intended to introduce more renewable resourcesinto the state’s electricity supply, Cape Wind hasencountered significant opposition from local groups andstate officials. Concerns have been raised about visualand noise impacts, safety issues associated with theproximity of the turbines to shipping lanes, impacts onthe visual features and recreational uses of NantucketSound, and impacts on fisheries and wildlife, includingimpacts on shorebirds, migratory birds, and other marineanimals, not to mention possible adverse impacts on thearea’s leading industry—tourism. The siting andpermitting process for the project, which involves severalfederal, state, and local agencies, began in 2001. Manyproject-related permits have been approved over theyears, including a state siting permit for the transmission

line connecting the wind farm to the on-shore grid. Andeven Congress has gotten involved, most recently byconsidering an amendment to a Coast Guardreauthorization bill that would give the governor theright to veto the project even though it is located infederal waters (this would effectively present the CapeWind project from moving forward as currently planned).

It should be emphasized that the Cape Windexperience may be atypical, given the project’sproximity to a coastal area with very high populationdensity, well-heeled opponents, and multiple competinguses for shipping, commercial fisheries, and recreation.Nevertheless, it does suggest that offshore windprojects—like other types of offshore energydevelopment—may confront a unique set of obstacles,particularly as coastal areas face increasing developmentpressures. Unlike Maple Ridge, coastal communitiesadjacent to offshore facilities will not automaticallyrealize the tangible economic benefits of lease paymentsand increased property taxes. These siting challenges aresignificant in light of the potential magnitude ofoffshore wind resources. According to recent DOEestimates the offshore resource base in the United Statescould support as much as 900,000 megawatts of newwind capacity.31

Prior to EPAct05, the Army Corps of Engineers wasresponsible for permitting offshore wind facilities infederal waters. (Projects within three nautical miles ofshore would fall under state jurisdiction.) EPAct05,however, transferred responsibility for siting thesefacilities to the Minerals Management Service (MMS),which manages other energy and mineral resources onthe Outer Continental Shelf. In December 2005, MMSissued an Advanced Notice of Proposed Rulemaking(NOPR) on the siting of alternative energy projectsoffshore. As the MMS rulemaking process movesforward, siting prospects for offshore wind projects arelikely to become clearer.


KEY QUESTIONS:

• What are the primary siting concerns for onshore wind projects; how problematic are they; and are they morecritical than regulatory, economic, or technology concerns?

• How effectively has the wind industry addressed siting concerns? Do these concerns require regulatoryintervention and if so by whom?

• Are impacts on birds and bats sufficiently well understood and is there consensus on a research agenda tosupport improved performance?

• What are the infrastructure implications of substantial renewable energy development in remote areas? Aretransmission constraints likely to be a major impediment and if so what aspects of this issue are mostchallenging?

• Are opportunities for synergistic land uses on agricultural and forest lands well understood? How can the rightparties be brought together to identify and exploit these opportunities?

• What are the unique siting and licensing challenges for offshore wind projects and how are differentstakeholders addressing these challenges?


3. Nuclear Power

Currently, there are 103 commercial nuclear powerplants operating in the United States generating about 20percent of the country’s electricity. No new nuclear plantshave been ordered in this country since 1978, and no plantordered since 1973 has been completed. The last nuclearplant to come on line began operations in 1996;meanwhile, several plants that once operated commerciallyhave been retired and shut down. As the Commissionnoted in its 2004 report, a number of challenges must beovercome to make possible an expansion of nuclear power-generating capacity in the United States, includingreducing costs, making further improvements in safety andsecurity, addressing proliferation risks, and resolving issuesrelated to nuclear waste storage and public acceptance. Atthe same time, today’s nuclear power plants provide nearly70 percent of the nation’s carbon-free generation andnuclear fuel is in abundant supply.

EPAct05 provides a number of incentives for theconstruction of new nuclear plants, including a 1.8 centper kilowatt-hour tax credit for eight years for up to 6,000 megawatts of new capacity, and government supportto offset the financial impact of delays beyond thecompany’s control for up to six new plants. As notedpreviously, EIA projects that 6,000 megawatts of newnuclear capacity (i.e., six new reactors) will be builtbetween 2005 and 2020, when the tax credit expires.While this expansion appears modest compared to totalanticipated capacity additions in the electric power sector,when combined with 3,200 megawatts of projecteduprates at existing nuclear facilities, it represents a 9percent increase in nuclear capacity by 2020.32

Government projections notwithstanding, noelectricity generating technology is likely to face moreformidable challenges to the siting of new facilities thannuclear power. A recent survey by the Galluporganization found that while 59 percent of Americansfavor the use of nuclear power, less than half (42 percent)favor new nuclear plants in their area.33 Public opinionpolls have historically shown that support for new plantsis stronger in communities currently hosting a plant site.What these polling results mean in terms of actualattitudes in the face of a new proposal is not clear, exceptthat they suggest that it may be difficult to site newnuclear plants outside of pre-existing nuclear plant sites.

In 1989, the NRC implemented three majorchanges to its licensing process for new nuclear power

plants with respect to design certification, early sitepermits, and combined construction and operatinglicenses. These changes were designed to encourage theearly resolution of safety, siting, and licensing issues inadvance of major financial commitments, therebyavoiding many of the permitting delays that occurredduring the 1970s and 1980s.

• Design certification — The design certificationprocess allows the NRC to approve reactor designsthrough public rulemaking. Design approvals are validfor 15 years.

• Early Site Permits — This process allow applicants toobtain approval of sites for new reactor units separatefrom an application for a construction permit orcombined construction and operating license so thatapplicants can resolve site-specific issues early on in theprocess. These permits are good for 10 to 20 years andcan be renewed for an additional 10 to 20 years.

• Combined construction/operating license (“COL”) —Applicants may seek a license authorizing bothconstruction and operation of a plant through a singleapplication process, rather than the two separateapplication processes that were previously needed.

In February 2002, the Department of Energy (DOE)launched its Nuclear Power 2010 (NP2010) initiative, acost-sharing program with the nuclear industry to test theNRC’s new licensing regime. As part of the NP2010program, three companies have now begun the process ofobtaining early site permits, though none has yet ordered anew reactor unit from a manufacturer. Specifically, ExelonGeneration Company LLC, Entergy’s System EnergyResources Inc., LLC, and Dominion Nuclear North AnnaLLC have applied for Early Site Permits to add new reactorunits at existing nuclear power plant sites. Despite strongsupport for new plants from the Bush Administration, andfrom some local elected officials, opponents have raised anumber of objections, many of which reprise concerns thatwere raised in connection with the existing facility at thetime each was originally licensed. In these cases, criticsargue that concerns about issues such as water usage andpublic safety remain pertinent because any existingimpacts will be compounded by the addition of a newreactor unit. While new reactor designs have higher safetymargins and employ passive safety features, opponents alsopoint to new concerns, such as the threat of terrorist


KEY QUESTIONS:

• What has been learned thus far from the early site permit process? Are new siting issues emerging that were notencountered during the 1970s, or are the major issues primarily the same?

• What new siting challenges and requirements for nuclear reactors might arise from the inability of the federalgovernment to license a permanent waste repository? Will the evolution of on-site spent fuel storagetechnology (casks) mitigate to some degree the unresolved licensing of the Yucca Mountain repository?

• What lessons, if any are applicable to the U.S. regulatory environment, can be learned from the experience of other countries (e.g., China, France, Japan, Taiwan) that are siting and in some cases building new nuclear reactors?

• Will “site banking” or “advanced siting” options provide opportunities for a project to move to development iffinancial and other factors warrant?

• What role will currently high natural gas prices and projections of future prices play in the deliberations ofstate regulators when deciding whether to site and then authorize utilities to recover costs associated with newnuclear plant investments?

• Will climate change considerations facilitate the siting process for new nuclear power plants?

• Is it financially and otherwise possible to develop new nuclear plants without securing advance long-termfinancial commitments from utilities or from their regulators?

• Should the NRC seek to establish a joint licensing-siting process with states where utilities are consideringnuclear plant projects?

• Will new reactor designs—so-called inherently safe/modular/standard design prototypes—facilitate siting decisions?

attacks at nuclear facilities. In addition, because of delaysin licensing Yucca Mountain as a permanent wastedepository, critics assert that existing nuclear reactor siteswill in effect serve as semi-permanent waste repositories.They argue that adding new reactor units will only createadditional waste that must be stored on site for someunknown period of time.34

Consortia led by NuStart Energy Development35 andDominion are participating in the NP2010 program toprepare three COL applications for new reactor designsthat they anticipate filing in 2007 and 2008 under theNP2010 program. Two of the three proposed reactorswould be at existing sites, while the third would be at a sitewhere reactor construction was begun but not completed.

In addition to the companies participating in theNP2010 program, six other utility companies have nowinformed the NRC that they intend to submit COLapplications for new reactors in the 2007–2008 timeframe.

Overall, nine companies have expressed their intention tofile applications for as many as 19 reactors in ten states.None of the utilities has yet made a commitment to actuallybuild plants at sites for which they obtain COL licenses.

While the NRC is the primary governing body forlicensing new facilities, siting remains a state responsibilityand other regulatory agencies could well involve themselvesin both licensing and siting processes. For example, ifutilities are seeking to include the costs of new facilities intheir retail rate base in the states where a generation-relatedrate base exists, they will require a “certificate of need” fromthe state public utility commission. Utilities must alsoacquire water discharge permits under the NationalPollutant Discharge Elimination System (“NPDES permit”)for the thermal pollution from the plant. Although EPAsupervises the NPDES program, individual states reviewapplications and issue the permits.


4. Coal Technology,Integrated Combined CycleGasification & CarbonCapture and Storage

Conventional, steam-electric power plants fired bypulverized coal currently account for more than 50percent of U.S. electricity generation. According to therecent EIA forecast discussed in Section D, coal will alsoaccount for a greater share of the overall increase inelectric generation capacity expected to occur by 2030than any other fuel or technology. Given the significantgreenhouse gas emissions associated with conventionalcoal technology, the implications of these projections interms of future efforts to address climate-change risks aresobering. Whether and how climate considerations willbe addressed in the sitting and permitting process fornew coal generating plants going forward is therefore animportant question. In addition, other coal-relatedissues—from concerns about the environmental effectsand infrastructure requirements associated with miningand transporting coal, to concerns about local air qualityimpacts and water requirements—are likely to play a rolein determining what types of coal facilities can be sited inthe future and where. Recent experience offers relativelylittle guidance in this regard, since electric-generatingcapacity expansions over the last two decades have beendominated by natural gas technologies. This seems likelyto change, however, in the wake of a sharp and sustainedincrease in natural gas prices that is eliciting a growingnumber of proposals to construct new coal-fired powerplants around the country.

To date, reaction to proposed new coal plants hasbeen mixed, depending on the location, perceivedenvironmental impacts, and size of the facility, theeconomic base of the host community, and otherattributes of the project. In Nevada, for example, aproposed new coal plant near Reno was stalled by acombination of public opposition and changed utilityregulations, whereas another 750-megawatt coal projectproposed near Mesquite has encountered little organizedopposition and appears to be moving forward with thesupport of local officials.36 Not surprisingly, plantsproposed in or near more densely populated areas arelikely to encounter greater opposition on the basis ofconcerns about local air quality and other site-specificenvironmental impacts. Other objections, however,particularly those related to climate change, are unlikely

to be affected by location and may lead to newpermitting or siting requirements in the future. Forexample, Massachusetts, Oregon, and Washington nowrequire that power plant developers offset at least aportion of carbon emissions associated with newfacilities. More recently, the California EnergyCommission has adopted a policy establishinggreenhouse gas emissions performance standards for allbaseload generation seeking new long-term investmentsfrom California utilities.37

To the extent that climate concerns are increasinglyincorporated into infrastructure investment decisions—either by being internalized through a mandatory,market-based emissions-reduction program such as theCommission has recommended, or through moreexplicit consideration in future siting and permittingprocesses—opportunities are likely to grow foralternatives to conventional pulverized-coal technology.IGCC technology, in particular, is viewed as promisingbecause, besides having lower conventional-pollutantemissions, it could allow for continued use of coal whilealso making possible the cost-effective capture andsequestration of carbon emissions.38 Given the relativeabundance and low-cost of coal—not only in the UnitedStates but elsewhere around the world—the importanceof developing low-carbon coal technologies that cansimultaneously advance multiple national and globaleconomic, environmental, and energy security goals isdifficult to overstate. In fact, the Commission concludedin its 2004 report that the future of coal and the successof greenhouse gas mitigation policies could well hingeon whether carbon-capture-ready IGCC technology canbe successfully commercialized over the next fewdecades. The expectation that coal IGCC will need toadvance to address climate concerns is also reflected inEIA’s latest forecast, which anticipates the constructionof 9,000 megawatts of new IGCC capacity by 2020 and82,000 megawatts by 2030.

Both IGCC plants themselves, as well as anyassociated carbon storage facilities, are likely to presentinfrastructure siting challenges. As has already beennoted, most significant electric generating capacity


expansions in the last decade or more have involvednatural gas facilities. How receptive policymakers andthe public will be to new coal plants—even if theseplants employ the latest pollution control equipment andutilize advanced technologies—is difficult to gauge andmay vary widely in different parts of the country. Ingeneral, the fact that IGCC has several advantages, froman environmental standpoint, over conventionalpulverized-coal technology should help to overcomesiting obstacles. For example, the next-generation IGCCplant is expected to achieve reductions in sulfur dioxide,nitrogen oxides and mercury that are comparable to, orgreater than pulverized coal plants with advanced post-combustion pollution control equipment. IGCC plantsalso require 30–60 percent less water than pulverizedcoal plants. Access to water is often one of the mostcontroversial issues in the permitting and siting of powerplants.39 Finally, because they are more efficient thanconventional coal plants and more amenable to carboncapture and storage (CCS), IGCC plants are viewedmore favorably by many environmental advocates.

Not surprisingly, the infrastructure sitingchallenges potentially associated with the large-scalecapture and permanent sequestration of carbon ingeologic formations are not yet well understood, giventhe relative short history of this technology. CCS is mostlikely to be feasible and cost-effective at large industrialfacilities or electric power plants where carbon dioxidecan be collected before it is released to the atmosphereand then compressed and transported via pipeline to ageologic repository or to enhanced oil recovery facilities.Carbon injection per se is not new and has been used fordecades in the petroleum industry to boost productionfrom underground oil and gas repositories. In fact,opportunities in some regions of the country to usecaptured carbon dioxide for enhanced oil recovery maysubstantially improve the economics of CCS and help toovercome associated siting challenges, especially in anenvironment of continued high oil prices.

In any case, carbon storage as part of a climate-change mitigation strategy would have to be undertakenon a scale that is orders of magnitude greater thancurrent levels and could present technical challenges andinfrastructure issues that have not yet been encounteredin today’s smaller-scale commercial applications of CCStechnology. Understanding these issues will likelyrequire substantial research, as well as several large-scaledemonstration projects during the next 10–15 years to

develop commercial experience. DOE and a group ofindustry co-sponsors are funding a large scaledemonstration project for IGCC with CCS known as the“FutureGen Initiative;” in addition, DOE has anextensive carbon sequestration research program.40

How aggressively CCS will be deployed as a carbonmanagement strategy in the future will depend on avariety of factors. On the one hand, CCS has emerged asa central component of most proposals for technologicalmeasures to reduce global risks from human-inducedclimate change. The importance of this technology wasrecently emphasized in an October 2005 Special Reportby the Intergovernmental Panel on Climate Change(IPCC), which concluded that CCS has the potential toreduce overall climate change mitigation costs andincrease flexibility in achieving greenhouse gas emissionreductions.41 On the other hand, given the current lackof a market incentive for limiting carbon emissions, EIA’slatest forecast shows no construction of CCS capacity by2030. As noted above, however, market conditions forCCS could change rapidly in regions whereopportunities exist to take advantage of potentialapplications for enhanced oil recovery.

Meanwhile, significant cost uncertainties andlimited experience with large-scale field applications ofCCS technology make it difficult to predict itsdeployment even in response to mandatory emissionlimits. Incentives and early deployment programs, such as those recommended by the Commission in its2004 report, can help to stimulate cost reductions thatlead to further deployment in later years. (TheCommission has proposed demonstration projectstotaling 4,000 megawatts of new IGCC with CCScapacity.) Over a longer timeframe and with higher levelsof incentives or more stringent greenhouse gas reductiontargets, penetration of CCS could be significantly greater.For example, one scenario developed by researchers atthe Pacific Northwest National Laboratory suggests thatthe adoption of policies to stabilize atmospheric levels ofcarbon dioxide at 550 parts per million by 2050, wouldresult in the construction of 536,000 megawatts (roughly500 units) of coal IGCC capacity with CCS.42

Although the theoretical carbon-storage capacity ofunderground geological repositories in the United Statesis plentiful, large-scale deployment of CCS wouldnevertheless require significant investments ininfrastructure, possibly including thousands of miles of


Figure 6Potential Sites for Geologic Carbon Sequestration

Capturing and permanently sequestering carbon in geologic formations offers a means to prevent emissions released

by fossil fuel use from reaching the atmosphere and thus may play an important role in the array of strategies used to

mitigate climate change risks in the future. Carbon capture and sequestration is most likely to be feasible and cost-

effective at large industrial facilities or electric power plants where carbon dioxide can be collected before it is released

to the atmosphere and then compressed and transported via pipeline to a geologic repository. Potential repositories

include depleted oil and gas fields, unmineable deep coal seams, or deep saline formations. Current estimates suggest

that in the United States, deep saline formations alone can potentially hold up to 3 trillion tons of carbon dioxide or

roughly 600 times current annual U.S. emissions. Given that many of these formations have safely stored hydrocarbons

for millennia, there is considerable optimism that they can reliably retain injected carbon dioxide.

The map below details potentially promising sequestration sites in (1) depleted gas fields, (2) depleted oil fields, (3)

unmineable coal seams, (4) deep saline formations, and (5) basalts. Each geologic formation presents a unique set of

characteristics, storage capacities, and challenges that must be carefully understood before large-scale sequestration

occurs. On the whole, however, potential sites are numerous and are, for the most part, close to much of the existing

fossil-fuel-based electric industry infrastructure.

Fossil Power Plants Potential Sequestration Areas

Adapted from Battelle, 2004


dedicated carbon dioxide pipelines.43 In addition, underoptimistic deployment scenarios, many thousands ofwells could be required to inject carbon dioxide intounderground repositories.44 Whether this type ofinfrastructure would be likely to encounter significantobstacles related to siting and public acceptance is anopen question. The limited research available on thistopic—most of which has focused on general perceptionsof CCS, rather than on likely public reaction if new wellsand reservoirs are proposed for a specific community—suggest that CCS is not well known or understood by thepublic. When introduced to CCS along with a range ofother options, most respondents prefer what theyconsider to be alternatives such as energy efficiency orrenewable energy for reducing emissions.45 A morefavorable view of the technology may emerge in thefuture as the public becomes increasingly aware of themagnitude of the emission reductions that may ultimatelybe necessary to reduce climate change risks.46 In sum,efforts to educate the public about CCS and to providefor public input on related siting and other decisions arelikely to be critical to advancing this technology.

Beyond siting and infrastructure issues, the mainchallenges to IGCC and CCS are economic, regulatory, andinstitutional.47 On the regulatory and institutional front, anew framework would have to be developed to governCCS. Currently, the use of underground carbon-dioxideinjection for enhanced oil recovery is regulated under theSafe Drinking Water Act and thousands of wells have beenpermitted under the Underground Injection Control (UIC)program. In addition, a small number of experimentalwells have been permitted to inject carbon dioxide forpurposes other than enhanced oil recovery.48 No provisionsare in place, however, to regulate the long-term storage ofcarbon dioxide which—because it would require measuresto prevent venting back to the atmosphere—could involvenew provisions for risk assessment, for monitoring theperformance of wells, for assuring the permanence of thecarbon stored, and for managing long-term liability if areservoir leaks.49 Large-scale CCS projects would likelyalso require the assessment of additional risks, includingthe risk of large releases of carbon dioxide to nearbypopulation centers, risks to groundwater quality, and risksfrom reactivity with underground minerals and solutions.50

Key Questions

• Should climate considerations be incorporated more explicitly into siting and permitting processes for new coalfacilities and if so, how?

• Will the smaller “environmental footprint” of IGCC make these plants easier to site than conventionalpulverized-coal power plants?

• How will public perceptions of CCS affect the ability to site power plants with carbon storage? Are there stepsthat can be taken now to facilitate future siting?

• How should “sequestration readiness” be incorporated into siting reviews of IGCC projects, in light ofexpectations that IGCC will be commercially ready ahead of sequestration options?

• Are there optimal and sub-optimal regions or localities for the siting of IGGC plants?

• Can considerations related to potentially limited IGCC and CCS siting options—and to the transmissionsystem expansions that may be necessary to accommodate these siting constraints—be integrated into state andregional planning processes?

• What lessons from the siting of other energy technologies are most relevant to CCS?

• How will the developing regulatory regime for CCS shape decisions on the siting of IGCC with CCS?


5. Liquefied Natural Gas (LNG)

Historically, U.S. demand for natural gas has beenlargely met by domestic resources, with imports fromCanada and small volumes imported in the form of LNG.As indicated in earlier sections, U.S. demand for naturalgas is expected to continue to grow even as productionfrom traditional North American sources has begun toplateau. In its 2004 report, the Commission noted recentindustry predictions suggesting that in spite of increaseddrilling activities, natural gas production from traditionalNorth American sources will remain flat and will be ableto satisfy only 75 percent of domestic demand by 2025,with the result that future demand growth will need to bemet through imports and from Alaska.51

A critical question for natural gas, therefore, iswhere future supplies will come from, given projectedsteady growth in U.S. demand. Most experts expect thatpart of the long-term answer will include theconstruction of a major new pipeline to ship gas fromAlaska’s North Slope together with a substantial increasein imports of LNG, which can be delivered from a varietyof distant sources via tanker ship. This section focuseson the infrastructure needs associated with a significantexpansion of LNG imports, which require largeterminals to receive tanker shipments, re-gasify thenatural gas, and deliver it into existing distributionsystems.52 (The Alaska natural gas pipeline is discussedin the next section.)

Currently LNG plays only a small role inaugmenting domestic supplies: it accounted for slightlyless than 3 percent (650 billion cubic feet) of the nation’stotal consumption of natural gas in 2004. Notsurprisingly, LNG imports play a more significant role insome of the regions where LNG terminals already exist.The United States currently has four operating onshoreLNG import facilities. They are located in Everett,Massachusetts; Cove Point, Delaware; Elba Island,Georgia; and Lake Charles, Louisiana. In addition, anoffshore LNG re-gasification terminal—the Gulf GatewayEnergy Bridge—recently commenced operation in theGulf of Mexico. Each of the four existing onshore terminalfacilities in the United States was put into service wellover two decades ago during an initial wave of LNGenthusiasm driven by natural gas shortages at that time.

Changes in market conditions, the regulatoryenvironment, and the politics of siting since these fourterminals were constructed leave considerableuncertainty regarding the siting of new facilities,particularly in regions outside the Gulf of Mexico. Ingeneral, onshore facilities fall under the primaryjurisdiction of FERC while offshore projects are subjectto oversight by the U.S. Coast Guard. Coastal states alsohave an important role to play in the siting processthrough their “consistency reviews” of both onshore andoffshore facilities under the Coastal Zone ManagementAct (CZMA). FERC authority to site LNG facilities wasrecently clarified in EPAct05 with the intention ofimproving the regulatory environment for siting thesefacilities. As noted above, however, federal approval isnot necessarily sufficient to move projects forward, asrecently evidenced by the determined resistance of stateand local officials to efforts to site a second onshore LNGterminal in Massachusetts.53

EIA’s forecast indicates that LNG imports willincrease by more than 400 percent by 2020 (an increaseof 3 tcf per year over the estimated 2005 levels) and 500percent by 2030 (an increase of 3.7 tcf, above today’slevels). To accommodate this increase, EIA estimates thatdomestic LNG terminal capacity will have to nearlyquadruple from its current level of roughly 1.4 tcf peryear to 5.4 tcf per year in 2020. EIA anticipates thatroughly half the expected increase will likely be achievedby expanding three of the four existing onshore LNGterminals, Cove Point, Elba Island, and Lake Charles.According to its projections, the only new U.S. facilitieswill be built along the Gulf Coast, where a long historyof energy development and familiarity with energyinfrastructure is likely to ease the siting process.54 Infact, two facilities are under construction in this regionpresently (Freeport and Sabine Pass) and several moreare anticipated. In addition, EIA expects that three newfacilities will be built to service the U.S. gas market fromLNG terminals located on foreign territory, one comingonline in Baja Mexico and two on the eastern coast ofCanada. Consistent with expectations of strong andgrowing U.S. demand for LNG, industry developers areactively considering some 40 additional facilities to serveNorth American gas markets (see Figure 7).


As of March 8, 2006US Jurisdiction

FERC

MARAD/USCG* US pipeline approved; LNG terminal pending in Bahamas

27

A

3 4

21

3619

38

37

13

B ,23

25

92420

C ,35

4012

5,30

8

6,31

4126

E

14

16

15

1718

42

711

29

102228

39

3334

D,12,32

43

CONSTRUCTEDA. Everett, MA: 1.035 Bcfd (SUEZ/Tractebel-DOMAC)B. Cove Point, MD: 1.0 Bcfd (Dominion -Cove Point LNG)C. Elba Island, GA: 1.2 Bcfd (El Paso -Southern LNG)D. Lake Charles, LA: 1.5 Bcfd (Southern Union -Trunkline LNG)E. Gulf of Mexico: 0.5 Bcfd (Gulf Gateway Energy Bridge -ExcelerateEnergy)

APPROVED BY FERC1. Lake Charles, LA: 0.6 Bcfd (Southern Union -Trunkline LNG)2. Hackberry, LA: 1.5 Bcfd (Cameron LNG -Sempra Energy)3. Bahamas: 0.84 Bcfd (AES Ocean Express)*4. Bahamas: 0.83 Bcfd (Calypso Tractebel)*5. Freeport, TX: 1.5 Bcfd (Cheniere/Freeport LNG Dev.)6. Sabine, LA: 2.6 Bcfd (Cheniere LNG)7. Corpus Christi, TX: 2.6 Bcfd (Cheniere LNG)8. Corpus Christi, TX: 1.0 Bcfd (Vista Del Sol -ExxonMobil)9. Fall River, MA: 0.8 Bcfd (Weaver's Cove Energy/Hess LNG)10. Sabine, TX: 1.0 Bcfd (Golden Pass -ExxonMobil)11. Corpus Christi, TX: 1.0 Bcfd (Ingleside Energy-Occidental Energy Ventures)

APPROVED BY MARAD/COAST GUARD12. Port Pelican: 1.6 Bcfd (Chevron Texaco)13. Louisiana Offshore: 1.0 Bcfd (Gulf Landing -Shell)

CANADIAN APPROVED TERMINALS14. St. John, NB: 1.0 Bcfd (Canaport-Irving Oil)15. Point Tupper, NS: 1.0 Bcf/d (Bear Head LNG -Anadarko

MEXICAN APPROVED TERMINALS16. Altamira, Tamulipas: 0.7 Bcfd, (Shell/Total/Mitsui)17. Baja California, MX: 1.0 Bcfd, (Energy Costa Azul-Sempra)18. Baja California -Offshore: 1.4 Bcfd, (Chevron Texaco)

PROPOSED TO FERC19. Long Beach, CA: 0.7 Bcfd, (Mitsubishi/ConocoPhillips-Sound Energy Solutions)20. Logan Township, NJ: 1.2 Bcfd (Crown Landing LNG -BP)21. Bahamas: 0.5 Bcfd, (Seafarer -El Paso/FPL )22.Port Arthur, TX: 1.5 Bcfd (Sempra)23. Cove Point, MD: 0.8 Bcfd (Dominion)24. LI Sound, NY: 1.0 Bcfd (Broadwater Energy -TransCanada/Shell)25.Pascagoula, MS: 1.0 Bcfd (Gulf LNG Energy LLC)26. Bradwood, OR: 1.0 Bcfd (Northern Star LNG -Northern Star Natural Gas LLC)27.Pascagoula, MS: 1.3 Bcfd (CasotteLanding-ChevronTexaco)28. Cameron, LA: 3.3 Bcfd (Creole Trail LNG -Cheniere LNG)29. Port Lavaca, TX: 1.0 Bcfd (Calhoun LNG -Gulf Coast LNG Partners)30. Freeport, TX: 2.5 Bcfd (Cheniere/Freeport LNG Dev. -Expansion)31. Sabine, LA: 1.4 Bcfd (Cheniere LNG -Expansion)32. Hackberry, LA: 1.15 Bcfd (Cameron LNG -Sempra Energy-Expansion)33. Pleasant Point, ME: 0.5 Bcfd (QuoddyBay, LLC)34. Robbinston, ME: 0.5 Bcfd (DowneastLNG -Kestrel Energy)35. Elba Island, GA: 0.9 Bcfd (El Paso -Southern LNG)

PROPOSED TO MARAD/COAST GUARD36. California Offshore: 1.5 Bcfd (CabrilloPort -BHP Billiton)37. So. California Offshore: 0.5 Bcfd, (Crystal Energy)38. Louisiana Offshore: 1.0 Bcfd (Main Pass McMoRanExp.)39. Gulf of Mexico: 1.0 Bcfd (Compass Port -ConocoPhillips)40. Gulf of Mexico: 1.5 Bcfd (Beacon Port Clean Energy Terminal-ConocoPhillips)41. Offshore Boston, MA: 0.4 Bcfd (Neptune LNG -Tractebel)42. Offshore Boston, MA: 0.8 Bcfd (Northeast Gateway -ExcelerateEnergy)43. Gulf of Mexico: 1.4 Bcfd (Bienville Offshore Energy Terminal -TORP Technology)

Figure 7

Existing and Proposed North American LNG Terminals

Source: Federal Energy Regulatory Commission.

effective and fair regulatory process. The uniqueproperties of natural gas could make LNG re-gasificationfacilities an appealing terrorist target, although it is notclear that the hazards are greater than those that exist atother large energy and chemical facilities.

At the same time, the emergence of new technologythat allows re-gasification to occur aboard ships so thatthe dry gas can be placed directly into existing pipelinescould substantially mitigate current safety concerns. Ifcost-effective, this technology could substantially reducethe need for large on-shore facilities. The siting equationfor much smaller on-shore processing facilities could bevery different, given that the potential risk associatedwith accidents, attacks, or explosions at such facilitieswould be substantially reduced.

Another set of concerns, of course, relates to thegeographic distribution of proposed new LNG capacity.Recent hurricanes in the Gulf region highlight the


In general, opposition to the siting of LNG facilitiescomes from local groups concerned about safety. LNG issuper-cooled natural gas with an energy density 600 timesthat of gaseous methane. While LNG itself is notflammable, it will re-vaporize if accidentally released tothe atmosphere. In vapor form, the natural gas wouldpresent a combustion hazard under certain conditions.The large quantities of LNG handled by transportationvessels and re-gasification facilities make this a realconcern for local communities. Industry proponents insistthat LNG can be handled safely and point to the extensivesafety record of the industry. (Indeed, there have been nomajor shipping incidents since the first LNG shipment leftport nearly a half century ago.55) For the most part,onshore LNG facilities can also boast exceptional safetyrecords, though there have been a small number of seriousaccidents at such facilities around the world over the past50 years. Recent anxiety over terrorist attacks andinfrastructure vulnerability add another dimension to thesafety and siting challenges that must be balanced in an

2010 2015 2020 2025 2030 2005

Total LNG Import Capacity

Trill

ion

cu

bic

feet

per

yea

r

0

1

2

3

4

5

6

7

0

1

2

3

4

5

6

7

2010 2015 2020 2025 2030 2005

Total LNG Import

New Terminals

Existing Onshore Terminals

Trill

ion

cu

bic

feet

per

yea

r

Figure 8

Total LNG Imports / Total LNG Import Capacity

EIA projections indicate a growing demand for LNG in the years ahead. Import capacity is projected to more than

quadruple from 2005 levels by 2030 as existing terminals are expanded and new facilities are constructed.Total

LNG imports are expected to rise even more quickly, from roughly 0.71 tcf/yr in 2005 to 4.36 tcf/yr in 2030, an

increase of over 500 percent.



disadvantages of concentrating LNG facilities in oneregion of the country. These concerns must be consideredin future LNG terminal siting processes, along with thevarious local-, regional-, and national-level risks andbenefits associated with LNG infrastructure.

Whether siting and permitting processes can bedeveloped that allow for an effective balancing of all ofthese concerns while satisfying the different public andprivate interests involved remains to be seen. In its 2004report, the Commission expressed its support for a strong

federal role in the siting of LNG facilities, but alsounderscored the importance of “cooperative federalism”in effectively implementing LNG proposals. Thiscooperative model recognizes the different authoritiesalready delegated to FERC, to coastal states, and to theCoast Guard (in the case of off-shore facilities), and seeksto ensure that states’ substantial interests in environmentalprotection, land use, and other issues are accommodatedthrough a variety of means—including, for example, thejoint preparation of environmental reviews by state andfederal agencies.

Key Questions:

• Are EIA estimates for future increases in LNG imports consistent with plans announced by the LNG industryfor expanding and constructing re-gasification facilities?

• Given the likelihood that new LNG facilities will initially be sited in the Gulf, what are the implications offurther concentrating natural gas supplies in this region? What, if any, steps should be taken to geographicallydiversify LNG infrastructure in the United States? Specifically, are there particular, regional infrastructure-diversity considerations that should be taken into account by FERC and other agencies in reviewing LNGproposals, especially where those proposals involve siting new LNG terminals in the Gulf as compared to otherregions that face growing gas demand?

• What are the primary concerns over safety, environmental impacts, resource reliability, and regulatory oversightwith regard to LNG siting and are these concerns substantially different than those encountered by other, morefamiliar, large energy and industrial facilities?

• What did EPAct05 do to address LNG siting and what is the outlook for the effectiveness of these provisions?

• What are the best ways to balance the local, regional, and national interests associated with large infrastructureprojects such as LNG facilities? Does the current process work and if not, what best practices would promotethe kind of “cooperative federalism” advocated in the Commission’s 2004 report?

• For regions with multiple competing proposals for new LNG projects, can regional analyses of the need foradditional natural gas supplies substantially aid the siting process, or will such inquiries simply add a furtherlayer of unneeded review and collateral approvals?

• Will new re-gasification technology reduce the requirements (and footprint) of on-shore facilities? Will itfacilitate consideration of siting in states currently opposed to LNG facilities?


6. Alaska Natural Gas Pipeline

The siting and financing challenges associated withan Alaska natural gas pipeline are, of course, quitedifferent from those that pertain to LNG and othertechnologies discussed in this section. Here the biggestobstacles have been the high cost and lengthy timeperiod required to construct the pipeline, although sitingand permitting uncertainties have also contributed to thedifficulty of moving this project forward. Recentdevelopments, however, may signal progress on theAlaska pipeline issue.

First, a number of provisions to promote thepipeline were included in EPAct05, which requires thatFERC submit regular reports to Congress describing theprogress made in licensing and constructing the project.In its most recent report detailing the status of theproject, FERC indicates that there are now threepotential options under consideration. Two would

involve constructing a major pipeline that would runthrough parts of Alaska and Canada, ultimatelyconnecting with the Alberta hub and the existing NorthAmerican pipeline network. A third would involveconstructing a shorter pipeline from the North Slope toAnderson Bay near Valdez, Alaska, where a liquefactionfacility would be built to send the gas into the globalLNG marketplace.56

FERC’s recent status report also outlines variousactions recently taken by the U.S. Congress, the Alaskalegislature, and the Canadian government to helpfacilitate this massive undertaking and indicates thatnegotiations under the Alaska Stranded GasDevelopment Act (SGA) are currently the focal point ofactivity. The SGA permits the state to negotiate terms ofpayment in lieu of taxes and royalties. Pipelinedevelopers have indicated that they will only moveforward with their applications once they have clarifiedfinancial terms with the state—at present, the state of

Figure 9Proposed Route for the Alaska Natural Gas Pipeline


Alaska has negotiated with only one group. OnFebruary 21, 2006, the Alaska Governor’s officeannounced that it had reached an initial agreement on afiscal contract for the gas pipeline, but this agreementhas yet to be approved by the state legislature.Following resolution with the state, numerous logisticalchallenges will still need to be overcome including thetiming of field surveys, the coordination of permits fromall relevant agencies, implementation of the federal loan

guarantee program, and the resolution of Canadianregulations. Market developments with respect to theavailability and cost of gas, steel, and labor may alsocreate new challenges, particularly to the extent they areimpacted by a separate arctic pipeline proposal aimed atdelivering gas from the Mackenzie Delta of Canada tothe lower 48 states. It is generally felt that steel andlabor constraints would limit the ability of both projectsto go forward simultaneously.

KEY QUESTIONS

• What remaining major policy barriers (state, federal, or international) need to be resolved before the pipelineproject can move forward?

• Are the siting and permitting requirements for the pipeline considered manageable? Can the federalgovernment or the state of Alaska do more to speed this process without compromising the important elementsof these provisions?

• How have the economics of the pipeline changed since the last major feasibility study was completed five yearsago? How would the economics and timing of the Alaska natural gas pipeline be impacted by initiation of theMackenzie pipeline project?

• Would pre-construction commitments to contract for the Alaska gas facilitate the choice of pipeline route andits implementation?

• Which is the most likely market for natural gas from Alaska—the West or the Midwest—and how will theanswer to this question influence final siting decisions?

• Should LNG options be considered as a complement to the pipeline for shipping part of Alaska’s natural gas tothe lower 48 and if so, what are the siting consequences for the pipeline and for LNG processing facilities?

7. Biofuels

Despite longstanding efforts to promote alternativesto petroleum-based transportation fuels as a means ofdiminishing oil dependence and reducing air emissions,the contribution of biomass-based fuels to the nation’soverall energy mix has, until recently, remained relativelysmall. The biofuels industry may be on the verge of aperiod of rapid expansion, however, as a result ofrenewed concern about the geopolitical, economic, andenvironmental risks associated with continued, near-exclusive reliance on petroleum-based fuels, the recentupturn in world oil prices and associated concern overfuture competition for world oil supplies with China andIndia, and (perhaps more importantly) as a result of newmandates and incentives to promote alternatives.

Perhaps the most important of these mandates is thenew federal Renewable Fuels Standard (RFS) established inEPAct05. It requires that at least 4 billion gallons ofrenewable fuels be used in 2006, ramping up to at least 7.5billion gallons in 2012. This represents an annual increaseof approximately 700 million gallons per year. EIAestimates that the RFS will reduce U.S. oil consumption by80,000 barrels per day by 2012. (Here it is worth notingthat while the term “renewable fuel” or “biofuel”—both inEPAct05 and in other contexts—generally includesbiodiesel and other biomass-derived liquid fuels, ethanol isexpected to be the dominant form of biofuel in the UnitedStates for some time to come. Accordingly the remainder ofthis discussion focuses on ethanol.) To implement the RFS,EPA is developing rules that require fuel refineries,blenders, distributors, and importers to introduce or sellminimum volumes of ethanol and biodiesel into thetransportation fuels market each year as required under theRFS. Starting in 2013 and each year thereafter, EPA isrequired to establish a new RFS, which—at a minimum—maintains the same volume of renewable fuels sold relativeto total gasoline sold on a percentage basis in 2012.

In addition to the RFS, EPAct05 includes a numberof incentives and other provisions to promote the use ofE-85 (a blend of 85 percent ethanol and 15 percentgasoline). These include tax credits for the installation ofrefueling infrastructure, DOE grants for theadvancement of hybrid flexible-fuel vehicles, and federalfleet requirements. The various provisions to promoterenewable fuels in EPAct05 are in addition to taxincentives established by Congress in 2004. At that time,

Congress established the Volumetric Ethanol Excise TaxCredit (VEETC) to extend the existing 51 cent-per-gallon tax incentive for renewable fuels, whileeliminating the impact of this credit on the FederalHighway Trust Fund.57

At present, corn is the feedstock for nearly allcommercially produced ethanol in the United States.Ultimately, however, the supply of corn available forconversion to ethanol is likely to be limited givencompeting demand for food and animal feed.58 Theamount of ethanol production that can be sustained oncorn feedstocks alone is uncertain, but many observersexpect it to be in the 10–12 billion-gallon-per-year range,which would account for less than 10 percent of thenation’s transportation fuel needs. Recognizing that adramatic expansion of domestic biofuels production willdepend upon the commercialization of technologies thatcan convert cellulosic (i.e., woody or fibrous) materials toethanol, Congress included a number of provisions inEPAct05 to promote the development of a maturecellulosic biomass ethanol industry. Cellulosic ethanoltechnology would allow for fuel production using a widerange of disparate—and hence more plentiful—feedstocks(e.g., rice hulls, corn stover, municipal solid waste, switchgrass). Provisions in EPAct05 that are specifically aimed atcellulosic ethanol include programs to provide loanguarantees and grants for the construction of cellulosicethanol production facilities, research grants, and anadvanced biofuels technology program.

In addition, EPAct05 stipulates that the federal RFSmust include a separate element to require at least 250million gallons of cellulosic ethanol production startingin 2013. Up to 2013, cellulosic ethanol qualifies forenhanced credit toward meeting the overall RFSrequirement. Specifically, one gallon of ethanol generatedfrom cellulosic and other feedstocks59 counts as 2.5gallons towards satisfying the RFS. Because of theprominence of cellulosic ethanol in current efforts topromote sustainable long-term alternatives to currenttransportation fuels, the remainder of this discussionfocuses on infrastructure issues related specifically to thedevelopment of a domestic cellulosic ethanol industry.

As a result of EPAct05 and other policies, the AEO2006 predicts that cellulosic ethanol production will


increase to 240 million gallons (0.02 quads) underbusiness-as-usual assumptions by 2020. With expandedR&D investments and further incentives for cellulosicethanol (such as those proposed in the Commission’sDecember 2004 report), EIA projects that annualproduction of cellulosic ethanol could reach 0.89 quadsor 10.7 billion gallons per year by 2025.60 It could beeven higher if continued high oil prices, politicalenthusiasm, and other developments prompt even moreconcerted—and sustained—efforts to reduce U.S. oildependence in the future. Meanwhile, production cost,more than any immediate infrastructure or siting issue,remains the chief obstacle to cellulosic ethanolproduction. In its 2004 report, the Commission notedthat despite substantial progress (research anddevelopment efforts have reduced costs by nearly afactor of three since 1980), cellulosic ethanol remainsuncompetitive with gasoline and is not currentlyproduced on a commercial scale anywhere in the world.

Assuming continued progress in overcoming costconstraints, the resource requirements associated with

greatly expanded cellulosic ethanol production—interms of how much land would be needed to growenergy crops, how many production facilities would berequired to make the ethanol, and what supportinginfrastructure would be needed to deliver it to market—are unclear at this point. Land-use concerns, inparticular, are likely to become extremely important inthe event of a large-scale expansion of the biofuelsindustry. In its 2004 report, the Commission noted thatto become economic on a large scale, energy-cropproduction would increasingly need to be integratedwith existing agricultural and forestry production. Forexample, grasslands can produce both ethanolfeedstocks and protein for animal feed; similarly forestscan produce ethanol feedstocks from the unusedportions of trees, as well as pulp.

One specific issue that has surfaced in the debateover how aggressively cellulosic ethanol can becommercialized is whether switchgrass or other ethanolfeedstocks can be grown on lands currently set asideunder the Conservation Reserve Program (CRP).


0

2,000

4,000

6,000

8,000

10,000

12,000

2005 2010 2015 2020 2025

Mill

ion

s o

f Gal

lon

s Pe

r Yea

r

Figure 10Cellulosic Ethanol Production

Scenarios for production of cellulosic ethanol vary widely, but production could increase significantly if certain

policies are adopted. Expanded R&D expenditures and further incentives for cellulosic ethanol, such as those

proposed in the Commission’s 2004 report, could dramatically boost production.This higher level of output

would require siting and building roughly 350 new ethanol production facilities.

Source: Energy Information Administration, Impacts of Modeled Recommendations of the National Commission on Energy

Policy. SR/OAIF/2005-02.

Nationwide, some 35 million acres of land have beentaken out of production to reduce erosion, improve waterquality, and provide wildlife habitat under the CRP, whichhas been implemented as part of the Farm Bill since themid-1980s. A 2003 study by the Oak Ridge NationalLaboratory identified 16.9 million acres of CRP land asbeing potentially available for bio-energy cropproduction, once climate-challenged and environmentallysensitive areas within the program were excluded.61

Wildlife conservation organizations have been reluctantto support the use of CRP lands for energy cropproduction, however, arguing that these lands lose theirhabitat value once they are harvested. Recent researchfrom sites in South Dakota suggests it may be possible togrow native grasses on CRP lands that can be harvestedin the winter with little damage to wildlife habitat. Morework needs to be done to determine if this is indeed trueand if it makes sense—assuming habitat and otherconcerns can be addressed—to allow some use of CRPlands for the production of bio-energy crops.

Besides land to grow feedstocks, large-scaleexpansion of the biofuels industry will require additionalinfrastructure to produce ethanol and deliver it to market.Typical new corn ethanol plants constructed today haveproduction capacities of 50–100 million gallons per yearand some have suggested that future cellulosic ethanolplants could produce as much as 250 million gallons peryear. In any case, current projections imply theconstruction of hundreds of new ethanol plants in theUnited States by 2025. Here, the fact that a sizable cornethanol industry already exists is likely to ease siting andother obstacles. In fact, corn-based ethanol plants havegenerally not faced the same level of public opposition ashave some other types of energy facilities. Instead, thesefacilities—many of which are located in agriculturalareas—are often seen as good sources of local jobs.62

Nevertheless, ethanol facilities have not been completelyfree from local opposition and ethanol developerssometimes encounter public concerns, particularly relatedto odors emitted from the plants.63 If there is a significantincrease in ethanol production and numerous new facilitiesare proposed for construction, public opposition maybecome a more common problem for ethanol producers.

Since feedstock transport costs are a major factor indetermining the economic viability of ethanol

operations, the expectation is that new plants forproducing cellulosic ethanol will usually be sited in closeproximity to feedstocks. In cases where corn stover,switch grass, rice hulls, bagasse, or other agriculturalmaterials or waste are used, facilities may be less likelyto encounter NIMBY concerns. Corn ethanol plants havebeen sited in rural areas with relative ease, perhaps tosome extent because rural communities are moreaccustomed to living near large agribusiness operations.By contrast, siting problems may be more likely wherefeedstocks originate in urban areas. For example, if itbecomes financially and technically feasible to convertmunicipal solid waste to ethanol, it will be advantageous(in terms of minimizing feedstock transport costs) to siteproduction facilities near large metropolitan areas, wherelarge amounts of waste are generated. However, publicopposition to the siting of large industrial facilities nearmajor population centers may make this challenging.

In addition, ethanol production facilities requireenergy to facilitate fermentation and, in many cases, todry distillers grains to reduce weight prior to shipment.The most common source of energy input is natural gas,although coal can also be used. A new configuration ofethanol facility/livestock feedlot/methane digester that isbeing built in Meade, Nebraska will be capable ofconverting livestock manure into methane, which willfuel the ethanol plant processes. This type of facilitycould be located away from rail and natural gaspipelines. More conventional types of ethanol facilities,however, will need to be located at or near rail hubs ornatural gas lines, as well as near feedstocks, which willlimit flexibility in siting them.

In terms of transporting ethanol to market, this isgenerally being accomplished today using rail cars andbarges. To the extent these remain the dominant modesfor delivering ethanol to end users it will beadvantageous to site production plants near rail hubs ormajor rivers with active barge operations. If, on the otherhand, the U.S. biofuels industry expands to the pointwhere it becomes economic to construct dedicatedpipelines for carrying ethanol to market, a wider range ofsites for new plants may become viable. In that case,proximity to new pipeline hubs would likely become animportant consideration in siting new ethanol plants.



Key Questions

• To what extent will the siting of future ethanol plants depend upon proximity to existing energy infrastructure,such as rail lines or natural gas pipelines (needed to supply energy inputs) or to barges, rail or dedicatedpipelines (needed for carrying the ethanol to markets)?

• To what extent will feedstock transportation costs force plants to be located within a few miles of feedstock sources?

• In parts of the country where citizens are not used to living in proximity to large agri-business facilities, butwhere potential exists to produce ethanol or biodiesel from new feedstocks, such a wood waste, municipal solidwaste, or waste grease, will communitities tolerate the siting of new biorefineries?

• Should CRP rules be changed to allow the cultivation and harvesting of energy crops on some CRP lands forthe purpose of expanding cellulosic ethanol feedstocks, and, if so, how can concerns about habitat preservationand other important CRP goals be effectively addressed of IGCC with CCS?


Previous sections give some indication of the scaleand complexity of the infrastructure challengesthat the United States is likely to face in coming

decades as it seeks to meet growing energy demand whileresponding to new economic, environmental, andnational security imperatives. Today, the nation dependson an energy infrastructure that was designed in thetwentieth century and expanded more or less on an adhoc and localized basis. The energy systems of the futurewill require an infrastructure that can support a widerrange of technologies and resources, some of which maybe highly dispersed. Siting is, of course, only one elementof the overall infrastructure equation, which must factorin many variables of cost, investment conditions,regulatory policy and uncertainty, technological andengineering limitations, and environmental concerns.Nevertheless, siting has emerged as an important cross-cutting issue for nearly all energy technologies—one thatseems likely to play a major role in shaping the natureand geographic distribution of future energy systems

The purpose of this document, as noted in theIntroduction, is primarily to identify and providecontext for some of the key energy-infrastructure issuesthat confront decision-makers today. An upcomingworkshop series, sponsored by the NationalCommission on Energy Policy in partnership withvarious other organizations, will provide an opportunityto explore the key questions posed in this report, as wellas other issues identified by interested stakeholders andexperts. Recognizing that many of these questions orissues are likely to defy simple policy prescriptions, theaim will nevertheless be to develop recommendationsfor further progress in addressing the nation’s mostimportant energy infrastructure needs. As theCommission emphasized in its 2004 report, no singletechnology or policy is likely to provide a silver-bullet

answer for the complex energy trade-offs that must beconfronted in the decades to come.

To conclude, the Commission wishes to end thisreport and introduce its upcoming workshop series on apositive note. Ensuring that the nation, and the world,develop the infrastructure needed to support a more robust,more flexible, and more diverse set of energy options is—ifnot the only prerequisite for sound twenty-first centuryenergy policy—a necessary ingredient for long-termsuccess. With that in mind, the Commission aims to buildon the steps already being taken in some parts of thecountry to foster better and faster siting decisions in thefuture. The best of those new examples inspire optimismthat there are siting processes that can successfully, andwith the confidence of the public, introduce cleaner andmore reliable technologies and resources while generatingsignificant local, regional, and even national benefits. Newapproaches to siting will help clear the way for the orderlyretirement of those energy facilities that are both aging andobsolete, for more aggressive efficiency improvements, andfor new infrastructure investments that are part of a broaderdrive to improve energy services and enhanceenvironmental quality. Innovative thinking on siting issueswill be required to achieve these ends and will be essential ifthere is to be any hope of making tough decisions onpermitting hard-to-site energy facilities—whether LNGterminals, new coal IGCC or nuclear plants, or even largewindfarms—in places where they may be needed toadvance a variety of economic and environmentalobjectives, but are nonetheless unpopular with oneimportant group or another. Stories about this or thatintractable siting problem have become all too familiar. Thechallenge now is to speed the transition to a whollydifferent and vastly more appealing siting paradigm. TheCommission looks forward to helping launch just such atransition in the months ahead.

F. CONCLUSION

1. The Nuclear Regulatory Commission, A Short History of Nuclear Regulation: 1946-1999, NUREG/BR-0175, Rev. 1, 2003.

2. B.M. Casper and P. D. Wellstone, Powerline: The First Battle of America’s Energy War, (Amherst, Massachusetts:The University of Massachusetts Press, 1981).

3. R. L.Keeney, Siting Energy Facilities, (New York: Academic Press, 1980).4. Ibid.5. Organization for Economic Co-operation and Development, The Siting of Major Energy Facilities, (Paris:

OECD, 1979); H. Kunreuther, J. Linnerooth, et al., Risk Analysis and Decision Processes: The Siting of Liquefied GasFacilities in Four Countries (Berlin: Springer-Verlag, 1983); D. W. Ducsik, ed., Public Involvement in Energy FacilityPlanning: The Electric Utility Experience, (Boulder, CO: Westview Press, 1986).

6. F. Fischer, Citizens, Experts, and the Environment: The Politics of Local Knowledge, (Durham: Duke UniversityPress, 2000); S. Tierney, “The Evolution of the Nuclear Debate: The Role of Public Participation,” Annual Review ofEnergy, 1978.

7. T.L. Vierima, Communicating with the Public About Rights-of-Way: A Practitioner’s Guide, EPRI Technical Report1005189, (Palo Alto, California: Electric Power Research Institute, 2001).

8. W. R. Freudeberg and S. K. Pastor, “NIMBYS and LULUS: Stalking the Syndromes,” Journal of Social Issues48(4) (1992): 39-61; other colorful acronyms that have emerged to characterize local opposition include NOPE (noton planet earth), LULU (locally unwanted land use), and even BANANA (build absolutely nothing anywhere nearanything); see K.P. Maize and J. McCaughey, “NIMBY, NOPE, LULU, and BANANA: A Warning to IndependentPower. Public Utilities Fortnightly,” 130(3) (1992): 19-22.; D. Mazmanian and D. Morell, “The NIMBY Syndrome:Facility Siting and the Failure of Democratic Discourse”, Environmental Policy for the 1990s, M. Kraft and N. Vig, eds,(Washington, DC: Congressional Quarterly Press, 1993).

9. R.E. Kasperson, D. Golding, et al., “Social Distrust as a Factor in Siting Hazardous Facilities andCommunicating Risks.” Journal of Social Issues 48(4) (1992): 161; R. Henshaw, “Siting Myopia Slows Power Project,”Times Union (Albany, New York: 2001), A7; T.C. Beierle and J. Cayford, Democracy in Practice: Public Participation inEnvironmental Decisions (Washington, DC: Resources for the Future, 2002).

10. R.G. Kuhn and K. R. Ballard, “Canadian Innovations in Siting Hazardous Waste Management Facilities,”Environmental Management, 22(4) (1998): 533-545; F. Fischer, Citizens, Experts, and the Environment: The Politics ofLocal Knowledge, (Durham: Duke University Press, 2000); T.C. Beierle, and J. Cayford, Democracy in Practice: PublicParticipation in Environmental Decisions, (Washington, DC: Resources For the Future, 2002); S. Tierney and P.Hibbard, “Siting Power Plants in the New Electric Industry Structure: Lessons California and Best Practices for OtherStates,” The Electricity Journal, June 2002.

11. H. Kunreuther, K. Fitzgerald, et al., “Siting Noxious Facilities: A Test of the Facilities Siting Credo,” RiskAnalysis, 13 (1993): 301-318; H. Kunreuther and D. Easterling, “The Role of Compensation in Siting HazardousFacilities,” Journal of Policy Analysis and Management, 15(4) (1996): 601-622; H. Inhaber, Slaying the NIMBY Dragon(New Brunswick, New Jersey: Transaction Publishers, 1998); E. Quah and K. C. Tan, “The Siting Problem of NIMBYFacilities: Cost-benefit Analysis and Auction Mechanisms,” Environment and Planning C-Government and Policy, 16(3)(1998): 255-264.

12. H. Inhaber, Slaying the NIMBY Dragon, (New Brunswick, New Jersey: Transaction Publishers, 1998);G.E. McAvoy, Controlling Technocracy: Citizen Rationality and the NIMBY Syndrome (Washington DC: GeorgetownUniversity Press, 1999); E. Quah and K. C. Tan, “The Siting Problem of NIMBY Facilities: Cost-Benefit Analysis andAuction Mechanisms,” Environment and Planning C-Government and Policy, 16(3) (1998): 255-264.

13. S.P. Vajjhala and P.S. Fischbeck, forthcoming, “Quantifying Siting Difficulty: A Case Study of U.S. Transmission Line Siting,” Energy Policy.

NOTES



14. National Commission on Energy Policy, Ending the Energy Stalemate: A Bipartisan Strategy to Meet America’sEnergy Challenge, (Washington, DC: National Commission on Energy Policy, 2004), 86.

15. United States Department of Energy, Energy Information Administration, Annual Energy Outlook 2006,DOE/EIA-0383, (Washington, DC: Energy Information Administration, 2006)http://www.eia.doe.gov/oiaf/aeo/index.html.

16. Ibid.17. Apart from other infrastructure considerations, this level of expansion of conventional coal-fired and gas-

fired electric generating capacity would have significant implications for U.S. greenhouse gas emissions. Specifically, itimplies a roughly 40 percent increase over current (2005) emissions from the U.S. electric power sector by 2030.

18. Ken Silverstein, “Energy Risk – Stormy Forecast for Coal?,” EnergyBiz Insider, (New York: January 23,2006). 19. These include: ERCOT in Texas, the Midwest ISO, the PJM Interconnection, the New England ISO, the New

York ISO, the Southwest Power Pool RTO, and the California ISO.20. North American Electric Reliability Council, Transmission Loading Relief Logs,

http://www.nerc.com/~filez/Logs/tlrlogs.html. 21. Congestion costs in PJM jumped dramatically in 2004 to $809 million, although much of this increase was

the result of integrating additional control areas into PJM. As a percent of total billings, which allows for a moreaccurate comparison of 2003 and 2004 data, congestion costs increased from 7 percent of total billings in 2003 to 9percent in 2004. PJM Interconnection, State of the Market2004, March 2005, http://www.pjm.com/markets/market-monitor/som.html. See also a recent study by the Consumer Energy Council of America, “Keeping the Power Flowing:Ensuring a Strong Transmission System to Support Consumer Needs for Cost-Effectiveness, Security and Reliability,”Report of the CECA Transmission Infrastructure Forum, January 2005.

22. American Transmission Company, Ten-Year Transmission System Assessment Report, 2005,http://www.atc10yearplan.com/pdf/Resources/SUMMARY%20REPORT.pdf.

23. Energy Security Analysis, Inc., Meeting U.S. Transmission Needs, (Washington, DC: Edison Electric Institute,July 2005), http://www.eei.org/industry_issues/energy_infrastructure/ transmission/meeting_trans_needs.pdf.

24. Ibid. p. vii.25. These provisions include tax incentives for new transmission investment as well as reforms to the Public

Utilities Holding Company Act that are aimed at facilitating mergers and new transmission investment.26. “Considerations for Transmission Congestion Study and Designation of National Interest Electric

Transmission Corridors, Notice of Inquiry,” Federal Register 7 (2 February 2006): 5660-5664. 27. United States Department of Agriculture, Department of the Interior, Department of Energy, Council on

Environmental Quality, Report to Congress: Corridors and Rights-of-Way on Federal Lands (Washington, DC:Department of Energy, 2005) http://www.electricity.doe.gov/documents/congress_020906.pdf.

28. American Wind Energy Association. “First Quarter Market Report: Wind Energy On Track for AnotherRecord Year.” May 3, 2006.

29. United States Department of Energy, Energy Information Administration, Renewable Energy Trends,(Washington, DC: Energy Information Administration, 2005), http://www.eia.doe.gov/cneaf/solar.renewables/page/trends/rentrends04.html.

30. American Wind Energy Association, “U.S. Wind Industry Ends Most Productive Year,” News Release, January24, 2006.

31. Massachusetts Technology Collaborative, United States Department of Energy, and GE Energy, A Frameworkfor Offshore Wind Energy Development in the United States. http://www.mtpc.org/offshore/final_09_20.pdf.

32. It is worth noting here that many experts regard the EIA projection as unrealistically aggressive, especiallyover the 14-year timeframe indicated. No one really knows how long it will take to site and then construct a nuclearpower plant of new design, even aside from the public opposition that such a project would likely encounter, buthistory cautions against optimistic forecasts of nuclear plant additions

33. Gallup Report, March 23, 2006.34. For example, see the Nuclear Regulatory Commission, Draft EIS for the North Anna ESP Site Public Meeting:

Official Transcript of Proceedings (2/17/05), Docket No. 52-008 (2005), http://www.nrc.gov/reactors/new-licensing/esp/public-meetings-esp.html.


35. NuStart Energy Development is a consortium that includes Constellation Energy, Duke Energy, Electricité deFrance International-North America, Entergy, Exelon, FPL Group, Progress Energy, SCANA Corporation, andSouthern Company. Other affiliated entities include the Tennessee Valley Authority, General Electric andWestinghouse. http://www.nustartenergy.com

36. J. Edwards, “Mesquite Area Coal Plant Moves Ahead,” Las Vegas Review Journal 11 March 2006,http://www.reviewjournal.com/lvrj_home/2006/Mar-11-Sat-2006/business/6289107.html.

37. Associated Press, “California Settles on Clean Coal Future,” MSNBC, 23 November 2005,http://www.msnbc.msn.com/id/10173908/. In another effort to limit greenhouse gas emissions from the electric powersector, the California Public Utilities Commission in April 2005 adopted a rule that requires the state’s three largeinvestor-owned utilities to factor a so-called “carbon adder” of $8 per ton into their resource planning processes. Thecarbon adder is intended to serve as a reasonable proxy for the likely cost of future carbon constraints.

38. H. Herzog and D. Golumb, “Carbon Capture and Storage from Fossil Fuel Use,” Encyclopedia of Energy,Cutler Cleveland and Robert U. Ayres eds., (Amsterdam: Elsevier, 2004).

39. W. G. Rosenberg, D. C. Alpern, and M. R. Walker, Deploying IGCC in This Decade with 3Party CovenantFinancing: Volume I, (Cambridge, MA: Belfer Center for Science and International Affairs, Kennedy School ofGovernment, Harvard University, July 2004).

40. United States Department of Energy, National Energy Technology Laboratory, Carbon Sequestration:Technology Roadmap and Program Plan 2005, (Washington, DC: National Energy Technology Laboratory, 2005).

41. Intergovernmental Panel on Climate Change, “Special Report on Carbon Capture and Storage,” September2005.

42. J.J. Dooley, C.L. Davidson, M.A. Wise, and R.T.Dahowski, Accelerated Adoption of Carbon Dioxide Capture andStorage Within the United States Electric Utility Industry: The Impact of Stabilizing at 450 PPMV and 550 PPMV, JointGlobal Change Research Institute, Batelle, Pacific Northwest Division, 2004.

43. International Energy Agency, Building the Cost Curves for CO2 Storage: North America, Report Number2005/3, February 2005.

44. A. Karimjee and B. J. Kobelski, “An Overview of Technical and Regulatory Considerations for Geologic CO2 Sequestration,” paper presented at the Ground Water Protection Council 2005 Annual UIC Conference, January 18, 2005.

45. T. Curry, D. M. Reiner, S. Ansolabehere, and H. J. Herzog, “How Aware is the Public of Carbon Capture andStorage?,” a working paper, viewed at http://sequestration.mit.edu/research/survey.html.

46. C. R. Palmgren, M. G. Morgan, W. Bruine de Bruin, and David W. Keith, “Initial Public Perceptions of DeepGeological and Oceanic Disposal of Carbon Dioxide,” Environmental Science and Technology, Vol. 38, No. 24 (2004).

47. For example, cost estimates developed in the context of the Commission’s earlier report suggest that the costof capturing 90 percent of carbon emissions at a large (500 MW) coal IGCC facility range from $12.40-$18.70 permegawatt-hour, while the costs of sequestration are on the order of $2.93 per metric ton of carbon dioxide.

48. Ibid., 7. 49. For a discussion of legal and liability issues, see B. N. McKee, Carbon Sequestration Leadership Forum

Policy Group, A Report from the Legal, Regulatory, and Financial Issues Task Force, “Considerations on Legal Issuesfor Carbon Dioxide Capture and Storage Projects,” August 2005.

50. Ibid., 7.51. National Petroleum Council, Committee on Natural Gas, Balancing Natural Gas Policy: Fueling the Demands

of a Growing Economy, vol. 1, Summary of Findings and Recommendations (Washington, DC: National PetroleumCouncil, 2003), 30, http://www.npc.org/reports/ng.html.

52. The development of technology that would allow for re-gasification to occur on board LNG tanker shipscould substantially impact the need for on-shore terminals.

53. For example, see Coalition for Responsible Siting of LNG Facilities, http://nolng.org.54. United States Department of Energy, Energy Information Administration, Annual Energy Outlook 2006 with

Projections to 2030, DOE/EIA-0383 (Washington, DC: Energy Information Administration, 2006), 9,http://www.eia.doe.gov/oiaf/aeo/production.html.


55. National Commission on Energy Policy, Staff et al. “The Safety of Liquefied Natural Gas,” 2, in NCEPTechnical Appendix (Washington, DC: National Commission on Energy Policy, 2004).

56. Federal Energy Regulatory Commission, Report to Congress on Progress Made in Licensing and Constructing theAlaska Natural Gas Pipeline (Washington, DC: Federal Energy Regulatory Commission, 2006), 1,http://www.ferc.gov/legal/staff-reports/alaska-report.pdf.

57. In addition, in EPAct05 Congress expanded eligibility requirements for the 10-cent-per-gallon smallproducer credit by allowing facilities that produce up to 60 million gallons of fuel annually (it was previously 30 million gallons) to take advantage of this credit for up to 15 million gallons of renewable fuel. The bill also createda small new biodiesel tax credit and extended the biodiesel VEETC credit through December 31 2008. A credit of 10-cents-per-gallon for up to 15 million gallons of agri-biodiesel is available to producers with annual capacity notexceeding 60 million gallons.

58. In 2003, 7 percent of the U.S. corn crop was used to make ethanol. Substantially expanding this share wouldlikely result in price increases for animal feed that would eventually affect the profitability of livestock operations,possibly leading to strong political opposition.

59. To qualify for the enhanced credit, the ethanol must be produced from feedstocks such as agriculturalresidues, woody biomass, fibers, municipal solid waste, or switchgrass, etc., or at “facilities where animal wastes orother waste materials are digested or otherwise used to displace 90 percent or more of the fossil fuel normally used inthe production of ethanol.”

60. United States Department of Energy, Energy Information Administration. Impacts of ModeledRecommendations of the National Commission on Energy Policy, SR/OIAF/2005-02 (Washington, DC: EnergyInformation Administration, 2005), http://www.eia.doe.gov/oiaf/servicerpt/bingaman/index.html.

61. D. G. De La Torre Ugarte, Marie E. Walsh, Hosein Shapouri and Steven P. Slinsky, “Bioenergy CropProduction in the United States: Potential Quantities, Land Use Changes, and Economic Impacts on the AgriculturalSector,” Environmental and Resource Economics, Volume 24, Number 4, April 2003.

62. Northeast Regional Biomass Program, “An Ethanol Production Guidebook for Northeast States,”(Washington, DC: 2001).

63. Ibid.

InfraStructure White Papers FINAL - New England Energy Alliance

Documents

Transcript of InfraStructure White Papers FINAL - New England Energy Alliance