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Sierra Club Motion
 

Sierra Club Motion

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Regarding importing liquified natural gas

Regarding importing liquified natural gas

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    Sierra Club Motion Sierra Club Motion Document Transcript

    • UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSIONIN THE MATTER OF ) ) Docket No. CP12-498APPLICATION OF )THE GAS COMPANY, LLC )FOR AUTHORIZATION UNDER SECTION 3 )OF THE NATURAL GAS ACT ) ) SIERRA CLUB’S MOTION TO INTERVENE, PROTEST, AND COMMENTSNathan Matthews Kathleen KrustEllen Medlin ParalegalAssociate Attorneys Sierra Club Environmental Law ProgramSierra Club Environmental Law Program 85 2nd St., Second Floor85 2nd St., Second Floor San Francisco, CA 94105San Francisco, CA 94105 (415) 977-5696 (tel)(415) 977-5646 (tel)(415) 977-5793 (fax)
    • Table of ContentsI. Sierra Club Should be Granted Intervention ................................................................ 2II. Information Regarding the Applicant & Service ........................................................... 3III. FERC’s Legal Obligations ............................................................................................... 5 A. Natural Gas Act .......................................................................................................... 5 1. FERC’s Jurisdiction Under the Natural Gas Act ....................................................... 5 a. Sierra Club Does Not Contest the Company’s Assertion that FERC Has Jurisdiction ........................................................................................................ 5 b. If FERC Determines That it Lacks Jurisdiction, Then the State of Hawaii Has Jurisdiction Over the Company’s Proposal ....................................................... 5 2. FERC’s Substantive Obligations Under the Natural Gas Act ................................... 6 B. National Environmental Policy Act ............................................................................ 8 C. Endangered Species Act ........................................................................................... 10 D. National Historic Preservation Act ........................................................................... 11IV. Effects of the Proposed Project .................................................................................. 12 A. FERC Must Consider the Effects of All Three Phases of the Company’s Proposed Facilities and May Not Analyze Phase 1 in Isolation ................................................ 12 1. NEPA Requires FERC to Analyze All Three Phases in a Single NEPA Document ... 13 2. Even if FERC Were Not Required to Analyze All Three Phases in a Single NEPA Document, Comprehensive Review is Prudent Here ........................................... 15 3. FERC Must, at a Bare Minimum, Analyze the Cumulative Impacts of All Three Facilities................................................................................................................. 16 B. FERC Should Prepare an EIS for the Three-Phase Project ....................................... 16 1. An EIS is Appropriate ............................................................................................ 16 2. Even if FERC Refuses to Prepare An EIS, it Must, at a Minimum, Take Public Comment on the EA .............................................................................................. 17 C. Direct Impacts of the Proposed Facilities ................................................................ 17 1. Air Emissions ......................................................................................................... 17 2. Water and Aquatic Habitat Impacts ..................................................................... 21 3. Noise, Light, Traffic, and Safety Issues.................................................................. 22 4. Fish and Wildlife.................................................................................................... 22 D. FERC Should Obtain Additional Information Enabling it to Analyze the Proposal’s Indirect Effects ......................................................................................................... 23 E. The Proposed Project’s Effects on Development of Renewable Energy Resources in Hawaii ...................................................................................................................... 24 F. Effects of the Proposal on Greenhouse Gas Emissions in Hawaii ........................... 26 G. Effects of The Additional Gas Production that Exports Will Induce ........................ 31 1. Effects Related to Induced Drilling ....................................................................... 31 a. The Company’s Imports of Natural Gas Will Induce Additional Natural Gas Production....................................................................................................... 32 b. FERC Must Consider Induced Production ....................................................... 32 c. FERC Is Required to Consider Induced Production Notwithstanding Its Decision Not to Do So in Sabine Pass ............................................................. 34
    • d. Natural Gas Production is a Major Source of Air Pollution ............................ 36 i. Air Pollution Problems from Natural Gas ................................................. 37 ii. EPA’s Air Rules Will Not Fully Address These Air Pollution Problems ...... 45 e. Gas Production Disrupts Landscapes and Habitats ........................................ 45 f. Gas Production Poses Risks to Ground and Surface Water ............................ 48 i. Water Withdrawals ................................................................................... 48 ii. Fracturing .................................................................................................. 49 iii. Waste Management ................................................................................. 53 H. The Existing Record Demonstrates that The Company’s Application Is Contrary to The Public Interest. .................................................................................................. 56V. The EIS Must Consider an Adequate Range of Alternatives ....................................... 57VI. Conclusion ................................................................................................................... 58
    • UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSIONIN THE MATTER OF ) ) Docket No. CP12-498APPLICATION OF )THE GAS COMPANY, LLC )FOR AUTHORIZATION UNDER SECTION 3 )OF THE NATURAL GAS ACT ) ) SIERRA CLUB’S MOTION TO INTERVENE, PROTEST, AND COMMENTSThe Gas Company, LLC (“the Company”) requests Federal Energy RegulatoryCommission (“FERC”) authorization for the first of three phases of facilities that,together, would be used, among other things, to receive, store, transport, and regasifyliquefied natural gas (“LNG”) sourced from liquefaction facilities in the continentalUnited States and transported by ship to Hawaii. The Company’s application focuses onthe first phase of these operations, which would include (1) a fleet of cryogenicintermodal, or “ISO,” containers that will be transported to Hawaii by cargo ship, (2) theuse of existing storage facilities or secured lots to store the ISO containers after theyarrive in Hawaii, and (3) mobile LNG regasification units that would be used to inject thegas into the Company’s distribution pipeline or deliver it to end-use customers.Sierra Club moves to intervene in FERC docket CP12-498 to protect our members’interests in the local environment, which will be impacted by this and the other phasesof the proposed operations. We also seek to protect our members’ interests in thebroader environment that will be affected by the import of LNG into Hawaii and theincrease in domestic natural gas production that this new market for LNG will induce.In conjunction with this motion to intervene, Sierra Club offers comment on the needfor FERC to comprehensively examine the local environmental impacts of all threephases of the proposed LNG import operations – rejecting the applicant’s improperrequest to segment review – as well as the operations’ impact on the development ofrenewable energy resources in Hawaii. We also reiterate our contention that FERC mustanalyze the effects of induced production. Although FERC recently refused to considerinduced production in a similar proceeding regarding Sabine Pass LNG, the Sabine Passdecisions were wrongly decided and do not bind FERC here. 1
    • I. Sierra Club Should be Granted InterventionFERC regulations permit intervention if “the movant has or represents an interest whichmay be directly affected by the outcome of the proceeding” or “the movant’sintervention is in the public interest.” FERC R. 214, 18 C.F.R. § 385.214(b)(2). This lowhurdle rightly reflects FERC’s Natural Gas Act responsibilities: FERC is seeking todetermine the public interest on matters that have weighty implications for the country,and so naturally benefits from hearing views from many perspectives as it weighs LNGterminal applications. Allowing intervention upon a clear statement of interest ensuresthat the record is well built and that all arguments are carefully presented.Sierra Club easily satisfies both of these alternative standards for intervention. SierraClub members live and work throughout the area that will be affected by the Company’sproposed operations, including in the regions adjacent to the proposed operations andin regions near the gas fields and liquefaction facilities necessary to supply the plant.The Club currently has 4,126 members in Hawaii and 598,848 members overall.Declaration of Yolanda Andersen at ¶ 7.1 Sierra Club’s asserted rights and interests inthis matter include, but are not limited to, its interests in the following: - The environmental consequences directly attributable to the construction, siting, and operation of the proposed project, including emissions and other pollution associated with the gasification process, environmental damage associated with facility construction and operation in the later phases of the proposed project, environmental impacts caused by hauling and shipping traffic, and other phases of operation. - The environmental and economic consequences of any expansion or change in natural gas production, especially in shale gas plays, as a result of increased use of natural gas in Hawaii. The Company anticipates sourcing its LNG from liquefaction plants in the continental United States, although it does not analyze the environmental consequences of producing gas to supple the liquefaction plans. Sierra Club members living in the gas-producing regions that supply gas for the proposed operations will be affected by the damage to air, land, and water resources caused by the increased development of natural gas, and the public health risks caused by these harms. - The impacts of importing gas into Hawaii through the proposed facilities, whether individually or in concert with imports from other terminals that may be proposed in the future. In particular, the Club works to promote the development of renewable energy and energy efficiency resources in Hawaii and elsewhere, and to reduce U.S. and global dependence on fossil fuels, including coal, gas, and oil. Since the import of LNG will impact Hawaii’s energy future,1 Attached as Exhibit 1. 2
    • including its future ability to transition from fossil fuel energy to renewables, Sierra Club’s interests are directly implicated by the outcome of this proceeding. - The public disclosure, in National Environmental Protection Act documents and other documents, of all environmental, cultural, social, and economic consequences of the Company’s proposal, and of all alternatives to that proposal.In short, Sierra Club’s members have vital economic, aesthetic, spiritual, personal, andprofessional interests in the proposed project.Sierra Club has demonstrated the vitality of these interests in many ways. Sierra Clubruns national advocacy and organizing campaigns dedicated to reducing Americandependence on fossil fuels, including natural gas, and to protecting public health. Thesecampaigns, including its Beyond Coal campaign and its Beyond Natural Gas campaign,are dedicated towards promoting a swift transition away from fossil fuels and toreducing the impacts of any remaining natural gas extraction. The Club’s HawaiiChapter also works to transition Hawaii away from fossil fuel dependence and towardgreater reliance on energy efficiency and renewable energy.Accordingly, Sierra Club satisfies both of Rule 214’s alternative standards, and FERCmust grant intervention here. See Sabine Pass Liquefaction, LLC, 139 FERC ¶ 61,039 P 15(Apr. 16, 2012) (granting Sierra Club’s motion to intervene based on similar interests).2 II. Information Regarding the Applicant & ServicePursuant to 18 C.F.R. § 385.203(b)(1)-(2), Sierra Club states that the exact name of themovant is the Sierra Club, and the movant’s principal place of business is 85 2nd St.,Second Floor, San Francisco, CA, 94105.Pursuant to 18 C.F.R. § 385.203(b)(3), Sierra Club identifies the following persons forservice of correspondence and communications regarding this application:2 If any other party opposes this motion, Sierra Club respectfully requests leave to reply.Cf. 10 C.F.R. §§ 590.302, 590.310 (providing for procedural motions in natural gasimport/export proceedings before DOE). 3
    • Nathan MatthewsEllen Medlin Kathleen Krust3Associate Attorneys ParalegalSierra Club Environmental Law Program Sierra Club Environmental Law Program85 2nd St., Second Floor 85 2nd St., Second FloorSan Francisco, CA 94105 San Francisco, CA 94105(415) 977-5695 (tel) (415) 977-5696 (tel); (415) 977-5793 (fax)3 The Sierra Club respectfully requests that the Commission add all three of theindividuals listed to the service list, notwithstanding 18 C.F.R. § 385.203(b)(3), whichlimits service to two individuals. 4
    • III. FERC’s Legal ObligationsFERC has significant substantive and procedural obligations to fulfill before it can act onthe Company’s proposal. We discuss the scope of some of those obligations created bythe Natural Gas Act, the National Environmental Policy Act, the Endangered Species Act,and the National Historic Preservation Act, here, before discussing the impacts of theproposal.A. Natural Gas Act 1. FERC’s Jurisdiction Under the Natural Gas Act a. Sierra Club Does Not Contest the Company’s Assertion that FERC Has JurisdictionSierra Club does not contest the Company’s assertion that FERC has jurisdiction over theCompany’s application under the Natural Gas Act, which gives FERC “authority toapprove or deny an application for the siting, construction, expansion, or operation ofan LNG terminal,” 15 U.S.C. § 717b(e)(1), and defines “LNG terminal” to include“natural gas facilities . . . used to receive, unload, load, store, transport, gasify, liquefy,or process natural gas that is . . . transported in interstate commerce by waterbornevessel.” Id. § 717a(11). b. If FERC Determines That it Lacks Jurisdiction, Then the State of Hawaii Has Jurisdiction Over the Company’s ProposalAlthough the Club does not contest FERC’s jurisdiction, we do not agree with theCompany that, if FERC concludes it lacks jurisdiction over the Company’s application,that conclusion “would result in a regulatory gap with respect to [the Company’s]activities, as neither the Commission nor the state would have jurisdiction.” App. at 33.As explained below, if FERC lacks jurisdiction, then state and local authorities, includingthe Hawaii Public Utilities Commission, have jurisdiction over the Company’s proposal.The Company’s “regulatory gap” argument is based on section 3(e) of the Natural GasAct, which gives FERC “exclusive authority to approve or deny an application for thesiting, construction, expansion, or operation of an LNG terminal.” 15 U.S.C. §717b(e)(1) (emphasis added). The Company argues that, even if some exceptionprevents FERC from exercising authority over the Company’s application, section 3(e)nonetheless precludes any other entity – such as the state – from exercising jurisdiction.App. at 33. In particular, the Company points to the so-called “Hinshaw exception,”which states that the Natural Gas Act “shall not apply to any person engaged in orlegally authorized to engage in the transportation in interstate commerce or the sale ininterstate commerce for resale, of natural gas received by such person from another 5
    • person within or at the boundary of a State if all the natural gas so received is ultimatelyconsumed within such State, or to any facilities used by such person for suchtransportation or sale, provided that the rates and service of such person and facilitiesbe subject to regulation by a State commission.” 15 U.S.C. § 717(c). According to theCompany, “if the Hinshaw exemption were deemed to apply to the siting, construction,expansion and operation of an LNG terminal, the relevant state would have nojurisdiction.” App. at 33.The Company’s argument makes little sense, for two reasons. First, the Hinshawexception could not possibly leave the proposed project in a total regulatory vacuumbecause it only applies to projects “subject to regulation by a State commission.” 15U.S.C. § 717(c). Here, then, the exception could only apply if the project were under thejurisdiction of the Hawaii Public Utilities Commission.Second, and more broadly, section 3(e) merely clarifies that, where FERC has authorityover an LNG terminal, its authority is exclusive. This provision, which was addedthrough the Energy Policy Act of 2005, was not meant to abrogate Congress’slongstanding policy, expressed in the Hinshaw exception, of “leav[ing]” to the statesjurisdiction over “companies engaged in the distribution of natural gas exclusively in theStates.” Gen’l Motors Corp. v. Tracy, 519 U.S. 278, 293 (1997). If FERC concludes that ithas no authority over the Company’s application – because it determines that theHinshaw exception applies, or for any other reason – then the application falls under theordinary jurisdiction of the state of Hawaii, including local authorities and the HawaiiPublic Utilities Commission. 2. FERC’s Substantive Obligations Under the Natural Gas ActSection 3(a) of the Natural Gas Act requires FERC to determine whether the siting,construction, and operation of the Company’s proposed terminal facilities are“consistent with the public interest.” 15 U.S.C. § 717b(a), DOE Delegation Order No. 00-044.00A at 1.21(A) (effective May 16, 2006). Courts, FERC, and DOE/FE, which makesanalogous “public interest” determinations for facilities that import or export naturalgas outside the U.S., have all interpreted the “public interest” at issue in theseprovisions as including environmental impacts.Both the Supreme Court and the D.C. Circuit Court of Appeals have held that the NaturalGas Act’s public interest provisions encompass environmental concerns. While thepublic interest inquiry is rooted in the Natural Gas Act’s “fundamental purpose [of]assur[ing] the public a reliable supply of gas at reasonable prices,” United Gas Pipe LineCo v. McCombs, 442 U.S. 529, 536 (1979), the Natural Gas Act also grants FERC“authority to consider conservation, environmental, and antitrust questions.” NAACP v.Fed. Power Comm’n, 425 U.S. 662, 670 n.4 (citing 15 U.S.C. § 717b as an example of apublic interest provision); n.6 (explaining that the “public interest” referred to in § 717bincludes environmental considerations) (1976). In interpreting an analogous public 6
    • interest provision applicable to hydroelectric power and dams, the Court has explainedthat the public interest determination “can be made only after an exploration of allissues relevant to the ‘public interest,’ including future power demand and supply,alternate sources of power, the public interest in preserving reaches of wild rivers andwilderness areas, the preservation of anadromous fish for commercial and recreationalpurposes, and the protection of wildlife.” Udall v. Fed. Power Commn, 387 U.S. 428, 450(1967) (interpreting § 7(b) of the Federal Water Power Act of 1920, as amended by theFederal Power Act, 49 Stat. 842, 16 U.S.C. § 800(b)). Other courts have applied this Udallholding to the Natural Gas Act. See, e.g., N. Natural Gas Co. v. Fed. Power Commn, 399F.2d 953, 973 (D.C. Cir. 1968) (interpreting section 7 of the Natural Gas Act). 4FERC has acknowledged that environmental issues weigh into FERC’s public interestcalculus. In FERC’s recent order approving siting, construction, and operation of LNGexport facilities in Sabine Pass, Louisiana, FERC considered potential environmentalimpacts of the terminal as part of its public interest assessment. Sabine PassLiquefaction, LLC, 139 FERC ¶ 61,039, PP 29-30 (Apr. 14, 2012).5DOE – which, again, makes public interest determinations analogous to FERC’s – hasreached the same conclusion. Deputy Assistant Secretary Smith recently testified that“[a] wide range of criteria are considered as part of DOE’s public interest reviewprocess, including . . . U.S. energy security . . . [i]mpact on the U.S. economy . . .[e]nvironmental considerations . . . [and] [o]ther issues raised by commenters and/orinterveners deemed relevant to the proceeding.” The Department of Energy’s Role inLiquified Natural Gas Export Applications: Hearing Before the S. Comm. on Energy andNatural Resources, 112th Cong. 4 (2011) (testimony of Christopher Smith, DeputyAssistant Secretary of Oil and Gas).6 DOE rules require export applicants to provideinformation documenting “[t]he potential environmental impact of the project.” 10C.F.R. § 590.202(b)(7). In a previous LNG export proceeding, DOE determined that thepublic interest inquiry looks to “domestic need” as well as “other considerations,”including the environment. Phillips Alaska Natural Gas Corporation and Marathon OilCompany, 2 FE ¶ 70,317, DOE FE Order No. 1473, *22 (April 2, 1999); accord Opinionand Order Conditionally Granting Long-Term Authorization to Export [LNG] from SabinePass LNG Terminal to Non-Free Trade Agreement Nations (“Sabine Pass”), DOE/FE Order2961 at 29 (May 20, 2011) (acknowledging that the public interest inquiry extendsbeyond effects on domestic natural gas supplies). Finally, DOE has applied its “policy4 Further support for the inclusion of environmental factors in the public interestanalysis is provided by NEPA, which declares that all federal agencies must seek toprotect the environment and avoid “undesirable and unintended consequences.” 42U.S.C. § 4331(b)(3).5 Sierra Club contends that other aspects of this order were wrongly decided, as wasFERC’s subsequent denial of Sierra Club’s petition for rehearing, as we explain below.6 Attached as Exhibit 2. 7
    • guidelines” regarding the public interest to focus review “on the domestic need for thenatural gas proposed to be exports; whether the proposed exports pose a threat to thesecurity of natural gas supplies, and any other issue determined to be appropriate.”Sabine Pass at 29 (citing 49 Fed. Reg. 6,684 (Feb. 22, 1984)) (emphasis added).7Accordingly, there is consensus among the pertinent authorities that public interestinquiries mandated by the Natural Gas Act, including those undertaken by FERC, musttake into account the environmental effects of the action under consideration.B. National Environmental Policy ActNEPA requires federal agencies to consider and disclose the “environmental impacts” ofproposed agency actions. 42 U.S.C. § 4332(C)(i). This requirement is implementedthrough a set of procedures that “insure [sic] that environmental information isavailable to public officials and citizens before decisions are made and before actions aretaken.” 40 C.F.R. § 1500.1(b) (emphases added). Agencies must “carefully consider [ ]detailed information concerning significant environmental impacts” and NEPA“guarantees that the relevant information will be made available” to the public. Dep’tof Transp. v. Public Citizen, 541 U.S. 752, 768 (2004) (quoting Robertson v. MethowValley Citizens Council, 490 U.S. 332, 349 (1989)). The Council on Environmental Quality(“CEQ”) directs agencies to “integrate the NEPA process with other planning at theearliest possible time to insure that planning and decisions reflect environmentalvalues.” 40 C.F.R. § 1501.2.Here, as discussed in part IV.B below, FERC must prepare a full environmental impactstatement (“EIS”), either in addition to or in place of the environmental assessment(“EA”) FERC has already announced an intention to prepare.8 NEPA requires an EISwhere a proposed major federal action would “significantly affect[] the quality of thehuman environment.” 42 U.S.C. § 4332(C). The significance of effects is determined byboth the context and intensity of the proposed action. 40 C.F.R. § 1508.27. If there is a“substantial question” as to the severity of impacts, an EIS must be prepared. SeeKlamath Siskiyou Wildlands Center v. Boody, 468 F.3d 549, 561-62 (9th Cir. 2006)(holding that the “substantial question” test sets a “low standard” for plaintiffs to meet).If it is not clear that a proposal will “significantly” affect the environment, the agencymay prepare an EA to determine whether an EIS is necessary. 40 C.F.R. § 1508.9. FERCregulations provide that an EIS is “normally” required for “[a]uthorization under sections7 DOE/FE’s policy guidelines provide only persuasive authority in FERC proceedings. Evenbefore DOE/FE, these guidelines are merely guidelines: they “cannot create a normbinding the promulgating agency.” Panhandle Producers & Royalty Owners Ass’n v.Econ. Reg. Admin., 822 F.2d 1105, 1110-11 (D.C. Cir. 1987).8 Notice of Application, The Gas Company, LLC, 77 Fed. Reg. 60,972 (Oct. 5, 2012). 8
    • 3 or 7 of the Natural Gas Act and DOE Delegation Order No. 0204–112.” 18 C.F.R. §380.6.Here, as discussed in more detail in parts IV.A and IV.B below, FERC is obligated toconsider all three phases of the Company’s proposed LNG terminal together, and mustprepare a single EIS to fulfill this obligation. Because the three-phased proposal calls forconstruction and operation of new LNG import facilities and supporting facilities, thereis at the very minimum a “substantial question” as to whether the project willsignificantly affect the environment. In other proceedings where proposed LNG exportfacilities would be constructed substantially outside existing terminal sites, FERC hasdetermined that an EIS is appropriate.9An EIS must describe: i. the environmental impact of the proposed action, ii. any adverse environmental effects which cannot be avoided should the proposal be implemented, iii. alternatives to the proposed action, iv. the relationship between local short-term uses of man’s environment and the maintenance and enhancement of long-term productivity, and v. any irreversible and irretrievable commitments of resources which would be involved in the proposed action should it be implemented.42 U.S.C. § 4332(C). The alternatives analysis “is the heart of the environmental impactstatement.” 40 C.F.R. § 1502.14. FERC must take care not to define the project purposeso narrowly as to prevent the consideration of a reasonable range of alternatives toactions under consideration by FERC. See, e.g., Simmons v. U.S. Army Corps of Eng’rs,120 F.3d 664, 666 (7th Cir. 1997). If FERC did otherwise, it would lack “a clear basis forchoice among options by the decisionmaker and the public.” See 40 C.F.R. § 1502.14.9 Notice of Intent to Prepare an Environmental Impact Statement for the Planned JordanCove Liquefaction and Pacific Connector Pipeline Projects, FERC Dockets PF12-7 andPF12-17 (Aug. 2, 2012) (EIS for proposed greenfield facility), Freeport LNG Development,L.P., Freeport LNG Expansion, L.P., FLNG Liquefaction LLC; Supplemental Notice of IntentTo Prepare an Environmental Impact Statement for the Planned Liquefaction Project, 77Fed. Reg. 43589 (July 25, 2012) (EIS where addition of liquefaction and export facilitiesto existing import terminal will involve, among other things, disturbance of 610.7 acresand permanent occupation of 215.1 acres). 9
    • An EIS must also describe the direct and indirect effects, and cumulative impacts of, aproposed action. 40 C.F.R §§ 1502.16, 1508.7, 1508.8; N. Plains Resource Council v.Surface Transp. Bd., 668 F.3d 1067, 1072-73 (9th Cir. 2011). These terms are distinctfrom one another: Direct effects are “caused by the action and occur at the same timeand place.” 40 C.F.R. § 1508.8(a). Indirect effects are also “caused by the action” but: are later in time or farther removed in distance, but are still reasonably foreseeable. Indirect effects may include growth inducing effects and other effects related to induced changes in the pattern of land use, population density or growth rate, and related effect on air and water and other natural systems, including ecosystems.40 C.F.R. § 1508.8(b). Cumulative impacts, finally, are not causally related to the action.Instead, they are: the impact on the environment which results from the incremental impact of the action when added to other past, present, and reasonably foreseeable future actions regardless of what agency (Federal or non-Federal) or person undertakes such other actions. Cumulative impacts can result from individually minor but collectively significant actions taking place over a period of time.40 C.F.R. § 1508.7. The EIS must give each of these categories of effect fair emphasis.Agencies may also prepare “programmatic” EISs, which address “a group of concertedactions to implement a specific policy or plan; [or] systematic and connected agencydecisions allocating agency resources to implement a specific statutory program orexecutive directive.” 40 C.F.R. § 1508.17(b)(3); see also 10 C.F.R. § 1021.330 (DOEregulations discussing this possibility). As we have discussed elsewhere, such an EIS isappropriate here.C. Endangered Species ActThe Endangered Species Act (ESA) directs that all agencies “shall seek to conserveendangered species.” 16 U.S.C. § 1531(c)(1). Consistent with this mandate, FERC mustensure that, if it approves the Company’s proposed project, the approval “is not likely tojeopardize the continued existence of any endangered species . . . or result in thedestruction or adverse modification of [critical] habitat of such species.” 16 U.S.C. §1536(a)(2). “Each Federal agency shall review its actions at the earliest possible time todetermine whether any action may affect listed species or critical habitat.” 50 C.F.R. §402.14(a); see also 16 U.S.C. § 1536(a)(2). 10
    • FERC must first conduct a biological assessment, including the “results of an on-siteinspection of the area affected,” “[t]he views of recognized experts on the species atissue,” a review of relevant literature, “[a]n analysis of the effects of the action on thespecies and habitat, including consideration of cumulative effects, and the results of anyrelated studies,” and “[a]n analysis of alternate actions considered by the Federalagency for the proposed action.” See 50 C.F.R. § 402.12(f). If that assessmentdetermines that impacts are possible, FERC must enter into formal consultation with theFish and Wildlife Service and the National Marine and Fisheries Service, as appropriate,to avoid jeopardizing any endangered species or adversely modifying its habitat as aconsequences of its approval of The Company’s proposal. 16 U.S.C. § 1536(a), (b).As we discuss in part IV.B below, available information indicates a possibility of sucheffects here. The proposed project is likely to adversely affect fish and wildlife bydirectly disturbing terrestrial and aquatic habitat. Moreover, FERC’s ESA review mustconsider not just the effects of the project at the proposed site, but the effects ofincreased gas production across the full region the plant affects.D. National Historic Preservation ActFERC must also fulfill its obligations under the National Historic Preservation Act(“NHPA”) to “take into account the effect of the undertaking on any district, site,building, structure, or object that is included in or eligible for inclusion in the NationalRegister.” 16 U.S.C. § 470f; see also Pit River Tribe v. U.S. Forest Serv., 469 F.3d 768, 787(9th Cir. 2006) (discussing the requirements of the NHPA). As the NHPA explains, “thepreservation of this irreplaceable heritage is in the public interest,” 16 U.S.C. §470(b)(4).FERC must, therefore, initiate the NHPA section 106 consultation and analysis process inorder to “identify historic properties potentially affected by the undertaking, assess itseffects and seek ways to avoid, minimize or mitigate any adverse effects on historicproperties.” 36 C.F.R. § 800.1(a). NHPA regulations make clear that the scope of aproper analysis is defined by the project’s area of potential effects, see 36 C.F.R. § 800.4,which in turn is defined as “the geographic area . . . within which an undertaking maydirectly or indirectly cause alterations in the character or use of historic properties,” 36C.F.R. § 800.16(d). This area is “influenced by the scale and nature of an undertaking,”Id. The area of potential effects should sweep quite broadly here because, as in the ESAand NEPA contexts, the reach of the Company’s proposal extends to the entire area inwhich it will increase gas production. Thus, to approve The Company’s proposal, FERCmust first understand and mitigate its impacts on any historic properties which it mayaffect.The regulations governing this process provide that “[c]ertain individuals andorganizations with a demonstrated interest in the undertaking may participate as 11
    • consulting parties” either “due to the nature of their legal or economic relation to theundertaking or affected properties, or their concern with the undertaking’s effects onhistoric properties.” 36 C.F.R. § 800.2(c)(5). Sierra Club meets that test, because theClub and its members are interested in preserving intact historic landscapes, for theirecological and social value, and reside through the regions affected by the Company’sproposal. Its members have worked for years to protect and preserve the rich humanand natural fabric of these regions, and would be harmed by any damage to thoseresources. Sierra Club must therefore be given consulting party status under the NHPAfor this application. IV. Effects of the Proposed ProjectAlthough, as explained above, the Natural Gas Act’s public interest inquiry requiresdiscussion of environmental impacts, a fully informed discussion cannot take place untilthe NEPA process has identified those impacts. Conversely, the Natural Gas Act’sincorporation of a broad scope of environmental concerns into the public interestdetermination facing FERC means the NEPA analysis must be similarly broad. “Because‘NEPA places upon an agency the obligation to consider every significant aspect of theenvironmental impact of a proposed action,’ the considerations made relevant by thesubstantive statute driving the proposed action must be addressed in NEPA analysis.”Oregon Natural Desert Ass’n v. Bureau of Land Mgmt., 625 F.3d 1092, 1109 (9th Cir.2010) (quoting Vt. Yankee Nuclear Power Corp. v. Natural Res. Def. Council, 435 U.S.519, 553 (1978)).Sierra Club anticipates submitting further comments during the NEPA process, whenmore information regarding the proposal, and FERC’s assessment of it, is available.10 Atthis stage, however, Sierra Club provides comments regarding the scope of theforthcoming NEPA review and a discussion of the already apparent adverseenvironmental effects. We first discuss FERC’s obligation to analyze the impacts of allthree phases of the Company’s proposed terminal together, rather than segmenting itsanalysis into three phases in the manner contemplated by the Company’s application.We then discuss both impacts directly attributable to the proposed project and impactsassociated with the natural gas that will be imported and the additional natural gasproduction those imports would induce.A. FERC Must Consider the Effects of All Three Phases of the Company’s Proposed Facilities and May Not Analyze Phase 1 in Isolation10 As we discuss elsewhere, FERC must prepare an EIS, and not merely an EA, for thisproject. 12
    • FERC must consider the effects of all three phases of the Company’s proposed facilitiestogether, and is not permitted to segment phase 1 from the other phases, as proposedby the Company. This obligation stems from three basic NEPA principles. First, FERC’sapproval of the three-phased LNG terminal project constitutes a single federal actionwhose impacts must be analyzed in a single, comprehensive NEPA document. Second,even if FERC were not required to prepare a single NEPA document for all threeproposed project phases, that approach is plainly prudent given that the three phasesare integrally connected. Third, even if FERC refuses to prepare a single NEPA documentfor all three phases, it must at a bare minimum analyze the cumulative impacts of thethree project phases. 1. NEPA Requires FERC to Analyze All Three Phases in a Single NEPA DocumentFirst, NEPA requires FERC to analyze all three phases of the Company’s proposaltogether, in a single NEPA document. NEPA regulations clearly state that “[p]roposals orparts of proposals which are related to each other closely enough to be, in effect, asingle course of action shall be evaluated in a single impact statement.” 40 C.F.R. §1502.4(a). 11 The regulations that clarify the appropriate scope of NEPA review alsoprovide guidance on which actions should be considered together in a single document.“Connected actions” are “closely related and therefore should be discussed in the sameimpact statement.” 40 C.F.R. § 1508.25(a)(1). Connected actions include those that are“independent parts of a larger action and depend on the larger action for theirjustification.” Id. § 1508.25(a)(1)(iii).Here, the Company’s own description shows that the three phases of the proposal areclosely related, and are therefore “connected actions” that must be discussed together.Id. § 1508.25(a)(1). The Company repeatedly emphasizes that its application concerns“the first of three phases of facilities” that will operate “together,” as part of “acomprehensive, multi-phased strategic plan.” App. at 1, 17; RR at 2. According to theCompany, “the Phase 1 Facilities are an integral part of the Company’s longer-term,comprehensive LNG supply and distribution strategy, and will be a subset of the facilitiesthat will comprise the ultimate LNG terminal in Hawaii upon completion of Phases 2 and3.” App. at 22 (emphasis added). These descriptions of the phases’ close relationshipshow that they amount to “a single course of action” that must be analyzed in a singleNEPA document. See Fla. Wildlife Fed’n v. U.S. Army Corps of Eng’rs, 401 F. Supp. 2d1298, 1312, 1318 (S.D. Fla. 2005) (requiring comprehensive analysis where the project“was conceptualized as an integrated whole, progressing in phases” and the agency“conceded that it was aware of plans for future development; that it will have11 NEPA’s prohibitions on segmentation in the EIS context apply equally toenvironmental assessments. See, e.g., Sierra Club v. Marsh, 769 F.2d 868, 881-82 (1stCir. 1985) (analyzing segmentation in the context of an EA). 13
    • jurisdiction over the next phases of development; and that it anticipates applications forthose phases”).Moreover, phase 1 “depend[s] on [a] larger action” – the three-phase terminal proposal– for its justification. 40 C.F.R. § 1508.25(a)(1)(iii). The Phase 1 facilities are intended tolay the groundwork for a much larger-scale rollout of natural gas facilities in Hawaii.Phase 1 will “introduce[e] LNG into the State” and “permit first responders and otheragencies in the State to become familiar with LNG prior to the installation of permanentstorage and vaporization facilities in Phases 2 and 3.” App. at 6. Where, as here, laterphases constitute a selling point or objective of an earlier phase, all phases must bediscussed together in a single document. Sierra Club v. Marsh, 769 F.2d 868, 878-79 (1stCir. 1985) (Breyer, J.).The three phases of the proposal are not only connected actions, but they are also“cumulative actions” that must be analyzed together under NEPA regulations.“Cumulative actions, which when viewed with other proposed actions have cumulativelysignificant impacts” should, like connected actions, “be discussed in the same impactstatement.” 40 C.F.R. § 1508.25(a)(2). As described more fully below, the three phasesof the project are likely to cause substantial direct harms to the local community andlocal wildlife; they also will cause substantial harms associated with the upstreamdrilling and liquefaction needed to supply the proposed terminal. Taken together, thesecumulatively significant impacts demonstrate that the three phases of the project are“cumulative actions” that must be analyzed together. See Thomas v. Peterson, 753 F.2d754, 759 (9th Cir. 1985) (proposed road, and timber sales the road was designed tofacilitate, were cumulative actions for which comprehensive analysis was required).FERC and the Company may not escape comprehensive review by arguing that, becausephase 1 may alleviate a potential shortage during an upcoming pipeline inspection,phase 1 therefore has independent utility from later project phases, allowing it to beanalyzed separately. See Hammond v. Norton, 370 F. Supp. 2d 226, 247 (D.D.C. 2005)(analyzing whether the NEPA review for two pipeline projects could properly besegmented based on whether the projects had “independent utility”; i.e., “whether oneproject will serve a significant purpose even if a second related project is not built”(internal quotation marks omitted)). The Company surely has an alternate plan in placefor dealing with the routine inspection that must be completed in the coming months,App. at 37. It cannot manufacture independent utility by insisting that LNG is suddenlyneeded before the inspection takes place. “[M]anipulation of a project design toconform to a concept of independent utility, particularly with the intention that apermit be expedited, undermines the underlying purposes of NEPA” and will not cure asegmentation problem. Fla. Wildlife Fed’n, 401 F. Supp. 2d at 1323.Nor does the Supreme Court’s decision in Kleppe v. Sierra Club, 427 U.S. 390 (1976),relieve FERC of its duty to prepare a comprehensive NEPA document for this three-phase proposal. The Court held in Kleppe that, while NEPA “may require a 14
    • comprehensive impact statement in certain situations where several proposed actionsare pending at the same time,” an agency is not required to prepare such an EIS absenta concrete “proposed action.” 427 U.S. at 401, 409. In Kleppe, the Department ofInterior and other federal agencies had prepared an EIS for a national mining program,and the challengers argued that an additional, separate EIS for regional mining in theNorthern Great Plains should be prepared. Id. at 397-99. The Court rejected thiscontention on the basis that there was “no proposal for a regional plan or program ofdevelopment.” Id. at 404. Here, by contrast, the Company has proposed an integrated,three-phase LNG terminal project. Unlike in Kleppe, comprehensive review would betethered to a concrete project and would be neither unduly speculative nor impractical.Moreover, even if Kleppe were not distinguishable here, comprehensive review wouldstill be required under later cases interpreting Kleppe. These cases have clarified thatKleppe does not give agencies carte blanche to segment review of integrally connectedactions. The Fifth Circuit has held that Kleppe “leaves room for a court to prohibitsegmentation or require a comprehensive . . . [impact statement] for two projects, evenwhen one is not yet proposed, if an agency has egregiously or arbitrarily violated theunderlying purpose of NEPA.” Envtl. Defense Fund, Inc. v. Marsh, 651 F.2d 983, 999 n.19 (5th Cir. 1981). The Ninth Circuit has also downplayed the significance of whether astring of anticipated actions are formal “proposals,” at least where it “ma[kes] goodsense to analyze [them] as a whole.” Churchill Cnty. v. Norton, 276 F.3d 1060, 1078-79(9th Cir. 2001). Under Marsh and Churchill County, FERC may not “arbitrarily segment[]”phase 1 from subsequent project phases, and must instead prepare a comprehensiveNEPA analysis. Marsh, 651 F.3d at 999 n.19. 2. Even if FERC Were Not Required to Analyze All Three Phases in a Single NEPA Document, Comprehensive Review is Prudent HereEven if FERC were not required to analyze all three phases of the Company’s proposaltogether, that is plainly the most prudent course. As mentioned, the Companyrepeatedly insists that the three phases are integrally connected and share commongoals. App. at 2 (listing project goals), 4 (“The Phase 1 Facilities are the initial phase of,and an integral component of, the Company’s longer-term, comprehensive LNG supplyand distribution strategy.”). Without comprehensive review, FERC will be unable tomake an informed decision at the outset about whether this strategy is in the publicinterest. Indeed, as the Hawaii Department of Transportation points out in itscomments, the Company is proposing to proceed without any meaningful review oflocal impacts. Acceding to this request could lead to significant complications later. Forexample, if substantial local impacts later prompt FERC to disapprove or requiremodifications to later phases of the project, the Company may have expendedsignificant resources for no useful purpose. Analyzing all impacts of the three-phaseproject now will give FERC a full picture of the project’s impacts, avoiding wasteful earlyresource expenditures and informing the public, including the local community, of theCompany’s longer-term plans. 15
    • 3. FERC Must, at a Bare Minimum, Analyze the Cumulative Impacts of All Three FacilitiesEven if FERC were not obligated, both by the law and by common sense, to prepare acomprehensive NEPA document for all three phases of the proposed project, it must ata bare minimum analyze the cumulative impacts of all three facilities. As mentionedabove, NEPA requires analysis of “the impact on the environment which results from theincremental impact of the action when added to other past, present, and reasonablyforeseeable future actions.” 40 C.F.R. § 1508.7. Agencies must conduct a “usefulanalysis of the cumulative impacts of past, present and future projects” in addition tothe proposal currently under consideration. City of Carmel-by-the-Sea v. U.S. Dep’t ofTransp., 123 F.3d 1142, 1160 (9th Cir. 1997). “Very broad and general statementsdevoid of specific, reasoned conclusions” are not adequate; agencies must evaluate thespecific environmental impacts that are likely to follow as a result of the present actionand future ones. Churchill Cnty., 276 F.3d at 1080; see also Native Ecosystems Council v.Dombeck, 304 F.3d 886, 894 (9th Cir. 2002).Here, the future phases of the Company’s proposal are obviously “reasonablyforeseeable,” as they are described, in the Company’s application, as later portions of anintegrally related strategy. 40 C.F.R. § 1508.7. Further, taken together, the proposedfacilities would have a range of environmental impacts that will be far more significantthan those described in the application. FERC is required to consider the impacts ofthese eminently foreseeable future phases together with those associated with the firstphase, so that the agency may clearly understand the impacts of embarking upon thismulti-phased project. Id.B. FERC Should Prepare an EIS for the Three-Phase Project 1. An EIS is AppropriateAs mentioned in part III.B above, FERC must prepare a full EIS for this three-phaseproposal, either in addition to or in place of the EA that FERC has already announced anintention to prepare.12 NEPA requires an EIS where a proposed major federal actionwould “significantly affect[] the quality of the human environment.” 42 U.S.C. § 4332(C).The significance of effects is determined by both the context and intensity of theproposed action. 40 C.F.R. § 1508.27. If there is a “substantial question” as to theseverity of impacts, an EIS must be prepared. See Klamath Siskiyou, 468 F.3d at 561-62.These direct impacts of the three-phased proposal are described in more detail in thesections that follow. Although, in many instances, FERC will be required to requestadditional information from the Company to adequately analyze the overall impacts of12 Notice of Application, The Gas Company, LLC, 77 Fed. Reg. 60,972 (Oct. 5, 2012). 16
    • this three-phase project, it is plain that there is a substantial question as to whether theproject will have significant impacts. 2. Even if FERC Refuses to Prepare An EIS, it Must, at a Minimum, Take Public Comment on the EAEven if FERC refuses to prepare an EIS for the proposed project, it must at the very leastensure opportunities for significant public input on any environmental assessment,including allowing the public the opportunity to comment on the draft EA before it isfinalized.13 We echo the Hawaii Department of Transportation’s concerns that theexisting notices for the proposed project might otherwise “have limited public outreachcapability locally,” and echo the Department’s request that FERC “make sure thatadequate efforts [are] made . . . to solicit public comments.”14C. Direct Impacts of the Proposed FacilitiesThe proposed facilities – including the transportation, storage, and regasificationequipment used during the phase 1 operations and the permanent storage tanks,terminal construction, and associated infrastructure necessary for phases 2 and 3 – willhave a range of adverse direct environmental effects. Few of these impacts arediscussed in the application and environmental report submitted by the Company, butFERC is required to analyze them to comply with its NEPA obligations. These impactsinclude (but are not limited to) air pollution, disruption of aquatic habitat, increasednoise and light pollution, and impacts on fish and wildlife related to the precedingimpacts. Each of these impacts is contrary to the public interest and must be consideredin FERC’s analysis. 1. Air EmissionsThe Company’s resource report states that no air quality issues are expected to resultfrom the operation of the phase 1 facilities, due to the type of equipment that will beused, and, perhaps, to phase 1’s small scale. RR at 4. This analysis, however, breaks upthe larger, three-phase project into smaller components in precisely the manner NEPAforbids. Churchill, 276 F.3d at 1076. FERC is required to engage in a fuller analysis,13 The public may “have less opportunity to comment on an EA than on an EIS.” SierraClub v. Marsh, 769 F.3d at 875. Whereas draft EIS’s must be circulated for publiccomment, 40 C.F.R. § 1503.1, the regulations require the agency to “involve . . . thepublic, to the extent practicable,” in preparing environmental assessments, id. §1501.4(b).14 Comment of Hawaii Department of Transportation re: Gas Company, LLC Request forAuthorization to Operate Liquified Natural Gas Facilities, FERC Docket CP12-498 (“DOTComments”) at 2. 17
    • considering air pollution that can be expected from the larger-scale phase 2 and 3operations as well.As revealed in the environmental review documents for LNG import terminal proposalsthat FERC has previously considered, LNG import terminals and associated infrastructurecan emit harmful quantities of a variety of air pollutants. For example, FERC’s EIS for theJordan Cove import terminal proposal that the agency considered several years agoestimated approximately 41 tons per year (tpy) of particulate matter (PM), 177 tpy ofsulfur dioxide (SO2), 250 tpy or less of nitrogen oxides (NOx), 136 tpy of carbonmonoxide (CO), and 17 tpy of volatile organic chemicals (VOC).15 Significant additionalquantities of many of these pollutants – including an additional 169 tpy of NOx – wereexpected from mobile sources associated with the project, id., and additional emissionswere expected from construction, id. at 4.11-17. In addition, the Jordan Cove EISpredicted about 70,000 tons of carbon dioxide, a greenhouse gas, during construction,and an additional 630,000 tons during annual operations. Id. at 4.11-30 to 31.The Company’s application does not address emissions of these pollutants (in either theoperation and construction phases) or discuss their harmful effects. The applicationthus underemphasizes their impact on the public interest.Sierra Club expects to provide further comment on the Company’s emissions during theNEPA public comment period. At this stage, we emphasize that the air emissions thatcan be expected from the Company’s proposed three-phase terminal project can causeextensive harmful impacts to human health and the environment. We briefly describethese impacts below.COCO can reduce oxygen delivery to the bodys organs and tissues.16 CO can beparticularly harmful to persons with various types of heart disease, who already have areduced capacity for pumping oxygenated blood to the heart. “For these people, short-term CO exposure further affects their body’s already compromised ability to respondto the increased oxygen demands of exercise or exertion.”17VOC and NOxVOC and NOx emissions harm the environment by increasing the formation of ground-level ozone (smog). Smog pollution harms the respiratory system and has been linkedto premature death, heart failure, chronic respiratory damage, and premature aging of15 Jordan Cove Import Terminal EIS § 4.11 at 4.11-19, attached as Exhibit 3.16 http://www.epa.gov/air/carbonmonoxide/health.html, attached as Exhibit 4.17 Id. 18
    • the lungs.18 Smog may also exacerbate existing respiratory illnesses, such as asthma andemphysema, or cause chest pain, coughing, throat irritation and congestion. Children,the elderly, and people with existing respiratory conditions are the most at risk fromozone pollution.19Significant ozone pollution also damages plants and ecosystems.20 In addition, ozonecontributes substantially to global climate change over the short term. According to arecent study by the United Nations Environment Program (UNEP), ozone is now thethird most significant contributor to human-caused climate change, behind carbondioxide and methane.21GHGsLNG terminals, such as the Jordan Cove import terminal proposal mentioned above, canemit significant quantities of greenhouse gases. Although the Company’s proposedfacilities are smaller in scale than Jordan Cove, the Jordan Cove application provides asense of the order of magnitude of potential greenhouse gas emissions that FERC mustanalyze. These greenhouse gas emissions will increase global warming, harming boththe local and global environments.The impacts of climate change caused by greenhouse gases include “increased air andocean temperatures, changes in precipitation patterns, melting and thawing of globalglaciers and ice, increasingly severe weather events, such as hurricanes of greaterintensity and sea level rise.” A warming climate will also lead to loss of coastal land indensely populated areas, shrinking snowpack in western states, increased wildfires, andreduced crop yields. More frequent heat waves as a result of global warming have18 EPA, Proposed New Source Performance Standards and Amendments to the NationalEmissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry:Regulatory Impact Analysis, 4-25 (July 2011), available athttp://www.epa.gov/ttnecas1/regdata/RIAs/oilnaturalgasfinalria.pdf and attached asExhibit 5 (hereinafter O&G NSPS RIA); Jerrett et al., Long-Term Ozone Exposure andMortality, New England Journal of Medicine (Mar. 12, 2009), available athttp://www.nejm.org/doi/full/10.1056/NEJMoa0803894#t=articleTop, attached asExhibit 6.19 See EPA, Ground-Level Ozone, Health Effects, available athttp://www.epa.gov/glo/health.html attached as Exhibit 7; EPA, Nitrogen Dioxide,Health, available at http://www.epa.gov/air/nitrogenoxides/health.html, attached asExhibit 8.20 O&G NSPS RIA at 4-26.21 Id. See also United Nations Environment Programme and World MeteorologicalOrganization, (2011): Integrated Assessment of Black Carbon and Tropospheric Ozone:Summary for Decision Makers (hereinafter “UNEP Report,” available at http://www.unep.org/dewa/Portals/67/pdf/Black_Carbon.pdf), at 7, attached as Exhibit 9. 19
    • already affected public health, leading to premature deaths. And threats to publichealth are only expected to increase as global warming intensifies. For example, awarming climate will lead to increased incidence of respiratory and infectious disease,greater air and water pollution, increased malnutrition, and greater casualties from fire,storms, and floods. Vulnerable populations—such as children, the elderly, and thosewith existing health problems—are the most at risk from these threats.Sulfur DioxideSulfur dioxide causes respiratory problems, including increased asthma symptoms.Short-term exposure to sulfur dioxide has been linked to increased emergency roomvisits and hospital admissions. Sulfur dioxide also reacts in the atmosphere to formparticulate matter (PM), an air pollutant which causes a great deal of harm to humanhealth.22 PM is discussed separately below.Particulate MatterPM consists of tiny particles of a range of sizes suspended in air. Small particles posethe greatest health risk. These small particles include “inhalable coarse particles,” whichare smaller than 10 micrometers in diameter (PM10), and “fine particles” which are lessthan 2.5 micrometers in diameter (PM2.5). PM10 is primarily formed from crushing,grinding or abrasion of surfaces; PM2.5 is primarily formed by incomplete combustion offuels or through secondary formation in the atmosphere.23PM causes a wide variety of health and environmental impacts. PM has been linked torespiratory and cardiovascular problems, including coughing, painful breathing,aggravated asthma attacks, chronic bronchitis, decreased lung function, heart attacks,and premature death. Sensitive populations, include the elderly, children, and peoplewith existing heart or lung problems, are most at risk from PM pollution.24 PM alsoreduces visibility,25 and may damage important cultural resources.26 Black carbon, a22 EPA, Sulfur Dioxide, Health, available athttp://www.epa.gov/air/sulfurdioxide/health.html, attached as Exhibit 10.23 See EPA, Particulate Matter, Health, available athttp://www.epa.gov/pm/health.html, attached as Exhibit 11; BLM, West TavaputsPlateau Natural Gas Full Field Development Plan Final Environmental Impact Statement(“West Tavaputs FEIS”), at 3-19 (July 2010), available athttp://www.blm.gov/ut/st/en/fo/price/energy/Oil_Gas/wtp_final_eis.html.24 O&G NSPS RIA at 4-19; EPA, Particulate Matter, Health25 EPA “Visibility – Basic Information” http://www.epa.gov/visibility/what.html, attachedas Exhibit 12.26 See EPA, Particulate Matter, Health; West Tavaputs EIS, at 3-19; O&G NSPS RIA at 4-24. 20
    • component of PM emitted by combustion sources such as flares and older dieselengines, also warms the climate and thus contributes to climate change.27Hydrogen SulfideHydrogen sulfide is an air pollutant with toxic properties that smells like rotten eggs andcan lead to neurological impairment or death. Long-term exposure to hydrogen sulfideis linked to respiratory infections, eye, nose, and throat irritation, breathlessness,nausea, dizziness, confusion, and headaches.28 Hydrogen sulfide emissions may beharmful even at low concentrations.29 2. Water and Aquatic Habitat ImpactsThe Company reports no water or aquatic habitat impacts, again due to its failure todisclose or analyze impacts associated with the second and third phases of the proposedterminal. RR at 3. As explained, FERC is required to analyze all impacts that can beexpected as a result of the three-phase terminal proposal, including harm to local waterquality as a result of increased stormwater pollution and increased shipping traffic. Webriefly describe some of these impacts below.Stormwater runoff from the proposed terminal can be expected to impair water quality.As the National Marine Fisheries Service has asserted in connection with another LNGterminal application, stormwater runoff associated with an LNG terminal can contain“heavy metals, petroleum products and brake chemicals and compounds that aredeleterious to fish and fish habitat.”30In addition, ship traffic inherent in LNG import activities can be expected to impair waterquality in Honolulu Harbor. As FERC explained in a prior EIS, LNG ship traffic causes“resuspension of bottom sediments and resulting increases in turbidity.” 31 Separate27 UNEP Report at 6; IPCC (2007) at Section 2.4.4.3.28 EPA, Office of Air Quality Planning and Standards, Report to Congress on HydrogenSulfide Air Emissions Associated with the Extraction of Oil and Natural Gas (EPA-453/R-93-045), at ii (Oct. 1993) (hereinafter “EPA Hydrogen Sulfide Report”), attached asExhibit 13.29 See James Collins & David Lewis, Report to CARB, Hydrogen Sulfide: Evaluation ofCurrent California Air Quality Standards with Respect to Protections of Children (Sept. 1,2000), available at http://oehha.ca.gov/air/pdf/oehhah2s.pdf, attached as Exhibit 14.30 Comment of National Marine Fisheries Service on Final Environmental ImpactStatement for the Jordan Cove Energy Liquefied Natural Gas Terminal and PacificConnector Gas Pipeline Project, FERC Docket CP07-441, at 2 (June 5, 2009) (hereinafter“NMFS Comment on CP07-441”), attached as Exhibit 15. Further information isprovided in the final EIS prepared for that docket at section 4-3.43.31 Jordan Cove CP07-441 EIS § 4.3.2.3, attached as Exhibit 16. 21
    • from effects on water quality, the frequent passage of LNG shipping traffic through thebay, coupled with the large exclusion zones that may be maintained around these shipsfor safety, will significantly disrupt other human users of the bay, including fishermenand recreational boaters. 3. Noise, Light, Traffic, and Safety IssuesConstruction and operation of the proposed project will cause significant increases inlocal noise and light pollution, which will adversely impact nearby residents and wildlife.The application fails to discuss such impacts in any detail, noting only the noise pollutionexpected from LNG moving through above-ground piping connecting the containers tobe used in phase 1 to the regasification units used to inject them into the distributionsystem. RR at 4. The Sierra Club reiterates the concerns, expressed by the HawaiiDepartment of Transportation, that the proposed project will negatively impact thebusinesses in the Domestic Commercial Fishing Village, which is adjacent to theproposed operations in Honolulu Harbor.32 FERC is required to seriously analyze suchimpacts under NEPA.The Club also shares the Department’s concern that the proposed project may impactthe safety of nearby residents and motorists on the nearby highway, and echoes itsrequest that safety considerations be fully analyzed and safety measures fully discussedand disclosed.33Finally, the Club echoes the Department’s concern that the traffic impacts of theproposed project be fully discussed and analyzed. The Company plans to use trucks tohaul LNG containers to various points on the Company’s distribution network, but failsto provide any analysis of the impacts of this additional truck traffic. RR at 2. FERC isrequired to discuss these impacts, and must also analyze cumulative traffic impactscaused by all three phases of the Company’s proposal. 4. Fish and WildlifeThe proposed project is likely to adversely affect fish and wildlife by directly disturbingterrestrial and aquatic habitat. Again, the Company has not made any attempt tocatalogue such impacts because its application’s discussion of impacts is improperlylimited to the impacts of phase 1. RR at 3. Considered together with phases 2 and 3,the proposed operations – which will ultimately include a storage capacity of up to 10millions gallons from permanent land-based storage facilities and potentially floating32 DOT Comments at 1.33 Id. 22
    • storage regasification units – will have substantial impacts on fish and wildlife. App. at23.Honolulu County, where the proposed project will be located, is home to theendangered Hawaiian hoary bat, as well as 12 endangered and threatened bird species,four endangered and threatened reptile species, and dozens of endangered plantspecies.34 The presence of so many endangered species in the county raises thesignificant possibility of species impacts, which FERC is required to consider carefully.The County may also shelter other species of conservation interest. Honolulu Harbor,which will be a delivery site for LNG during phase 1 and is likely to remain so during laterphases of the project, App. at 19, shelters spinner dolphins and, during the wintermonths, humpback whales.35 Whales and dolphins can easily suffer injury or death as aresult of a ship collision, and the areas of greatest concern relative to ship strikes arelocated near the harbor entrance.36 FERC is required to seriously assess the impacts ofthe proposed LNG imports and the anticipated LNG terminal infrastructure on whales,dolphins, and other local wildlife.D. FERC Should Obtain Additional Information Enabling it to Analyze the Proposal’s Indirect EffectsAt present, the application fails to provide FERC with basic information regarding theamount and likely source of the LNG to be used by the Gas Company. The Companyinsists that all of the LNG it will use will come from the continental United States, App.at 18, 21, 27, and mentions that it will come from liquefaction facilities such as those inthe northeast or Midwest, App. at 29. But the application does not even identify whichliquefaction facilities will supply the proposed operations. The application vaguelymentions two companies that operate liquefaction facilities, Air Liquide and Praxair,although it does not state where the facilities are located or where the operators obtaintheir natural gas supplies. App. at 30. It also provides only a vague sense of how muchLNG the completed terminal facilities are expected to process and use, stating only thatthe facilities will provide fuel for 75% of customer requirements, plus 400 MW of gas-fired generation. App. at 23. Information about the extent and provenance of the LNG34 U.S. Fish and Wildlife Service, Species by County Report, Honolulu County, available athttp://ecos.fws.gov/tess_public/countySearch!speciesByCountyReport.action?fips=15003, and attached as Exhibit 17.35 Marc O. Lammers et al., The Occurrence and Distribution of Marine Mammals AlongOahu’s Ewa/Honolulu Coast, Marine Mammal Research Program/Hawaii Institute ofMarine Biology Technical Report 20001, 3 (2000), available athttp://www.oceanwidescience.org/PDF/Navatek%20Final%20Report.PDF, and attachedas Exhibit 18.36 Id. at 17. 23
    • that will be used by the proposed project would assist FERC in analyzing the project’simpacts on Hawaii’s energy future, and could also assist the agency in analyzing theextensive impacts of the drilling likely to be induced as a result of the Company’sproposal. FERC should obtain this information to assist it in analyzing the proposal’simpacts.E. The Proposed Project’s Effects on Development of Renewable Energy Resources in HawaiiThe proposed project will also have a variety of indirect effects. Chief among these is itsimpact on the development of renewable energy resources in Hawaii. The Companyargues, without any real support, that the phase 1 facilities further the goals of theHawaii Clean Energy Initiative. The Company offers scant evidence for this contention,however. FERC must not accept the Company’s arguments at face value and mustinstead take a close look at the impact of LNG import on development of renewableenergy in the state.Hawaii has made it a public policy priority to develop clean, renewable energy in thestate. As the Company’s application mentions, the Hawaii Clean Energy Initiative aims“to achieve 70% clean energy by 2030 with 30% from efficiency measures, and 40%coming from locally generated renewable sources.”37 As the Company recognizes,however, the goals of the Clean Energy Initiative are not legally binding, although thestate’s legally binding renewable portfolio standard (RPS) has taken the first steptowards achieving the ambitious goals of the initiative. App. at 13 n.18.Further, despite adoption of the RPS, there is still potential for delay or missteps inachieving Hawaii’s renewable energy goals. The RPS allows utilities to avoid penaltiesassociated with a failure to meet RPS goals if they can demonstrate their “[i]nability toacquire sufficient renewable energy due to lapsing of tax credits related to renewableenergy development” or even simply their “[i]nability to acquire sufficient cost-effectiverenewable energy.” Haw. Rev. Stat. § 269-92(d). Hawaii still has significant progress leftto make before it achieves its renewable energy goals, and, as these exceptionsdemonstrate, it is not certain that all of the goals will ultimately be achieved.Accordingly, FERC must be attentive to the potential for the Company’s proposal toimpede or delay Hawaii’s achievement of its renewable energy objectives, keeping inmind that Hawaii has already decided that swift deployment of renewable energy is inthe public interest. In particular, FERC must closely examine the company’s argumentthat importing a new fossil fuel will assist Hawaii in transitioning to renewable energy.Below, we examine each of the Company’s contentions in turn.37 Hawaii Clean Energy Initiative, http://www.hawaiicleanenergyinitiative.org/. 24
    • First, the Company argues that LNG import will advance Hawaii’s clean energy goalsbecause “[u]tilizing a lower cost energy source such as natural gas would significantlyreduce the cost per kilowatt hour of electricity.” App. at 35. Even the Company’s claimthat natural gas will have a consistently low cost may be too facile; at a seminarpresented by the Company itself in August 2012, “an LNG industry consultant explainedthat because of transport issues, wholesale LNG prices can vary by more than 25times.”38 Given this variation, it is not clear that LNG will be consistently cheap forHawaii. Moreover, even assuming Hawaii can consistently access affordable LNG, it isunclear how infrastructure facilitating the use of fossil fuel energy will assist Hawaii indeveloping renewable energy resources. In fact, investors’ incentives to invest ininnovative renewable energy technologies may diminish if opportunities to invest inmore “familiar” fossil fuel technologies become available. App. at 6.Indeed, the International Energy Agency expects that, in the United States alone, thenatural gas boom will result in a 10% reduction in renewables relative to a baselineworld without increased gas use and trade.39 In other words, as senior InternationalEnergy Agency officials recently warned, “[r]enewable energy may be the victim ofcheap gas prices.”40 Researchers at the Renewable and Sustainable Energy Instituteagree: “Wind,” they observe, “had [before the fracking boom] been capable ofcompeting with natural gas generation on a cost basis, thanks to advances in technologyand a federal production tax credit. Installation of new renewable energy facilities hasnow all but dried up, unable to compete on a grid now flooded with a low-cost, high-energy fuel that can provide power on demand.”41 Pulitzer-prize winning oil and gashistorian Daniel Yergin agrees that “[a]bundant, relatively low-priced supplies now makenatural gas a highly competitive alternative to both nuclear and wind power.”4238 Jeff Mikulina, LNG: Smart Public Policy Or Bridge To Nowhere?, Honolulu Civil Beat,Oct. 8, 2012, available at http://www.civilbeat.com/posts/2012/10/08/17317-lng-smart-public-policy-or-bridge-to-nowhere/, and attached as Exhibit 19.39 International Energy Agency, Golden Rules for a Golden Age of Gas, Ch. 2 p. 80 (2012),attached as Exhibit 20 and available at http://www.iea.org/publications/freepublications/publication/WEO2012_GoldenRulesReport.pdf.40 Fiona Harvey, Golden age of gas threatens renewable energy, IEA warns, TheGuardian, May 29, 2012, available athttp://www.guardian.co.uk/environment/2012/may/29/gas-boom-renewables-agency-warns, and attached as Exhibit 21.41 Kevin Doran & Adam Reed, Natural Gas and Its RoleIn the U.S. Energy Endgame, Yale Environment 360, Aug. 12, 2012, available athttp://e360.yale.edu/feature/natural_gas_role_in_us_energy_endgame/2561/, andattached as Exhibit 22.42 Daniel Yergin, Stepping on the Gas, The Wall St. Journal, Apr. 2, 2011, available athttp://resourceroyaltyllc.com/EducationalInformation/Articals/DanielYerginWSJ02042011.pdf, and attached as Exhibit 23. 25
    • Bringing LNG into Hawaii accordingly introduces the potential for investment dollarsthat might once have gone towards renewables development to be diverted to LNGinvestments. In fact, investment in renewables may not even be possible – let aloneattractive – if the Company’s limited resources have been expended on new LNGinfrastructure.The Company also states that “natural gas-fired electric generation could be used tosupport the State’s renewable resources,” suggesting, perhaps, that substitutingHawaii’s aging power plants with newer natural gas combined-cycle technologies wouldreduce the cost of electricity and lower emissions. App. at 36. But Hawaii’s goal is notto replace fossil fuel generation with more efficient fossil fuel generation – its goal is tomake fossil fuel generation unnecessary (or less necessary) by reducing demand forpower through energy efficiency or introducing renewables. See Haw. Rev. Stat. § 269-91 (excluding “fossil-fueled qualifying facilities that sell electricity to electric utilitycompanies” from the set of combined heat and power systems that count towardsenergy efficiency targets in the state’s renewable portfolio standard). The goal ofdemand reduction is not advanced by the Company’s proposal.Further, LNG imports, and even new combined-cycle natural gas plants, are notnecessary to development of renewable energy resources in Hawaii; indeed, they couldbe detrimental to renewables’ development, for the reasons explained. Combined-cyclepower plants like those mentioned in the Company’s application, App. at 36, can be aflexible complement to renewables, but they are not necessary for renewablesdevelopment. Hawaii can achieve the same reliability by taking advantage of smartstorage technologies, in addition to firm renewable energy sources. Moreover, even adecision by Hawaii to upgrade its fossil fuel plants to better complement renewableenergy technologies does not depend on LNG import; the state could potentiallyupgrade its existing power plants without introducing a new fossil fuel that has thepotential to divert dollars from renewable energy investments.Finally, the Company points to a letter from Governor Abercrombie expressing supportfor natural gas development in Hawaii. App. at 35; Ex. I. The letter suggests that “theportion of power generation that would continue to use imported petroleum oil duringthe transition to renewable energy could instead be converted to a potentially cheaperand cleaner fuel such as liquefied natural gas.” App. at Ex. 1. The letter does notgrapple, however, with the potential for the introduction of natural gas to impedeinvestment in renewables and demand-side energy efficiency. FERC must give theseimportant questions close and careful attention before concluding that LNG import is inthe public interest.F. Effects of the Proposal on Greenhouse Gas Emissions in HawaiiBecause the proposal could disrupt development of renewable energy technologies inHawaii, the proposal’s impacts on greenhouse gas emissions must be closely examined. 26
    • Even if the proposal enables Hawaii to switch away from a relatively carbon-intensivefossil fuel like the petroleum-based synthetic natural gas the Company currently uses, itsutility in decreasing overall greenhouse gas emissions is questionable if it ultimatelydiscourages investment in renewable energy resources.Moreover, even if the proposed project somehow had no impact on renewable energydevelopment, FERC would still be obligated to carefully analyze whether switching toLNG will truly provide significant greenhouse gas emissions reductions, even if the LNGis replacing synthetic natural gas (SNG) prepared from naphtha-based feedstock.43 App.at 2. Throughout the application, the Company suggests that importing LNG into Hawaiican provide an environmental benefit by helping Hawaii switch away from petroleum-based fuel. See, e.g., App. at 17. But the available evidence demonstrates substantialuncertainty as to the greenhouse gas reductions available through use of LNG.First, on a global level, the IEA has concluded that high levels of gas production andtrade will produce “only a small net shift” in global greenhouse gas emissions, withatmospheric CO2 levels stabilizing at over 650 ppm and global warming in excess of 3.5degrees Celsius, “well above the widely accepted 2°C target.”44Second, when LNG is imported into a new market to substitute for fuel oil or coal, theavailable evidence indicates that this substitution is likely to cause little, if any,reduction in global greenhouse gas emissions. As explained below, the production ofnatural gas itself causes substantial greenhouse gas emissions. Additional energy is thenconsumed in the transportation of the gas, with attendant greenhouse gas emissions.Finally, as contemplated in the Company’s application, LNG must be regasified at theimport terminal, again consuming fuel and causing additional emissions. Theseoperations drastically increase the lifecycle greenhouse gas emissions of LNG, addingbetween 24.7 and 27.5 tons of CO2e per MMBtu.4543 As illustrated by Figure 1, below, SNG can be extraordinarily greenhouse gas intensive.For the reasons explained in this section, however, FERC must not uncritically assumethat LNG is a significantly less GHG-intensive source, given the extensive greenhousegases emitted during production, liquefaction, transportation, and regasification.44 IEA, Golden Rules at 80.45 Paulina Jaramillo, W. Michael Griffin, H. Scott Matthews, Comparative Life-Cycle AirEmissions of Coal, Domestic Natural Gas, LNG, and SNG for Electricity Generation, 41Environ. Sci. Technol. 6,290 (2007) (Jaramillo 2007), available athttp://www.ce.cmu.edu/~gdrg/readings/2007/09/13/Jaramillo_ComparativeLCACoalNG.pdf, and attached as Exhibit 24. The supporting information for this article is availableat http://pubs.acs.org/doi/suppl/10.1021/es063031o/suppl_file/es063031osi20070516_042542.pdf, and attached as Exhibit 25 (“Jaramillo SupportingInformation”). An earlier, related report with some additional information is PaulinaJaramillo, W. Michael Griffin, H. Scott Matthews, Comparative Life Cycle Carbon 27
    • Due to emissions from liquefaction, transportation and gasification, LNG generatessignificantly more greenhouse gas emissions than domestic natural gas. Forperspective, natural gas combustion emits roughly 120 pounds of CO2e per MMBtu. See,e.g., Jaramillo Supporting Info at 9. Using the above conservative figures, the process ofliquefying, transporting, and regasifying LNG accordingly emits 19% to 23% of the CO2eemitted by natural gas combustion itself—a substantial increase. In their 2007 study,Jaramillo et al. concluded that this increase could bring LNG’s lifecycle greenhouse gasemissions into parity with coal:Figure 1: Life-Cycle Emissions of LNG, Natural Gas, and Coal in Electricity Generation46Jaramillo’s analysis may even underestimate the emissions associated with LNG. It doesnot reflect recent studies that have raised estimates for emissions associated withnatural gas production. Recent studies have concluded that these emissions aresubstantial. Because these studies post-date the Jaramillo studies regarding exportemissions, they cast still further doubt on any climate advantage to LNG. In particular,the Jaramillo studies were conducted prior to shale gas boom. As explained furtherbelow, shale gas production’s methane emissions are drastically higher than those ofconventional gas production. Moreover, in April 2011 (well after the Jaramillo studieswere published), EPA released improved methodologies for estimating fugitive methaneemissions from all natural gas systems (unconventional and otherwise), which lead toEmissions of LNG Versus Coal and Gas for Electricity Generation (2005), available athttp://www.ce.cmu.edu/~gdrg/readings/2005/10/12/Jaramillo_LifeCycleCarbonEmissionsFromLNG.pdf, and attached as Exhibit 26.46 From Jaramillo 2007 at 6,295. “SNG,” in the figure, refers to synthetic natural gasmade from coal. 28
    • higher estimates. EPA, Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990 –2009, U.S. EPA, EPA 430-R-11-005.47These recent studies estimate that aggregate domestic natural gas production releasesat least 44 pounds of CO2e per MMBtu. A report from the Worldwatch Institute andDeutsche Bank summarizes much of the recent work.48 Specifically, the WorldwatchReport synthesizes three other reports that used “bottom-up” methodologies toestimate natural gas production emissions, prepared by Dr. Robert Howarth et al., ofCornell,49 Mohan Jiang et al. of Carnegie-Mellon,50 and Timothy Skone of NETL.51 TheWorldwatch Report separately derived a “top-down” estimate, which produced a resultsimilar to the NETL estimate. Worldwatch Report at 9. These various assessments aresummarized in the following chart:47 Attached as Exhibit 27. The executive summary to this document is Exhibit 28.48 Mark Fulton et al., Comparing Life-Cycle Greenhouse Gas Emissions from Natural Gasand Coal (Aug. 25, 2011) (“Worldwatch Report”), attached as Exhibit 29.49 Robert W. Howarth et al., Methane and the greenhouse-gas footprint of natural gasfrom shale formations, Climactic Change (Mar. 2011), attached as Exhibit 30.50 Mohan Jiang et al., Life cycle greenhouse gas emissions of Marcellus shale gas,Environ. Res. Letters 6 (Aug. 2011), attached as Exhibit 31.51 Timothy J. Skone, Life Cycle Greenhouse Gas Analysis of Natural Gas Extraction andDelivery in the United States, Presentation to Cornell (May 12, 2011), attached as Exhibit32. NETL has also put out a fuller version of this analysis. See also Timothy J. Skone, LifeCycle Greenhouse Gas Inventory of Natural Gas Extraction, Delivery and ElectricityProduction (Oct. 24, 2011), attached as Exhibit 33. 29
    • Figure 2: Comparison of Recent Life-Cycle Assessments52As this figure demonstrates, although the 2011 studies differ, they all estimateproduction greenhouse gas emissions (combined methane and “upstream CO2”) in asimilar range. Synthesizing these studies, the Worldwatch Report estimated normalizedlife-cycle GHG emissions from domestic natural gas production (i.e., excludingliquefaction, transport, and gasification of LNG) at approximately 20.1 kilograms, or over44 pounds, of CO2e/MMBtu. Worldwatch Report at 15 Ex. 8. Moreover, some studiesestimate that production emissions are significantly higher.Jaramillo used production emission estimates that are much lower than those producedby the more recent studies, and using the recent and higher figures appears to erodewhat little climate advantage Jaramillo found LNG to have over coal. Jaramillo usedestimates of 15.3 to 20.1 pounds CO2e/ MMBtu, i.e., estimates that were at least 24pounds lower than the 2011 studies’. Jaramillo Supporting Information at 8. Jamarilloestimated total life-cycle emissions for LNG at 149.6 to 192.3 lbs CO2e/MMBtu. Id.Simply increasing these life-cycle estimates by 24 lbs CO2e represents a 12% to 16%52 Worldwatch Report at 3. 30
    • increase in total emissions. This increase substantially erodes any climate advantageLNG-fired electricity generation may have over coal-fired generation. As these studiesdemonstrate, the long-term benefits of switching to LNG are extremely complex andmust be carefully examined.Further, rough estimates demonstrate that, although it is possible that replacingpetroleum-based fuel with LNG may ultimately produce some greenhouse gas benefits,this too is an extremely complicated question that FERC should examine closely. Thelifecycle greenhouse gas emissions data generated by California for purposes of its newLow Carbon Fuels Standard (which covers transportation fuels) show greenhouse gasemissions from petroleum products that may be roughly comparable to fuel oil to be inthe range of 95g CO2e per megajoule, or about 752 lb CO2e/mWh.53 A comparison toFigure 1 reveals that this 752 lb CO2e/mWh figure is actually lower than Jaramillo 2007’sestimate of lifecycle emissions of LNG combusted using the current U.S. fleet of powerplants, suggesting, at least at first blush, that replacing fuel oil with LNG provides nogreenhouse gas benefit. The estimate derived from the California database may wellunderstate emissions from the fuel used in Hawaii, of course. An accurate estimatewould more closely mirror the Company’s operations, using naphtha as the base fueland accounting for additional greenhouse gas emissions associated with converting thefuel into synthetic natural gas. App. at 8-9. Such an estimate also would account for thefuel efficiency of the power plants in which the fuel is ultimately combusted. Butalthough these back-of-the-envelope calculations are highly imperfect, they do illustratethat the greenhouse gas benefits that the Company’s proposal will provide are highlyuncertain and must be examined in detail. FERC must not accept the Company’sassertions that LNG is a “cleaner” alternative at face value.G. Effects of The Additional Gas Production that Exports Will InduceThe proposed project also will induce additional natural gas production, likely fromshale gas plays in which hydraulic fracturing is used. This induced production is likely toresult in significant environmental harms. Although FERC recently declined to considersuch impacts in the Sabine Pass proceeding, FERC Docket CP11-72, those orders arefactually distinguishable and do not bind FERC here.FERC must consider these effects in its own NGA public interest analysis. These effectsalso must be examined during the NEPA process. 1. Effects Related to Induced Drilling53 Cal. Air Resources Bd., LCFS Lookup Tables as of December 2009, Table 6. CarbonIntensity Lookup Table for Gasoline and Fuels that Substitute for Gasoline, available athttp://www.arb.ca.gov/fuels/lcfs/121409lcfs_lutables.pdf, and attached as Exhibit 34. 31
    • Although the Company’s application will not likely impact domestic natural gasproduction to the same degree as the many LNG export applications currently beforethe Commission, it is nonetheless certain to induce additional production, albeit on asmaller scale.As we explain below, this increased production will have significant adverseenvironmental effects that are undoubtedly “indirect effects” which NEPA and the NGArequire FERC to consider. Although FERC declined to consider these effects in its SabinePass orders, FERC should not follow Sabine Pass here. Accordingly, FERC must evaluatethe environmental impacts of the additional natural gas production that will be inducedby operation of the proposed project. a. The Company’s Imports of Natural Gas Will Induce Additional Natural Gas ProductionIncreased consumption of LNG through export from the continental United States toHawaii will induce further gas production, primarily from shale gas. The EnergyInformation Administration (“EIA”) recently studied LNG export at the behest of DOE/FE,and concluded that across all modeled export scenarios, “[n]atural gas markets in theUnited States [would] balance in response to increased natural gas exports largelythrough increased natural gas production.” EIA, Effect of Increased Natural Gas Exportson Domestic Energy Markets (“EIA Study”), p.6 (Jan. 2012).54 Although the EIA studyfocused on export of natural gas outside the United States, its reasoning also applies toexports from the continental United States, where most U.S. gas production occurs, toHawaii.It is likely that the majority of this induced production will come from shale gas sources.EIA concluded that “On average, across all cases and export scenarios, the shares of theincrease in total domestic production coming from shale gas, tight gas, [and] coalbedsources are 72 percent, 13 percent, [and] 8 percent,” respectively. EIA Study at 11.Shale gas production (as well as coalbed and tight sands production) requires thecontroversial practice of hydraulic fracturing, or fracking. See DOE, Secretary of Energy’sAdvisory Board, Shale Gas Production Subcommittee First 90-Day Report (Aug. 18, 2011)at 8.55 The extensive impacts of fracking are discussed in detail below. First, however,we explain FERC’s obligation to consider the effects of fracking and the other impactsassociated with induced production. b. FERC Must Consider Induced Production54 Attached as Exhibit 35.55 Attached as Exhibit 36. The Board’s Second 90-Day Report is attached as Exhibit 37. 32
    • Natural gas production—from both conventional and unconventional sources—is asignificant air pollution source, can disrupt ecosystems and watersheds, leads toindustrialization of entire landscapes, and presents challenging waste disposal issues.These impacts were recently highlighted by a Subcommittee of the DOE’s Secretary ofEnergy’s Advisory Board, which identified “a real risk of serious environmentalconsequences” resulting from continued expansion of shale gas production. DOE,Secretary of Energy’s Advisory Board, Shale Gas Production Subcommittee Second 90-Day Report (Nov. 18, 2011) at 10.56 These risks are discussed in greater detail below.Although some states and federal agencies are taking steps to limit these harms, theseefforts are uncertain and, even if fully implemented, will not eliminate the dangers.Environmental impacts of this increased production, including “growth inducingeffects,” are thus manifestly “reasonably foreseeable” indirect effects of the Company’sproposal. Environmental effects of therefore production must be included in the NEPAanalysis. See 40 C.F.R. § 1508.8. These effects will be added to the effects of gasproduction (and other environmental burdens from other industries) already present inthe gas plays which the Company affects, and will add to the production induced byinternational export proposals. FERC must, in an EIS, fully describe all of these effectsand develop alternatives which would avoid them, including the alternative of denyingthe Company’s application, limiting the LNG used by the Company, or imposingenvironmental controls on gas produced for shipment to Hawaii.The requirement to consider indirect impacts such as induced drilling is clear on the faceof the statute and its implementing regulations and has been repeatedly reinforced bythe courts. As the Ninth Circuit Court of Appeals recently explained, “Because ‘NEPAplaces upon an agency the obligation to consider every significant aspect of theenvironmental impact of a proposed action,’ the considerations made relevant by thesubstantive statute driving the proposed action must be addressed in NEPA analysis.”Oregon Natural Desert Ass’n, 625 F.3d at 1109 (quoting Vt. Yankee Nuclear Power Corp.,435 U.S. at 553). Here, the “substantive statute” requires FERC and DOE/FE todetermine whether or not gas exports are in the “public interest,” a term which theSupreme Court has repeatedly held includes consideration of environmental impacts inhis context. NAACP, 425 U.S.at 670 n.4; Udall, 387 U.S. at 450. Thus, just as theagencies must consider upstream environmental impacts in their Natural Gas Actdeterminations, so, too, FERC (and DOE/FE) must analyze and disclose these impacts inthe NEPA analysis that will support these final determinations.Infrastructure projects, like the Company’s proposal, that enable resource extractionactivities to expand upstream naturally must fully analyze those impacts in the NEPAframework. In Northern Plains Resource Council v. Surface Transportation Board, 668F.3d 1067, 1081-82 (9th Cir. 2011), for instance, the Court considered a railway line that56 Attached as Exhibit 37. 33
    • was developed in order to expand coal production at several mines. Id. It held that theSurface Transportation Board’s NEPA analysis for the line was illegal because the Boardhad refused to consider the mines’ impacts. The Court held that such impacts wereplainly “reasonably foreseeable” – and, indeed, were the premise for the constructionproject in the first place. Id. They therefore had to be considered in the NEPA analysis.The same analysis applies here; increased production is a reasonably foreseeable resultof the Company’s proposal, and FERC must therefore fully account for this production inan EIS for its decision.DOE’s earlier efforts provide a useful example. In its 2005 Final Environmental ImpactStatement (EIS) for the Imperial-Mexicali 230-kV Transmission Lines, DOE wasconsidering, as it is here, whether it was in the public interest to construct newinfrastructure which directly enabled substantial upstream environmental impacts. TheImperial-Mexicali EIS considers the impacts of a transmission line that would enable theoperation of two Mexican power plants serving the U.S. market. Although DOE initiallyattempted to avoid considering the impacts of those plants, confining its analysis to theline itself, it was corrected by court order. See Border Power Plant Working Group v.Department of Energy, 260 F.Supp.2d 997 (S.D.Cal. 2003). The final EIS on remandaccordingly reviews both the transmission project and the upstream impacts of theplants to the extent they affected the U.S., including ways to mitigate those impacts. 57See, e.g., Final EIS at 4-43- 4-65 (analysis of air quality impacts and mitigation measures).We offer no particular view as to the technical merits of that analysis, but the approachused there – a description of induced upstream impacts coupled with consideration ofalternative ways to mitigate them – is generally appropriate for considering theupstream production impacts of LNG export. Indeed, the LNG case is simpler, becausethe upstream effects are domestic. Thus, unlike in the Imperial-Mexicali case, DOE neednot partition foreign from U.S. impacts, nor be concerned that certain mitigationmeasures proposed for another jurisdiction will not be enforceable. See 70 Fed. Reg.21,189, 21,195 (Apr. 25, 2005) (Record of Decision for the Imperial-Mexicali line,expressing some of these concerns). If DOE could manage the complex internationalissues inherent in the Border Power Plant Working Group EIS, FERC can certainlyadequately consider the domestic production impacts chiefly at issue here. c. FERC Is Required to Consider Induced Production Notwithstanding Its Decision Not to Do So in Sabine PassSierra Club recognizes that FERC has recently declined to address the environmentaleffects of induced production in two orders relating to a proposal to export LNG fromSabine Pass, Louisiana. 139 FERC ¶ 61,039 (April 16, 2012); 140 FERC ¶ 61,076 (July 26,57 The final EIS is available at: http://energy.gov/nepa/downloads/eis-0365-final-environmental-impact-statement. 34
    • 2012). These orders not bind FERC in this proceeding, and in any event were wronglydecided.First, prior FERC orders limit FERC’s authority only insofar as the AdministrativeProcedure Act requires FERC to provide a reasoned explanation for any departure fromits prior reasoning. See, e.g., Entergy Services, Inc. v. FERC, 391 F.3d 1240, 1251 (D.C.Cir. 2004). Indeed, FERC may reverse its position “with or without a change incircumstances” so long as FERC provides “a reasoned analysis” for the change.Louisiana Pub. Serv. Commn v. FERC, 184 F.3d 892, 897 (D.C. Cir. 1999) (quoting MotorVehicle Mfrs. Assn v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 57 (1983)). Concluding(as FERC should) that those orders were wrongly decided or factually distinguishablewould provide such a “reasoned analysis.”Second, the orders dismissed the possibility of analyzing induced production on thefaulty basis that such analysis would require localized predictions of productionresponse that FERC believed to be unavailable. Since the orders were issued, however,a study and model developed by Deloitte Marketpoint and used in Corpus Christi’srecent section 3 application has demonstrated the feasibility of the sort of localizedpredictions that FERC claims are necessary to assessment of environmental impacts.Numerous other LNG export terminal proponents have relied on this study inapplications to FERC and DOE/FE, and Corpus Christi applicant Cheniere Energy citedand endorsed the reports in its DOE/FE application.58 This Deloitte Report appears toforecast production shifts in specific shale plays in response to a given level of export.Deloitte Report at 6. According to Deloitte, its “World Gas Model” and its component“North American Gas Model” are designed precisely to provide the sort of fine-grainedanalysis that FERC contends is necessary before environmental impacts of induceddrilling can be considered. Deloitte explains that “[t]he North American Gas Model isdesigned to simulate how regional interactions of supply, transportation, and demanddetermine market clearing prices, flowing volumes, storage, reserve additions, and newpipelines throughout the North American natural gas market.” See Deloitte, Natural GasModels.59 The model “contains field size and depth distributions for every play, with afinding and development cost model included. This database connects these gas plays58 Deloitte Marketpoint, Made in America: The Economic Impact of LNG Exports from theUnited States (2011) (hereinafter “Deloitte Report”), available athttp://www.deloitte.com/assets/Dcom-UnitedStates/Local%20Assets/Documents/Energy_us_er/us_er_MadeinAmerica_LNGPaper_122011.pdf and attached as Exhibit38.59 Available at: http://www.deloitte.com/view/en_US/us/Industries/power-utilities/deloitte-center-for-energy-solutions-power-utilities/marketpoint-home/marketpoint-data-models/b2964d1814549210VgnVCM200000bb42f00aRCRD.htm and attached as Exhibit39. 35
    • with other energy products such as coal, power, and emissions.” Id. According toDeloitte, its modeling thus allows it to predict how gas production, infrastructureconstruction, and storage will respond to changing demand conditions. Id. To theextent that these predictions of local impact are not yet in the record, NEPA regulationsprovide that FERC “shall” obtain this information unless FERC demonstrates that thecosts of obtaining it are “exorbitant.” 40 C.F.R. §1502.22. Although Sierra Clubexpresses no particular view as to the particular merits of Deloitte’s approach, themodel’s existence demonstrates that it is not impossible to forecast the response ofdomestic LNG production to additional demand generated by proposals like the GasCompany’s.Third, we reiterate that the Sabine Pass orders were wrongly decided. Most broadly,FERC’s conclusion that its analysis should focus on local impacts, 139 FERC ¶ 61,039 at P27, n.35, is contrary to FERC’s own regulations. FERC regulations require, as part of thedemonstration of consistency with the public interest, a showing as to whether theproject will “improve the dependability of international energy trade” or “enhancecompetition within the United States for natural gas transportation or supply,” 18 C.F.R.153.7(c)(1)(i), both of which are factors that plainly extend beyond the purely localeffects of the project. More specifically, in holding that induced production was toouncertain to support environmental analysis, FERC conflated two types of uncertainty.First, FERC argued that there was uncertainty as to the total amount of production thatany particular export proposal would induce. This argument is belied by the numerousfederal and private entities that have made exactly this kind of prediction: at the bareminimum, FERC could have used the EIA Study’s prediction that 60 to 70% of exportedgas would be supplied by induced production, multiplying these percentages by thetotal volume of gas the Company proposes to bring into Hawaii from the continentalU.S. Second, FERC argued that it was uncertain exactly where any induced productionwould occur. As explained above, it is possible to make this sort of prediction, and NEPArequires FERC to seek out the information necessary to do so. But even if this type ofinformation were unavailable, this would not preclude meaningful discussion of theenvironmental impacts of induced production. FERC has offered no explanation as towhy knowledge of the particular location at which production will occur is necessary toassessment of the environmental effects of that production, and, as Sierra Club hasdemonstrated in the Sabine Pass proceedings and elsewhere, meaningful discussion ofaggregate environmental impacts can be provided without knowledge of specific wellsites. See, e.g.,DOE/FE Docket No. 10-111-LNG, Sierra Club Petition for Rehearing (Sept.6, 2012).60 d. Natural Gas Production is a Major Source of Air Pollution60 Attached as Exhibit 40. 36
    • Below, we briefly describe some of the primary air pollution problems caused by thenatural gas industry. These issues include direct emissions from production equipmentand indirect emissions caused by natural gas replacing cleaner energy sources. EPA hasmoved to correct some of these problems with new air regulations finalized this year,but as we later discuss, these standards do not fully address the problem. FERC musttherefore consider the air pollution impacts of increased natural gas production even ifEPA’s rules are finalized. i. Air Pollution Problems from Natural GasOil and gas operations emit methane (CH4), volatile organic compounds (VOCs), nitrogenoxides (NOx), sulfur dioxide (SO2), hydrogen sulfide (H2S), and particulate matter (PM10and PM2.5). Oil and natural gas operations also emit listed hazardous air pollutants(HAPs) in significant quantities, and so contribute to cancer risks and other acute publichealth problems. Pollutants are emitted during all stages of natural gas development,including (1) oil and natural gas production, (2) natural gas processing, (3) natural gastransmission, and (4) natural gas distribution.61 Within these development stages, themajor sources of air pollution include wells, compressors, pipelines, pneumatic devices,dehydrators, storage tanks, pits and ponds, natural gas processing plants, and trucksand construction equipment.Figure 1: The Oil and Natural Gas Sector61 EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and NaturalGas Production, Transmission, and Distribution, Background Technical SupportDocument for the Proposed Rules (“TSD”) at 2-4 (July 2011), attached as Exhibit 41. 37
    • There is strong evidence that emissions from natural gas production are higher thanhave been commonly understood. In particular, a recent study by a consortium ofresearchers led by the National Ocean and Atmospheric Administration (NOAA) EarthSystem Research Laboratory recorded pollution concentrations near gas fieldssubstantially greater than EPA estimates would have predicted. That researchmonitored air quality around oil and gas fields.62 It observed high levels of methane,propane, benzene, and other volatile organic compounds, in the air around the fields.The researchers write that their “analysis suggests that the emissions of the species wemeasured” – that is the cancer-causing, smog-forming, and climate-disrupting pollutantsreleased from these operations – “are most likely underestimated in currentinventories,” perhaps by as much as a factor of two.63These emissions have dire practical consequences. A second research team, led by theColorado School of Public Health, measured benzene and other pollutants released fromunconventional well completions.64 Elevated levels of these pollutants correspond toincreased cancer risks for people living within half of a mile from a well65 – a very largepopulation which will increase as drilling expands.We discuss the harmful effects of many of these pollutants in part IV.A.1, above. Below,we detail the sources of emissions within the gas production industry and providefurther information regarding the serious global, regional, and local impacts theseexploration and production emissions entail:Methane: Methane is the dominant pollutant from the oil and gas sector. Emissionsoccur as result of intentional venting or unintentional leaks during drilling, production,processing, transmission and storage, and distribution. For example, methane is emittedwhen wells are completed and vented, as part of operation of pneumatic devices andcompressors, and as a result of leaks (fugitive emissions) in pipelines, valves, and otherequipment. EPA has identified natural gas systems as the “single largest contributor toUnited States anthropogenic methane emissions.”66 The industry is responsible for over62 G. Petron et al., Hydrocarbon emissions characterization in the Colorado Front Range:A pilot study, 117 J. of Geophysical Research 4304, DOI 10.1029/2011JD016360 (2012),attached as Exhibit 42.63 Id. at 4304.64 L. McKenzie et al., Human Health Risk Assessment of Air Emissions from Developmentof Unconventional Natural Gas Resources, Science of the Total Environment (In Press,Mar. 22, 2012), attached as Exhibit 43.65 Id. at 2.66 76 Fed. Reg. 52,738, 52,792 (Aug. 23, 2011) (EPA proposed air rules for oil and gasproduction sector), attached as Exhibit 44. 38
    • 40% of total U.S. methane emissions.67 Methane causes harm both because of itscontributions to climate change and as an ozone precursor.Beginning with climate change, methane is a potent greenhouse gas that contributessubstantially to global climate change. Methane has at least 25 times the globalwarming potential of carbon dioxide over a 100 year time frame and at least 72 timesthe global warming potential of carbon dioxide over a 20-year time frame.68 The oil andgas production industry’s methane emissions amount to 5% of all carbon dioxideequivalent (CO2e) emissions in the country.69Because of methane’s effects on climate, EPA has found that methane, along with fiveother well-mixed greenhouse gases, endangers public health and welfare within themeaning of the Clean Air Act.70Methane also reacts in the atmosphere to form ozone.71 As we discuss elsewhere,ozone is a major public health threat, linked to a wide range of maladies. Ozone can alsodamage vegetation, agricultural productivity, and cultural resources. Ozone is also asignificant greenhouse gas in its own right, meaning that methane is doubly damaging toclimate – first in its own right, and then as an ozone precursor.Volatile Organic Compounds (VOCs) and NOx: The gas industry is a major source of theozone precursors VOCs and NOx.72 VOCs are emitted from well drilling and completions,compressors, pneumatic devices, storage tanks, processing plants, and fugitives fromproduction and transmission.73 The primary sources of NOx are compressor engines,67 Id. at 52,791–92.68 IPCC 2007—The Physical Science Basis, Section 2.10.2, and IPCC 2007- Summary forPolicymakers, attached as Exhibit 45. We note that these global warming potentialfigures may be revised upward in the next IPCC report. A more recent study by Shindellet al. estimates methane’s 100-year GWP at 33; this same source estimates methane’s20-year GWP at 105.69 76 Fed. Reg. 52,738 at 52,791–92.70 EPA, Endangerment and Cause or Contribute Findings for Greenhouse Gases, 74 Fed.Reg. 66,496, 66,516 (Dec. 15, 2009) (“Endangerment Finding”), attached as Exhibit 46.71 76 Fed. Reg. at 52,791.72 See, e.g., EPA Fact Sheet at 3; Al Armendariz, Emissions from Natural Gas Productionin the Barnett Shale Area and Opportunities for Cost-Effective Improvements (Jan. 26,2009), available at http://www.edf.org/documents/9235_Barnett_Shale_Report.pdf(hereinafter “Barnett Shale Report”) at 24, attached as Exhibit 47.73 See, e.g., TSD at 4-7, 5-6, 6-5, 7-9, 8-1; see also Barnett Shale Report at 24. 39
    • turbines, and other engines used in drilling and hydraulic fracturing.74 NOx is alsoproduced when gas is flared or used for heating.75As a result of significant VOC and NOx emissions associated with oil and gasdevelopment, numerous areas of the country with heavy concentrations of drilling arenow suffering from serious ozone problems. For example, the Dallas Fort Worth area inTexas is home to substantial oil and gas development. Within the Barnett shale region,as of September 2011, there were more than 15,306 gas wells and another 3,212 wellspermitted.76 Of the nine counties surrounding the Dallas Forth Worth area that EPA hasdesignated as “nonattainment” for ozone, five contain significant oil and gasdevelopment.77 A 2009 study found that summertime emissions of smog-formingpollutants from these counties were roughly comparable to emissions from motorvehicles in those areas.78Oil and gas development has also brought serious ozone pollution problems to ruralareas, such as western Wyoming.79 On March 12, 2009, the governor of Wyomingrecommended that the state designate Wyoming’s Upper Green River Basin as an ozonenonattainment area.80 The Wyoming Department of Environmental Quality conducted74 See, e.g., TSD at 3-6; See also Barnett Shale Report at 24. Air Quality Impact AnalysisTechnical Support Document for the Revised Draft Supplemental Environmental ImpactStatement for the Pinedale Anticline Oil and Gas Exploration and Development Projectat 11 (Table 2.1).75 TSD at 3-6; Colorado Department of Public Health and Environment, ColoradoVisibility and Regional Haze State Implementation Plan for the Twelve Mandatory Class IFederal Areas in Colorado, Appendix D at 1 (2011), available athttp://www.cdphe.state.co.us/ap/RegionalHaze/AppendixD/4-FactorHeaterTreaters07JAN2011FINAL.pdf, attached as Exhibit 48.76 Texas Railroad Commission,http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf (Accessed Nov. 21, 2011),attached as Exhibit 49.77 Barnett Shale Report at 1, 3.78 Id. at 1, 25-26.79 Schnell, R.C, et al. (2009), “Rapid photochemical production of ozone at highconcentrations in a rural site during winter,” Nature Geosci. 2 (120 – 122). DOI:10.1038/NGEO415, attached as Exhibit 50.80 See Letter from Wyoming Governor Dave Freudenthal to Carol Rushin, Acting RegionalAdministrator, USEPA Region 8, (Mar. 12, 2009) (“Wyoming 8-Hour Ozone DesignationRecommendations”), available athttp://deq.state.wy.us/out/downloads/Rushin%20Ozone.pdf, attached as Exhibit 51;Wyoming Department of Environmental Quality, Technical Support Document I forRecommended 8-hour Ozone Designation of the Upper Green River Basin (March 26,2009) (“Wyoming Nonattainment Analysis”), at vi-viii, 23-26, 94-05, available at 40
    • an extended assessment of the ozone pollution problem and found that it was“primarily due to local emissions from oil and gas . . . development activities: drilling,production, storage, transport, and treating.”81 Last winter alone, the residents ofSublette County suffered thirteen days with ozone concentrations considered“unhealthy” under EPA’s current air-quality index, including days when the ozonepollution levels exceeded the worst days of smog pollution in Los Angeles. 82 Residentshave faced repeated warnings regarding elevated ozone levels and the resulting risks ofgoing outside.83Ozone problems are mounting in other Rocky Mountain states as well. NortheasternUtah recorded unprecedented ozone levels in the Uintah Basin in 2010 and 2011. In thefirst three months of 2010—which was the first time that winter ozone was monitoredin the region—air quality monitors measured more than 68 exceedances of the federalhealth standard. On three of these days, the levels were almost twice the federalstandard.84 Between January and March 2011, there were 24 days where the NationalAmbient Air Quality Standard (NAAQS) for ozone were exceeded in the area. Again,ozone pollution levels climbed to nearly twice the federal standard.85 The Bureau ofhttp://deq.state.wy.us/out/downloads/Ozone%20TSD_final_rev%203-30-09_jl.pdf,attached as Exhibit 52.81 Wyoming Nonattainment Analysis at viii.82 EPA, Daily Ozone AQI Levels in 2011 for Sublette County, Wyoming, available athttp://www.epa.gov/cgi-bin/broker?msaorcountyName=countycode&msaorcountyValue=56035&poll=44201&county=56035&msa=-1&sy=2011&flag=Y&_debug=2&_service=data&_program=dataprog.trend_tile_dm.sas, attached as Exhibit53; see also Wendy Koch, Wyomings Smog Exceeds Los Angeles Due to Gas Drilling,USA Today, available at http://content.usatoday.com/communities/greenhouse/post/2011/03/wyomings-smog-exceeds-los-angeles-due-to-gas-drilling/1, attached as Exhibit54.83 See, e.g., 2011 DEQ Ozone Advisories, Pinedale Online! (Mar. 17, 2011) (documentingten ozone advisories in February and March 2011), available athttp://www.pinedaleonline.com/news/2011/03/OzoneCalendar.htm, attached asExhibit 55; Wyoming Department of Environmental Quality, Ozone Advisory forMonday, Feb. 28, Pinedale Online! (Feb. 27, 2011), available athttp://www.pinedaleonline.com/news/2011/02/OzoneAdvisoryforMond.htm, attachedas Exhibit 56.84 Scott Streater, Air Quality Concerns May Dictate Uintah Basins Natural Gas DrillingFuture, N.Y. TIMES, Oct. 1, 2010, available at http://www.nytimes.com/gwire/2010/10/01/01greenwire-air-quality-concerns-may-dictate-uintah-basins-30342.html, attachedas Exhibit 57.85 See EPA, AirExplorer, Query Concentrations (Ozone, Uintah County, 2011), available athttp://www.epa.gov/cgi-bin/htmSQL/mxplorer/query_daily.hsql?msaorcountyName=countycode&msaorcounty 41
    • Land Management (BLM) has identified the multitude of oil and gas wells in the regionas the primary cause of the ozone pollution.86Rampant oil and gas development in Colorado and New Mexico is also leading to highlevels of VOCs and NOx. In 2008, the Colorado Department of Public Health andEnvironment concluded that the smog-forming emissions from oil and gas operationsexceed vehicle emissions for the entire state.87 Moreover, significant additional drillinghas occurred since 2008. Colorado is now home to more than 46,000 wells.88 There isalso significant development in the San Juan Basin in southeastern Colorado andnorthwestern New Mexico, with approximately 35,000 wells in the Basin. As a result ofthis development and several coal-fired power plants in the vicinity, the Basin suffersfrom serious ozone pollution.89 This pollution is taking a toll on residents of San JuanCounty. The New Mexico Department of Public Health has documented increasedemergency room visits associated with high ozone levels in the County.90VOC and NOx emissions from oil and gas development are also harming air quality innational parks and wilderness areas. Researchers have determined that numerous“Class I areas” – a designation reserved for national parks, wilderness areas, and othersuch lands91 – are likely to be impacted by increased ozone pollution as a result of oiland gas development in the Rocky Mountain region, including Mesa Verde National Parkand Weminuche Wilderness Area in Colorado and San Pedro Parks Wilderness Area,Value=49047&poll=44201&county=49047&site=-1&msa=-1&state=-1&sy=2011&flag=Y&query=download&_debug=2&_service=data&_program=dataprog.query_daily3P_dm.sas, attached as Exhibit 58.86 BLM, GASCO Energy Inc. Uinta Basin Natural Gas Development Draft EnvironmentalImpact Statement (“GASCO DEIS”), at 3-13, available athttp://www.blm.gov/ut/st/en/fo/vernal/planning/nepa_/gasco_energy_eis.html,attached as Exhibit 59.87 Colo. Dept. of Public Health & Env’t, Air Pollution Control Division, Oil and GasEmission Sources, Presentation for the Air Quality Control Commission Retreat, at 3-4(May 15, 2008), attached as Exhibit 60.88 Colorado Oil & Gas Conservation Commission, Colorado Weekly & Monthly Oil andGas Statistics, at 12 (Nov. 7, 2011), available at http://cogcc.state.co.us/ (library—statistics—weekly/monthly well activity), attached as Exhibit 61.89 See Four Corners Air Quality Task Force Report of Mitigation Options, at vii (Nov. 1,2007), available at http://www.nmenv.state.nm.us/aqb/4C/TaskForceReport.html,attached as Exhibit 62.90 Myers et al., The Association Between Ambient Air Quality Ozone Levels and MedicalVisits for Asthma in San Juan County (Aug. 2007), available athttp://www.nmenv.state.nm.us/aqb/4c/Documents/SanJuanAsthmaDocBW.pdf,attached as Exhibit 63.91 See 42 U.S.C. § 7472(a). 42
    • Bandelier Wilderness Area, Pecos Wilderness Area, and Wheeler Peak Wilderness Areain New Mexico.92 These areas are all near concentrated oil and gas development in theSan Juan Basin.93As oil and gas development moves into new areas, particularly as a result of the boom indevelopment of shale resources, ozone problems are likely to follow. For example,regional air quality models predict that gas development in the Haynesville shale willincrease ozone pollution in northeast Texas and northwest Louisiana and may lead toviolations of ozone NAAQS.94Sulfur dioxide: Oil and gas production emits sulfur dioxide, primarily from natural gasprocessing plants.95 Sulfur dioxide is released as part of the sweetening process, whichremoves hydrogen sulfide from the gas.96 Sulfur dioxide is also created when gascontaining hydrogen sulfide (discussed below) is combusted in boilers or heaters.97Hydrogen sulfide: Some natural gas contains hydrogen sulfide. When hydrogen sulfidelevels are above a specific threshold, gas is classified as “sour gas.”98 According to EPA,there are 14 major areas in the U.S., found in 20 different states, where natural gastends to be sour.99 All told, between 15 and 20% of the natural gas in the U.S. maycontain hydrogen sulfide.10092 Rodriguez et al., Regional Impacts of Oil and Gas Development on Ozone Formation inthe Western United States, 59 Journal of the Air and Waste Management Association111 (Sept. 2009), available athttp://www.wrapair.org/forums/amc/meetings/091111_Nox/Rodriguez_et_al_OandG_Impacts_JAWMA9_09.pdf, attached as Exhibit 64.93 Id. at 1112.94 See Kemball-Cook et al., Ozone Impacts of Natural Gas development in the HaynesvilleShale 44 Environ. Sci. Technol. 9357, 9362 (Nov. 18, 2010), attached as Exhibit 65.95 76 Fed. Reg. at 52,756.96 TSD 3-3 to 3-5.97 76 Fed. Reg. at 52,756.98 76 Fed. Reg. at 52,756. Gas is considered “sour” of hydrogen sulfide concentration isgreater than 0.25 grain per 100 standard cubic feet, along with the presence of carbondioxide. Id.99 EPA, Office of Air Quality Planning and Standards, Report to Congress on HydrogenSulfide Air Emissions Associated with the Extraction of Oil and Natural Gas (EPA-453/R-93-045), at ii (Oct. 1993) (hereinafter “EPA Hydrogen Sulfide Report”), attached asExhibit 13.100 Lana Skrtic, Hydrogen Sulfide, Oil and Gas, and People’s Health (“Skrtic Report”), at 6(May 2006), available athttp://www.earthworksaction.org/pubs/hydrogensulfide_oilgas_health.pdf, attached asExhibit 66. 43
    • Given the large amount of drilling in areas with sour gas, EPA has concluded that thepotential for hydrogen sulfide emissions from the oil and gas industry is “significant.”101Hydrogen sulfide may be emitted during all stages of development, includingexploration, extraction, treatment and storage, transportation, and refining. 102 Forexample, hydrogen sulfide is emitted as a result of leaks from processing systems andfrom wellheads in sour gas fields.103Hydrogen sulfide emissions from the oil and gas industry are concerning because, asnoted in part IV.A.1 above, this pollutant may be harmful even at low concentrations.104Although direct monitoring of hydrogen sulfide around oil and gas sources is limited,there is evidence that these emissions may be substantial, and have a serious impact onpeople’s health. For example, North Dakota reported 3,300 violations of an odor-basedhydrogen sulfide standard around drilling wells.105 People in northwest New Mexico andwestern Colorado living near gas wells have long complained of strong odors, includingbut not limited to hydrogen sulfide’s distinctive rotten egg smell. Residents have alsoexperienced nose, throat and eye irritation, headaches, nose bleeds, and dizziness. 106 Anair sample taken by a community monitor at one family’s home in western Colorado inJanuary 2011 contained levels of hydrogen sulfide concentrations 185 times higher thansafe levels.107Particulate Matter (PM): The oil and gas industry is a major source of PM pollution. Thispollution is generated by heavy equipment used to move and level earth during well padand road construction. Vehicles also generate fugitive dust by traveling on access roadsduring drilling, completion, and production activities.108 Diesel engines used in drillingrigs and at compressor stations are also large sources of fine PM/diesel soot emissions.VOCs are also a precursor to formation of PM2.5.109101 EPA Hydrogen Sulfide Report at III-35.102 Id. at ii.103 TSD at 2-3.104 See James Collins & David Lewis, Report to CARB, Hydrogen Sulfide: Evaluation ofCurrent California Air Quality Standards with Respect to Protections of Children (Sept. 1,2000), available at http://oehha.ca.gov/air/pdf/oehhah2s.pdf, attached as Exhibit 14.105 EPA Hydrogen Sulfide Report at III-35.106 See Global Community Monitor, Gassed! Citizen Investigation of Toxic Air Pollutionfrom Natural Gas Development, at 11-14 (July 2011), attached as Exhibit 67.107 Id. at 21.108 See BLM, GASCO Energy Inc. Uinta Basin Natural Gas Development Project DraftEnvironmental Impact Statement, at App. J at 2 (Oct. 2010) (“GASCO DEIS”)109 O&G NSPS RIA at 4-18. 44
    • PM emissions from the oil and gas industry are leading to significant pollution problems.For example, monitors in Uintah County and Duchesne County, Utah have repeatedlymeasured wintertime PM2.5 concentrations above federal standards.110 These elevatedlevels of PM2.5 have been linked to oil and gas activities in the Uinta Basin.111 WestTavaputs FEIS at 3-20. Modeling also shows that road traffic associated with energydevelopment is pushing PM10 levels very close to violating NAAQS standards.112 ii. EPA’s Air Rules Will Not Fully Address These Air Pollution ProblemsAlthough EPA’s recently finalized new source performance standards and standards forhazardous air pollutants113 do reduce some of these pollution problems, they will notsolve them. The rules, first, do not even address some pollutants, including NOx,methane, and hydrogen sulfide, so any reductions of these pollutants occur only as co-benefits of the VOC reductions that the rules require.114 Second, the rules do not controlemissions from most transmission infrastructure.115 Third, existing sources of airpollution are not controlled for any pollutant, meaning that increased use of existinginfrastructure will produce emissions uncontrolled by the rules. Fourth, without fullenforcement, the rules will not reduce emissions completely. Thus, though FERC mightwork with EPA to fully understand the emissions levels likely after the rules are fullyimplemented, it may not rely upon the EPA rules to avoid weighing and disclosing theseimpacts. e. Gas Production Disrupts Landscapes and HabitatsIncreased oil and gas production will transform the landscape of regions overlying shalegas plays, bringing industrialization to previously rural landscapes and significantlyaffecting ecosystems, plants, and animals. These impacts are large, and difficult tomanage. Land use disturbance associated with gas development impacts plants andanimals through direct habitat loss, where land is cleared for gas uses, and indirect110 GASCO DEIS at 3-12.111 West Tavaputs FEIS, at 3-20 (July 2010).112 See GASCO DEIS at 4-27.113 See EPA, Oil and Natural Gas Sector: New Source Performance Standards andNational Emission Standards for Hazardous Air Pollutants, Final Rule (Apr. 17, 2012), notyet published in the Federal Register, but available athttp://www.epa.gov/airquality/oilandgas/actions.html.114 See id.128-31.115 See, e.g., id. at 173, 177 45
    • habitat loss, where land adjacent to direct losses loses some of its importantcharacteristics.Regarding direct losses, land is lost through development of well pads, roads, pipelinecorridors, corridors for seismic testing, and other infrastructure. The NatureConservancy (“TNC”) estimated that, in Pennsylvania,“[w]ell pads occupy 3.1 acres onaverage while the associated infrastructure (roads, water impoundments, pipelines)takes up an additional 5.7 acres, or a total of nearly 9 acres per well pad.” TNC,Pennsylvania Energy Impacts Assessment, Report 1: Marcellus Shale Natural Gas andWind (2010) at 10, 116 see also id. at 18. New York’s Department of EnvironmentalConservation reached similar estimates. New York Department of EnvironmentalConservation’s Revised Draft Supplemental General Environmental Impact Statement onthe Oil, Gas and Solution Mining Regulatory Program, 5-5 (Sept. 2011) (hereinafter “NYRDSGEIS”).117 After initial drilling is completed the well pad is partially restored, but 1 to3 acres of the well pad will remain disturbed through the life of the wells, estimated tobe 20 to 40 years. Id. at 6-13. Associated infrastructure such as roads and corridors willlikewise remain disturbed. Because these disturbances involve clearing and grading ofthe land, directly disturbed land is no longer suitable as habitat. Id. at 6-68.Indirect losses occur on land that is not directly disturbed, but where habitatcharacteristics are affected by direct disturbances. “Adjacent lands can also beimpacted, even if they are not directly cleared. This is most notable in forest settingswhere clearings fragment contiguous forest patches, create new edges, and changehabitat conditions for sensitive wildlife and plant species that depend on “interior”forest conditions.” TNC, Pennsylvania Energy Impacts Assessment, Report 1: MarcellusShale Natural Gas and Wind at 10. “Research has shown measureable impacts oftenextend at least 330 feet (100 meters) into forest adjacent to an edge.” NY RDSGEIS 6-75.TNC’s study of the impacts of gas extraction in Pennsylvania is particularly telling. TNCmapped projected wells across the state, considering how the wells and their associatedinfrastructure, including roads and pipelines, interacted with the landscape. TNC’sconclusions make for grim reading. It concluded:  About 60,000 new Marcellus wells are projected by 2030 in Pennsylvania with a range of 6,000 to 15,000 well pads, depending on the number of wells per pad;  Wells are likely to be developed in at least 30 counties, with the greatest number concentrated in 15 southwestern, north central, and northeastern counties;116 Attached as Exhibit 68.117 Available at http://www.dec.ny.gov/energy/75370.html 46
    •  Nearly two thirds of well pads are projected to be in forest areas, with forest clearing projected to range between 34,000 and 83,000 acres depending on the number of number of well pads that are developed. An additional range of 80,000 to 200,000 acres of forest interior habitat impacts are projected due to new forest edges created by well pads and associated infrastructure (roads, water impoundments); On a statewide basis, the projected forest clearing from well pad development would affect less than one percent of the state’s forests, but forest clearing and fragmentation could be much more pronounced in areas with intensive Marcellus development; Approximately one third of Pennsylvania’s largest forest patches (>5,000 acres) are projected to have a range of between 1 and 17 well pads in the medium scenario; Impacts on forest interior breeding bird habitats vary with the range and population densities of the species. The widely-distributed scarlet tanager would see relatively modest impacts to its statewide population while black-throated blue warblers, with a Pennsylvania range that largely overlaps with Marcellus development area, could see more significant population impacts; Watersheds with healthy eastern brook trout populations substantially overlap with projected Marcellus development sites. The state’s watersheds ranked as “intact” by the Eastern Brook Trout Joint Venture are concentrated in north central Pennsylvania, where most of these small watersheds are projected to have between two and three dozen well pads; Nearly a third of the species tracked by the Pennsylvania Natural Heritage Program are found in areas projected to have a high probability of Marcellus well development, with 132 considered to be globally rare or critically endangered or imperiled in Pennsylvania. Several of these species have all or most of their known populations in Pennsylvania in high probability Marcellus gas development areas. Marcellus gas development is projected to be extensive across Pennsylvania’s 4.5 million acres of public lands, including State Parks, State Forests, and State Game Lands. Just over 10 percent of these lands are legally protected from surface development. 47
    • TNC, Pennsylvania Energy Impacts Assessment, Report 1: Marcellus Shale Natural Gasand Wind (2010) at 29.118 Increased gas production will exacerbate these problems,which is bad news for the state’s lands and wildlife, and the hunting, angling, tourism,and forestry industries that depend upon them. Although TNC adds that impacts couldbe reduced with proper planning, id., more development makes mitigation moredifficult. Indeed, the Pennsylvania Department of Conservation and Natural Resourcesrecently concluded that “zero” remaining acres of the state forests are suitable forleasing with surface disturbing activities, or the forests will be significantly degraded.Penn. Dep’t of Conservation and Natural Resources, Impacts of Leasing Additional StateForest for Natural Gas Development (2011).119 These costs are not in the public interest.These effects will harm rural economies and decrease property values, as major gasinfrastructure transforms and distorts the existing landscape. They will also harmendangered species in regions where production would increase in response to heCompany’s exports. Harm to these species and their habitat is, too, against theprofound public interest in species conservation, as expressed in the EndangeredSpecies Act and similar statutes. f. Gas Production Poses Risks to Ground and Surface WaterIt is likely that much of the increased production that would result from the Company’sproposal will be from shale and other unconventional gas sources, and producing gasfrom these sources requires hydraulic fracturing, or fracking. See DOE, Shale GasProduction Subcommittee First 90-Day Report at 8.120 Hydraulic fracturing involvesinjecting a base fluid (typically water),121 sand or other proppant, and various fracturingchemicals into the gas-bearing formation at high pressures to fracture the rock andrelease additional gas. Each step of this process presents a risk to water resources.Withdrawal of the water may overtax the water source. Fracking itself may contaminategroundwater with either chemicals added to the fracturing fluid or with naturallyoccurring chemicals mobilized by fracking. After the well is fracked, some water willreturn to the surface, composed of both fracturing fluid and naturally occurring“formation” water. This water, together with drilling muds and drill cuttings, must bedisposed of without further endangering water resources. i. Water Withdrawals118 See Exhibit 68.119 Attached as Exhibit 69.120 Attached as Exhibit 36.121 The majority of hydraulic fracturing operations are conducted with a water basedfracturing fluid. Fracking may also be conducted with oil or synthetic-oil based fluid,with foam, or with gas. 48
    • The first step is the procurement of water. The precise amount of water varies by theshale formation being fracked. To use one example formation, fracking a MarcellusShale well requires between 4 and 5 million gallons of water. TNC, Pennsylvania EnergyImpacts Assessment, Report 1: Marcellus Shale Natural Gas and Wind, 5.122 Fresh waterconstitutes 80% to 90% of the total water used a well even where operators recycle“flowback” water from the fracking of previous well for use in fracking the current one.New York Department of Environmental Conservation’s Revised Draft SupplementalGeneral Environmental Impact Statement on the Oil, Gas and Solution MiningRegulatory Program, 6-13 (Sept. 2011) (hereinafter “NY RDSGEIS”).123Water withdrawals can drastically impact aquatic ecosystems and human communities.Reductions in instream flow negatively affect aquatic species by changing flow depthand velocity, raising water temperature, changing oxygen content, and alteringstreambed morphology. Id. 6-3 to 6-4. Even when flow reductions are not themselvesproblematic, the intake structures can harm aquatic organisms. Id. at 6-4. Where wateris withdrawn from aquifers, rather than surface sources, withdrawal risks permanentdepletion. This risk is even more prevalent with withdrawals for fracking than it is forother withdrawal, because fracking is a consumptive use. Fluid injected during thefracking process is (barring accident) deposited below freshwater aquifers and intosealed formations. Id. 6-5; DOE Subcommittee First 90 Day Report at 19 (“in someregions and localities there are significant concerns about consumptive water use forshale gas development.”). Thus, the water withdrawn from the aquifer will be used in away that provides no opportunity to percolate back down to the aquifer and recharge it. ii. FracturingFracturing poses a serious risk of groundwater contamination. Contaminants includechemicals added to the fracturing fluid and naturally occurring chemicals that are122 Accord New York Department of Environmental Conservation’s Revised DraftSupplemental General Environmental Impact Statement on the Oil, Gas and SolutionMining Regulatory Program, (September 2011) (“Between July 2008 and February 2011,average water usage for high-volume hydraulic fracturing within the Susquehanna RiverBasin in Pennsylvania was 4.2 million gallons per well, based on data for 553 wells.”),available at http://www.dec.ny.gov/data/dmn/rdsgeisfull0911.pdf. Other estimates arethat as much as 7.2 million gallons of frack fluid may be used in a 4000 foot well bore.NRDC, et al., Comment on NY RDSGEIS on the Oil, Gas and Solution Mining RegulatoryProgram (Jan. 11, 2012) (Attachment 2, Report of Tom Myers, at 10), attached as Exhibit70 (hereafter Comment on NY RDSGEIS). Water needs in other geological formations vary. See Exhibit 37 at 19 (estimatingthat nationwide, fracking an individual well requires between 1 and 5 million gallons ofwater).123 Available at http://www.dec.ny.gov/energy/75370.html 49
    • mobilized from deeper formations to groundwater by the fracking process.Contamination may occur through several methods, including where the well casing failsor where the created fractures intersect an existing a poorly sealed well. Althoughinformation on groundwater contamination is incomplete, the available researchindicates that contamination has already occurred on multiple occasions.One category of potential contaminants includes chemicals added to the drilling mudand fracturing fluid. The fluid used for slickwater fracturing is typically comprised ofmore than 98% fresh water and sand, with chemical additives comprising 2% or less ofthe fluid. NY RDSGEIS 5-40. Chemicals are added as solvents, surfactants, frictionreducers, gelling agents, bactericides, and for other purposes. Id. 5-49. New Yorkrecently identified 322 unique ingredients used in fluid additives, recognizing that thisconstituted a partial list. Id. 5-41. These chemicals include petroleum distillates;aromatic hydrocarbons; glycols; glycol ethers; alcohols and aldehydes; amides; amines;organic acids, salts, esters and related chemicals; microbicides; and others. Id. 5-75 to 5-78. Many of these chemicals present health risks. Id. Of particular note is the use ofdiesel, which the DOE Subcommittee has singled out for its harmful effects andrecommended be banned from use as a fracturing fluid additive. DOE SubcommitteeFirst 90-Day Report, 25. The minority staff of the House Committee on Energy andCommerce determined that despite diesel’s risks, between 2005 and 2009 “oil and gasservice companies injected 32.2 million gallons of diesel fuel or hydraulic fracturingfluids containing diesel fuel in wells in 19 states.” Natural Resources Defense Council,Earthjustice, and Sierra Club, Comments [to EPA] on Permitting Guidance for Oil and GasHydraulic Fracturing Activities Using Diesel Fuels (June 29, 2011) at 3 (quoting Letterfrom Reps. Waxman, Markey, and DeGette to EPA Administrator Lisa Jackson (Jan. 31,2001) at 1) (hereafter Comment on Diesel Guidance).124Contamination may also result from chemicals naturally occurring in the formation.Flowback and produced water “may include brine, gases (e.g. methane, ethane), tracemetals, naturally occurring radioactive elements (e.g. radium, uranium) and organiccompounds.” DOE Subcommittee first 90 day report at 21; see also Comment on NYRDSGEIS (attachment 3, Report of Glen Miller, at 2). For example, mercury naturallyoccurring in the formation becomes mixed in with water-based drilling muds, resultingin up to 5 pounds of mercury in the mud per well drilled in the Marcellus region.Comment on NY RDSGEIS (attachment 1, Report of Susan Harvey, at 92).There are several vectors by which these chemicals can reach groundwater supplies.Perhaps the most common or significant are inadequacies in the casing of the verticalwell bore. DOE Subcommittee First 90 Day Report, 20. The well bore inevitably passesthrough geological strata containing groundwater, and therefore provides a conduit bywhich chemicals injected into the well or traveling from the target formation to the124 Attached as Exhibit 71. 50
    • surface may reach groundwater. The well casing isolates the groundwater fromintermediate strata and the target formation. This casing must be strong enough towithstand the pressures of the fracturing process--the very purpose of which is toshatter rock. Multiple layers of steel casing must be used, each pressure tested beforeuse, then centered within the well bore. Each layer of casing must be cemented, withcareful testing to ensure the integrity of the cementing. Comment on Diesel Guidance,5-9. Proper casing construction is an elaborate engineering effort, with multiple layersof steel casing (that have been pressure tested), centralizers to center the casing in thewell bore, careful cementing of the casing strings (together with testing to ensure theintegrity of this cementing). Id.Separate from casing failure, contamination may occur when the zone of fractured rockintersects an abandoned and poorly-sealed well or natural conduit in the rock.Comment on NY RDSGEIS (Attachment 3, Report of Tom Myers, 12 - 15). One recentstudy concluded, on the basis of geologic modeling, that frack fluid may migrate fromthe hydraulic fracture zone to freshwater aquifers in less than ten years.125Available empirical data indicates that fracking has resulting in groundwatercontamination in at least five documented instances. One study “documented thehigher concentration of methane originating in shale gas deposits . . . into wellssurrounding a producing shale production site in northern Pennsylvania.” DOESubcommittee first 90 day report at 20 (citing Stephen G. Osborn, Avner Vengosh,Nathaniel R. Warner, and Robert B. Jackson, Methane contamination of drinking wateraccompanying gas-well drilling and hydraulic fracturing, Proceedings of the NationalAcademy of Science, 108, 8172-8176, (2011)). By looking at particular isotopes ofmethane, this study was able to determine that the methane originated in the shaledeposit, rather than from a shallower source. Id. The DOE Subcommittee referred to thisas “a recent, credible, peer-reviewed study.” Id. Two other reports “have documentedor suggested the movement of fracking fluid from the target formation to water wellslinked to fracking in wells.” Comment on NY RDSGEIS (Attachment 2, Report of TomMeyers, 13). “Thyne (2008)[126] found bromide in wells 100s of feet above the frackedzone.” Id. “The EPA (1987)[127] documented fracking fluid moving into a 416‐ foot deepwater well in West Virginia; the gas well was less than 1000 feet horizontally from thewater well, but the report does not indicate the gas‐bearing formation.” Id.125 Tom Myers, Potential Contaminant Pathways from Hydraulically Fractured Shale toAquifers, Ground Water (Apr. 17, 2012), attaches as Exhibit 72.126 Dr. Meyers relied on Thyne, G. 2008. Review of Phase II Hydrogeologic Study.Prepared for Garfield County, Colorado.127 Environmental Protection Agency. 1987. Report to Congress, Management of Wastesfrom the Exploration, Development, and Production of Crude Oil, Natural Gas, andGeothermal Energy, Volume 1 of 3, Oil and Gas. Washington, D.C., available atnepis.epa.gov/Exe/ZyPURL.cgi?Dockey=20012D4P.txt, attached as Exhibit 73. 51
    • More recently, EPA has investigated groundwater contamination in Pavillion, Wyomingand Dimock, Pennsylvania. In Pavillion, EPA’s draft report concludes that “whenconsidered together with other lines of evidence, the data indicates likely impact toground water that can be explained by hydraulic fracturing.” EPA, Draft Investigation ofGround Water Contamination near Pavillion, Wyoming (Dec. 2011), at xiii.128 EPA testedwater from wells extending to various depths within the range of local groundwater. Atthe deeper tested wells, EPA discovered inorganics (potassium, chloride), syntheticorganic (isopropanol, glycols, and tert-butyl alcohol), and organics (BTEX, gasoline anddiesel range organics) at levels higher than expected. Id. at xii. At shallower levels, EPAdetected “high concentrations of benzene, xylenes, gasoline range organics, diesel rangeorganics, and total purgeable hydrocarbons.” Id. at xi. EPA determined that surface pitspreviously used for storage of drilling wastes and produced/flowback waters were alikely source of contamination for the shallower waters, and that fracturing likelyexplained the deeper contamination. Id. at xi, xiii. Although this is a draft report in anongoing investigation, an independent expert who reviewed the EPA Pavillon study atthe request of Sierra Club and other environmental groups has supported EPA’sfindings.129 The report, and the expert’s findings, demonstrate a possibility ofcontamination that DOE must consider in its public interest evaluation.EPA is also investigating groundwater contamination in Dimock, Pennsylvania. EPARegion III, Action Memorandum - Request for Funding for a Removal Action at theDimock Residential Groundwater Site (Jan. 19, 2012).130 In Dimock, EPA has determinedthat “a number of home wells in the Dimock area contain hazardous substances, someof which are not naturally found in the environment.” Id. at 1. Specifically, wells arecontaminated with arsenic, barium, bis(2(ethylhexyl)phthalate, glycol compounds,manganese, phenol, and sodium. Id. at 3-4. Many of these chemicals are hazardoussubstances as defined under CERCLA section 101(14); see also 40 C.F.R. § 302.4. EPA’sdetermination is based on “Pennsylvania Department of Environmental Protection(PADEP) and Cabot Oil and Gas Corporation (Cabot) sampling information, consultationwith an EPA toxicologist, the Agency for Toxic Substances and Disease Registry (ATSDR)Record of Activity (AROA), issued, 12/28/11, and [a] recent EPA well survey effort.” Id.The PADEP information provided reason to believe that drilling activities in the area ledto contamination of these water supplies. Drilling in the area began in 2008, and was128 Attached as Exhibit 74, available athttp://www.epa.gov/region8/superfund/wy/pavillion/EPA_ReportOnPavillion_Dec-8-2011.pdf129 Tom Myers, Review of DRAFT: Investigation of Ground Water Contamination nearPavillion Wyoming (April 30, 2012), attached as Exhibit 75 and available athttp://docs.nrdc.org/energy/files/ene_12050101a.pdf.130 Attached as Exhibit 76, available athttp://www.epaosc.org/sites/7555/files/Dimock%20Action%20Memo%2001-19-12.PDF 52
    • conducted using the hazardous substances that have since been discovered in wellwater. Id. at 1, 2. Shortly thereafter methane contamination was detected in privatewell water. Id. at 2. In addition, there were several surface spills in connection with thedrilling operation. Id. at 1. After the contamination was detected, PADEP entered aconsent decree with Cabot which required permanent restoration or replacement of thewater supply. Id. at 2. Cabot has installed or is installing a “gas mitigation” system forthe affected wells. Id., see also Agency for Toxic Substances and Disease Registry, Recordof Activity/Technical Assist (Dec. 28, 2011) at 2 (hereafter ATSDR).131Pursuant to the consent decree, Cabot was providing replacement water to all 18 homesuntil November 30, 2011, at which point Cabot halted delivery with PADEP’s consent.ATSDR at 2. EPA has intervened because “EPA does not know what, if any, hazardoussubstances these ‘gas mitigation’ systems, originally designed to address methane, areremoving.” EPA Action Memorandum at 2. EPA sampled water from 64 home wells.132,“EPA found hazardous substances, specifically arsenic, barium or manganese, all ofwhich are also naturally occurring substances, in well water at five homes at levels thatcould present a health concern. In all cases the residents have now or will have theirown treatment systems that can reduce concentrations of those hazardous substancesto acceptable levels at the tap.”133 iii. Waste ManagementFracturing produces a variety of liquid and solid wastes that must be managed anddisposed of. These include the drilling mud used to lubricate the drilling process, thedrill cuttings removed from the well bore, the “flowback” of fracturing fluid that returnsto the surface in the days after fracking, and produced water that is produced over thelife of the well (a mixture of water naturally occurring in the shale formation andlingering fracturing fluid). These wastes contain the same contaminants described in thepreceding section. They present environmental hazards with regard to their onsitemanagement and with their eventual disposal.On site, drilling mud, drill cuttings, flowback and produced water are often stored inpits. Such open pits can have harmful air emissions, can leach into shallow groundwater,and can fail and result in surface discharges. Many of these harms can be minimized bythe use of seal tanks in a “closed loop” system. See, e.g., NY RDSGEIS at 1-12. Presently,131 Attached as Exhibit 77, available athttp://www.epa.gov/aboutepa/states/dimock.pdf.132 EPA, EPA Completes Drinking Water Sampling in Dimock, Pa (July 25, 2012), attachedas Exhibit 78, and available athttp://yosemite.epa.gov/opa/admpress.nsf/0/1A6E49D193E1007585257A46005B61AD133 Id. 53
    • only New Mexico mandates the use of closed loop waste management systems, and pitsremain in use elsewhere.Flowback and produced water must ultimately be disposed of offsite. Some of thesefluids may be recycled and used in further fracturing operations, but even where a fluidrecycling program is used, recycling leaves concentrated contaminants that must bedisposed of. The most common methods of disposal are disposal in undergroundinjection wells or through water treatment facilities leading to eventual surfacedischarge.Underground injection wells present risks of groundwater contamination similar tothose identified above for fracking itself. Gas production wastes are not categorized ashazardous under the Safe Drinking Water Act, 42 U.S.C. § 300f et seq., and may bedisposed of in Class II injection wells. Class II wells are brine wells, and the standards andsafeguards in place for these wells were not designed with the contaminants found infracking wastes in mind. See NRDC et al., Petition for Rulemaking Pursuant to Section6974(a) of the Resource Conservation and Recovery Act Concerning the Regulation ofWastes Associated with the Exploration, Development, or Production of Crude Oil orNatural Gas or Geothermal Energy (Sept. 8, 2010).134Additionally, underground injection of fracking wastes appears to have inducedearthquakes in several regions. Underground injection of fracking waste in Ohio hasbeen correlated with earthquakes as high as 4.0 on the Richter scale. ColumbiaUniversity, Lamont-Doherty Earth Observatory, Ohio Quakes Probably Triggered byWaste Disposal Well, Say Seismologists (Jan. 6, 2012).135 Underground injection maycause earthquakes by causing movement on existing fault lines: “Once fluid enters apreexisting fault, it can pressurize the rocks enough to move; the more stress placed onthe rock formation, the more powerful the earthquake.” Id. Underground injection ismore likely than fracking to trigger large earthquakes via this mechanism, “becausemore fluid is usually being pumped underground at a site for longer periods.” Id. In lightof the apparent induced seismicity, Ohio has put a moratorium on injection in theaffected region. Id. Similar associations between earthquakes and injection haveoccurred in Arkansas, Texas, Oklahoma and the United Kingdom. Id., Alexis Flynn, StudyTies Fracking to Quakes in England, Wall Street Journal (Nov. 3, 2011).136 In light of theseeffects, Ohio and Arkansas have placed moratoriums on injection in the affected areas.Lamont-Doherty Earth Observatory; Arkansas Oil and Gas Commission, Class II134 Attached as Exhibit 79.135 Attached as Exhibit 80, available at http://www.ldeo.columbia.edu/news-events/seismologists-link-ohio-earthquakes-waste-disposal-wells136 Attached as Exhibit 81, available at http://online.wsj.com/article/SB10001424052970203804204577013771109580352.html 54
    • Commercial Disposal Well or Class II Disposal Well Moratorium (Aug. 2, 2011).137 Therecently released abstract of a forthcoming United States Geological Survey studyaffirms the connection between disposal wells and earthquakes. Ellsworth, W. L., et al.,Are Seismicity Rate Changes in the Midcontinent Natural or Manmade?, SeismologicalSociety of America, (April 2012).138As an alternative to underground injection, flowback and produced water is also sent towater treatment facilities, leading to eventual surface discharge. This presents aseparate set of environmental hazards, because these facilities (particularly publiclyowned treatment works) are not designed to handle the nontraditional pollutants foundin fracking wastes. For example: One serious problem with the proposed discharge (dilution) of fracture treatment wastewater via a municipal or privately owned treatment plant is the observed increases in trihalomethane (THM) concentrations in drinking water reported in the public media (Frazier and Murray, 2011), due to the presence of increased bromide concentrations. Bromide is more reactive than chloride in formation of trihalomethanes, and even though bromide concentrations are generally lower than chloride concentrations, the increased reactivity of bromide generates increased amounts of bromodichloromethane and dibromochloromethane (Chowdhury, et al., 2010). Continued violations of an 80microgram/L THM standard may ultimately require a drinking water treatment plant to convert from a standard and cost effective chlorination disinfection treatment to a more expensive chloramines process for water treatment. Although there are many factors affecting THM production in a specific water, simple (and cheap) dilution of fracture treatment water in a stream can result in a more expensive treatment for disinfection of drinking water. This transfer of costs to the public should not be permitted.137 Attached as Exhibit 82, available athttp://www.aogc.state.ar.us/Hearing%20Orders/2011/July/180A-2-2011-07.pdf138 This abstract is attached as Exhibit 83, and is available athttp://www2.seismosoc.org/FMPro?-db=Abstract_Submission_12&-recid=224&-format=%2Fmeetings%2F2012%2Fabstracts%2Fsessionabstractdetail.html&-lay=MtgList&-find 55
    • Comment on NY RDSGEIS (attachment 3, Report of Glen Miller, at 13). Similarly,municipal treatment works typically to not treat for radioactivity, whereas producedwater can have high levels of naturally occurring radioactive materials. In oneexamination of three samples of produced water, radioactivity (measured as gross alpharadiation) were found ranging from 18,000 pCi / L to 123,000 pCi/L, whereas the safedrinking water standard is 15 pCi/L. Id. (Miller Report at 4).The Commission is required to analyze all of these indirect impacts of the increasednatural gas production that will result from the Company’s three-phase LNG terminalproposal.H. The Existing Record Demonstrates that The Company’s Application Is Contrary to The Public Interest.The Natural Gas Act and subsequent DOE delegation orders and regulations charge FERCwith determining whether siting, construction, and operation of jurisdictional LNGterminal facilities is in the public interest. See, e.g. 15 U.S.C. § 717b(a). Regardless ofany presumptions FERC may employ, FERC has a duty to make its own determination.Panhandle Producers and Royalty Owners Ass’n, 822 F.2d at 1110-11. Simply put, “theagency must examine the relevant data and articulate a satisfactory explanation for itsaction including a rational connection between the facts found and the choice made.”Motor Vehicle Mfrs. Ass’n of the United States v. State Farm Mut. Auto. Ins. Co., 463 U.S.29, 43 (1983) (emphasis supplied). FERC cannot rationally find for the Company on therecord in this case.FERC must carefully examine both the positive and negative impacts of natural gasterminal proposals. Here, the Company’s application briefly presents the benefits of asingle phase of its three-phase proposal. However, as discussed, the Company refusesto present the potential costs of any of the three phases of its proposal, which may havesubstantial consequences for Hawaii’s environment and its ability to transition awayfrom greenhouse gas-intensive fossil fuels. If all three phases are analyzed together (asthey must be, under NEPA), the significant harms associated with the three-phaseproposal are apparent.The Sierra Club has demonstrated the potentially devastating environmental harmsassociated with the natural gas drilling that would be required to bring LNG into Hawaiiin significant quantities. We have also demonstrated the potential for LNG to delay orimpede development of renewable energy, undermining the Hawaii Clean EnergyInitiative, a key state policy goal, and eliminating a purported project benefit touted bythe Company. Given these significant impacts and the elusiveness of many of theproject’s benefits, FERC must find that the project is contrary to the public interest. 56
    • V. The EIS Must Consider an Adequate Range of AlternativesBoth NEPA and the Natural Gas Act require FERC to fully consider alternatives to theCompany’s proposal. Specifically, the public interest analysis requires an “exploration ofall issues relevant to the ‘public interest’,” an inquiry which the Supreme Court held inUdall must be wide-ranging. In that case, which concerned hydropower, the regulatoryagency was required to consider, for instance, “alternate sources of power,” the state ofthe power market generally, and options to mitigate impacts on wildlife. Here, likewise,FERC must consider alternatives to the Company’s proposal to import LNG into Hawaiithat would better serve the public interest. Given imports’ sweeping impacts onHawaii’s energy future, FERC must broadly analyze other approaches to phasing outHawaii’s dependence on oil and promoting development of renewable energyresources.NEPA is designed to support this sort of broad consideration. “[T]he heart of theenvironmental impact statement” (which, as stated above, is required here) is analternatives analysis that presents sharply defined issues and offers a “clear basis forchoice among options by the decisionmaker and the public.” 40 C.F.R. § 1502.14.Crucially, the alternatives must include “reasonable alternatives not within thejurisdiction of the lead agency,” – meaning that FERC must review actions which itcannot directly order – and must include “appropriate mitigation measures not alreadyincluded in the proposed action or alternatives.” Id. Because alternatives are so centralto decisionmaking and mitigation, “the existence of a viable but unexamined alternativerenders an environmental impact statement inadequate.” Oregon Natural Desert Ass’n,625 F.3d at 1122 (internal alterations and citations omitted).The resource report the Company submitted in conjunction with its application containsa totally inadequate discussion of alternatives to the proposed project. RR at 4-5. Theonly alternative to LNG imports, the Company states, is the status quo. This range ofalternatives is far too narrow, and the discussion of the only identified alternative is toocursory. FERC must go well beyond this cursory discussion of alternatives in developingthe EIS. The EIS must consider, at a minimum, the following alternatives: (1) Whether limitations on the sources of imported gas – e.g., limiting import from particular plays, formations, or regions – would help to mitigate environmental and economic impacts. The application offers no discussion whatsoever of this issue. (2) Whether to condition import on the presence of an adequate regulatory framework, including the fulfillment of the recommendations for safe production made by the DOE’s Shale Gas Subcommittee, would better serve the public interest by ensuring that the production increases associated with Hawaiian import will not increase poorly regulated unconventional gas production. 57
    • (3) Whether to delay, deny, or condition imports based upon their effect on Hawaiis utility market and the development of renewable energy resources in Hawaii. (4) Whether to require the Company to certify that any unconventional gas produced as a result of its proposal (or shipped through its facilities) has been produced in accordance with all relevant environmental laws and according to a set of best production practices (such as that discussed by the DOEs Shale Gas Subcommittee). (5) Whether to deny the Companys proposal altogether as contrary to the public interest.Other alternatives are, no doubt, also available, but FERC must at a minimum considerthe possibilities listed above, as they are reasonable and bear directly on the publicinterest determination before it. VI. ConclusionSierra Club therefore moves to intervene, offers the above comments, and protests theCompanys application for approval of the proposed LNG terminal facilities.Respectfully submitted,Ellen MedlinNathan MatthewsEllen MedlinAssociate AttorneysSierra Club Environmental Law Program nd85 2 St., Second FloorSan Francisco, CA 94105 58
    • Certificate of Service    I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Secretary in this proceeding. Dated at San Francisco, CA this 19th day of October, 2012.      /s/Ellen Medlin  Ellen Medlin  Sierra Club Environmental Law Program  85 2nd St., Second Floor  San Francisco, CA 94105