UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

IN THE MATTER OF ) ) Docket No. CP12-498 APPLICATION OF ) THE GAS COMPANY, LLC ) FOR AUTHORIZATION UNDER SECTION 3 ) OF THE NATURAL GAS ACT )

)

SIERRA CLUB’S MOTION TO INTERVENE, PROTEST, AND COMMENTS

Nathan Matthews Kathleen Krust Ellen Medlin Paralegal Associate Attorneys Sierra Club Environmental Law Program Sierra Club Environmental Law Program 85 2nd St., Second Floor 85 2nd St., Second Floor San Francisco, CA 94105 San Francisco, CA 94105 (415) 977-5696 (tel) (415) 977-5646 (tel) (415) 977-5793 (fax)

Table of Contents

I. Sierra Club Should be Granted Intervention ................................................................ 2

II. Information Regarding the Applicant & Service ........................................................... 3

III. 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 ........................................................................... 11

IV. 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. .................................................................................................. 56

V. The EIS Must Consider an Adequate Range of Alternatives ....................................... 57

VI. Conclusion ................................................................................................................... 58

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UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

IN THE MATTER OF ) ) Docket No. CP12-498 APPLICATION OF ) THE GAS COMPANY, LLC ) FOR AUTHORIZATION UNDER SECTION 3 ) OF THE NATURAL GAS ACT )

)

SIERRA CLUB’S MOTION TO INTERVENE, PROTEST, AND COMMENTS

The Gas Company, LLC (“the Company”) requests Federal Energy Regulatory Commission (“FERC”) authorization for the first of three phases of facilities that, together, would be used, among other things, to receive, store, transport, and regasify liquefied natural gas (“LNG”) sourced from liquefaction facilities in the continental United States and transported by ship to Hawaii. The Company’s application focuses on the first phase of these operations, which would include (1) a fleet of cryogenic intermodal, or “ISO,” containers that will be transported to Hawaii by cargo ship, (2) the use of existing storage facilities or secured lots to store the ISO containers after they arrive in Hawaii, and (3) mobile LNG regasification units that would be used to inject the gas 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 phases of the proposed operations. We also seek to protect our members’ interests in the broader environment that will be affected by the import of LNG into Hawaii and the increase 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 need for FERC to comprehensively examine the local environmental impacts of all three phases of the proposed LNG import operations – rejecting the applicant’s improper request to segment review – as well as the operations’ impact on the development of renewable energy resources in Hawaii. We also reiterate our contention that FERC must analyze the effects of induced production. Although FERC recently refused to consider induced production in a similar proceeding regarding Sabine Pass LNG, the Sabine Pass decisions were wrongly decided and do not bind FERC here.

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I. Sierra Club Should be Granted Intervention FERC regulations permit intervention if “the movant has or represents an interest which may be directly affected by the outcome of the proceeding” or “the movant’s intervention is in the public interest.” FERC R. 214, 18 C.F.R. § 385.214(b)(2). This low hurdle rightly reflects FERC’s Natural Gas Act responsibilities: FERC is seeking to determine 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 LNG terminal applications. Allowing intervention upon a clear statement of interest ensures that the record is well built and that all arguments are carefully presented. Sierra Club easily satisfies both of these alternative standards for intervention. Sierra Club members live and work throughout the area that will be affected by the Company’s proposed operations, including in the regions adjacent to the proposed operations and in 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 in this 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.

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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, and professional interests in the proposed project. Sierra Club has demonstrated the vitality of these interests in many ways. Sierra Club runs national advocacy and organizing campaigns dedicated to reducing American dependence on fossil fuels, including natural gas, and to protecting public health. These campaigns, including its Beyond Coal campaign and its Beyond Natural Gas campaign, are dedicated towards promoting a swift transition away from fossil fuels and to reducing the impacts of any remaining natural gas extraction. The Club’s Hawaii Chapter also works to transition Hawaii away from fossil fuel dependence and toward greater reliance on energy efficiency and renewable energy. Accordingly, Sierra Club satisfies both of Rule 214’s alternative standards, and FERC must 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 & Service Pursuant to 18 C.F.R. § 385.203(b)(1)-(2), Sierra Club states that the exact name of the movant 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 for service 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 gas import/export proceedings before DOE).

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Nathan Matthews Ellen Medlin Kathleen Krust3 Associate Attorneys Paralegal Sierra Club Environmental Law Program Sierra Club Environmental Law Program 85 2nd St., Second Floor 85 2nd St., Second Floor San 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 the individuals listed to the service list, notwithstanding 18 C.F.R. § 385.203(b)(3), which limits service to two individuals.

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III. FERC’s Legal Obligations FERC has significant substantive and procedural obligations to fulfill before it can act on the Company’s proposal. We discuss the scope of some of those obligations created by the Natural Gas Act, the National Environmental Policy Act, the Endangered Species Act, and the National Historic Preservation Act, here, before discussing the impacts of the proposal.

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 Jurisdiction

Sierra Club does not contest the Company’s assertion that FERC has jurisdiction over the Company’s application under the Natural Gas Act, which gives FERC “authority to approve or deny an application for the siting, construction, expansion, or operation of an 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 waterborne vessel.” Id. § 717a(11).

b. If FERC Determines That it Lacks Jurisdiction, Then the State of Hawaii Has Jurisdiction Over the Company’s Proposal

Although the Club does not contest FERC’s jurisdiction, we do not agree with the Company 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, including the 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 Gas Act, which gives FERC “exclusive authority to approve or deny an application for the siting, construction, expansion, or operation of an LNG terminal.” 15 U.S.C. § 717b(e)(1) (emphasis added). The Company argues that, even if some exception prevents 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 or legally authorized to engage in the transportation in interstate commerce or the sale in interstate commerce for resale, of natural gas received by such person from another

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person within or at the boundary of a State if all the natural gas so received is ultimately consumed within such State, or to any facilities used by such person for such transportation or sale, provided that the rates and service of such person and facilities be subject to regulation by a State commission.” 15 U.S.C. § 717(c). According to the Company, “if the Hinshaw exemption were deemed to apply to the siting, construction, expansion and operation of an LNG terminal, the relevant state would have no jurisdiction.” App. at 33. The Company’s argument makes little sense, for two reasons. First, the Hinshaw exception could not possibly leave the proposed project in a total regulatory vacuum because it only applies to projects “subject to regulation by a State commission.” 15 U.S.C. § 717(c). Here, then, the exception could only apply if the project were under the jurisdiction of the Hawaii Public Utilities Commission. Second, and more broadly, section 3(e) merely clarifies that, where FERC has authority over an LNG terminal, its authority is exclusive. This provision, which was added through the Energy Policy Act of 2005, was not meant to abrogate Congress’s longstanding policy, expressed in the Hinshaw exception, of “leav[ing]” to the states jurisdiction over “companies engaged in the distribution of natural gas exclusively in the States.” Gen’l Motors Corp. v. Tracy, 519 U.S. 278, 293 (1997). If FERC concludes that it has no authority over the Company’s application – because it determines that the Hinshaw exception applies, or for any other reason – then the application falls under the ordinary jurisdiction of the state of Hawaii, including local authorities and the Hawaii Public Utilities Commission.

2. FERC’s Substantive Obligations Under the Natural Gas Act

Section 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 makes analogous “public interest” determinations for facilities that import or export natural gas outside the U.S., have all interpreted the “public interest” at issue in these provisions as including environmental impacts. Both the Supreme Court and the D.C. Circuit Court of Appeals have held that the Natural Gas Act’s public interest provisions encompass environmental concerns. While the public 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 Line Co 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 a public interest provision); n.6 (explaining that the “public interest” referred to in § 717b includes environmental considerations) (1976). In interpreting an analogous public

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interest provision applicable to hydroelectric power and dams, the Court has explained that the public interest determination “can be made only after an exploration of all issues relevant to the ‘public interest,’ including future power demand and supply, alternate sources of power, the public interest in preserving reaches of wild rivers and wilderness areas, the preservation of anadromous fish for commercial and recreational purposes, and the protection of wildlife.” Udall v. Fed. Power Comm'n, 387 U.S. 428, 450 (1967) (interpreting § 7(b) of the Federal Water Power Act of 1920, as amended by the Federal Power Act, 49 Stat. 842, 16 U.S.C. § 800(b)). Other courts have applied this Udall holding to the Natural Gas Act. See, e.g., N. Natural Gas Co. v. Fed. Power Comm'n, 399 F.2d 953, 973 (D.C. Cir. 1968) (interpreting section 7 of the Natural Gas Act). 4 FERC has acknowledged that environmental issues weigh into FERC’s public interest calculus. In FERC’s recent order approving siting, construction, and operation of LNG export facilities in Sabine Pass, Louisiana, FERC considered potential environmental impacts of the terminal as part of its public interest assessment. Sabine Pass Liquefaction, LLC, 139 FERC ¶ 61,039, PP 29-30 (Apr. 14, 2012).5 DOE – which, again, makes public interest determinations analogous to FERC’s – has reached the same conclusion. Deputy Assistant Secretary Smith recently testified that “[a] wide range of criteria are considered as part of DOE’s public interest review process, including . . . U.S. energy security . . . [i]mpact on the U.S. economy . . . [e]nvironmental considerations . . . [and] [o]ther issues raised by commenters and/or interveners deemed relevant to the proceeding.” The Department of Energy’s Role in Liquified Natural Gas Export Applications: Hearing Before the S. Comm. on Energy and Natural Resources, 112th Cong. 4 (2011) (testimony of Christopher Smith, Deputy Assistant Secretary of Oil and Gas).6 DOE rules require export applicants to provide information documenting “[t]he potential environmental impact of the project.” 10 C.F.R. § 590.202(b)(7). In a previous LNG export proceeding, DOE determined that the public interest inquiry looks to “domestic need” as well as “other considerations,” including the environment. Phillips Alaska Natural Gas Corporation and Marathon Oil Company, 2 FE ¶ 70,317, DOE FE Order No. 1473, *22 (April 2, 1999); accord Opinion and Order Conditionally Granting Long-Term Authorization to Export [LNG] from Sabine Pass LNG Terminal to Non-Free Trade Agreement Nations (“Sabine Pass”), DOE/FE Order 2961 at 29 (May 20, 2011) (acknowledging that the public interest inquiry extends beyond effects on domestic natural gas supplies). Finally, DOE has applied its “policy

4 Further support for the inclusion of environmental factors in the public interest analysis is provided by NEPA, which declares that all federal agencies must seek to protect the environment and avoid “undesirable and unintended consequences.” 42 U.S.C. § 4331(b)(3). 5 Sierra Club contends that other aspects of this order were wrongly decided, as was FERC’s subsequent denial of Sierra Club’s petition for rehearing, as we explain below. 6 Attached as Exhibit 2.

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guidelines” regarding the public interest to focus review “on the domestic need for the natural gas proposed to be exports; whether the proposed exports pose a threat to the security 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).7 Accordingly, there is consensus among the pertinent authorities that public interest inquiries mandated by the Natural Gas Act, including those undertaken by FERC, must take into account the environmental effects of the action under consideration.

B. National Environmental Policy Act NEPA requires federal agencies to consider and disclose the “environmental impacts” of proposed agency actions. 42 U.S.C. § 4332(C)(i). This requirement is implemented through a set of procedures that “insure [sic] that environmental information is available to public officials and citizens before decisions are made and before actions are taken.” 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’t of Transp. v. Public Citizen, 541 U.S. 752, 768 (2004) (quoting Robertson v. Methow Valley 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 the earliest possible time to insure that planning and decisions reflect environmental values.” 40 C.F.R. § 1501.2. Here, as discussed in part IV.B below, FERC must prepare a full environmental impact statement (“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 EIS where a proposed major federal action would “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 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. See Klamath 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 agency may prepare an EA to determine whether an EIS is necessary. 40 C.F.R. § 1508.9. FERC regulations provide that an EIS is “normally” required for “[a]uthorization under sections

7 DOE/FE’s policy guidelines provide only persuasive authority in FERC proceedings. Even before DOE/FE, these guidelines are merely guidelines: they “cannot create a norm binding 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).

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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 to consider all three phases of the Company’s proposed LNG terminal together, and must prepare a single EIS to fulfill this obligation. Because the three-phased proposal calls for construction and operation of new LNG import facilities and supporting facilities, there is at the very minimum a “substantial question” as to whether the project will significantly affect the environment. In other proceedings where proposed LNG export facilities would be constructed substantially outside existing terminal sites, FERC has determined that an EIS is appropriate.9 An 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 impact statement.” 40 C.F.R. § 1502.14. FERC must take care not to define the project purpose so narrowly as to prevent the consideration of a reasonable range of alternatives to actions 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 for choice 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 Jordan Cove Liquefaction and Pacific Connector Pipeline Projects, FERC Dockets PF12-7 and PF12-17 (Aug. 2, 2012) (EIS for proposed greenfield facility), Freeport LNG Development, L.P., Freeport LNG Expansion, L.P., FLNG Liquefaction LLC; Supplemental Notice of Intent To Prepare an Environmental Impact Statement for the Planned Liquefaction Project, 77 Fed. Reg. 43589 (July 25, 2012) (EIS where addition of liquefaction and export facilities to existing import terminal will involve, among other things, disturbance of 610.7 acres and permanent occupation of 215.1 acres).

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An EIS must also describe the direct and indirect effects, and cumulative impacts of, a proposed 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 distinct from one another: Direct effects are “caused by the action and occur at the same time and 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 concerted actions to implement a specific policy or plan; [or] systematic and connected agency decisions allocating agency resources to implement a specific statutory program or executive directive.” 40 C.F.R. § 1508.17(b)(3); see also 10 C.F.R. § 1021.330 (DOE regulations discussing this possibility). As we have discussed elsewhere, such an EIS is appropriate here.

C. Endangered Species Act The Endangered Species Act (ESA) directs that all agencies “shall seek to conserve endangered species.” 16 U.S.C. § 1531(c)(1). Consistent with this mandate, FERC must ensure that, if it approves the Company’s proposed project, the approval “is not likely to jeopardize the continued existence of any endangered species . . . or result in the destruction 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 to determine 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).

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FERC must first conduct a biological assessment, including the “results of an on-site inspection of the area affected,” “[t]he views of recognized experts on the species at issue,” a review of relevant literature, “[a]n analysis of the effects of the action on the species and habitat, including consideration of cumulative effects, and the results of any related studies,” and “[a]n analysis of alternate actions considered by the Federal agency for the proposed action.” See 50 C.F.R. § 402.12(f). If that assessment determines that impacts are possible, FERC must enter into formal consultation with the Fish and Wildlife Service and the National Marine and Fisheries Service, as appropriate, to avoid jeopardizing any endangered species or adversely modifying its habitat as a consequences 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 such effects here. The proposed project is likely to adversely affect fish and wildlife by directly disturbing terrestrial and aquatic habitat. Moreover, FERC’s ESA review must consider not just the effects of the project at the proposed site, but the effects of increased gas production across the full region the plant affects.

D. National Historic Preservation Act FERC 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 National Register.” 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, “the preservation 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 in order to “identify historic properties potentially affected by the undertaking, assess its effects and seek ways to avoid, minimize or mitigate any adverse effects on historic properties.” 36 C.F.R. § 800.1(a). NHPA regulations make clear that the scope of a proper 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 may directly or indirectly cause alterations in the character or use of historic properties,” 36 C.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 ESA and NEPA contexts, the reach of the Company’s proposal extends to the entire area in which it will increase gas production. Thus, to approve The Company’s proposal, FERC must first understand and mitigate its impacts on any historic properties which it may affect. The regulations governing this process provide that “[c]ertain individuals and organizations with a demonstrated interest in the undertaking may participate as

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consulting parties” either “due to the nature of their legal or economic relation to the undertaking or affected properties, or their concern with the undertaking’s effects on historic properties.” 36 C.F.R. § 800.2(c)(5). Sierra Club meets that test, because the Club and its members are interested in preserving intact historic landscapes, for their ecological and social value, and reside through the regions affected by the Company’s proposal. Its members have worked for years to protect and preserve the rich human and natural fabric of these regions, and would be harmed by any damage to those resources. Sierra Club must therefore be given consulting party status under the NHPA for this application.

IV. Effects of the Proposed Project Although, as explained above, the Natural Gas Act’s public interest inquiry requires discussion of environmental impacts, a fully informed discussion cannot take place until the NEPA process has identified those impacts. Conversely, the Natural Gas Act’s incorporation of a broad scope of environmental concerns into the public interest determination facing FERC means the NEPA analysis must be similarly broad. “Because ‘NEPA places upon an agency the obligation to consider every significant aspect of the environmental impact of a proposed action,’ the considerations made relevant by the substantive 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, when more information regarding the proposal, and FERC’s assessment of it, is available.10 At this stage, however, Sierra Club provides comments regarding the scope of the forthcoming NEPA review and a discussion of the already apparent adverse environmental effects. We first discuss FERC’s obligation to analyze the impacts of all three phases of the Company’s proposed terminal together, rather than segmenting its analysis into three phases in the manner contemplated by the Company’s application. We then discuss both impacts directly attributable to the proposed project and impacts associated with the natural gas that will be imported and the additional natural gas production 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 Isolation

10 As we discuss elsewhere, FERC must prepare an EIS, and not merely an EA, for this project.

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FERC must consider the effects of all three phases of the Company’s proposed facilities together, and is not permitted to segment phase 1 from the other phases, as proposed by the Company. This obligation stems from three basic NEPA principles. First, FERC’s approval of the three-phased LNG terminal project constitutes a single federal action whose 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 three proposed project phases, that approach is plainly prudent given that the three phases are integrally connected. Third, even if FERC refuses to prepare a single NEPA document for all three phases, it must at a bare minimum analyze the cumulative impacts of the three project phases.

1. NEPA Requires FERC to Analyze All Three Phases in a Single NEPA Document

First, NEPA requires FERC to analyze all three phases of the Company’s proposal together, in a single NEPA document. NEPA regulations clearly state that “[p]roposals or parts of proposals which are related to each other closely enough to be, in effect, a single 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 also provide guidance on which actions should be considered together in a single document. “Connected actions” are “closely related and therefore should be discussed in the same impact 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 their justification.” Id. § 1508.25(a)(1)(iii). Here, the Company’s own description shows that the three phases of the proposal are closely 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 “a comprehensive, multi-phased strategic plan.” App. at 1, 17; RR at 2. According to the Company, “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 facilities that will comprise the ultimate LNG terminal in Hawaii upon completion of Phases 2 and 3.” App. at 22 (emphasis added). These descriptions of the phases’ close relationship show that they amount to “a single course of action” that must be analyzed in a single NEPA document. See Fla. Wildlife Fed’n v. U.S. Army Corps of Eng’rs, 401 F. Supp. 2d 1298, 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 have

11 NEPA’s prohibitions on segmentation in the EIS context apply equally to environmental assessments. See, e.g., Sierra Club v. Marsh, 769 F.2d 868, 881-82 (1st Cir. 1985) (analyzing segmentation in the context of an EA).

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jurisdiction over the next phases of development; and that it anticipates applications for those 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 to lay 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 other agencies in the State to become familiar with LNG prior to the installation of permanent storage and vaporization facilities in Phases 2 and 3.” App. at 6. Where, as here, later phases constitute a selling point or objective of an earlier phase, all phases must be discussed together in a single document. Sierra Club v. Marsh, 769 F.2d 868, 878-79 (1st Cir. 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 cumulatively significant impacts” should, like connected actions, “be discussed in the same impact statement.” 40 C.F.R. § 1508.25(a)(2). As described more fully below, the three phases of the project are likely to cause substantial direct harms to the local community and local wildlife; they also will cause substantial harms associated with the upstream drilling and liquefaction needed to supply the proposed terminal. Taken together, these cumulatively significant impacts demonstrate that the three phases of the project are “cumulative actions” that must be analyzed together. See Thomas v. Peterson, 753 F.2d 754, 759 (9th Cir. 1985) (proposed road, and timber sales the road was designed to facilitate, were cumulative actions for which comprehensive analysis was required). FERC and the Company may not escape comprehensive review by arguing that, because phase 1 may alleviate a potential shortage during an upcoming pipeline inspection, phase 1 therefore has independent utility from later project phases, allowing it to be analyzed 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 be segmented based on whether the projects had “independent utility”; i.e., “whether one project 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 place for 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 suddenly needed before the inspection takes place. “[M]anipulation of a project design to conform to a concept of independent utility, particularly with the intention that a permit be expedited, undermines the underlying purposes of NEPA” and will not cure a segmentation 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

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comprehensive impact statement in certain situations where several proposed actions are pending at the same time,” an agency is not required to prepare such an EIS absent a concrete “proposed action.” 427 U.S. at 401, 409. In Kleppe, the Department of Interior 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 the Northern Great Plains should be prepared. Id. at 397-99. The Court rejected this contention on the basis that there was “no proposal for a regional plan or program of development.” Id. at 404. Here, by contrast, the Company has proposed an integrated, three-phase LNG terminal project. Unlike in Kleppe, comprehensive review would be tethered to a concrete project and would be neither unduly speculative nor impractical. Moreover, even if Kleppe were not distinguishable here, comprehensive review would still be required under later cases interpreting Kleppe. These cases have clarified that Kleppe does not give agencies carte blanche to segment review of integrally connected actions. The Fifth Circuit has held that Kleppe “leaves room for a court to prohibit segmentation or require a comprehensive . . . [impact statement] for two projects, even when one is not yet proposed, if an agency has egregiously or arbitrarily violated the underlying 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 a string of anticipated actions are formal “proposals,” at least where it “ma[kes] good sense 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 comprehensive NEPA 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 Here

Even if FERC were not required to analyze all three phases of the Company’s proposal together, that is plainly the most prudent course. As mentioned, the Company repeatedly insists that the three phases are integrally connected and share common goals. 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 supply and distribution strategy.”). Without comprehensive review, FERC will be unable to make an informed decision at the outset about whether this strategy is in the public interest. Indeed, as the Hawaii Department of Transportation points out in its comments, the Company is proposing to proceed without any meaningful review of local impacts. Acceding to this request could lead to significant complications later. For example, if substantial local impacts later prompt FERC to disapprove or require modifications to later phases of the project, the Company may have expended significant resources for no useful purpose. Analyzing all impacts of the three-phase project now will give FERC a full picture of the project’s impacts, avoiding wasteful early resource expenditures and informing the public, including the local community, of the Company’s longer-term plans.

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3. FERC Must, at a Bare Minimum, Analyze the Cumulative Impacts of All Three

Facilities

Even if FERC were not obligated, both by the law and by common sense, to prepare a comprehensive NEPA document for all three phases of the proposed project, it must at a bare minimum analyze the cumulative impacts of all three facilities. As mentioned above, NEPA requires analysis of “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.” 40 C.F.R. § 1508.7. Agencies must conduct a “useful analysis of the cumulative impacts of past, present and future projects” in addition to the proposal currently under consideration. City of Carmel-by-the-Sea v. U.S. Dep’t of Transp., 123 F.3d 1142, 1160 (9th Cir. 1997). “Very broad and general statements devoid of specific, reasoned conclusions” are not adequate; agencies must evaluate the specific environmental impacts that are likely to follow as a result of the present action and 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 “reasonably foreseeable,” as they are described, in the Company’s application, as later portions of an integrally related strategy. 40 C.F.R. § 1508.7. Further, taken together, the proposed facilities would have a range of environmental impacts that will be far more significant than those described in the application. FERC is required to consider the impacts of these eminently foreseeable future phases together with those associated with the first phase, so that the agency may clearly understand the impacts of embarking upon this multi-phased project. Id.

B. FERC Should Prepare an EIS for the Three-Phase Project

1. An EIS is Appropriate

As mentioned in part III.B above, FERC must prepare a full EIS for this three-phase proposal, either in addition to or in place of the EA that FERC has already announced an intention to prepare.12 NEPA requires an EIS where a proposed major federal action would “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 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. See Klamath Siskiyou, 468 F.3d at 561-62. These direct impacts of the three-phased proposal are described in more detail in the sections that follow. Although, in many instances, FERC will be required to request additional information from the Company to adequately analyze the overall impacts of

12 Notice of Application, The Gas Company, LLC, 77 Fed. Reg. 60,972 (Oct. 5, 2012).

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this three-phase project, it is plain that there is a substantial question as to whether the project will have significant impacts.

2. Even if FERC Refuses to Prepare An EIS, it Must, at a Minimum, Take Public

Comment on the EA

Even if FERC refuses to prepare an EIS for the proposed project, it must at the very least ensure opportunities for significant public input on any environmental assessment, including allowing the public the opportunity to comment on the draft EA before it is finalized.13 We echo the Hawaii Department of Transportation’s concerns that the existing notices for the proposed project might otherwise “have limited public outreach capability locally,” and echo the Department’s request that FERC “make sure that adequate efforts [are] made . . . to solicit public comments.”14

C. Direct Impacts of the Proposed Facilities The proposed facilities – including the transportation, storage, and regasification equipment used during the phase 1 operations and the permanent storage tanks, terminal construction, and associated infrastructure necessary for phases 2 and 3 – will have a range of adverse direct environmental effects. Few of these impacts are discussed in the application and environmental report submitted by the Company, but FERC is required to analyze them to comply with its NEPA obligations. These impacts include (but are not limited to) air pollution, disruption of aquatic habitat, increased noise and light pollution, and impacts on fish and wildlife related to the preceding impacts. Each of these impacts is contrary to the public interest and must be considered in FERC’s analysis.

1. Air Emissions

The Company’s resource report states that no air quality issues are expected to result from the operation of the phase 1 facilities, due to the type of equipment that will be used, and, perhaps, to phase 1’s small scale. RR at 4. This analysis, however, breaks up the larger, three-phase project into smaller components in precisely the manner NEPA forbids. 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.” Sierra Club v. Marsh, 769 F.3d at 875. Whereas draft EIS’s must be circulated for public comment, 40 C.F.R. § 1503.1, the regulations require the agency to “involve . . . the public, to the extent practicable,” in preparing environmental assessments, id. § 1501.4(b). 14 Comment of Hawaii Department of Transportation re: Gas Company, LLC Request for Authorization to Operate Liquified Natural Gas Facilities, FERC Docket CP12-498 (“DOT Comments”) at 2.

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considering air pollution that can be expected from the larger-scale phase 2 and 3 operations as well. As revealed in the environmental review documents for LNG import terminal proposals that FERC has previously considered, LNG import terminals and associated infrastructure can emit harmful quantities of a variety of air pollutants. For example, FERC’s EIS for the Jordan Cove import terminal proposal that the agency considered several years ago estimated approximately 41 tons per year (tpy) of particulate matter (PM), 177 tpy of sulfur dioxide (SO2), 250 tpy or less of nitrogen oxides (NOx), 136 tpy of carbon monoxide (CO), and 17 tpy of volatile organic chemicals (VOC).15 Significant additional quantities of many of these pollutants – including an additional 169 tpy of NOx – were expected from mobile sources associated with the project, id., and additional emissions were expected from construction, id. at 4.11-17. In addition, the Jordan Cove EIS predicted 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 the operation and construction phases) or discuss their harmful effects. The application thus underemphasizes their impact on the public interest. Sierra Club expects to provide further comment on the Company’s emissions during the NEPA public comment period. At this stage, we emphasize that the air emissions that can be expected from the Company’s proposed three-phase terminal project can cause extensive harmful impacts to human health and the environment. We briefly describe these impacts below. CO CO can reduce oxygen delivery to the body's organs and tissues.16 CO can be particularly harmful to persons with various types of heart disease, who already have a reduced capacity for pumping oxygenated blood to the heart. “For these people, short-term CO exposure further affects their body’s already compromised ability to respond to the increased oxygen demands of exercise or exertion.”17 VOC and NOx VOC and NOx emissions harm the environment by increasing the formation of ground-level ozone (smog). Smog pollution harms the respiratory system and has been linked to premature death, heart failure, chronic respiratory damage, and premature aging of

15 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.

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the lungs.18 Smog may also exacerbate existing respiratory illnesses, such as asthma and emphysema, or cause chest pain, coughing, throat irritation and congestion. Children, the elderly, and people with existing respiratory conditions are the most at risk from ozone pollution.19 Significant ozone pollution also damages plants and ecosystems.20 In addition, ozone contributes substantially to global climate change over the short term. According to a recent study by the United Nations Environment Program (UNEP), ozone is now the third most significant contributor to human-caused climate change, behind carbon dioxide and methane.21 GHGs LNG terminals, such as the Jordan Cove import terminal proposal mentioned above, can emit significant quantities of greenhouse gases. Although the Company’s proposed facilities are smaller in scale than Jordan Cove, the Jordan Cove application provides a sense of the order of magnitude of potential greenhouse gas emissions that FERC must analyze. These greenhouse gas emissions will increase global warming, harming both the local and global environments. The impacts of climate change caused by greenhouse gases include “increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingly severe weather events, such as hurricanes of greater intensity and sea level rise.” A warming climate will also lead to loss of coastal land in densely populated areas, shrinking snowpack in western states, increased wildfires, and reduced crop yields. More frequent heat waves as a result of global warming have

18 EPA, Proposed New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry: Regulatory Impact Analysis, 4-25 (July 2011), available at http://www.epa.gov/ttnecas1/regdata/RIAs/oilnaturalgasfinalria.pdf and attached as Exhibit 5 (hereinafter O&G NSPS RIA); Jerrett et al., Long-Term Ozone Exposure and Mortality, New England Journal of Medicine (Mar. 12, 2009), available at http://www.nejm.org/doi/full/10.1056/NEJMoa0803894#t=articleTop, attached as Exhibit 6. 19 See EPA, Ground-Level Ozone, Health Effects, available at http://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 as Exhibit 8. 20 O&G NSPS RIA at 4-26. 21 Id. See also United Nations Environment Programme and World Meteorological Organization, (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.

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already affected public health, leading to premature deaths. And threats to public health are only expected to increase as global warming intensifies. For example, a warming 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 those with existing health problems—are the most at risk from these threats. Sulfur Dioxide Sulfur dioxide causes respiratory problems, including increased asthma symptoms. Short-term exposure to sulfur dioxide has been linked to increased emergency room visits and hospital admissions. Sulfur dioxide also reacts in the atmosphere to form particulate matter (PM), an air pollutant which causes a great deal of harm to human health.22 PM is discussed separately below. Particulate Matter PM consists of tiny particles of a range of sizes suspended in air. Small particles pose the greatest health risk. These small particles include “inhalable coarse particles,” which are smaller than 10 micrometers in diameter (PM10), and “fine particles” which are less than 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 of fuels or through secondary formation in the atmosphere.23 PM causes a wide variety of health and environmental impacts. PM has been linked to respiratory 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 people with existing heart or lung problems, are most at risk from PM pollution.24 PM also reduces visibility,25 and may damage important cultural resources.26

Black carbon, a

22 EPA, Sulfur Dioxide, Health, available at http://www.epa.gov/air/sulfurdioxide/health.html, attached as Exhibit 10. 23 See EPA, Particulate Matter, Health, available at http://www.epa.gov/pm/health.html, attached as Exhibit 11; BLM, West Tavaputs Plateau Natural Gas Full Field Development Plan Final Environmental Impact Statement (“West Tavaputs FEIS”), at 3-19 (July 2010), available at http://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, Health 25 EPA “Visibility – Basic Information” http://www.epa.gov/visibility/what.html, attached as Exhibit 12. 26 See EPA, Particulate Matter, Health; West Tavaputs EIS, at 3-19; O&G NSPS RIA at 4-24.

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component of PM emitted by combustion sources such as flares and older diesel engines, also warms the climate and thus contributes to climate change.27 Hydrogen Sulfide Hydrogen sulfide is an air pollutant with toxic properties that smells like rotten eggs and can lead to neurological impairment or death. Long-term exposure to hydrogen sulfide is linked to respiratory infections, eye, nose, and throat irritation, breathlessness, nausea, dizziness, confusion, and headaches.28 Hydrogen sulfide emissions may be harmful even at low concentrations.29

2. Water and Aquatic Habitat Impacts

The Company reports no water or aquatic habitat impacts, again due to its failure to disclose or analyze impacts associated with the second and third phases of the proposed terminal. RR at 3. As explained, FERC is required to analyze all impacts that can be expected as a result of the three-phase terminal proposal, including harm to local water quality as a result of increased stormwater pollution and increased shipping traffic. We briefly 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 LNG terminal application, stormwater runoff associated with an LNG terminal can contain “heavy metals, petroleum products and brake chemicals and compounds that are deleterious to fish and fish habitat.”30 In addition, ship traffic inherent in LNG import activities can be expected to impair water quality in Honolulu Harbor. As FERC explained in a prior EIS, LNG ship traffic causes “resuspension of bottom sediments and resulting increases in turbidity.”31 Separate

27 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 Hydrogen Sulfide 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 as Exhibit 13. 29 See James Collins & David Lewis, Report to CARB, Hydrogen Sulfide: Evaluation of Current 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 Impact Statement for the Jordan Cove Energy Liquefied Natural Gas Terminal and Pacific Connector Gas Pipeline Project, FERC Docket CP07-441, at 2 (June 5, 2009) (hereinafter “NMFS Comment on CP07-441”), attached as Exhibit 15. Further information is provided 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.

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from effects on water quality, the frequent passage of LNG shipping traffic through the bay, coupled with the large exclusion zones that may be maintained around these ships for safety, will significantly disrupt other human users of the bay, including fishermen and recreational boaters.

3. Noise, Light, Traffic, and Safety Issues

Construction and operation of the proposed project will cause significant increases in local 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 pollution expected from LNG moving through above-ground piping connecting the containers to be used in phase 1 to the regasification units used to inject them into the distribution system. RR at 4. The Sierra Club reiterates the concerns, expressed by the Hawaii Department of Transportation, that the proposed project will negatively impact the businesses in the Domestic Commercial Fishing Village, which is adjacent to the proposed operations in Honolulu Harbor.32 FERC is required to seriously analyze such impacts under NEPA. The Club also shares the Department’s concern that the proposed project may impact the safety of nearby residents and motorists on the nearby highway, and echoes its request that safety considerations be fully analyzed and safety measures fully discussed and disclosed.33 Finally, the Club echoes the Department’s concern that the traffic impacts of the proposed project be fully discussed and analyzed. The Company plans to use trucks to haul LNG containers to various points on the Company’s distribution network, but fails to provide any analysis of the impacts of this additional truck traffic. RR at 2. FERC is required to discuss these impacts, and must also analyze cumulative traffic impacts caused by all three phases of the Company’s proposal.

4. Fish and Wildlife

The proposed project is likely to adversely affect fish and wildlife by directly disturbing terrestrial and aquatic habitat. Again, the Company has not made any attempt to catalogue such impacts because its application’s discussion of impacts is improperly limited 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 10 millions gallons from permanent land-based storage facilities and potentially floating

32 DOT Comments at 1. 33 Id.

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storage regasification units – will have substantial impacts on fish and wildlife. App. at 23. Honolulu County, where the proposed project will be located, is home to the endangered Hawaiian hoary bat, as well as 12 endangered and threatened bird species, four endangered and threatened reptile species, and dozens of endangered plant species.34 The presence of so many endangered species in the county raises the significant 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 later phases of the project, App. at 19, shelters spinner dolphins and, during the winter months, humpback whales.35 Whales and dolphins can easily suffer injury or death as a result of a ship collision, and the areas of greatest concern relative to ship strikes are located near the harbor entrance.36 FERC is required to seriously assess the impacts of the 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 Effects

At present, the application fails to provide FERC with basic information regarding the amount and likely source of the LNG to be used by the Gas Company. The Company insists 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 in the northeast or Midwest, App. at 29. But the application does not even identify which liquefaction facilities will supply the proposed operations. The application vaguely mentions two companies that operate liquefaction facilities, Air Liquide and Praxair, although it does not state where the facilities are located or where the operators obtain their natural gas supplies. App. at 30. It also provides only a vague sense of how much LNG the completed terminal facilities are expected to process and use, stating only that the 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 LNG

34 U.S. Fish and Wildlife Service, Species by County Report, Honolulu County, available at http://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 Along Oahu’s Ewa/Honolulu Coast, Marine Mammal Research Program/Hawaii Institute of Marine Biology Technical Report 20001, 3 (2000), available at http://www.oceanwidescience.org/PDF/Navatek%20Final%20Report.PDF, and attached as Exhibit 18. 36 Id. at 17.

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that will be used by the proposed project would assist FERC in analyzing the project’s impacts on Hawaii’s energy future, and could also assist the agency in analyzing the extensive impacts of the drilling likely to be induced as a result of the Company’s proposal. FERC should obtain this information to assist it in analyzing the proposal’s impacts.

E. The Proposed Project’s Effects on Development of Renewable Energy Resources in Hawaii

The proposed project will also have a variety of indirect effects. Chief among these is its impact on the development of renewable energy resources in Hawaii. The Company argues, without any real support, that the phase 1 facilities further the goals of the Hawaii Clean Energy Initiative. The Company offers scant evidence for this contention, however. FERC must not accept the Company’s arguments at face value and must instead take a close look at the impact of LNG import on development of renewable energy in the state. Hawaii has made it a public policy priority to develop clean, renewable energy in the state. 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 the state’s legally binding renewable portfolio standard (RPS) has taken the first step towards 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 in achieving Hawaii’s renewable energy goals. The RPS allows utilities to avoid penalties associated with a failure to meet RPS goals if they can demonstrate their “[i]nability to acquire sufficient renewable energy due to lapsing of tax credits related to renewable energy development” or even simply their “[i]nability to acquire sufficient cost-effective renewable energy.” Haw. Rev. Stat. § 269-92(d). Hawaii still has significant progress left to make before it achieves its renewable energy goals, and, as these exceptions demonstrate, 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 to impede or delay Hawaii’s achievement of its renewable energy objectives, keeping in mind that Hawaii has already decided that swift deployment of renewable energy is in the public interest. In particular, FERC must closely examine the company’s argument that 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/.

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First, the Company argues that LNG import will advance Hawaii’s clean energy goals because “[u]tilizing a lower cost energy source such as natural gas would significantly reduce the cost per kilowatt hour of electricity.” App. at 35. Even the Company’s claim that natural gas will have a consistently low cost may be too facile; at a seminar presented by the Company itself in August 2012, “an LNG industry consultant explained that because of transport issues, wholesale LNG prices can vary by more than 25 times.”38 Given this variation, it is not clear that LNG will be consistently cheap for Hawaii. Moreover, even assuming Hawaii can consistently access affordable LNG, it is unclear how infrastructure facilitating the use of fossil fuel energy will assist Hawaii in developing renewable energy resources. In fact, investors’ incentives to invest in innovative renewable energy technologies may diminish if opportunities to invest in more “familiar” fossil fuel technologies become available. App. at 6. Indeed, the International Energy Agency expects that, in the United States alone, the natural gas boom will result in a 10% reduction in renewables relative to a baseline world without increased gas use and trade.39 In other words, as senior International Energy Agency officials recently warned, “[r]enewable energy may be the victim of cheap gas prices.”40 Researchers at the Renewable and Sustainable Energy Institute agree: “Wind,” they observe, “had [before the fracking boom] been capable of competing with natural gas generation on a cost basis, thanks to advances in technology and a federal production tax credit. Installation of new renewable energy facilities has now 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 gas historian Daniel Yergin agrees that “[a]bundant, relatively low-priced supplies now make natural gas a highly competitive alternative to both nuclear and wind power.”42

38 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, The Guardian, May 29, 2012, available at http://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 Role In the U.S. Energy Endgame, Yale Environment 360, Aug. 12, 2012, available at http://e360.yale.edu/feature/natural_gas_role_in_us_energy_endgame/2561/, and attached as Exhibit 22. 42 Daniel Yergin, Stepping on the Gas, The Wall St. Journal, Apr. 2, 2011, available at http://resourceroyaltyllc.com/EducationalInformation/Articals/DanielYerginWSJ02042011.pdf, and attached as Exhibit 23.

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Bringing LNG into Hawaii accordingly introduces the potential for investment dollars that might once have gone towards renewables development to be diverted to LNG investments. In fact, investment in renewables may not even be possible – let alone attractive – if the Company’s limited resources have been expended on new LNG infrastructure. The Company also states that “natural gas-fired electric generation could be used to support the State’s renewable resources,” suggesting, perhaps, that substituting Hawaii’s aging power plants with newer natural gas combined-cycle technologies would reduce the cost of electricity and lower emissions. App. at 36. But Hawaii’s goal is not to replace fossil fuel generation with more efficient fossil fuel generation – its goal is to make fossil fuel generation unnecessary (or less necessary) by reducing demand for power through energy efficiency or introducing renewables. See Haw. Rev. Stat. § 269-91 (excluding “fossil-fueled qualifying facilities that sell electricity to electric utility companies” from the set of combined heat and power systems that count towards energy efficiency targets in the state’s renewable portfolio standard). The goal of demand reduction is not advanced by the Company’s proposal. Further, LNG imports, and even new combined-cycle natural gas plants, are not necessary to development of renewable energy resources in Hawaii; indeed, they could be detrimental to renewables’ development, for the reasons explained. Combined-cycle power plants like those mentioned in the Company’s application, App. at 36, can be a flexible complement to renewables, but they are not necessary for renewables development. Hawaii can achieve the same reliability by taking advantage of smart storage technologies, in addition to firm renewable energy sources. Moreover, even a decision by Hawaii to upgrade its fossil fuel plants to better complement renewable energy technologies does not depend on LNG import; the state could potentially upgrade its existing power plants without introducing a new fossil fuel that has the potential to divert dollars from renewable energy investments. Finally, the Company points to a letter from Governor Abercrombie expressing support for natural gas development in Hawaii. App. at 35; Ex. I. The letter suggests that “the portion of power generation that would continue to use imported petroleum oil during the transition to renewable energy could instead be converted to a potentially cheaper and cleaner fuel such as liquefied natural gas.” App. at Ex. 1. The letter does not grapple, however, with the potential for the introduction of natural gas to impede investment in renewables and demand-side energy efficiency. FERC must give these important questions close and careful attention before concluding that LNG import is in the public interest.

F. Effects of the Proposal on Greenhouse Gas Emissions in Hawaii Because the proposal could disrupt development of renewable energy technologies in Hawaii, the proposal’s impacts on greenhouse gas emissions must be closely examined.

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Even if the proposal enables Hawaii to switch away from a relatively carbon-intensive fossil fuel like the petroleum-based synthetic natural gas the Company currently uses, its utility in decreasing overall greenhouse gas emissions is questionable if it ultimately discourages investment in renewable energy resources. Moreover, even if the proposed project somehow had no impact on renewable energy development, FERC would still be obligated to carefully analyze whether switching to LNG will truly provide significant greenhouse gas emissions reductions, even if the LNG is replacing synthetic natural gas (SNG) prepared from naphtha-based feedstock.43 App. at 2. Throughout the application, the Company suggests that importing LNG into Hawaii can provide an environmental benefit by helping Hawaii switch away from petroleum-based fuel. See, e.g., App. at 17. But the available evidence demonstrates substantial uncertainty 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 and trade will produce “only a small net shift” in global greenhouse gas emissions, with atmospheric CO2 levels stabilizing at over 650 ppm and global warming in excess of 3.5 degrees Celsius, “well above the widely accepted 2°C target.”44 Second, when LNG is imported into a new market to substitute for fuel oil or coal, the available evidence indicates that this substitution is likely to cause little, if any, reduction in global greenhouse gas emissions. As explained below, the production of natural gas itself causes substantial greenhouse gas emissions. Additional energy is then consumed in the transportation of the gas, with attendant greenhouse gas emissions. Finally, as contemplated in the Company’s application, LNG must be regasified at the import terminal, again consuming fuel and causing additional emissions. These operations drastically increase the lifecycle greenhouse gas emissions of LNG, adding between 24.7 and 27.5 tons of CO2e per MMBtu.45

43 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 assume that LNG is a significantly less GHG-intensive source, given the extensive greenhouse gases 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 Air Emissions of Coal, Domestic Natural Gas, LNG, and SNG for Electricity Generation, 41 Environ. Sci. Technol. 6,290 (2007) (Jaramillo 2007), available at http://www.ce.cmu.edu/~gdrg/readings/2007/09/13/Jaramillo_ComparativeLCACoalNG.pdf, and attached as Exhibit 24. The supporting information for this article is available at http://pubs.acs.org/doi/suppl/10.1021/es063031o/suppl_file/ es063031osi20070516_042542.pdf, and attached as Exhibit 25 (“Jaramillo Supporting Information”). An earlier, related report with some additional information is Paulina Jaramillo, W. Michael Griffin, H. Scott Matthews, Comparative Life Cycle Carbon

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Due to emissions from liquefaction, transportation and gasification, LNG generates significantly more greenhouse gas emissions than domestic natural gas. For perspective, 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 of liquefying, transporting, and regasifying LNG accordingly emits 19% to 23% of the CO2e emitted 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 gas emissions into parity with coal: Figure 1: Life-Cycle Emissions of LNG, Natural Gas, and Coal in Electricity Generation46

Jaramillo’s analysis may even underestimate the emissions associated with LNG. It does not reflect recent studies that have raised estimates for emissions associated with natural gas production. Recent studies have concluded that these emissions are substantial. Because these studies post-date the Jaramillo studies regarding export emissions, 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 further below, shale gas production’s methane emissions are drastically higher than those of conventional gas production. Moreover, in April 2011 (well after the Jaramillo studies were published), EPA released improved methodologies for estimating fugitive methane emissions from all natural gas systems (unconventional and otherwise), which lead to

Emissions of LNG Versus Coal and Gas for Electricity Generation (2005), available at http://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 gas made from coal.

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higher estimates. EPA, Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990 – 2009, U.S. EPA, EPA 430-R-11-005.47 These recent studies estimate that aggregate domestic natural gas production releases at least 44 pounds of CO2e per MMBtu. A report from the Worldwatch Institute and Deutsche Bank summarizes much of the recent work.48 Specifically, the Worldwatch Report synthesizes three other reports that used “bottom-up” methodologies to estimate natural gas production emissions, prepared by Dr. Robert Howarth et al., of Cornell,49 Mohan Jiang et al. of Carnegie-Mellon,50 and Timothy Skone of NETL.51 The Worldwatch Report separately derived a “top-down” estimate, which produced a result similar to the NETL estimate. Worldwatch Report at 9. These various assessments are summarized 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 Gas and Coal (Aug. 25, 2011) (“Worldwatch Report”), attached as Exhibit 29. 49 Robert W. Howarth et al., Methane and the greenhouse-gas footprint of natural gas from 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 and Delivery in the United States, Presentation to Cornell (May 12, 2011), attached as Exhibit 32. NETL has also put out a fuller version of this analysis. See also Timothy J. Skone, Life Cycle Greenhouse Gas Inventory of Natural Gas Extraction, Delivery and Electricity Production (Oct. 24, 2011), attached as Exhibit 33.

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Figure 2: Comparison of Recent Life-Cycle Assessments52

As this figure demonstrates, although the 2011 studies differ, they all estimate production greenhouse gas emissions (combined methane and “upstream CO2”) in a similar range. Synthesizing these studies, the Worldwatch Report estimated normalized life-cycle GHG emissions from domestic natural gas production (i.e., excluding liquefaction, transport, and gasification of LNG) at approximately 20.1 kilograms, or over 44 pounds, of CO2e/MMBtu. Worldwatch Report at 15 Ex. 8. Moreover, some studies estimate that production emissions are significantly higher. Jaramillo used production emission estimates that are much lower than those produced by the more recent studies, and using the recent and higher figures appears to erode what little climate advantage Jaramillo found LNG to have over coal. Jaramillo used estimates of 15.3 to 20.1 pounds CO2e/ MMBtu, i.e., estimates that were at least 24 pounds lower than the 2011 studies’. Jaramillo Supporting Information at 8. Jamarillo estimated 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.

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increase in total emissions. This increase substantially erodes any climate advantage LNG-fired electricity generation may have over coal-fired generation. As these studies demonstrate, the long-term benefits of switching to LNG are extremely complex and must be carefully examined. Further, rough estimates demonstrate that, although it is possible that replacing petroleum-based fuel with LNG may ultimately produce some greenhouse gas benefits, this too is an extremely complicated question that FERC should examine closely. The lifecycle greenhouse gas emissions data generated by California for purposes of its new Low Carbon Fuels Standard (which covers transportation fuels) show greenhouse gas emissions from petroleum products that may be roughly comparable to fuel oil to be in the range of 95g CO2e per megajoule, or about 752 lb CO2e/mWh.53 A comparison to Figure 1 reveals that this 752 lb CO2e/mWh figure is actually lower than Jaramillo 2007’s estimate of lifecycle emissions of LNG combusted using the current U.S. fleet of power plants, suggesting, at least at first blush, that replacing fuel oil with LNG provides no greenhouse gas benefit. The estimate derived from the California database may well understate emissions from the fuel used in Hawaii, of course. An accurate estimate would more closely mirror the Company’s operations, using naphtha as the base fuel and accounting for additional greenhouse gas emissions associated with converting the fuel into synthetic natural gas. App. at 8-9. Such an estimate also would account for the fuel efficiency of the power plants in which the fuel is ultimately combusted. But although these back-of-the-envelope calculations are highly imperfect, they do illustrate that the greenhouse gas benefits that the Company’s proposal will provide are highly uncertain and must be examined in detail. FERC must not accept the Company’s assertions that LNG is a “cleaner” alternative at face value.

G. Effects of The Additional Gas Production that Exports Will Induce The proposed project also will induce additional natural gas production, likely from shale gas plays in which hydraulic fracturing is used. This induced production is likely to result in significant environmental harms. Although FERC recently declined to consider such impacts in the Sabine Pass proceeding, FERC Docket CP11-72, those orders are factually distinguishable and do not bind FERC here. FERC must consider these effects in its own NGA public interest analysis. These effects also must be examined during the NEPA process.

1. Effects Related to Induced Drilling

53 Cal. Air Resources Bd., LCFS Lookup Tables as of December 2009, Table 6. Carbon Intensity Lookup Table for Gasoline and Fuels that Substitute for Gasoline, available at http://www.arb.ca.gov/fuels/lcfs/121409lcfs_lutables.pdf, and attached as Exhibit 34.

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Although the Company’s application will not likely impact domestic natural gas production to the same degree as the many LNG export applications currently before the Commission, it is nonetheless certain to induce additional production, albeit on a smaller scale. As we explain below, this increased production will have significant adverse environmental effects that are undoubtedly “indirect effects” which NEPA and the NGA require FERC to consider. Although FERC declined to consider these effects in its Sabine Pass orders, FERC should not follow Sabine Pass here. Accordingly, FERC must evaluate the environmental impacts of the additional natural gas production that will be induced by operation of the proposed project.

a. The Company’s Imports of Natural Gas Will Induce Additional Natural Gas Production

Increased consumption of LNG through export from the continental United States to Hawaii will induce further gas production, primarily from shale gas. The Energy Information 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 the United States [would] balance in response to increased natural gas exports largely through increased natural gas production.” EIA, Effect of Increased Natural Gas Exports on Domestic Energy Markets (“EIA Study”), p.6 (Jan. 2012).54 Although the EIA study focused on export of natural gas outside the United States, its reasoning also applies to exports from the continental United States, where most U.S. gas production occurs, to Hawaii. 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 the increase in total domestic production coming from shale gas, tight gas, [and] coalbed sources 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 the controversial practice of hydraulic fracturing, or fracking. See DOE, Secretary of Energy’s Advisory 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 impacts associated with induced production.

b. FERC Must Consider Induced Production

54 Attached as Exhibit 35. 55 Attached as Exhibit 36. The Board’s Second 90-Day Report is attached as Exhibit 37.

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Natural gas production—from both conventional and unconventional sources—is a significant air pollution source, can disrupt ecosystems and watersheds, leads to industrialization of entire landscapes, and presents challenging waste disposal issues. These impacts were recently highlighted by a Subcommittee of the DOE’s Secretary of Energy’s Advisory Board, which identified “a real risk of serious environmental consequences” 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, these efforts are uncertain and, even if fully implemented, will not eliminate the dangers. Environmental impacts of this increased production, including “growth inducing effects,” are thus manifestly “reasonably foreseeable” indirect effects of the Company’s proposal. Environmental effects of therefore production must be included in the NEPA analysis. See 40 C.F.R. § 1508.8. These effects will be added to the effects of gas production (and other environmental burdens from other industries) already present in the gas plays which the Company affects, and will add to the production induced by international export proposals. FERC must, in an EIS, fully describe all of these effects and develop alternatives which would avoid them, including the alternative of denying the Company’s application, limiting the LNG used by the Company, or imposing environmental controls on gas produced for shipment to Hawaii. The requirement to consider indirect impacts such as induced drilling is clear on the face of the statute and its implementing regulations and has been repeatedly reinforced by the courts. As the Ninth Circuit Court of Appeals recently explained, “Because ‘NEPA places upon an agency the obligation to consider every significant aspect of the environmental impact of a proposed action,’ the considerations made relevant by the substantive 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 to determine whether or not gas exports are in the “public interest,” a term which the Supreme Court has repeatedly held includes consideration of environmental impacts in his context. NAACP, 425 U.S.at 670 n.4; Udall, 387 U.S. at 450. Thus, just as the agencies must consider upstream environmental impacts in their Natural Gas Act determinations, so, too, FERC (and DOE/FE) must analyze and disclose these impacts in the NEPA analysis that will support these final determinations. Infrastructure projects, like the Company’s proposal, that enable resource extraction activities to expand upstream naturally must fully analyze those impacts in the NEPA framework. In Northern Plains Resource Council v. Surface Transportation Board, 668 F.3d 1067, 1081-82 (9th Cir. 2011), for instance, the Court considered a railway line that

56 Attached as Exhibit 37.

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was developed in order to expand coal production at several mines. Id. It held that the Surface Transportation Board’s NEPA analysis for the line was illegal because the Board had refused to consider the mines’ impacts. The Court held that such impacts were plainly “reasonably foreseeable” – and, indeed, were the premise for the construction project 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 result of the Company’s proposal, and FERC must therefore fully account for this production in an EIS for its decision. DOE’s earlier efforts provide a useful example. In its 2005 Final Environmental Impact Statement (EIS) for the Imperial-Mexicali 230-kV Transmission Lines, DOE was considering, as it is here, whether it was in the public interest to construct new infrastructure which directly enabled substantial upstream environmental impacts. The Imperial-Mexicali EIS considers the impacts of a transmission line that would enable the operation of two Mexican power plants serving the U.S. market. Although DOE initially attempted to avoid considering the impacts of those plants, confining its analysis to the line 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 remand accordingly reviews both the transmission project and the upstream impacts of the plants to the extent they affected the U.S., including ways to mitigate those impacts.57 See, 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 approach used there – a description of induced upstream impacts coupled with consideration of alternative ways to mitigate them – is generally appropriate for considering the upstream production impacts of LNG export. Indeed, the LNG case is simpler, because the upstream effects are domestic. Thus, unlike in the Imperial-Mexicali case, DOE need not partition foreign from U.S. impacts, nor be concerned that certain mitigation measures 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 international issues inherent in the Border Power Plant Working Group EIS, FERC can certainly adequately 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 Pass

Sierra Club recognizes that FERC has recently declined to address the environmental effects of induced production in two orders relating to a proposal to export LNG from Sabine 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.

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2012). These orders not bind FERC in this proceeding, and in any event were wrongly decided. First, prior FERC orders limit FERC’s authority only insofar as the Administrative Procedure Act requires FERC to provide a reasoned explanation for any departure from its 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 in circumstances” so long as FERC provides “a reasoned analysis” for the change. Louisiana Pub. Serv. Comm'n v. FERC, 184 F.3d 892, 897 (D.C. Cir. 1999) (quoting Motor Vehicle Mfrs. Ass'n 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 distinguishable would provide such a “reasoned analysis.” Second, the orders dismissed the possibility of analyzing induced production on the faulty basis that such analysis would require localized predictions of production response 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’s recent section 3 application has demonstrated the feasibility of the sort of localized predictions that FERC claims are necessary to assessment of environmental impacts. Numerous other LNG export terminal proponents have relied on this study in applications to FERC and DOE/FE, and Corpus Christi applicant Cheniere Energy cited and endorsed the reports in its DOE/FE application.58 This Deloitte Report appears to forecast 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-grained analysis that FERC contends is necessary before environmental impacts of induced drilling can be considered. Deloitte explains that “[t]he North American Gas Model is designed to simulate how regional interactions of supply, transportation, and demand determine market clearing prices, flowing volumes, storage, reserve additions, and new pipelines throughout the North American natural gas market.” See Deloitte, Natural Gas Models.59 The model “contains field size and depth distributions for every play, with a finding and development cost model included. This database connects these gas plays

58 Deloitte Marketpoint, Made in America: The Economic Impact of LNG Exports from the United States (2011) (hereinafter “Deloitte Report”), available at http://www.deloitte.com/assets/Dcom-UnitedStates/Local%20Assets/Documents/ Energy_us_er/us_er_MadeinAmerica_LNGPaper_122011.pdf and attached as Exhibit 38. 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 Exhibit 39.

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with other energy products such as coal, power, and emissions.” Id. According to Deloitte, its modeling thus allows it to predict how gas production, infrastructure construction, and storage will respond to changing demand conditions. Id. To the extent that these predictions of local impact are not yet in the record, NEPA regulations provide that FERC “shall” obtain this information unless FERC demonstrates that the costs of obtaining it are “exorbitant.” 40 C.F.R. §1502.22. Although Sierra Club expresses no particular view as to the particular merits of Deloitte’s approach, the model’s existence demonstrates that it is not impossible to forecast the response of domestic LNG production to additional demand generated by proposals like the Gas Company’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 P 27, n.35, is contrary to FERC’s own regulations. FERC regulations require, as part of the demonstration of consistency with the public interest, a showing as to whether the project will “improve the dependability of international energy trade” or “enhance competition 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 local effects of the project. More specifically, in holding that induced production was too uncertain to support environmental analysis, FERC conflated two types of uncertainty. First, FERC argued that there was uncertainty as to the total amount of production that any particular export proposal would induce. This argument is belied by the numerous federal and private entities that have made exactly this kind of prediction: at the bare minimum, FERC could have used the EIA Study’s prediction that 60 to 70% of exported gas would be supplied by induced production, multiplying these percentages by the total volume of gas the Company proposes to bring into Hawaii from the continental U.S. Second, FERC argued that it was uncertain exactly where any induced production would occur. As explained above, it is possible to make this sort of prediction, and NEPA requires FERC to seek out the information necessary to do so. But even if this type of information were unavailable, this would not preclude meaningful discussion of the environmental impacts of induced production. FERC has offered no explanation as to why knowledge of the particular location at which production will occur is necessary to assessment of the environmental effects of that production, and, as Sierra Club has demonstrated in the Sabine Pass proceedings and elsewhere, meaningful discussion of aggregate environmental impacts can be provided without knowledge of specific well sites. 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 Pollution

60 Attached as Exhibit 40.

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Below, we briefly describe some of the primary air pollution problems caused by the natural gas industry. These issues include direct emissions from production equipment and indirect emissions caused by natural gas replacing cleaner energy sources. EPA has moved 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 must therefore consider the air pollution impacts of increased natural gas production even if EPA’s rules are finalized.

i. Air Pollution Problems from Natural Gas Oil and gas operations emit methane (CH4), volatile organic compounds (VOCs), nitrogen oxides (NOx), sulfur dioxide (SO2), hydrogen sulfide (H2S), and particulate matter (PM10 and 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 public health problems. Pollutants are emitted during all stages of natural gas development, including (1) oil and natural gas production, (2) natural gas processing, (3) natural gas transmission, and (4) natural gas distribution.61 Within these development stages, the major sources of air pollution include wells, compressors, pipelines, pneumatic devices, dehydrators, storage tanks, pits and ponds, natural gas processing plants, and trucks and construction equipment. Figure 1: The Oil and Natural Gas Sector

61 EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution, Background Technical Support Document for the Proposed Rules (“TSD”) at 2-4 (July 2011), attached as Exhibit 41.

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There is strong evidence that emissions from natural gas production are higher than have been commonly understood. In particular, a recent study by a consortium of researchers led by the National Ocean and Atmospheric Administration (NOAA) Earth System Research Laboratory recorded pollution concentrations near gas fields substantially greater than EPA estimates would have predicted. That research monitored 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 we measured” – that is the cancer-causing, smog-forming, and climate-disrupting pollutants released from these operations – “are most likely underestimated in current inventories,” perhaps by as much as a factor of two.63 These emissions have dire practical consequences. A second research team, led by the Colorado School of Public Health, measured benzene and other pollutants released from unconventional well completions.64 Elevated levels of these pollutants correspond to increased cancer risks for people living within half of a mile from a well65 – a very large population 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 provide further information regarding the serious global, regional, and local impacts these exploration and production emissions entail: Methane: Methane is the dominant pollutant from the oil and gas sector. Emissions occur as result of intentional venting or unintentional leaks during drilling, production, processing, transmission and storage, and distribution. For example, methane is emitted when wells are completed and vented, as part of operation of pneumatic devices and compressors, and as a result of leaks (fugitive emissions) in pipelines, valves, and other equipment. EPA has identified natural gas systems as the “single largest contributor to United States anthropogenic methane emissions.”66 The industry is responsible for over

62 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 Development of 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 gas production sector), attached as Exhibit 44.

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40% of total U.S. methane emissions.67 Methane causes harm both because of its contributions to climate change and as an ozone precursor. Beginning with climate change, methane is a potent greenhouse gas that contributes substantially to global climate change. Methane has at least 25 times the global warming potential of carbon dioxide over a 100 year time frame and at least 72 times the global warming potential of carbon dioxide over a 20-year time frame.68 The oil and gas production industry’s methane emissions amount to 5% of all carbon dioxide equivalent (CO2e) emissions in the country.69 Because of methane’s effects on climate, EPA has found that methane, along with five other well-mixed greenhouse gases, endangers public health and welfare within the meaning of the Clean Air Act.70 Methane 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 also damage vegetation, agricultural productivity, and cultural resources. Ozone is also a significant greenhouse gas in its own right, meaning that methane is doubly damaging to climate – 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 the ozone precursors VOCs and NOx.

72 VOCs are emitted from well drilling and completions, compressors, pneumatic devices, storage tanks, processing plants, and fugitives from production 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 for Policymakers, attached as Exhibit 45. We note that these global warming potential figures may be revised upward in the next IPCC report. A more recent study by Shindell et al. estimates methane’s 100-year GWP at 33; this same source estimates methane’s 20-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 Production in 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.

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turbines, and other engines used in drilling and hydraulic fracturing.74 NOx is also produced when gas is flared or used for heating.75 As a result of significant VOC and NOx emissions associated with oil and gas development, numerous areas of the country with heavy concentrations of drilling are now suffering from serious ozone problems. For example, the Dallas Fort Worth area in Texas 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 wells permitted.76 Of the nine counties surrounding the Dallas Forth Worth area that EPA has designated as “nonattainment” for ozone, five contain significant oil and gas development.77 A 2009 study found that summertime emissions of smog-forming pollutants from these counties were roughly comparable to emissions from motor vehicles in those areas.78 Oil and gas development has also brought serious ozone pollution problems to rural areas, such as western Wyoming.79 On March 12, 2009, the governor of Wyoming recommended that the state designate Wyoming’s Upper Green River Basin as an ozone nonattainment area.80 The Wyoming Department of Environmental Quality conducted

74 See, e.g., TSD at 3-6; See also Barnett Shale Report at 24. Air Quality Impact Analysis Technical Support Document for the Revised Draft Supplemental Environmental Impact Statement for the Pinedale Anticline Oil and Gas Exploration and Development Project at 11 (Table 2.1). 75 TSD at 3-6; Colorado Department of Public Health and Environment, Colorado Visibility and Regional Haze State Implementation Plan for the Twelve Mandatory Class I Federal Areas in Colorado, Appendix D at 1 (2011), available at http://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 high concentrations 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 Regional Administrator, USEPA Region 8, (Mar. 12, 2009) (“Wyoming 8-Hour Ozone Designation Recommendations”), available at http://deq.state.wy.us/out/downloads/Rushin%20Ozone.pdf, attached as Exhibit 51; Wyoming Department of Environmental Quality, Technical Support Document I for Recommended 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

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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 of Sublette County suffered thirteen days with ozone concentrations considered “unhealthy” under EPA’s current air-quality index, including days when the ozone pollution levels exceeded the worst days of smog pollution in Los Angeles.82 Residents have faced repeated warnings regarding elevated ozone levels and the resulting risks of going outside.83 Ozone problems are mounting in other Rocky Mountain states as well. Northeastern Utah recorded unprecedented ozone levels in the Uintah Basin in 2010 and 2011. In the first three months of 2010—which was the first time that winter ozone was monitored in the region—air quality monitors measured more than 68 exceedances of the federal health standard. On three of these days, the levels were almost twice the federal standard.84 Between January and March 2011, there were 24 days where the National Ambient 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 of

http://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 at http://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 Exhibit 53; see also Wendy Koch, Wyoming's 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 Exhibit 54. 83 See, e.g., 2011 DEQ Ozone Advisories, Pinedale Online! (Mar. 17, 2011) (documenting ten ozone advisories in February and March 2011), available at http://www.pinedaleonline.com/news/2011/03/OzoneCalendar.htm, attached as Exhibit 55; Wyoming Department of Environmental Quality, Ozone Advisory for Monday, Feb. 28, Pinedale Online! (Feb. 27, 2011), available at http://www.pinedaleonline.com/news/2011/02/OzoneAdvisoryforMond.htm, attached as Exhibit 56. 84 Scott Streater, Air Quality Concerns May Dictate Uintah Basin's Natural Gas Drilling Future, 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, attached as Exhibit 57. 85 See EPA, AirExplorer, Query Concentrations (Ozone, Uintah County, 2011), available at http://www.epa.gov/cgi-bin/htmSQL/mxplorer/query_daily.hsql?msaorcountyName=countycode&msaorcounty

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Land Management (BLM) has identified the multitude of oil and gas wells in the region as the primary cause of the ozone pollution.86 Rampant oil and gas development in Colorado and New Mexico is also leading to high levels of VOCs and NOx. In 2008, the Colorado Department of Public Health and Environment concluded that the smog-forming emissions from oil and gas operations exceed vehicle emissions for the entire state.87 Moreover, significant additional drilling has occurred since 2008. Colorado is now home to more than 46,000 wells.88 There is also significant development in the San Juan Basin in southeastern Colorado and northwestern New Mexico, with approximately 35,000 wells in the Basin. As a result of this development and several coal-fired power plants in the vicinity, the Basin suffers from serious ozone pollution.89 This pollution is taking a toll on residents of San Juan County. The New Mexico Department of Public Health has documented increased emergency room visits associated with high ozone levels in the County.90 VOC and NOx emissions from oil and gas development are also harming air quality in national parks and wilderness areas. Researchers have determined that numerous “Class I areas” – a designation reserved for national parks, wilderness areas, and other such lands91 – are likely to be impacted by increased ozone pollution as a result of oil and gas development in the Rocky Mountain region, including Mesa Verde National Park and 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 Environmental Impact Statement (“GASCO DEIS”), at 3-13, available at http://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 Gas Emission 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 and Gas 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 Medical Visits for Asthma in San Juan County (Aug. 2007), available at http://www.nmenv.state.nm.us/aqb/4c/Documents/SanJuanAsthmaDocBW.pdf, attached as Exhibit 63. 91 See 42 U.S.C. § 7472(a).

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Bandelier Wilderness Area, Pecos Wilderness Area, and Wheeler Peak Wilderness Area in New Mexico.92 These areas are all near concentrated oil and gas development in the San Juan Basin.93 As oil and gas development moves into new areas, particularly as a result of the boom in development of shale resources, ozone problems are likely to follow. For example, regional air quality models predict that gas development in the Haynesville shale will increase ozone pollution in northeast Texas and northwest Louisiana and may lead to violations of ozone NAAQS.94 Sulfur dioxide: Oil and gas production emits sulfur dioxide, primarily from natural gas processing plants.95 Sulfur dioxide is released as part of the sweetening process, which removes hydrogen sulfide from the gas.96 Sulfur dioxide is also created when gas containing hydrogen sulfide (discussed below) is combusted in boilers or heaters.97 Hydrogen sulfide: Some natural gas contains hydrogen sulfide. When hydrogen sulfide levels 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 gas tends to be sour.99 All told, between 15 and 20% of the natural gas in the U.S. may contain hydrogen sulfide.100

92 Rodriguez et al., Regional Impacts of Oil and Gas Development on Ozone Formation in the Western United States, 59 Journal of the Air and Waste Management Association 111 (Sept. 2009), available at http://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 Haynesville Shale 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 is greater than 0.25 grain per 100 standard cubic feet, along with the presence of carbon dioxide. Id. 99 EPA, Office of Air Quality Planning and Standards, Report to Congress on Hydrogen Sulfide 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 as Exhibit 13. 100 Lana Skrtic, Hydrogen Sulfide, Oil and Gas, and People’s Health (“Skrtic Report”), at 6 (May 2006), available at http://www.earthworksaction.org/pubs/hydrogensulfide_oilgas_health.pdf, attached as Exhibit 66.

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Given the large amount of drilling in areas with sour gas, EPA has concluded that the potential for hydrogen sulfide emissions from the oil and gas industry is “significant.”101 Hydrogen sulfide may be emitted during all stages of development, including exploration, extraction, treatment and storage, transportation, and refining.102 For example, hydrogen sulfide is emitted as a result of leaks from processing systems and from wellheads in sour gas fields.103 Hydrogen sulfide emissions from the oil and gas industry are concerning because, as noted in part IV.A.1 above, this pollutant may be harmful even at low concentrations.104 Although 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 on people’s health. For example, North Dakota reported 3,300 violations of an odor-based hydrogen sulfide standard around drilling wells.105 People in northwest New Mexico and western Colorado living near gas wells have long complained of strong odors, including but not limited to hydrogen sulfide’s distinctive rotten egg smell. Residents have also experienced nose, throat and eye irritation, headaches, nose bleeds, and dizziness.106 An air sample taken by a community monitor at one family’s home in western Colorado in January 2011 contained levels of hydrogen sulfide concentrations 185 times higher than safe levels.107 Particulate Matter (PM): The oil and gas industry is a major source of PM pollution. This pollution is generated by heavy equipment used to move and level earth during well pad and road construction. Vehicles also generate fugitive dust by traveling on access roads during drilling, completion, and production activities.108 Diesel engines used in drilling rigs and at compressor stations are also large sources of fine PM/diesel soot emissions. VOCs are also a precursor to formation of PM2.5.109

101 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 of Current 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 Pollution from 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 Draft Environmental Impact Statement, at App. J at 2 (Oct. 2010) (“GASCO DEIS”) 109 O&G NSPS RIA at 4-18.

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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 repeatedly measured wintertime PM2.5 concentrations above federal standards.110 These elevated levels of PM2.5 have been linked to oil and gas activities in the Uinta Basin.111 West Tavaputs FEIS at 3-20. Modeling also shows that road traffic associated with energy development is pushing PM10 levels very close to violating NAAQS standards.112

ii. EPA’s Air Rules Will Not Fully Address These Air Pollution Problems

Although EPA’s recently finalized new source performance standards and standards for hazardous air pollutants113 do reduce some of these pollution problems, they will not solve 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 control emissions from most transmission infrastructure.115 Third, existing sources of air pollution are not controlled for any pollutant, meaning that increased use of existing infrastructure will produce emissions uncontrolled by the rules. Fourth, without full enforcement, the rules will not reduce emissions completely. Thus, though FERC might work with EPA to fully understand the emissions levels likely after the rules are fully implemented, it may not rely upon the EPA rules to avoid weighing and disclosing these impacts.

e. Gas Production Disrupts Landscapes and Habitats Increased oil and gas production will transform the landscape of regions overlying shale gas plays, bringing industrialization to previously rural landscapes and significantly affecting ecosystems, plants, and animals. These impacts are large, and difficult to manage. Land use disturbance associated with gas development impacts plants and animals through direct habitat loss, where land is cleared for gas uses, and indirect

110 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 and National Emission Standards for Hazardous Air Pollutants, Final Rule (Apr. 17, 2012), not yet published in the Federal Register, but available at http://www.epa.gov/airquality/oilandgas/actions.html. 114 See id.128-31. 115 See, e.g., id. at 173, 177

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habitat loss, where land adjacent to direct losses loses some of its important characteristics. Regarding direct losses, land is lost through development of well pads, roads, pipeline corridors, corridors for seismic testing, and other infrastructure. The Nature Conservancy (“TNC”) estimated that, in Pennsylvania,“[w]ell pads occupy 3.1 acres on average 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 and Wind (2010) at 10, 116 see also id. at 18. New York’s Department of Environmental Conservation reached similar estimates. New York Department of Environmental Conservation’s Revised Draft Supplemental General Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program, 5-5 (Sept. 2011) (hereinafter “NY RDSGEIS”).117 After initial drilling is completed the well pad is partially restored, but 1 to 3 acres of the well pad will remain disturbed through the life of the wells, estimated to be 20 to 40 years. Id. at 6-13. Associated infrastructure such as roads and corridors will likewise remain disturbed. Because these disturbances involve clearing and grading of the 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 habitat characteristics are affected by direct disturbances. “Adjacent lands can also be impacted, even if they are not directly cleared. This is most notable in forest settings where clearings fragment contiguous forest patches, create new edges, and change habitat conditions for sensitive wildlife and plant species that depend on “interior” forest conditions.” TNC, Pennsylvania Energy Impacts Assessment, Report 1: Marcellus Shale Natural Gas and Wind at 10. “Research has shown measureable impacts often extend 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. TNC mapped projected wells across the state, considering how the wells and their associated infrastructure, including roads and pipelines, interacted with the landscape. TNC’s conclusions 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

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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.

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TNC, Pennsylvania Energy Impacts Assessment, Report 1: Marcellus Shale Natural Gas and 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 could be reduced with proper planning, id., more development makes mitigation more difficult. Indeed, the Pennsylvania Department of Conservation and Natural Resources recently concluded that “zero” remaining acres of the state forests are suitable for leasing with surface disturbing activities, or the forests will be significantly degraded. Penn. Dep’t of Conservation and Natural Resources, Impacts of Leasing Additional State Forest 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 gas infrastructure transforms and distorts the existing landscape. They will also harm endangered species in regions where production would increase in response to he Company’s exports. Harm to these species and their habitat is, too, against the profound public interest in species conservation, as expressed in the Endangered Species Act and similar statutes.

f. Gas Production Poses Risks to Ground and Surface Water It is likely that much of the increased production that would result from the Company’s proposal will be from shale and other unconventional gas sources, and producing gas from these sources requires hydraulic fracturing, or fracking. See DOE, Shale Gas Production Subcommittee First 90-Day Report at 8.120 Hydraulic fracturing involves injecting a base fluid (typically water),121 sand or other proppant, and various fracturing chemicals into the gas-bearing formation at high pressures to fracture the rock and release 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 contaminate groundwater with either chemicals added to the fracturing fluid or with naturally occurring chemicals mobilized by fracking. After the well is fracked, some water will return to the surface, composed of both fracturing fluid and naturally occurring “formation” water. This water, together with drilling muds and drill cuttings, must be disposed of without further endangering water resources.

i. Water Withdrawals

118 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 based fracturing fluid. Fracking may also be conducted with oil or synthetic-oil based fluid, with foam, or with gas.

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The first step is the procurement of water. The precise amount of water varies by the shale formation being fracked. To use one example formation, fracking a Marcellus Shale well requires between 4 and 5 million gallons of water. TNC, Pennsylvania Energy Impacts Assessment, Report 1: Marcellus Shale Natural Gas and Wind, 5.122 Fresh water constitutes 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 Supplemental General Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program, 6-13 (Sept. 2011) (hereinafter “NY RDSGEIS”).123 Water withdrawals can drastically impact aquatic ecosystems and human communities. Reductions in instream flow negatively affect aquatic species by changing flow depth and velocity, raising water temperature, changing oxygen content, and altering streambed morphology. Id. 6-3 to 6-4. Even when flow reductions are not themselves problematic, the intake structures can harm aquatic organisms. Id. at 6-4. Where water is withdrawn from aquifers, rather than surface sources, withdrawal risks permanent depletion. This risk is even more prevalent with withdrawals for fracking than it is for other withdrawal, because fracking is a consumptive use. Fluid injected during the fracking process is (barring accident) deposited below freshwater aquifers and into sealed formations. Id. 6-5; DOE Subcommittee First 90 Day Report at 19 (“in some regions and localities there are significant concerns about consumptive water use for shale gas development.”). Thus, the water withdrawn from the aquifer will be used in a way that provides no opportunity to percolate back down to the aquifer and recharge it.

ii. Fracturing Fracturing poses a serious risk of groundwater contamination. Contaminants include chemicals added to the fracturing fluid and naturally occurring chemicals that are

122 Accord New York Department of Environmental Conservation’s Revised Draft Supplemental General Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program, (September 2011) (“Between July 2008 and February 2011, average water usage for high-volume hydraulic fracturing within the Susquehanna River Basin 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 are that 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 Regulatory Program (Jan. 11, 2012) (Attachment 2, Report of Tom Myers, at 10), attached as Exhibit 70 (hereafter Comment on NY RDSGEIS). Water needs in other geological formations vary. See Exhibit 37 at 19 (estimating that nationwide, fracking an individual well requires between 1 and 5 million gallons of water). 123 Available at http://www.dec.ny.gov/energy/75370.html

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mobilized from deeper formations to groundwater by the fracking process. Contamination may occur through several methods, including where the well casing fails or where the created fractures intersect an existing a poorly sealed well. Although information on groundwater contamination is incomplete, the available research indicates that contamination has already occurred on multiple occasions. One category of potential contaminants includes chemicals added to the drilling mud and fracturing fluid. The fluid used for slickwater fracturing is typically comprised of more than 98% fresh water and sand, with chemical additives comprising 2% or less of the fluid. NY RDSGEIS 5-40. Chemicals are added as solvents, surfactants, friction reducers, gelling agents, bactericides, and for other purposes. Id. 5-49. New York recently identified 322 unique ingredients used in fluid additives, recognizing that this constituted 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 of diesel, which the DOE Subcommittee has singled out for its harmful effects and recommended be banned from use as a fracturing fluid additive. DOE Subcommittee First 90-Day Report, 25. The minority staff of the House Committee on Energy and Commerce determined that despite diesel’s risks, between 2005 and 2009 “oil and gas service companies injected 32.2 million gallons of diesel fuel or hydraulic fracturing fluids 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 Gas Hydraulic Fracturing Activities Using Diesel Fuels (June 29, 2011) at 3 (quoting Letter from Reps. Waxman, Markey, and DeGette to EPA Administrator Lisa Jackson (Jan. 31, 2001) at 1) (hereafter Comment on Diesel Guidance).124 Contamination may also result from chemicals naturally occurring in the formation. Flowback and produced water “may include brine, gases (e.g. methane, ethane), trace metals, naturally occurring radioactive elements (e.g. radium, uranium) and organic compounds.” DOE Subcommittee first 90 day report at 21; see also Comment on NY RDSGEIS (attachment 3, Report of Glen Miller, at 2). For example, mercury naturally occurring in the formation becomes mixed in with water-based drilling muds, resulting in 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 vertical well bore. DOE Subcommittee First 90 Day Report, 20. The well bore inevitably passes through geological strata containing groundwater, and therefore provides a conduit by which chemicals injected into the well or traveling from the target formation to the

124 Attached as Exhibit 71.

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surface may reach groundwater. The well casing isolates the groundwater from intermediate strata and the target formation. This casing must be strong enough to withstand the pressures of the fracturing process--the very purpose of which is to shatter rock. Multiple layers of steel casing must be used, each pressure tested before use, then centered within the well bore. Each layer of casing must be cemented, with careful testing to ensure the integrity of the cementing. Comment on Diesel Guidance, 5-9. Proper casing construction is an elaborate engineering effort, with multiple layers of steel casing (that have been pressure tested), centralizers to center the casing in the well bore, careful cementing of the casing strings (together with testing to ensure the integrity of this cementing). Id. Separate from casing failure, contamination may occur when the zone of fractured rock intersects 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 recent study concluded, on the basis of geologic modeling, that frack fluid may migrate from the hydraulic fracture zone to freshwater aquifers in less than ten years.125 Available empirical data indicates that fracking has resulting in groundwater contamination in at least five documented instances. One study “documented the higher concentration of methane originating in shale gas deposits . . . into wells surrounding a producing shale production site in northern Pennsylvania.” DOE Subcommittee first 90 day report at 20 (citing Stephen G. Osborn, Avner Vengosh, Nathaniel R. Warner, and Robert B. Jackson, Methane contamination of drinking water accompanying gas-well drilling and hydraulic fracturing, Proceedings of the National Academy of Science, 108, 8172-8176, (2011)). By looking at particular isotopes of methane, this study was able to determine that the methane originated in the shale deposit, rather than from a shallower source. Id. The DOE Subcommittee referred to this as “a recent, credible, peer-reviewed study.” Id. Two other reports “have documented or suggested the movement of fracking fluid from the target formation to water wells linked to fracking in wells.” Comment on NY RDSGEIS (Attachment 2, Report of Tom Meyers, 13). “Thyne (2008)[126] found bromide in wells 100s of feet above the fracked zone.” Id. “The EPA (1987)[127] documented fracking fluid moving into a 416‐ foot deep water well in West Virginia; the gas well was less than 1000 feet horizontally from the water well, but the report does not indicate the gas‐bearing formation.” Id.

125 Tom Myers, Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers, 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 Wastes from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy, Volume 1 of 3, Oil and Gas. Washington, D.C., available at nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=20012D4P.txt, attached as Exhibit 73.

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More recently, EPA has investigated groundwater contamination in Pavillion, Wyoming and Dimock, Pennsylvania. In Pavillion, EPA’s draft report concludes that “when considered together with other lines of evidence, the data indicates likely impact to ground water that can be explained by hydraulic fracturing.” EPA, Draft Investigation of Ground Water Contamination near Pavillion, Wyoming (Dec. 2011), at xiii.128 EPA tested water from wells extending to various depths within the range of local groundwater. At the deeper tested wells, EPA discovered inorganics (potassium, chloride), synthetic organic (isopropanol, glycols, and tert-butyl alcohol), and organics (BTEX, gasoline and diesel range organics) at levels higher than expected. Id. at xii. At shallower levels, EPA detected “high concentrations of benzene, xylenes, gasoline range organics, diesel range organics, and total purgeable hydrocarbons.” Id. at xi. EPA determined that surface pits previously used for storage of drilling wastes and produced/flowback waters were a likely source of contamination for the shallower waters, and that fracturing likely explained the deeper contamination. Id. at xi, xiii. Although this is a draft report in an ongoing investigation, an independent expert who reviewed the EPA Pavillon study at the request of Sierra Club and other environmental groups has supported EPA’s findings.129 The report, and the expert’s findings, demonstrate a possibility of contamination that DOE must consider in its public interest evaluation. EPA is also investigating groundwater contamination in Dimock, Pennsylvania. EPA Region III, Action Memorandum - Request for Funding for a Removal Action at the Dimock Residential Groundwater Site (Jan. 19, 2012).130 In Dimock, EPA has determined that “a number of home wells in the Dimock area contain hazardous substances, some of which are not naturally found in the environment.” Id. at 1. Specifically, wells are contaminated with arsenic, barium, bis(2(ethylhexyl)phthalate, glycol compounds, manganese, phenol, and sodium. Id. at 3-4. Many of these chemicals are hazardous substances as defined under CERCLA section 101(14); see also 40 C.F.R. § 302.4. EPA’s determination is based on “Pennsylvania Department of Environmental Protection (PADEP) and Cabot Oil and Gas Corporation (Cabot) sampling information, consultation with 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 led to contamination of these water supplies. Drilling in the area began in 2008, and was

128 Attached as Exhibit 74, available at http://www.epa.gov/region8/superfund/wy/pavillion/EPA_ReportOnPavillion_Dec-8-2011.pdf 129 Tom Myers, Review of DRAFT: Investigation of Ground Water Contamination near Pavillion Wyoming (April 30, 2012), attached as Exhibit 75 and available at http://docs.nrdc.org/energy/files/ene_12050101a.pdf. 130 Attached as Exhibit 76, available at http://www.epaosc.org/sites/7555/files/Dimock%20Action%20Memo%2001-19-12.PDF

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conducted using the hazardous substances that have since been discovered in well water. Id. at 1, 2. Shortly thereafter methane contamination was detected in private well water. Id. at 2. In addition, there were several surface spills in connection with the drilling operation. Id. at 1. After the contamination was detected, PADEP entered a consent decree with Cabot which required permanent restoration or replacement of the water supply. Id. at 2. Cabot has installed or is installing a “gas mitigation” system for the affected wells. Id., see also Agency for Toxic Substances and Disease Registry, Record of Activity/Technical Assist (Dec. 28, 2011) at 2 (hereafter ATSDR).131 Pursuant to the consent decree, Cabot was providing replacement water to all 18 homes until 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, hazardous substances these ‘gas mitigation’ systems, originally designed to address methane, are removing.” EPA Action Memorandum at 2. EPA sampled water from 64 home wells.132, “EPA found hazardous substances, specifically arsenic, barium or manganese, all of which are also naturally occurring substances, in well water at five homes at levels that could present a health concern. In all cases the residents have now or will have their own treatment systems that can reduce concentrations of those hazardous substances to acceptable levels at the tap.”133

iii. Waste Management Fracturing produces a variety of liquid and solid wastes that must be managed and disposed of. These include the drilling mud used to lubricate the drilling process, the drill cuttings removed from the well bore, the “flowback” of fracturing fluid that returns to the surface in the days after fracking, and produced water that is produced over the life of the well (a mixture of water naturally occurring in the shale formation and lingering fracturing fluid). These wastes contain the same contaminants described in the preceding section. They present environmental hazards with regard to their onsite management and with their eventual disposal. On site, drilling mud, drill cuttings, flowback and produced water are often stored in pits. 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 by the use of seal tanks in a “closed loop” system. See, e.g., NY RDSGEIS at 1-12. Presently,

131 Attached as Exhibit 77, available at http://www.epa.gov/aboutepa/states/dimock.pdf. 132 EPA, EPA Completes Drinking Water Sampling in Dimock, Pa (July 25, 2012), attached as Exhibit 78, and available at http://yosemite.epa.gov/opa/admpress.nsf/0/1A6E49D193E1007585257A46005B61AD 133 Id.

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only New Mexico mandates the use of closed loop waste management systems, and pits remain in use elsewhere. Flowback and produced water must ultimately be disposed of offsite. Some of these fluids may be recycled and used in further fracturing operations, but even where a fluid recycling program is used, recycling leaves concentrated contaminants that must be disposed of. The most common methods of disposal are disposal in underground injection wells or through water treatment facilities leading to eventual surface discharge. Underground injection wells present risks of groundwater contamination similar to those identified above for fracking itself. Gas production wastes are not categorized as hazardous under the Safe Drinking Water Act, 42 U.S.C. § 300f et seq., and may be disposed of in Class II injection wells. Class II wells are brine wells, and the standards and safeguards in place for these wells were not designed with the contaminants found in fracking wastes in mind. See NRDC et al., Petition for Rulemaking Pursuant to Section 6974(a) of the Resource Conservation and Recovery Act Concerning the Regulation of Wastes Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas or Geothermal Energy (Sept. 8, 2010).134 Additionally, underground injection of fracking wastes appears to have induced earthquakes in several regions. Underground injection of fracking waste in Ohio has been correlated with earthquakes as high as 4.0 on the Richter scale. Columbia University, Lamont-Doherty Earth Observatory, Ohio Quakes Probably Triggered by Waste Disposal Well, Say Seismologists (Jan. 6, 2012).135 Underground injection may cause earthquakes by causing movement on existing fault lines: “Once fluid enters a preexisting fault, it can pressurize the rocks enough to move; the more stress placed on the rock formation, the more powerful the earthquake.” Id. Underground injection is more likely than fracking to trigger large earthquakes via this mechanism, “because more fluid is usually being pumped underground at a site for longer periods.” Id. In light of the apparent induced seismicity, Ohio has put a moratorium on injection in the affected region. Id. Similar associations between earthquakes and injection have occurred in Arkansas, Texas, Oklahoma and the United Kingdom. Id., Alexis Flynn, Study Ties Fracking to Quakes in England, Wall Street Journal (Nov. 3, 2011).136 In light of these effects, Ohio and Arkansas have placed moratoriums on injection in the affected areas. Lamont-Doherty Earth Observatory; Arkansas Oil and Gas Commission, Class II

134 Attached as Exhibit 79. 135 Attached as Exhibit 80, available at http://www.ldeo.columbia.edu/news-events/seismologists-link-ohio-earthquakes-waste-disposal-wells 136 Attached as Exhibit 81, available at http://online.wsj.com/article/ SB10001424052970203804204577013771109580352.html

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Commercial Disposal Well or Class II Disposal Well Moratorium (Aug. 2, 2011).137 The recently released abstract of a forthcoming United States Geological Survey study affirms the connection between disposal wells and earthquakes. Ellsworth, W. L., et al., Are Seismicity Rate Changes in the Midcontinent Natural or Manmade?, Seismological Society of America, (April 2012).138 As an alternative to underground injection, flowback and produced water is also sent to water treatment facilities, leading to eventual surface discharge. This presents a separate set of environmental hazards, because these facilities (particularly publicly owned treatment works) are not designed to handle the nontraditional pollutants found in 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 at http://www.aogc.state.ar.us/Hearing%20Orders/2011/July/180A-2-2011-07.pdf 138 This abstract is attached as Exhibit 83, and is available at http://www2.seismosoc.org/FMPro?-db=Abstract_Submission_12&-recid=224&-format=%2Fmeetings%2F2012%2Fabstracts%2Fsessionabstractdetail.html&-lay=MtgList&-find

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Comment on NY RDSGEIS (attachment 3, Report of Glen Miller, at 13). Similarly, municipal treatment works typically to not treat for radioactivity, whereas produced water can have high levels of naturally occurring radioactive materials. In one examination of three samples of produced water, radioactivity (measured as gross alpha radiation) were found ranging from 18,000 pCi / L to 123,000 pCi/L, whereas the safe drinking water standard is 15 pCi/L. Id. (Miller Report at 4). The Commission is required to analyze all of these indirect impacts of the increased natural gas production that will result from the Company’s three-phase LNG terminal proposal.

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 FERC with determining whether siting, construction, and operation of jurisdictional LNG terminal facilities is in the public interest. See, e.g. 15 U.S.C. § 717b(a). Regardless of any 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, “the agency must examine the relevant data and articulate a satisfactory explanation for its action 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 the record in this case. FERC must carefully examine both the positive and negative impacts of natural gas terminal proposals. Here, the Company’s application briefly presents the benefits of a single phase of its three-phase proposal. However, as discussed, the Company refuses to present the potential costs of any of the three phases of its proposal, which may have substantial consequences for Hawaii’s environment and its ability to transition away from greenhouse gas-intensive fossil fuels. If all three phases are analyzed together (as they must be, under NEPA), the significant harms associated with the three-phase proposal are apparent. The Sierra Club has demonstrated the potentially devastating environmental harms associated with the natural gas drilling that would be required to bring LNG into Hawaii in significant quantities. We have also demonstrated the potential for LNG to delay or impede development of renewable energy, undermining the Hawaii Clean Energy Initiative, a key state policy goal, and eliminating a purported project benefit touted by the Company. Given these significant impacts and the elusiveness of many of the project’s benefits, FERC must find that the project is contrary to the public interest.

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V. The EIS Must Consider an Adequate Range of Alternatives Both NEPA and the Natural Gas Act require FERC to fully consider alternatives to the Company’s proposal. Specifically, the public interest analysis requires an “exploration of all issues relevant to the ‘public interest’,” an inquiry which the Supreme Court held in Udall must be wide-ranging. In that case, which concerned hydropower, the regulatory agency was required to consider, for instance, “alternate sources of power,” the state of the 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 Hawaii that would better serve the public interest. Given imports’ sweeping impacts on Hawaii’s energy future, FERC must broadly analyze other approaches to phasing out Hawaii’s dependence on oil and promoting development of renewable energy resources. NEPA is designed to support this sort of broad consideration. “[T]he heart of the environmental impact statement” (which, as stated above, is required here) is an alternatives analysis that presents sharply defined issues and offers a “clear basis for choice among options by the decisionmaker and the public.” 40 C.F.R. § 1502.14. Crucially, the alternatives must include “reasonable alternatives not within the jurisdiction of the lead agency,” – meaning that FERC must review actions which it cannot directly order – and must include “appropriate mitigation measures not already included in the proposed action or alternatives.” Id. Because alternatives are so central to decisionmaking and mitigation, “the existence of a viable but unexamined alternative renders 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 contains a totally inadequate discussion of alternatives to the proposed project. RR at 4-5. The only alternative to LNG imports, the Company states, is the status quo. This range of alternatives is far too narrow, and the discussion of the only identified alternative is too cursory. FERC must go well beyond this cursory discussion of alternatives in developing the 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.

(3) Whether to delay, deny, or condition imports based upon their effect onHawaii's utility market and the development of renewable energy resources inHawaii.

(4) Whether to require the Company to certify that any unconventional gasproduced as a result of its proposal (or shipped through its facilities) has beenproduced in accordance with all relevant environmental laws and according to aset of best production practices (such as that discussed by the DOE's Shale GasSubcommittee).

(5) Whether to deny the Company's proposal altogether as contrary to the publicinterest.

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. Conclusion

Sierra Club therefore moves to intervene, offers the above comments, and protests theCompany's application for approval of the proposed LNG terminal facilities.

Respectfully submitted,

Ellen Medlin

Nathan MatthewsEllen MedlinAssociate AttorneysSierra Club Environmental Law Program85 2nd St., Second FloorSan Francisco, CA 94105

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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